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India Utilities Waiting for a new dawn INDIA | Utilities

28 April 2015

The Indian Power Utilities sector has underperformed the BSE Sensex 15%/2% during FY14 /FY15 as the sector grappled with fuel uncertainty and suppressed demand from loss making SEBs leading to lower utilization for generators. Post a series of reform measures initiated over the past few years, we are constructive on the transmission utilities and fuel suppliers while still cautious on the generation segment, pending distribution reforms. We initiate coverage with a BUY on Coal India, Power Grid, PTC India and a Neutral rating on NTPC. Slowdown in pace of capacity addition We believe India’s annual pace of capacity addition of ~ 18‐20GW (ex renewable) during past few years to slow down to 12‐ 14GW during FY17‐19E. We note limited near term ability of Coal India (CIL) to ramp up supply which coupled with distribution related issues would lead developers to delay commissioning. Note that Coal India has signed FSA’s with 78GW of plants commissioning till FY15 – there is little clarity on fuel supplies for power plants commissioning post FY15 and this would lead to delays in CoD. Demand‐Supply equilibrium by 2020 Based on our estimate of 86GW capacity addition during FY15‐20E (83GW in the XIIth plan), we expect supply growth at 8.5% CAGR. Supply would be driven by coal based generation at 9% CAGR. We expect utilization would pick up; however PLF will still continue to be sub optimal. Transmission constraints, limited availability of indigenous fuel and under utilization would continue, in our view. Thus, based on an 8% electricity demand growth, we expect India to attain equilibrium in electricity by FY20. However, we do note that for India to maintain this equilibrium in XIIIth and XIVth plan it is necessary to commence equipment ordering during FY16‐18E. Gradual ramp up in fuel supply – no quick fix solution possible We expect India will continue to be a net importer of coal unless India makes progress to improve domestic supply. Although new government has shown strong intent in speeding up construction of critical rail links for coal evacuation, benefits of these lines will accrue post FY18. Thus, we expect all India demand for coal to rise at 7% CAGR during FY14‐20E to 1.1bn tons driven by demand for power utilities and supply at 7.4% CAGR, implying 6% CAGR in import to 225mn tone by FY20. For utilities, we expect demand to grow 8% CAGR during FY14‐20E to 780mn tone and supply to grow to 681mn tone (8% CAGR) during same period leading to 7% CAGR growth in import. Distribution‐ the weakest link which remains unresolved Distribution remains the weakest link in the Indian power sector value chain as continued interference of state governments coupled with unremunerative tariffs has resulted in losses to the tune of Rs1060bn (FY13) to state discoms. Chronic under investment in distribution due to weak financial health of discoms ensures ~25% of power input in system remain unbilled. Although measures such as FRP (2003 and 2013) and feeder separation schemes have been initiated to mitigate losses, however implementation has been sketchy. Key stock recommendations We initiate coverage on PGCIL with Buy rating and target price of Rs 176 as we remain optimistic on transmission capex. We also initiate coverage on Coal India with target price of Rs 475 as we expect production and dispatches to improve driven by faster clearances. We initiate coverage on PTC India with target price of Rs 120 led by volume driven growth and strong performance of subsidiary driven by renewable capex. We initiate coverage on NTPC with Neutral rating and target price of Rs 160 as we expect stringent operational parameters under new tariff norms will result in subdued 4% CAGR during FY15‐17E.

Companies Coal India Reco BUY CMP, Rs 376 Target Price, Rs 475 NTPC Reco Neutral CMP, Rs 153 Target Price, Rs 160 PGCIL Reco BUY CMP, Rs 150 Target Price, Rs 176 PTC India Reco BUY CMP, Rs 75 Target Price, Rs 120 Ankur Sharma(+ 9122 6667 9759) [email protected] Hrishikesh Bhagat(+ 9122 6667 9986) [email protected]


UTILITIES SECTOR

Valuation Table Target ___________ PE___________ ___________ PB ___________ __________ ROE __________

CMP Price Rating FY15E FY16E FY17E FY15E FY16E FY17E FY15E FY16E FY17E Coal India 376 475 BUY 15.8 12.9 11.3 5.7 4.8 4.1 36% 37% 36% NTPC 150 160 Neutral 15.0 13.3 12.3 1.5 1.4 1.3 11% 11% 11% PGCIL 150 176 BUY 15.1 12.1 10.3 2.1 1.9 1.7 14% 16% 17% PTC India 75 121 BUY 7.9 7.8 6.6 0.8 0.7 0.7 6% 7% 7%

Source: Phillip Capital India Research Estimates Stock performance v/s Sensex

Source: Phillip Capital India Research Estimates

‐10

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30

50

70

90

110

130

150

1/1/2011 1/1/2012 1/1/2013 1/1/2014 1/1/2015

BSE Sensex PGCIL NTPC PTCIN Coal India


UTILITIES SECTOR

Contents

Big Opportunity clouded by weak execution ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 4

Generation‐ Private Sector leads the way ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 7

Mapping Demand and Supply ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 11

Fuel: Challenges to persist ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 15

Distribution ‐ Weak link in the value chain ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 22

Transmission‐ Bright Spot ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 27

Companies Section

Coal India ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 28

NTPC ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 43

Power Grid Corporation of India ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 61

PTC India ‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐‐ 78


UTILITIES SECTOR

Big opportunity clouded by weak execution India has one of the lowest per capita power consumption which represents a huge opportunity at macro level; however this has been clouded due to weak execution. Note that chronic under investments, high power deficits coupled with rising demand during the last decade compelled government to delicense generation (2003) and introduce competitive based bidding (2006) to attract private players in the sector; however outcome has been relatively mixed. Although substantial focus was made on the generation segment of the value chain, however such skewed approach in past decade led to inadequate focus on fuel and transmission segment, the impact of which was felt during FY10‐14. Per Capita Consumption

Source:WorldFactbook, Phillip Capital Deficit Chart

Source: CEA We note since electricity in India comes under concurrent list of constitution, presence of State government particularly in distribution segment of value chain has significantly impacted the sector performance. Although government in India had embarked upon ambitious project “Power for All by 2012”, the deadline for the same has been a moving target. The government’s (State as well as Central) halfhearted approach towards reforms in sector has kept investors largely cautious. The ideal ratio is Rs0.5 in transmission for every Re 1 invested in generation. But the focus in early plan period has largely been generation. We note capacity addition during FY07‐14 was a CAGR of 7% as against 4% witnessed during FY94‐04.

498

3493

6017

11919

2286

4347

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10000

12000

14000

India China Russia USA Brazil South Africa

Per Capita Power consumption (Kwh)

0

5

10

15

20

25

30

FY02 FY03 FY04 FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15

Base Deficit Peak Deficit

India has one of the lowest per capita consumption and elevated deficit


UTILITIES SECTOR

Installed Capacity

Source: CEA Evolution of Indian Power Sector Year Particular 1910 The Electricity Act 1910 created broad framework for electric supply 1948 The Electricity Act 1910 amended to create SEB to encourage electrification 1970‐1990 Creation of Central Utilities NTPC,NHPC, NEEPCO and transmission utilities 1991 The Electricity Act 19148 amended to allow private participation 1995 Introduction of Mega Power Policy, privatization of distribution initiated 1998 The Electricity Act (amendment) 1948 that promulgated creation of SERC and CERC and central and State transmission utility 2002 SEB restructuring 2003 Electricity Act 2003, allowed for Open Access, performance based regulation, delicensing of power generation and introduction of power trading2006 Competitive bidding guidelines introduced, Rural Electrification Policy 2007 Electricity (act ) amended , clarity on cross subsidy 2008 Introduction of Power Exchanges 2009 LTOA regulation 2011 PoC charges

Source: PhillipCapital India Research

0

50,000

100,000

150,000

200,000

250,000Capacity addition (MW)

7%

4% Pace of capacity addition has picked up post 2008 with entry of private sector


UTILITIES SECTOR

Significant steps…..but mixed outcomes During past two years, sector has gone through a significant pain as large capacity additions was not followed up with much needed ramp up in fuel supply and investment in T&D. Despite SEB restructuring undertaken in 2002, we note political intervention coupled with unremunerative tariffs has led to huge losses to distribution companies resulting in second round of restructuring (FRP) in 2013. Higher losses impaired purchasing power leading to weak demand from SEB. Further lack of environmental clearances impacted CIL’s production, leading to fuel shortage. We note since 2012, the government has taken series of steps to revive investors’ sentiment, however the outcomes of these steps has largely been mixed. Steps Undertaken by the government to revive the power sector 1. CIL agreed to sign FSA for 78 GW (includes 8GW for tapering linkage). 2. PPA tariff revision for unremunerative PPA initiated by CERC and MERC. 3. Revised Case II SBD issued and revised Case I SBD expected in near term. 4. FRP approved for debt restructuring of discoms and working capital finance

recommenced by banks and PFC & REC. 5. Pass through of imported coal cost in lieu of domestic shortage for linkage plants

approved by CCEA subject to SERC’s approval 6. Removal of Go‐No Go policy by the MOEF. 7. Synchronisation of southern grid with national grid 8. Final regulation for MYT 2015‐19 issued by CERC 9. Deendayal Upadhyaya Gram Jyoti Yojana” for feeder separation launched 10. Coal block auction policy issued post de allocation of mines by Supreme Court 11. Amendment to Electricity Act initiated and approved by the Cabined in

December, 2014. This needs to be passed by the Parliament. 12. Land acquisition bill amendment approved by Cabinet – pending clearance in

parliament. 13. Coal Swapping to reduce logistics cost for utilities We note final impact of these steps has largely been mixed bag. Although, coal production has begun to improve led by speedier clearances, however imports continue to surge. On distribution front, however implementation of FRP has not been in its true spirit. Although demand has improved in key states driven by disbursal, however this has not been followed up with requisite measures such as tariff hike, implementation of “Model State Electricity Distribution Act”, reduction of T&D by states. Further, tariff revision initiated by electricity commissions’ remain stuck in legal quagmire. Power Index performance

Source: Bloomberg

0

100

200

300

400

500

600

BSE Power

Entry of private players boost sentiments

Strong primary market activity from private players kept

sentiment bouyant

Reality check as fuelshortage and weak SEB

Reformmeasures and hopes of strong government boost


UTILITIES SECTOR

Generation ‐ Private Sector leads the way We acknowledge India’s effort towards increasing capacity addition. The government taking cognizance of rising deficit in early decade allowed entry of private sector by delicensing the sector. Post the aggressive entry of private sector in generation segment, pace of capacity addition gained significant traction. Thus we note India added 59GW during FY12‐14, and to put that into perspective it was 2x capacity addition during FY08‐11.We note share of private sector in India’s generation sector gone up from 13% in FY07 to 26% in FY14. Deficit

Source: CEA Capacity addition

Source: CEA The capacity addition from private sector was aided by a favorable policy environment led by tax holiday, easy financing and swift clearances.

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2.0

4.0

6.0

8.0

10.0

12.0

FY98 FY99 FY01 FY02 FY03 FY04 FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15

Base Deficit (%)

0

5,000

10,000

15,000

20,000

25,000 Capacity addition (MW)

Higher deficit ushered entry of private sector

Capacity addition gained traction


UTILITIES SECTOR

……….however pace to slow down We expect pace of capacity addition to slow down in upcoming years. We believe India’s annual capacity addition of ~ 18‐20GW during past few years to slow down to 12‐ 14GW. Thus, in XIIth plan we expect India to add 83GW (54 GW achieved till Feb’15) capacity lower than CEA’s estimate of 88GW. At 83 GW the capacity addition will be equivalent to India’s total capacity addition during Xth and XIth plan. Also during FY18‐20E we expect capacity addition at 40 GW. Capacity addition

Source: CEA Our key arguments in favor of slowdown in capacity addition are: 1. CIL’s ability to meet FSA’s only to the extent of 78 GW for plants commissioned

till FY15. This would continue to create fuel uncertainty for plants to be commissioned post FY15 and delay commissioning of such plants.

2. Existing issues at distribution end continue to remain unresolved thus suppressing demand and PLF’s. Further we believe during past FY11‐15e, India’s capacity addition was not commensurate to demand (105GW). Thus, as existing capacity gets absorbed in the system, and till utilization of existing capacity picks up developers would continue to delay CoD.

3. Further we note equipment ordering has slowed down materially post euphoria witnessed during FY07‐10, thus raising concerns over capacity addition during 13th plan. Also, a large segment of orders is being driven by state utilities that are prone to delays. We believe capacity addition in early part of 13th plan would largely be led by slippages of 12th plan, and state utilities to drive capacity addition in the 13th plan.

BTG ordering

Source: PhillipCapital India Research Estimate

9

3

10

12

21 21

18

22

13

10

16

13 11

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5

10

15

20

25 Capacity addition (GW)

Pace of capacity addition to slow down


UTILITIES SECTOR

4. Leverage on IPP’s balance sheet continues to be elevated as most of their existing capacity remains stuck in unremunerative tariff. Unless issues on unremunerative tariffs are addressed through legal solution, balance sheet and cash flow strain will continue for IPP’s which in turn will impact new capacity addition.

Leverage of various players (graphs)

Source: Bloomberg, PhillipCapital India Research Estimate We note higher leverage has opened up significant inorganic opportunities within the sector. Many leveraged developers have sold assets to address cash flow issues. We expect merger and asset sale to continue, however we note many assets continue to struggle due to unremunerative PPA and coupled with cost escalation the ROE;s continue to be suppressed. M&A in the Power sector has picked up with IPP’s looking to deleverage Asset Capacity Developer Acquirer Amount Rs/MWBaspa & Karcham 1391 JPVL JSW Energy 94,260 68 Budhil 70 Lanco Infra Tejassarnika Hydro Energies Private 6,240 89 Udupi 1200 Lanco Infra Adani Power 60,000 50 Korba West 600 Avantha Power Adani Power 42,000 70 Karcham and Baspa 1391 JPVL JSW Energy 97,000 70 Bela TPS 540 Ideal Energy Tata Power NA NAJangir Champa 1200 DB Power IDFC PE(15% stake) 5,000 28

Source: PhillipCapital India Research Like in previous plans, we expect capacity addition to be driven by coal sector. Limited availability of indigenous gas would impact capacity additions. We also note that hydro based capacity in India continue to be impacted by lack of clearances and local issues. Capacity addition estimate‐ Fuel wise Fuel FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15E FY16E FY17E FY18E FY19E FY20E Coal 5,620 2,010 6,655 9,225 17,884 18,115 15,095 18,765 10,525 8,620 12,730 11,540 10,460 Lignite ‐ ‐ 335 635 520 540 ‐ 250 ‐ ‐ ‐ ‐ ‐Gas 1,000 475 2,116 1,391 674 1,457 1,672 1,189 ‐ ‐ 2,400 770 ‐Thermal 6,620 2,485 9,106 11,251 19,078 20,112 16,767 20,204 10,525 8,620 15,130 12,310 10,460 Hydro 2,423 969 39 690 1,423 501 1,060 872 1,496 1,671 1,190 900 400 Nuclear 220 ‐ 440 220 ‐ ‐ ‐ 1,000 1,000 ‐ ‐ ‐ 500 Total 9,263 3,454 9,585 12,161 20,501 20,613 17,827 22,076 13,021 10,291 16,320 13,210 11,360

Source: CEA, PhillipCapital India Research Estimate We note capacity addition would be driven by the private sector in the 12th plan and its share in overall capacity mix would increase. However based on ordering it is likely

0

1

2

3

4

5

6

7

8

NTPC TPWR RPWR NHPC ADANI JSW JPVL NLC SJVN

Debt Equity (x)

Leverage continues to be elevated across most private players


UTILITIES SECTOR

that share of private sector could stagnate by end of 12th plan and capacity addition from state and central utilities would pick up. Capacity addition estimate‐ Ownership wise Ownership FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15E FY16E FY17E FY18E FY19E FY20E Centre 3,240 750 2,180 3,780 5,820 5,397 2,575 4,405 4,315 2,300 3,710 5,360 7,400 State 5,273 1,821 3,118 3,259 3,761 3,958 3,367 3,416 3,930 2,595 750 ‐ ‐Private 750 883 4,287 5,122 10,920 11,258 11,885 14,255 4,776 5,396 11,860 7,850 3,960 Total 9,263 3,454 9,585 12,161 20,501 20,613 17,827 22,076 13,021 10,291 16,320 13,210 11,360

Capacity addition break‐ up

Source: CEA, PhillipCapital India Research Estimates

State wise capacity addition (MW) MW FY08 FY09 FY10 FY11 FY12 FY13 FY14E FY15E FY16E FY17E FY18E FY19E FY20EAndhra Pradesh 249 39 1,516 1,586 1,189 300 300 2,190 2,120 960 3,060 1,430 ‐Arunachal Pradesh ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ 300 410 ‐ ‐ ‐Assam ‐ ‐ ‐ ‐ 37 ‐ ‐ 250 250 250 ‐ ‐ ‐Bihar 500 ‐ 500 ‐ ‐ ‐ 660 1,105 445 500 1,320 1,980 660Chhattisgarh 1,500 1,000 850 500 1,490 1,345 3,530 3,135 1,020 960 3,780 3,060 1,600Delhi 1,072 286 250 500 ‐ ‐ ‐ ‐ ‐ ‐Gujarat 40 383 1,874 1,570 4,481 5,024 1,151 776 ‐ 250 760 ‐ ‐HARYANA 600 ‐ 600 1,100 1,160 1,160 ‐ ‐ ‐ ‐ ‐ ‐ ‐HP ‐ ‐ ‐ 192 1,100 301 597 437 500 675 ‐ 640 400J&K ‐ 450 ‐ 120 ‐ 44 285 ‐ ‐ ‐ 330 ‐ ‐Jharkhand ‐ ‐ 500 ‐ 1,550 1,040 ‐ ‐ 500 ‐ 1,740 1,860 2,640Karnataka 720 230 600 1,070 1,100 ‐ ‐ ‐ ‐ ‐ 1,600 800 ‐Kerala ‐ ‐ ‐ 100 ‐ ‐ ‐ 30 30 ‐ ‐ ‐ ‐Madhya Pradesh 1,020 210 ‐ ‐ ‐ 2,350 2,875 3,240 660 600 400 1,200 1,980Maharashtra 990 500 500 1,005 2,481 3,580 2,760 1,500 1,860 2,220 500 ‐ 1,320Manipur ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐Meghalaya ‐ ‐ ‐ ‐ 84 42 ‐ ‐ 40 ‐ ‐ ‐ ‐Mizoram ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐ ‐Orissa 150 ‐ ‐ 1,200 600 950 700 1,200 350 700 1,050 660 2,260Punjab 250 250 ‐ ‐ ‐ ‐ 700 1,360 660 930 ‐ ‐ ‐Rajasthan 220 ‐ 1,395 635 270 650 1,570 900 600 ‐ ‐ ‐ ‐Sikkim 510 ‐ ‐ ‐ ‐ ‐ 100 96 200 320 200 ‐ ‐Tamil Nadu ‐ 92 ‐ ‐ 750 1,865 1,295 2,350 2,100 150 660 ‐ 500TRI ‐ ‐ ‐ 21 ‐ 363 ‐ 363 ‐ ‐ ‐ ‐ ‐Uttar Pradesh ‐ ‐ 790 790 2,410 1,250 500 500 1,160 660 660 1,320 ‐Uttarakhand 304 ‐ ‐ 200 200 ‐ ‐ 99 166 166 260 260 ‐West Bengal 2,210 300 460 1,000 1,313 99 283 900 1,020 540 ‐ ‐ ‐Total 9,263 3,454 9,585 12,161 20,501 20,613 17,806 20,431 13,981 10,291 16,320 13,210 11,360

Source: PhillipCapital India Research Estimates

Center33%

State 40%

Private27%

FY14

Center33%

State 32%

Private35%

FY20


UTILITIES SECTOR

Mapping electricity demand and supply India’s electricity growth has historically shown an average elasticity of 0.7‐0.8x of GDP growth. We note even during period of FY04‐08 when India experienced 7‐8% GDP growth, demand growth as reported by CEA, was in range of 6‐8%, implying lower elasticity. Demand elasticity

Source: PhillipCapital India Research Estimates Base and Peak Deficit(%)

Source: CEA, PhillipCapital India Research Estimates We understand India’s lower demand elasticity could be attributed to weak distribution. Due to weak financial health, state discoms’ preferred to shed demand rather than meet incremental demand and strain finances. Thus, during FY14 in addition to robust supply led by strong capacity addition, demand was also weak leading to sharp reduction in deficit. This has continued into FY15 as well. Further, lower demand elasticity is also attributed to India’s electricity demand composition that is different as compared to other countries due to contribution of industry and services in GDP. Thus based on sector classification, services contribute 57% and industry at 26% to India’s economy as against 44% for industry and 46% for services to China’s economy.

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0.20

0.40

0.60

0.80

1.00

1.20

1.40

1.60

FY02 FY03 FY04 FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14

Demand elasticity

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5

10

15

20

25

30




UTILITIES SECTOR

Demand Composition – FY13

Source: PFC In order to project future demand, we analyzed demand growth in key cities of Mumbai, Kolkata, Ahmedabad and Surat which could be used as best case reference to project India’s demand. Our analysis of demand in these cities indicates during FY02‐14, demand in Mumbai, Kolkata and Ahmedabad and Surat grew 6‐8%. We have used similar nos. to project future electricity demand growth on a pan India basis. Demand growth (mn units)

Source: SERC, PhillipCapital India Research Estimates Based on historic demand and assumption of GDP of 6% (old series) we expect demand to grow at 8% during FY15‐17E implying elasticity 1.33 (higher than 12 years average of 0.7x). Our demand estimate incorporates pent up demand due to improvement in discoms finances and rising electrification. We note demand was relatively subdued in FY14 and FY15 due to weak financial health of discoms and weak industrial demand.

Domestic28%

Commercial10%

Industry35%

Railways2%

Agriculture25%

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FY01 FY02 FY03 FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12

Kolkatta Ahmedabad + Surat Mumbai


UTILITIES SECTOR

Deficits to inch up….... Based on our estimate of 86GW capacity addition during FY15‐20E (83GW in XIIth plan) we expect supply at 8.5% CAGR. Supply would be driven by coal based generation at 9.3% CAGR. As economic recovery gains traction, demand would pick up and this would lead to increase in deficit during FY16‐17E. We expect utilization would also pick up; however PLF’s would still continue to remain sub ‐ optimal. Transmission constraints, limited availability of indigenous fuel and under utilisation would continue to cap merchant rates. Further unlike during FY07‐10, we expect deficit to be largely concentrated in regions where state government have not proactively planned power procurement and/or are facing transmission constraints. Thus, based on our capacity addition we expect higher deficits to prevail in Uttar Pradesh and Southern region particularly Telangana, Tamil Nadu and Karnataka. We expect aggregate utilization to pick up to historic high of 50‐55% from current 48% in FY14. We expect coal plant utilization to increase to 65‐67% from current 60%.Thus we expect India to attain equilibrium in electricity by FY20. However we do note that for India to maintain this equilibrium in XIIIth and XIVth plan it is necessary to commence equipment ordering during FY16‐17E. Projected deficit

Source: CEA, PhillipCapital India Research Estimates Base and Peak Deficits (%)


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14%

FY10 FY11 FY12 FY13 FY14 FY15E FY16E FY17E FY18E FY19E FY20E


We expect utilization to pick gradually led by improvement in fuel supply and demand pick up.

Deficit to stay elevated during FY15‐17E but reduce post FY18 and reach equilibrium by FY20

Deficit to inch up during FY16‐17E


UTILITIES SECTOR

Also despite higher deficit we maintain cautious stance on merchant power. We note lower utilization of existing plants would continue to put pressure on merchant markets. Further we expect merchant capacity would face headwinds on offtake front due to availability of competitively priced power post auction of captive mines. Merchant Price

Source: CERC, PhillipCapital India Research Estimates Demand – Supply dynamics

FY10 FY11 FY12 FY13 FY14 FY15E FY16E FY17E FY18E FY19E FY20EEnergy Available ‐ Ex Bus (MU) 746,645 788,355 857,928 908,329 962,916 1,036,176 1,117,046 1,214,058 1,320,404 1,442,862 1,549,530Growth (%) 5.6 8.8 5.9 6.0 7.6 7.8 8.7 8.8 9.3 7.4Energy Demand (MU) 830,594 861,591 936,913 995,491 1,002,257 1,082,438 1,169,033 1,262,555 1,363,560 1,472,644 1,549,530Growth (%) 6.9 3.7 8.7 6.3 0.7 8.0 8.0 8.0 8.0 8.0 8.0Energy Deficit (MU) 83,949 73,236 78,985 87,162 39,341 46,261 51,987 48,497 43,156 29,783 ‐Energy Deficit 10.1% 8.5% 8.4% 8.8% 3.9% 4.3% 4.4% 3.8% 3.2% 2.0% 0.0%Peak Demand 119,166 122,287 130,006 135,453 135,918 146,791 158,535 171,218 184,915 199,708 215,685Growth (%) 2.6 6.3 4.2 0.3 8.0 8.0 8.0 8.0 8.0 8.0Peak Avbl 104,249 110,256 116,191 123,294 129,815 141,403 149,735 160,868 177,234 194,126 215,685Growth (%) 5.8 5.4 6.1 5.3 8.9 5.9 7.4 10.2 9.5 11.1Peak Deficit 14,917 12,031 13,815 12,159 6,103 5,388 8,799 10,350 7,680 5,582 ‐Peak Deficit 12.5% 9.8% 10.6% 9.0% 4.5% 3.7% 5.6% 6.0% 4.2% 2.8% 0.0%


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FY09 FY10 FY11 FY12 FY13 FY14

Price Traders (Rs/kwh) Price ‐Exchange (Rs/kwh)


UTILITIES SECTOR

Fuel: Challenges to persist We expect challenges to persist in fuel supply both on Gas and Coal. India has had an adhoc approach towards capacity addition due to which pace of capacity addition has been sporadic. During FY07‐09 although India planned for 50GW+ capacity addition, we note similar follow through arrangement was not done on fuel front. Consequently, a large part of India’s capacity was planned based on “Letter of Assurances’ (LoA) from Coal India; however these LoA were not converted to FSA. Thus CIL struggled to meet increased demand with production growth of 4% during FY07‐14. Thus, large capacity has been synchronized with limited fuel availability which has stranded capacity to a great extent. Also India’s had limited success on captive coal. The problem of existing inefficiency was further aggravated by delayed clearances leading to stagnant coal production from CIL. Thus during FY04‐14, India witnessed 22% CAGR growth in coal imports (coking and non‐coking coal) Coal Imports

Source: CEA, PhillipCapital India Research Estimates Limited availability of domestic gas impacted gas based generation leading to suboptimal PLF. ~ 10 GW of gas based capacity remains stranded for want of gas. As against the requirement of 107mmmscmd, gas availability has dropped to 32 mmscmd from indigenous sources. Gas requirement


22 29

39 44 51 59

68 69

103

146 158

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20

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80

100

120

140

160

180

FY04 FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14

22%

9.0

9.4

9.9

10.2

10.2

10.9

12.4

13.4

13.6

15.8

16.6

16.9

18.4

21.7

45 46 48 49 50 53 61

66 67

78 81 81 91

107

24 24 25 26 31

35 35 38 37

55 59 56

40 32

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120

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15

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25


Gas‐based Capacity (GW)Gas required (mmscmd)*Gas supplied (mmscmd)


UTILITIES SECTOR

Gas ‐ PLF

Source: CEA We expect India will continue to be net importer of coal unless India makes progress to improve domestic supply. We note during FY07‐14, even as demand for coal was up 6.7%, supply was up mere 4.5% due to subdued captive production and weak production from CIL leading to higher imports. With aggregate production of ~50mn per annum as against potential 1.2bn tonne, share of captive coal in India’s coal production is significantly lower at ~10‐15%. The problem of shortage in indigenous coal supply was further aggravated due to logistic constraints leading to lower despatches. We note lack of clearances has delayed construction of critical rail links of 450km connecting key coal bearing states leading to lower despatch. Thus India had planned Tori‐Shivpuri‐Kathotia in North Karanpura in Jharkand in 2000; however line is yet to see light of day and is expected by FY18. Similar delay is witnessed in Jharsuguda‐Barpalli‐Sardega railway line (53 kms)) and Bhupdevpur‐Korichapan‐Dharamjaigarh(180 kms) in Mand‐Raigarh coalfield, Chhattisgarh. Although the new government has shown strong intent in speeding up construction of these lines, however benefits of these lines will accrue post FY18‐19. Together these lines will contribute to ~100mn tones coal. We expect construction to gain traction with the election of BJP government in Jharkand leading to better Centre and State co‐ordination. We expect all India demand for Coal at 7% CAGR during FY14‐20E to 1.1 bn tones by FY 20 driven by demand by Power utilities and supply at 7.4% CAGR, implying 6% CAGR in import to 226 mn tone by FY20. We note supply from captive mines could surprise on upside with faster clearances. For Power Utilities, we expect demand to grow 8% CAGR during FY14‐20E to 780 mn tone and supply to grow to 681 (8% CAGR) during same period leading to 7% CAGR growth in import.

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80

FY08 FY09 FY10 FY11 FY12 FY13 FY14

Gas based PLF have been down significantly due to lower indigineous gas supply.

Logistic constraints has also impacted supply


UTILITIES SECTOR

All India Coal Demand Supply Dynamics FY12 FY13 FY14E FY15E FY16E FY17E FY18E FY19E FY20E CAGR FY14‐20E

Coal consumption / Demand Coking coal 47 52 52 55 58 62 65 69 74 6.0 Power (Utilities) 412 457 504 538 571 604 652 722 780 7.5 Power (Non‐Utilities) 47 55 47 50 53 56 59 63 67 6.0 Cement 23 24 24 26 28 30 32 34 37 7.0 Sponge Iron / CDI 22 25 22 24 25 27 28 30 32 6.0 BRK & Others/Fert/Export/SSF/NLW 88 107 80 85 90 95 101 107 113 6.0 Non‐Coking coal 591 668 678 723 766 812 873 956 1,028 7.2 Raw coal consumption / demand 638 721 730 778 825 873 938 1,026 1,102 7.1

Coal Supply CIL (Offtake) 433 466 471 491 531 568 602 638 677 6.2 SCCL 51 53 48 50 52 54 56 58 61 4.0 Others 51 56 52 59 57 78 97 118 139 17.8 TOTAL INDIGENOUS COAL SUPPLY 535 575 571 600 640 700 756 814 876 7.4

Imports 103 146 158 178 184 173 183 211 226 6.1

Source: CEA, PhillipCapital India Research Estimates Coal demand for Power Utilities

FY12 FY13 FY14 FY15E FY16E FY17E FY18E FY19E FY20E CAGR FY14‐20EConsumption / Demand from Power utilities 412 457 488 538 570 604 652 722 780 8.1Growth (%) 6.0 10.8 6.8 10.3 5.9 6.0 8.0 10.7 8.0

CIL ‐ Offtake 433 466 471 491 531 568 602 638 677 6.2Growth (%) 2.0 7.7 1.1 4.1 8.2 6.9 6.0 6.0 6.0CIL ‐ Offtake to Power Utilities 312 347 355 401 417 433 459 511 541 7.3Growth (%) 2.5 11.2 2.2 13.1 4.0 3.8 6.0 11.2 6.0Supply to PU as prop. Of Total offtake of coal 72 74 75 82 79 76 76 80 80SCCL ‐ Offtake to Power Utilities 37 35 37 38 39 40 41 43 44 3.0Captive Mines ‐ Offtake to Power Utilities 18 25 30 37 35 42 65 81 96 21.3Total Indigenious Coal ‐ Power Utilities 367 407 421 476 491 516 565 634 681 8.3

Coal to be imported(GCV adjusted volumes) 36 40 53 49 63 71 70 70 79



UTILITIES SECTOR

Addressing fuel supply challenges Post 2012, government initiated several measures such as mandating CIL to sign FSA and attempted for coal/gas price pooling on fuel front. We note however most of these measures would address fuel supply issue in long run, but in 13th plan India too continue to be net importer of coal. We highlight below few such measures: Coal Price pooling: remains a non‐starter In 2013 to address shortage of indigenous fuel supply government decided to undertake coal price pooling. The mechanism included blending of domestic and imported coal by CIL and supplying coal at pooled price. The excess cost paid for the imported coal would be borne by the consumers of domestic coal. Although it didn’t take off in 2013, however it has been proposed and shelved multiple times in recent years. Key difficulty was opposition from discoms as tariffs would increase. Also we believe administering coal price mechanism would be significant challenge due to its complexity of mechanism. The coal price pooling mechanism will lead to increase in cost of coal supplied by CIL to all the power plants and will lower the cost of blended coal for new plants with LoA/FSA and consequently improve the PLF of new plants. Thus mechanism implicitly involved subsidizing new plants by old plants. We expect noises in favor of implementation of coal price pooling to reduce going forward if CIL improves dispatches and/or government successfully undertake coal block auction. E‐auction of captive coal mines: Fuel security over economics? In Sept 2014, the SC cancelled 204 captive coal blocks allotted on discretionary basis since 1993. In December the government issued regulation to allot coal blocks in transparent manner. In first stage government intends to auction, 101 coal blocks with capacity of 340mntonne of peak production capacity during next few months. We highlight the entire auction process has been drafted with adequate checks and balances to ensure that captive coal production that has been relatively stagnant gains traction. We note penalty for deviation from mining targets and end use restriction ensures only serious players will participate in auction. Further, we note early stage auction will most likely lead to re allotment of operational blocks and will unlock stuck projects. However new capex cycle will commence once pending 103 blocks are auctioned. We expect 22% CAGR during FY14‐20E. We note operational blocks auctioned in initial stage have witnessed aggressive biddings with participants quoting negative bids to win coal blocks. This implies bidders are willing to forego mining costs and instead pay a premium in order to ensure fuel security. In case of regulated plants; claiming pass through for negative bids become further difficult unlike in case of plants with open capacity wherein utility can incorporate mining cost in its fixed cost while signing PPA. We note the bidding strategy indicates, participants have prioritised fuel security over economics, implying RoE’s for these projects will continue to be on lower side.


UTILITIES SECTOR

We highlight below sensitivity of RoE for to various parameters. Impact of fuel cost under‐ recovery on RoE Ceteris paribus; every Rs100/ton under recovery due to negative bid impacts RoE by 2%, implying utility has to offset this with efficiency. ROE/Under Recovery(Rs/ton) 400 300 200 100 0Impact 8.08% 9.93% 11.79% 13.64% 15.50% Impact of savings in SHR Ceteris paribus; every 50kcal/kwh improvement in SHR improves RoE by 0.55%. ROE/SHR(kcal) 300 250 200 150 100 50 0

Impact 18.79% 18.24% 17.69% 17.14% 16.60% 16.05% 15.50%

Impact of savings in O&M Ceteris paribus; every 3% savings in O&M cost improves RoE by 0.21% ROE/O&M 15% 12% 9% 6% 3% 0%Impact 15.5% 16.5% 16.3% 16.1% 15.9% 15.7% 15.5%

Recent coal bids Mine State Capacity Developer Bids (Rs/tone)Gare‐Palma‐IV/2 Chhattisgarh ‐MandRaigarh II 6.25 Jindal Power (108)Tokisud North Jharkhand ‐South Karanpura II 2.32 Essar Power (1,110)Amelia (North) Madhya Pradesh‐Singrauli II 2.8 JPVL (715)Talabira‐I Orissa ‐IB Valley II 3 GMR Chattisgarh (478)Sarisatolli West Bengal ‐ Raniganj II 3.5 CESC (470)Trans Damodar West Bengal ‐Barjora II 1 Durgapur Projects (940)Mandakini Orissa ‐Talcher III 7.5 Mandakini exploration and mining Company (650)Utkal‐C Orissa ‐Talcher III 3.37 Monnet Power Company (770)Jitpur Jharkhand ‐ Rajmahal III 2.5 Adani Power (302)Ganeshpur Jharkhand ‐North Karanpura III 4 GMR Energy Chhatisgarh (704)Tara Chhattisgarh‐HasoAnand III 6 Jindal Power (126)

Source: Coal Ministry


UTILITIES SECTOR

Reviving stranded gas assets In order to revive stranded gas based assets, CCEA has come out with mechanism to import gas and supply to stranded assets subject to a price cap. The current mechanism was devised as earlier mechanism of “Gas Price Pooling” did not take off. The mechanism envisages importing regasified Liquified Natural Gas (RLNG) for supply to these plants so that they can generate power. Imported gas will be supplied to both stranded assets as well plant with domestic gas allocation and commensurate to 30% PLF. In order to secure fuel supply, generation companies will require to participate in reverse bidding with net purchase price for discoms capped at Rs 5.5/kwh for stranded assets and Rs 4.19/kwh for plants running on domestic fuel. Developers will have to quote per unit price support and incremental generation that they would undertake. Price support will be provided through PSDF. For FY16, the ceiling price for stranded plants will be Rs 0.94/kwh and Rs 1.26/kwh for plants receiving domestic gas and for FY17 at Rs 0.95/kwh and Rs 1.28/kwh. The bidders will have to quote lower support from the ceiling price. The government has targeted PLF of 25‐30% for plants and PSDF support has been capped at Rs 35bn/40bn for FY16/FY17 respectively. Further the mechanism also envisages reduction in transportation tariff, marketing margin and re‐gasification charges on the incremental RLNG of gas transporters and re‐gassification terminal operators. An empowered pool management committee (EPMC) will oversee the auction process and release the subsidy support to the discoms buying power from successful bidders. The discoms, in turn, will pay the gross value of purchased power (including the amount received from PSDF). The lead banker to the developer will control a trust and retention account (TRA) which will oversee payment to the firm. Under this mechanism developers will be allowed to recover only variable cost, O&M and debt servicing cost after capping fixed cost. We note off the 24 GW gas based installed capacity, 14 GW is stranded due to lack of gas and balance capacity is also operating at suboptimal PLF. These 14 GW that is facing under recovery will require 20mmscmd gas at 30% PLF. Since mechanism involves reverse auction, we note developers will require to sacrifice RoE to compete for gas. This implies except lenders, equity holders in power plant are not likely to benefit significantly from these measures. KG‐D6 production (mmscmd) Gas‐ PLF

Source: CEA PhillipCapital India Research Estimates We note even under reverse bidding the least developer will recover is variable cost and interest cost. We note at landed price of USD 10/mmbtu fuel cost stands at Rs 4.5/kwh. Further at Rs 50mn/MW cost of capacity, for gas based capacity running at

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60 59 5855

51 49 4651

34 3228

2319

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UTILITIES SECTOR

30% PLF, fixed cost (interest and O&M) would be Rs 1.7/kwh, implying cost of power of Rs 6.2/kwh. Thus we note at Rs 6.2/kwh based power continues to be uneconomical proposition even compared to 100% imported coal and weak discoms’ financials will make absorption of such expensive power difficult. The current policy would most likely favour plants with lower fixed cost and will not benefits stranded assets with higher capital cost. New plants will require support from lenders too to ensure selling price remains viable to discoms. Southern India could see marginal demand for expensive gas based power due to transmission constraints and higher deficit. However unless government introduce “peaking power policy” gas based capacity would continue to operate at suboptimal. Further gas plants would continue to face headwinds from underutilized coal based capacity. Variable cost for running a gas based power plant

Natural Gas IDR Coal e‐auction Linkage Indonesia Coal

Power Capacity 1000 MW 1000 1000 1000 MW PLF 30% % 90% 90% 90% % Gross Gen 2,628 mn kwh 7,884 7,884 7,884 mn KWH AUX 3.0% % 8.0% 8.0% 8.0% % Net Gen 2,549 mn KWH 7,253 7,253 7,253 mn KWH Calorific Value 9,000 kcal / scm of gas 4,800 3,600 3,600 Kcal / Kg SHR ‐ GCV 1,760 kcal / kwh 2,400 2,250 2,250 kcal / kwh Fuel Reqd 1.4 mmscmd 3.94 4.93 4.93 mn MT INR / USD 62 x 62 62 62 x Fuel Cost 10.00 USD / mmbtu 60 42 24 USD / Tonne Fuel Cost 2,460 Rs / mn kcal 775 722 417 Rs / mn kcal Fuel Cost 620 Rs / mmbtu 3,720 2,600 1,500 Rs/ Tonne Fuel Cost 11,380 Rs mn 14,664 12,812 7,391 Rs mn Energy Charge 4.5 Rs / kwh 2.02 1.77 1.02 Rs / kwh

Source: PhillipCapital India Research Estimates Fixed cost at different level of utilization Capacity (MW) 1,000 1,000 1,000Cost /MW 50 50 50Rs mn 50,000 50,000 50,000Equity 15,000 15,000 15,000Debt 35,000 35,000 35,000PLF 30% 50% 70%MU 2,628 4,380 4,380 Fixed Cost Rs/kwh Rs/kwh Rs/kwh RoE 0.9 0.5 0.4Interest 1.3 0.8 0.6Depreciation 0.7 0.4 0.3O&M 0.4 0.3 0.2Total 3.3 2.0 1.4



UTILITIES SECTOR

Distribution ‐ Weakest link in the value chain Distribution remains the weakest link in Indian Power Sector value chain. Higher interference of state government coupled with unremunerative tariffs has resulted in losses to the tune of Rs1060bn (FY13) to state discoms. Chronic under investment in distribution due to weak financial health of discoms ensures~25% of power input in system remains unbilled. Thus in FY13, only 4 discoms of 30 discoms reported profit on ex subsidy basis. Vicious circle of weak distribution Source: PhillipCapital AT&C loss

Source: PFC

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FY04 FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13

Under recovery of tariffs

Higher cash losses

Under investment in T&D infrastructure

Higher T&D losses

Higher AT&C losses due to under investment in distribution infrastructure…..


UTILITIES SECTOR

Average Cost of Supply and Realisation

Discoms Losses (Rsbn)

Source: PFC We note six states viz. Rajasthan, UP, TN , AP , Haryana, Jharkand and Punjab contribute 80% of losses. Despite undergoing restructuring exercise in FY02 and unbundling of state utilities, lack of political willingness ensured distribution sector in remains in abysmal state.Further high debt (Rs 57000bn as on FY13) largely led by short term debt to meet opertional cost continue to hit discoms. We note continuing with stance of earliergovernment, current government continue to accord high priority to distribution sector. Modernizing transmission and distribution (T&D) infrastructure will help in overcoming the electricity crisis, The meeting reinforced my belief that

power crisiscan be solved to a large extent by modernizing T&D infrastructure.

‐Power Minister Piyush Goyal addressing conference in Rajahasthan We are planning investments of Rs 3 lakh crore in the T&D sector and have already started the Deen Dayal Grameen Jyoti Yojana and Integrated Power

Development Scheme, with all this I think we will be able to reach the length and breadth of the country and enhance the T&D network and make

sure everybody gets adequate power Power Minister Piyush Goyal in Press release to PTI

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Average Cost of Supply (Rs/kwh) Average Realisation (Rs /kwh)

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FY02 FY03 FY04 FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13

Limited tariff hike resulting in realisation lower than cost of supply

Leading to higher losses


UTILITIES SECTOR

Distribution reforms…lack execution at state level: We note that with power being on concurrent list, despite top down reforms from Centre to State at the end of day execution remains in hand of state. States that were willing to bite bullet and take hard measures have succeeded in reforming power sector. Further with success of Mr. Narendra Modi from Chief Minister of Gujarat to Prime Minister or successive election of Mr. Shivraj Singh Chouhan as CM of MP, lot of states’ CM have gradually acknowledged the political leverage that can be gained by addressing the basic necessity of electricity. Consequently we expect significant improvement in political willingness to institute reforms in states. We highlight below few measures taken over past few years to address distribution segment and their impact: • Tariff hike: We note tariff hikes have become more pronounced over past few

years as state discoms pursue the path to reduce their losses. State with higher losses has taken tariff hike to tune of 15‐20% since FY11. Due to elections in several states in FY15 along with the general elections, tariff hikes were taken in very few states.

Tariff hikes Name of state FY12 FY13 FY14 FY15 FY16Andhra Pradesh 4 20 23 5Arunachal Pradesh 19 5 6 ‐ NAAssam ‐ 2 ‐ NABihar ‐ 12 7 ‐ 3Chandigarh ‐ 10 ‐ ‐ ‐Chhattisgarh 14 18 ‐ 21 12Delhi ‐ 21 5 8 NAGujarat 1.5‐3.5 2 6 ‐ 2Haryana 17 18 13 ‐ NAHimachal 10 13 13 ‐ ‐J&K 12 6 9 ‐ NAJharkhand 11 9 ‐ NAKarnataka 6 3 ‐ 10 5Kerala ‐ 30 8 16 NAMadhya Pradesh 11 7 1 ‐ 10Maharashtra 3 17 NAManipur 15 8 ‐ 8 5Mizoram 11 10 ‐ 2Orissa 20 12 2 ‐ 5Punjab 8 12 9 3 NARajasthan 19 10 ‐ NATamil Nadu 11 37 ‐ 15 NATripura 3 21 NAUP 14 9 8 20 NAUttarakhand 3 7 5 ‐ 7West Bengal 11 ‐ ‐ ‐ NA

Source: SERC However we note tariff hikes would work in short term and going forward to ensure sustainable turnaround SEB’s need to address key issue of higher T&D losses and limited recovery of dues. We note current tariff hikes have largely been concentrated on industrial and commercial segments that have continue to cross subsidise residential segment. Thus India’s industrial segments tariff are higher relative to purchasing power and compared to other countries. • Financial Restructuring Plan: With an objective to improve financial conditions

of discoms and ensure sustainable turnaround, government came out with Financial Restructuring Plan. The Restructuring of SEB is the second such exercise undertaken by government after 2001. The Plan entails restructuring Short Term Liabilities of discoms in assistance with State and Central


UTILITIES SECTOR

Government and lenders. As per the scheme, 50% of Short Term Liabilities of State Discoms outstanding as on March 2012, would be taken over by State Governments. This involves converting STL into bonds backed by State Government guarantee and to be issued to lenders. The State Government would gradually take over liability (50%) over next 2‐5 years in phased manner. The bond issuance would take place such that States do not breach FRBM limit. The balance 50% of STL would be rescheduled by lenders and serviced by DISCOMS with moratorium of 3 years. The restructuring exercise would be accompanied suitable actions from discoms end to improve their operational performance. The FRP scheme would be aided by Transitional Finance Mechanism (TFM) to be set up by MoP. The transitional finance mechanism would provide grants to State government conditional to achieving prescribed reduction in AT&C losses and reducing gap between ARR and ACS.

We note eight states viz. Tamil Nadu, Uttar Pradesh, Rajasthan, Haryana, Jharkhand, Bihar, Andhra Pradesh and Telangana availed FRP; however implementation has met with limited success. Most of these states failed to meet requisite condition of reduction in T&D losses, consistent tariff hike or reducing power purchase cost. Thus FRP simply infused cash in discoms without concomitant measures from discoms end. Further even as power ministry introduced “Model State Electricity Distribution Bill” that entailed prudent measures from state discoms to improve financial performance, discoms failed to implement bill at state level. Also we note apart from interest cost Power purchase cost and employee cost significant portion of discoms’ expenditure and unless these costs are not addressed, turnaround of discoms will remain pipe dream. Break up of Expenditure of discoms

Source: PFC • Feeder separation scheme: The government launched the “Deen Dayal

Upadhyaya Gram Jyoti Yojna” (DDUGY) with an aim to strengthen distribution. We note agriculture remains the biggest bane for discoms and political compulsion ensured tariffs for this segment significantly lower than cost of supply. Consequently a significant chunk of power meant for agriculture is transferred for household purpose leading to higher losses. With an objective to put lid to this DDUGY was launched so as to ensure a. Separate agriculture and non‐agriculture feeders and ensuring reliable

supply to farmers. b. Strengthening and augmentation of sub transmission and distribution

infrastructure in rural areas, including metering of distribution c. Also existing rural electrification (RGVVY) scheme would be subsumed in

this scheme.

Power Purchase Cost 63%Fuel Cost

12%

Employee cost8%

Interest cost8%

O&M1%

Others8%


UTILITIES SECTOR

We note RGVVY had cost of Rs392bn including budgetary support of Rs 354bn. Apart from this DDUGY had overall outlay of Rs 430bn including budgetary support of Rs 334bn. Further the overall scheme of DDUGY has been designed in such a way to ensure financial burden on states remain minimal. Further scheme involves milestone based payment of grants so as ensure effective implementation. Funding Mechanism Agency Grant % support for non special states % support for non special statesCentre 60 85Discom contribution Own Fund 10 5Lenders(FI/Banks) Loan 30 10Additional grants on achievement of prescribed milestones Grant 50% of total loan =15% 50% of total loan =5%Maximum grant by GoI including additional grants Grant 75% 75%

Source: Power Ministry We note implementation of feeder separation scheme through Jyoti gram Yojna in Gujarat has played key role in turnaround of discoms in Gujarat. Feeder separation ensured that farmers get quality power at fixed time and leakages are curtailed. It ensured accurate measurement of the power used for agricultural purposes as well, thus ensuring proper targeting of subsidies. Gujarat SEB

Source: PFC Introduction of revised Standard Bidding Document: Earlier SBD for projects introduced during 10th plan ushered the way for competitively bid power projects. However the document had short comings due to which fuel risks was largely borne by generation utilities. ~18‐20 GW capacity suffered due to aggressive bidding resulting in lower than expected return. In FY13, taking cognizance of shortcoming and risk aversion from discoms to call for bids government introduced Case II bids. However despite introduction of new bids discoms continue to focus on short term power rather than procure long term power. The revised SBD altered earlier provision and allowed for fuel cost pass through and involved bidding based on capacity charge. Further unlike previous SBD that selected bids based on levellised tariff, new SBD require developers to indicate first year tariffs. However despite government inviting bids for TN and Orissa UMPP based on revised SBD, interest of private players was significantly low due to DBOT provision that called for transfer of project back to state as against earlier provision that allowed developer to maintain ownership; thus inviting criticism from lenders.

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AT&C loss (Gujarat )


UTILITIES SECTOR

Transmission‐ Bright Spot Despite the pain that sector went through, transmission segment of value chain continue to remain relatively buoyant led by strong capex from PGCIL. We continue to remain optimistic on this segment as strong capacity addition will also require necessary evacuation system. Thus, we expect transmission capex to remain robust in 13th plan too. We note going forward PGCIL’s capex would be geared towards high end equipment. Transmission Capex Capex details ________10thplan_______ _______11th plan_______ _______12th plan_______ _______13th plan_______Rsbn Total PGCIL Share Total PGCIL Share Total PGCIL Share Total PGCIL ShareInter State 200 190 95% 564 553 98% 1,250 1,100 80% 1,350 675 50%Intra State 255 664 0% 550 112 9% 950 238 25%Green Energy Corridor Intra state 200 20 10%Interstate 220 22 10%Total 455 190 42% 1,228 553 25% 1,800 1,212 23% 2,720 955 35%

Source: Power Ministry We note similar to generation, government introduced competitive based bidding in transmission projects. We note in initial bids competition had been significantly intense. Recent bids however indicate lower competitive intensity. Also some projects have been awarded to PGCIL on nomination basis to ensure timely completion of project Transmission bids

Developer Award Date No. of

bidders Date of LoILevellised

Revenue (L1)Sterlite Technologies Jan‐10 8 Jul‐10 1,188 Sterlite Transmission Projects Jan‐11 33 Jan‐11 1,421 Sterlite Transmission Projects Jan‐11 22 Jan‐11 1,995 PGCIL Mar‐12 22 Mar‐12 987 Techno Electric and Engineering 7 Sep‐13 274 Sterlite Grid Sep‐13 10 Sep‐13 365 Sterlite Grid Sep‐13 7 Sep‐13 589 EsselInfraprojects Ltd 10 Oct‐13 1,174 PGCIL Dec‐09 1,440 PGCIL Dec‐09 2,580 Patel Engg, Simplex Infra & BS Transcomm Dec‐10 35 Dec‐10 293 PGCIL Mar‐12 1,197 PGCIL Jul‐13 14 Jul‐13 2,311 L&T IDPL Jul‐13 11 Jul‐13 1,796 Sterlite Grid May‐14 6 Feb‐14 4,377 PGCIL 7 Feb‐14 594 EsselInfraprojects Ltd 7 Feb‐14 887

Source: REC, PFC



Coal India (COAL IN) Play for volume recovery INDIA | POWER | Initiating

28 April 2015

Investment Rationale We initiate coverage on COAL INDIA with a BUY rating and a target price of Rs475. CIL enjoys competitive advantage of captive mines with one of the lowest strip ratios. Also CIL is likely to be the direct beneficiary of the Indian government’s policies to addresses fuel constraints and undertake measures to remove bottlenecks of rake availability and environmental clearance. Production growth to revive: We expect CIL to ramp up production as the government provides speedier environment clearances and higher rake availability by Indian Railways. Accordingly CIL is likely to report 6% CAGR in production during FY15‐17E higher than 2% growth reported during FY11‐14E. Our confidence stems from the fact that during FY06‐10 CIL had reported CAGR production of 6% driven by faster clearances, post which production declined as norms for clearance became stringent. Additional measures taken by government such as PMG for coal production, expediting critical rail links and increase in CIL capex on equipment will support production growth. Incentives earnings to dip but unlikely to miss commitment: CIL had earned Rs 13bn and Rs 8bn incentives during FY13 and FY14 respectively as it supplied more than 90% ACQ to plants commissioned before 2009. Our analysis of India’s capacity addition and those with FSA commitment with CIL indicates due to delay in commissioning, CIL would be able to meet its FSA commitment albeit by reducing supply to plants commissioned till 2009.We note in absence of critical logistic support despatches might suffer in 13th plan. We believe in case plants within 78GW list do not commence on time, CIL will divert supply to pre 2009 FSA and earn incentive. E‐auction sale to drive realization: The decision by SC that led to de‐allocation of coal blocks will lead to increase in demand under e‐auction. The government had in early 2015 reduced supply under e‐auction to increase supply to power plants. We note this restriction has been removed and expect supply to increase under e‐auction. We expect realization to remain robust as incremental demand from erstwhile captive mine owners is diverted to e‐auction. Earnings and Valuations: We like CIL as it is expected to achieve 13% CAGR PAT during FY15‐17E led by 7% production growth. Although CIL’s pricing remains at discount to international prices, however we believe CIL would be able to maintain steady margins as significant sale being undertaken at notified price and as e‐auction sales witness gradual increase in demand. We note CIL remains proxy play on railway capex that could lead to improvement in despatches. At CMP of Rs376, CIL trades at 6xFY17 EV/EBITDA adjusted for OBR. We value CIL at 7x times EV/EBITDA to arrive at target price of Rs475 and initiate coverage with BUY rating on the stock. Key risks to our BUY call: Key risks to our BUY call are: a) Lower production growth b) government mandating CIL to sign FSA’s more than it can commit (less probability) c) inability to take price hike d) Correction in international coal prices impacting e‐auction realization d) opening up of coal sector for commercial mining.

BUY CMP RS 376 TARGET RS 475 (+24%) COMPANY DATA O/S SHARES (MN) : 6316MARKET CAP (RSBN) : 2376MARKET CAP (USDBN) : 37.352 ‐ WK HI/LO (RS) : 424 / 275LIQUIDITY 3M (USDMN) : 35.8PAR VALUE (RS) : 10 SHARE HOLDING PATTERN, % PROMOTERS : 79.7FII / NRI : 8.3FI / MF : 9.1NON PROMOTER CORP. HOLDINGS : 1.1PUBLIC & OTHERS : 1.8 PRICE PERFORMANCE, %

1MTH 3MTH 1YRABS 1.6 ‐4.5 24.6REL TO BSE 4.1 1.7 4.5 PRICE VS. SENSEX

Source: Phillip Capital India Research KEY FINANCIALS Rs mn FY15E FY16E FY17ENet Sales 729,642 835,306 943,069EBIDTA 164,498 216,024 254,773Net Profit 149,971 184,415 210,949EPS, Rs 23.7 29.2 33.4PER, x 15.8 12.9 11.3EV/EBIDTA, x 11.2 8.2 6.6P/BV, x 5.7 4.8 4.1ROE, % 36.0 37.4 36.4Debt/Equity (%) 0.4 0.3 0.3

Source: PhillipCapital India Research Est. AnkurSharma(+ 9122 6667 9759) [email protected] HrishikeshBhagat(+ 9122 6667 9986) [email protected]

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Jan‐11 Mar‐12 May‐13 Jul‐14Coal India BSE Sensex


COAL INDIA INITIATING COVERAGE

Policy action to aid production growth We expect CIL’s subdued production growth to be a thing of past and expect production trajectory to improve. We note post formation of new government, the emphasis has shifted to improvement in coal production and increasing availability. Accordingly the government has taken initiatives to aid production growth. We note in 2010, government introduced “Go” and “No‐Go” policy of environment clearance that effectively brought to halt to coal mining as 203 blocks with capacity of 660 mn ton were brought under ambit of “No‐Go” area. Environmental Clearances granted Sectors FY10 FY11 FY12 FY13 FY14 9MFY15Industrial projects 360 241 196 305 118 82Infra & Misc. projects & CRZ 83 88 74 150 60 31Thermal projects 60 63 51 34 8 12Coal mining 56 36 22 41 34 25Mining projects 93 87 46 34 73 35New constr. projects & Industrial estates 63 40 27 37 11 6River valley & Hydroelectric projects 15 8 5 3 5 1Nuclear projects 1 1 3 1 0Grand Total 731 564 421 607 310 192

Source: MOEF Consequently, there was significant decline in environment clearances during FY11‐12, thus impacting CIL’s production growth. CIL reported production CAGR of 6% during FY06‐10 when environment norms were relatively relaxed, however during FY11‐14, the production CAGR stood at 1.62% as introduction of stringent environmental norms hampered production. We expect production CAGR of 7% during FY16‐17E led by speedier environmental clearances and softening of environmental norms since 2HFY13. Thus, CIL would reach production of 566mn ton by FY17e. Further CIL enjoys competitive advantage of one of the lowest strip ratio in its mine and significant production (88% in FY14) being driven by open cast mines, thus leading to faster ramp up. Coal Production

Source: Company, PhillipCapital India Research Estimates We highlight few measures taken by MOEF • Exemption from Public Hearings: MOEF has allowed for one time expansion of

production for mines with capacity upto 20 MT to expand production by upto 50% without public hearing.

(1)

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9

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600

FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15E FY16E FY17E

Production Growth (%) (rhs)



• Cluster Clearances: As against earlier approach that required separate environmental approvals for each mine in coalfield, the MOEF has considered allowing group clearances for adjacent mines. The Ministry has identified 94 such clusters in various CIL units. CIL mines which already have clearance would be rearranged into clusters for future clearance.

• Mine prospecting norms relaxed: The norms for prospecting forest areas exempted from tribal consent. Further compensatory afforestation have been done away with and no government inspection is required for prospecting upto 100 hectares



Dispatches lead by Power Sector Dispatches from CIL have witnessed CAGR 4.5% during FY07‐14 led by 4.5% growth in supply to power sector. We note supply to power sector accounts for 79% of CIL dispatches. A significant portion of supply is undertaken under FSA basis to Power sector. We expect CIL to maintain dispatches at CAGR of 6.2% led by improvement in demand from power sector and materialization of FSA’s for plants commissioned till FY15. In line with power ministry notification, sales through e‐auction was reduced from 58 mn tonne and capped at 7% of sales in early FY15. CIL did 45mn tone (9% of sales). However, reducing the e‐auction quantity to meet higher requirement of power sector has led to sharp increase in e‐auction realization and also impacted fuel supply to other sectors (steel, cement) that depend on e‐auction supply. Further evacuation constraint continues to impact despatches for CIL. We note government has done away with cap on e‐auction and accordingly expect e‐auction sales at 55mn tone during FY16‐17E. Sector‐wise Off take

Coal off take

CIL sales

FY10 FY11 FY12 FY13 FY14 FY15E FY16E FY17EFSA 320.9 328.2 362.1 397.1 396.3 429 441.1 470.8Proportion (%) 78.3 78.1 83.7 85.6 84.0 87.6 84.2 82.8E‐Auction 45.7 47.7 50.9 49.1 58.0 45.0 55.0 55.0Proportion (%) 11.2 11.4 11.8 10.6 12.3 9.2 10.5 9.7Washed Coal 14.6 15.5 16.9 14.1 12.9 12.1 21.3 33.0Proportion (%) 3.6 3.7 3.9 0.3 2.7 2.5 4.1 5.8

Source::Company, PhillipCapital India Research Estimates

Power75%

Steel/hard Coke 2%

Others 23%

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Offtake Growth (%) (rhs)

Dispatches to Power Sector constitute significant portion of sales

We expect dispatches to grow CAGR 6.5% during FY15‐17E led by private sector. Dispatches during FY14 were subdued due to weak demand from power sector

We expect supply through E‐auction to increase post removal of cap on e‐ auction coal.



Increasing FSA commitment to reduce incentives A) Coal India incentives in FY14 reduced on account of lower supply to pre 2009

FSA’s CIL used to supply >100% ACQ to pre 2009 FSA’s. CIL earned incentives of Rs 13bn in FY13 for 305mton of quantity supplied for Pre 2009 FSA’s implying per ton incentives of Rs 40. Similarly, CIL earned Rs 8bn incentives in FY14 due to increase in commitment to plant under new FSA arrangement. We expect incentives to decline as additional FSA materializes with commissioning of new capacity. CIL 4Q realization is higher led by higher incentives

Source: Company, PhillipCapital India Research The incentives would reduce from FY15 onwards. We highlight below two scenarios of commitment that CIL may be required to meet. Case I highlights coal requirement based on CIL’s assumption of CoD and Case II (base case) is based on our assumption. Case I: As per CIL’s FSA list ~11GW of capacity would get commissioned by end of FY14 and ~20.5GW of capacity would get commissioned in FY15. Assuming that most of the capacity is commissioned at the end of the years and also considering the optimal utilization of capacity with a year lag, CIL would require ~45mton of additional coal in FY15 and ~90mton of additional coal in FY16 to meet its FSA requirements. This would be the worst case scenario for CIL which really seems to be difficult. It is possible only if discoms sign PPA’s aggressively and all the idle capacities are tied up and secondly all the capacities commission within the time frame which is difficult to materialize as delay in commissioning would continue. Estimated commissioning of the capacity as per the MoP for FSA’s:

Sector wise break up FY10 FY11 FY12 FY13 FY14 FY15Tapering linkages Total

C 1,990 2,490 4,870 4,660 1,695 2,855 1,700 20,260S 2,505 1,310 2,750 2,700 2,050 2,120 2,250 15,685P 1,150 1,905 4,877 3,830 7,330 15,574 5,890 40,556Total 5,645 5,705 12,497 11,190 11,075 20,549 9,840 76,501

Source: Company, PhillipCapital India Research Estimates Case II: Further analyzing these capacities on the basis of commissioning schedule as per our estimates and considering coal supply to only those projects which have PPA in place, we estimate the coal requirement for utilities from CIL at 387mn ton in FY15 and 434mntonne in FY16 and 459 by FY17E. This would cap the coal supply to Pre 2009 capacity at the trigger level of 90%, completely wiping out the incentives by the

1,02

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2QFY11

3QFY11

4QFY11

1QFY12

2QFY12

3QFY12

4QFY12

1QFY13

2QFY13

3QFY13

4QFY13

1QFY14

2QFY14

3QFY14

4QFY14

1QFY15

2QFY15

3QFY15

CIL realisation

INR145

INR165

INR171 INR86



CIL. We have assumed despite de‐allocation of coal blocks by SC, CIL would continue to honor tapering linkage based on trigger level of 75%, 50% and 25% during three years. We note CIL might increase supply to pre 2009 FSA to earn higher incentives as domestic capacities are delayed. Coal requirement and availability as per our estimates Description FY14 FY15 FY16 FY17Pre 2009 270 270 270 270FSA Post 20009 90 105 127 153Total requirement 367 387 406 425 Total supply 353 386 411 445 (Shortfall)/Surplus for incentives ( 14 ) ( 2) 5 19

Source: Company, PhillipCapital India Research Estimates Limited possibility of penalty unless tapering linkages are converted: We do not estimate significant shortage under new FSA arrangement as diversion of E‐auction coal coupled with delayed commissioning will lead to lower requirement. We maintain that despite de allocation of captive coal mines by SC, CIL’s commitment towards tapering linkages would be under erstwhile arrangement. However if tapering linkages are converted to FSA, this would entail shortfall of 23mn tonne in FY17 assuming none of the companies are able to retain captive blocks. Under such CIL would be liable for marginal penalty. Penalty structure as per the model FSA Penalty Structure FY14 FY15 FY16 FY1775‐70 ‐ ‐ ‐ 0‐570‐67 ‐ ‐ ‐ 5‐1067‐65 ‐ ‐ 0‐2 5‐1065‐60 0‐5 0‐5 2‐7 10‐2060‐55 5‐10 5‐10 7‐20 20‐4055‐50 10‐20 10‐20 20‐40 20‐40Below 50 20‐40 20‐40 20‐40 20‐40

Source: Company, PhillipCapital India Research Estimates Logistics support critical to meet off take targets: CIL has production target of 615 mntonne by end of FY17, implying production CAGR 8.5% per annum during FY14‐17E. We note this is aggressive, considering CIL’s ability to ramp‐up production would be contingent on availability of logistic infrastructure and rake availability to aid evacuation. In absence of timely completion of rail infrastructure, CIL’s production would be 50‐55mn tonne lower than target. The following rail links are very crucial for CIL to meet its offtake/production targets as they will potentially lead to offtake of 83mn tonne.

Critical Rail Links Rail Link Distance Coal Fields State CIL subsidary Production Tori ‐Shivpur‐ Kathautia 93.5 North Karanpura Jharkhand CCL 32 Jharsuguda‐Barpalli‐Sardega 53 IB Valley Odisha MCL 19 Bhupdevpur‐Korichapar‐Dharamjaigarh(East Corridor) 180 Mand‐Raigarh Chhattisgarh SECL 32 Gevra Road to Pasan (East‐ West Corridor) 122 Korba ‐Gevra Chhattisgarh SECL Total 448.5 83

Source: Ministry of Railways Tori Shivpur –Kathautia and Jharsuguda‐Sardega is being constructed by Eastern railways and South Eastern railways. The East Corridor and East West corridor is being constructed by JV of SECL, IRCON international and Government of Chhattisgarh with equity of 64%, 26% and 10% respectively. Although these lines have been accorded priority status by ministry of railways, however the commissioning is likely to be delayed. Based on revised CoD, Tori –

CIL may most likely end up paying penalty if capacity with tapering linkages are converted into long‐term FSA or if capacity are commissioned earlier than our expectation



Shivpur is expected by Dec 2016 and Jharsuguda –Sardega by June 16. We expect only partial benefit to CIL from these lines in 12th plan and expect major gains to accrue in 13th plan during FY18. We note although Tori‐Shivpur (Phase I) has most clearances in place; however land acquisition has been delayed. Rake availability

Source: Company

157 162 168 184 190

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FY10 FY11 FY12 FY13 FY14

Rakes/Day

The improvement in rake availability is also attributed to weak mining activity in FY14



E‐auction – Drivers to margin In sweet spot, supply squeeze to drive realization The government’s drive to meet incremental demand of power sector has led to reduction of supply under e‐auction. We note supply under e‐auction was reduced to 40mn ton (8% of supply) during FY15 lower than 58 mn ton (12% of supply) in FY14. We note E‐auction coal contributes ~40% of the EBITDA for CIL. Recent SC decision to scrap captive coal mines will further fuel additional demand for e‐auction, leading to significant demand supply mismatch in this market. We note government has relaxed cap on e‐auction sales, however we expect demand pull to continue in FY16 led by companies that failed to retain coal block in auction. Accordingly, we expect realization in this segment to rise during FY16 and FY17. E‐auction Quantity and realization

Source: Company,PhillipCapital India Research Estimates International coal prices at lowest since 2009; impacting e‐auction realization International coal prices have declined 13% in last 1 year and are at lowest level in past five years. The declining trend in international coal prices is negative for the E‐auction coal prices as it would lead to the shifting of customers from E‐auction coal to imported (depending upon the feasible logistics). The overall decline in the RB index prices in rupee terms is 15% in last 1 year. Despite substantial decline in international coal prices, weak currency offset decline in coal prices. Coal price

Source: Bloomberg

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E auction realisation (INR/ton) RB index (INR/ton) (rhs)



Cost analysis We highlight CIL ‘s revenue during FY06‐14 had CAGR of 11.5% and CIL has largely been able to maintain EBITDA margins of 23‐25% as CIL has been able to take hike albeit with a lag to offset cost impact. However, we note that in FY15 with no price hikes taken in FSA supplies and a fall in e auction volumes, margins have declined. History of price hikes Oct 2009 CIL takes 11% price hike Feb‐11 CIL takes 12% price hike across all categories of coal and applicable to all sectors Jan‐12 Transition to GCV based price mechanism May‐13 Price hike of 10% for low grade coal except for WCL Dec‐13 CIL takes 10% price hike at WCL, also revises loading charges Apr‐14 CIL revises price at Rajmahal mine due to grade classification

Source: Coal Ministry Cost Structure

Source: Company We note employee cost constitute ~ 50% of overall cost as CIL has employee strength of 0.35 mn. Wage hike lead to ~ 15.5% CAGR increase in employee cost during FY07‐14. CIL intends to rationalize 50000 employees, over five years that would result in operating leverage. Number of employees

Source: Company

Stores and Spares14%

Employee Cost54%

Power & Fuel 4%

Welfare expenses1%

Repairs 2%

Contractual Expenses 13%

Provisions6%

OBR adjustments6%

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During FY07‐14 CIL has reduced employee strength by 92000.



Wage agreement NCWA II Signed on Duration of agreement (years) Period of agreementNCWA II Dec‐74 4 Jan 1975‐Dec 1978NCWA II Aug‐79 4 Jan 1979‐Dec 1982NCWA III Nov‐83 4 Jan 1983‐Dec 1986NCWA IV Jul‐89 4.5 Jan 1987‐June 1991NCWA V Jan‐96 5 July 1991‐June 1996NCWA VI Dec‐00 5 July 1996‐June 2001NCWA VII Jul‐05 5 July 2001‐June 2006NCWA VIII Jan‐09 5 July 2006‐June 2011NCWA IX Jan‐12 5 July 2011‐June 2016

Source: Coal Ministry Since 1970’s the wage structure and other conditions of service such as fringe benefits, welfare measures etc. of the non‐executive grade employees in the Coal Industry have been settled by Bipartite Wage Negotiations by a committee constituted by Govt. Of India. The committee is functioning in the name of Joint Bipartite Committee for the Coal Industry consisting of representatives of 5 Central Trade Unions and the management of Coal Companies. The wage revision has happened every five years and next wage revision is due in FY17 and becomes the key factor to monitor.



A) Recovery in EBITDA margins after fall in FY15 CIL enjoys EBITDA margins of 30‐34% as 80‐85% of sales are driven by notified prices that are relatively immune to international coal prices. The sales through e‐auction however are key lever to margins. We expect price hike in FSA coal to be relatively muted during FY14‐17E and expect e‐auction coal to drive margins. We note margins have declined in FY15 due to lower e‐auction sales and expect them to improve as cap is removed.

EBITDA margins

Source: Company, PhillipCapital India Research Estimates B) Strong Cash generation ensuring healthy dividend payout: CIL generates cash flow of Rs 150bn with significant sales under notified price regime. We note CIL has strong debt free balance sheet with Rs523bn cash (Rs 83 per share), 50% of asset ensuring healthy dividend payout. During FY14, CIL’s dividend payout was relatively large to meet promoters’ (GOI’s) financing need. We expect dividend payout to stabilize at 50% during FY15‐17 as government raises fund through divestment. Stron Cash Generation

Source: Company, PhillipCapital India Research Estimates

25 24

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29 33

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CFO (Rs bn) CFI(Rs bn) CFF (Rs bn) Dividend payout (%)



C) Healthy returns profile: CIL‘s dominant monopoly position in India’s coal market coupled with relative immunity from volatile international prices ensure healthy return of 30‐35%. We expect return to remain robust and led by operating leverage driven by volume recovery, return ratio to improve. RoE and RoCE


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FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15e FY16e FY17e

RoE ROCE



Key sensitivities Change in FSA price hike to target price

0% 1% 3% 5% 7% 10% 460 463 469 475 481 491

Change in FSA price hike to EPS

0% 1% 3% 5% 7%30 31 32 33 35

Sensitivity of EPS to 10mn tonne increase in production

546 556 566 576 586 596 54633 33 33 34 34 34 33

Sensitivity of target to 10mn increase in production

546 556 566 576 586 596 546391 433 475 521 567 614 391

Source: PhillipCapital India Research Estimates Sensitivity of e‐auction realization and volume to EPS

EPS 25 30 35 40 45 50 55

E‐au

ction realisation 2,550 29 30 30 31 31 32 33

2,600 29 30 30 31 32 32 33 2,650 29 30 31 31 32 32 33 2,700 29 30 31 31 32 33 33 2,750 30 30 31 32 32 33 34 2,800 30 30 31 32 33 33 34 2,850 30 31 31 32 33 34 34

Source: PhillipCapital India Research Estimates Sensitivity of e‐auction realisation and volume to target price

EPS 25 30 35 40 45 50 55

E‐au

ction realisation 2,550 457 459 462 464 466 469 471

2,600 458 460 462 465 467 470 472 2,650 458 461 463 466 468 471 473 2,700 459 461 464 466 469 472 475 2,750 459 462 465 467 470 473 476 2,800 460 462 465 468 471 474 477 2,850 460 463 466 469 472 475 479




1year forward P/E band P/BV band

Source: Company, PhillipCapital India Research We like CIL as it is expected to achieve 13% CAGR PAT during FY15‐17E led by 7% production growth. Although CIL’s pricing remains at discount to international prices, however we believe CIL would be able to maintain steady margins led by significant sale at notified price and as e‐auction sales witness higher volume and realization. At CMP of Rs376, CIL trades at 5.5x time EV/EBITDA adjusted for OBR. We value CIL at 7x EV/EBITDA adjusted for OBR to arrive at target price of Rs473.We initiate coverage with BUY rating on the stock. Key risks to our target price is government mandating CIL to sign FSA’s more than it can commit (less probability), inability to take price hike and further decline in international coal prices thus impacting e‐auction margins; opening up sector for commercial mining. Consensus

___________Consensus___________ ___________PC Estimates___________ ___________Deviation___________FY15E FY16E FY17E FY15E FY16E FY17E FY15E FY16E FY17E

Sales 717,728.9 793,288.6 883,514.0 729,642 835,306 943,069 2% 5% 7%EBITDA 154,156.3 184,526.7 217,575.4 164,498 216,024 254,773 7% 17% 17%PAT 147,689.7 173,239.6 194,063.4 149,971 184,415 210,949 2% 6% 9%

Source: Bloomberg, PhillipCapital India Research Estimates International peers

Mkt Cap (USD bn) P/E RoE EV/EBITDACoal India 37.9 13.4 35.3 9.2 GMDC 0.5 7.1 14.4 4.7 China Shenhua Energy Ltd 75.9 10.0 10.6 7.4 China Coal Energy 16.9 226.3 0.7 21.2 Yanzhou Coal Mining Ltd 10.8 36.1 2.8 16.5 Shanxi Xishan Coal 5.2 79.4 2.5 11.2 Yangquan coal Industry 4.6 47.2 4.6 11.7 Adaro Energy Tbk PT 2.4 10.5 7.2 5.5 Indo TambangrayaMegahTbk 1.2 8.1 17.2 3.9 Average 26 9 11.8

Source: Bloomberg

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Financials

Income Statement Y/E Mar, Rs mn FY14 FY15e FY16e FY17eNet sales 688,100 729,642 835,306 943,069Growth, % 1 6 14 13Total income 688,100 729,642 835,306 943,069Raw material expenses ‐71,147 ‐70,242 ‐80,281 ‐90,518Employee expenses ‐277,694 ‐296,299 ‐316,152 ‐337,334Other Operating expenses ‐170,657 ‐198,602 ‐222,850 ‐260,444EBITDA (Core) 168,602 164,498 216,024 254,773Growth, % (6.8) (2.4) 31.3 17.9 Margin, % 24.5 22.5 25.9 27.0 Depreciation ‐19,964 ‐22,031 ‐25,391 ‐28,751EBIT 148,638 142,468 190,634 226,023Growth, % (8.6) (4.2) 33.8 18.6 Margin, % 21.6 19.5 22.8 24.0 Interest paid ‐580 ‐72 ‐68 ‐64Pre‐tax profit 228,795 227,228 279,417 319,620Tax provided ‐77,679 ‐77,258 ‐95,002 ‐108,671Profit after tax 151,116 149,971 184,415 210,949Others (Minorities, Associates) 0 0 0 0Net Profit 151,116 149,971 184,415 210,949Growth, % (7.7) (6.3) 23.0 14.4 Net Profit (adjusted) 160,072 149,971 184,415 210,949 Unadj. shares (m) 6,316 6,316 6,316 6,316 Wtdavg shares (m) 6,316 6,316 6,316 6,316 Balance Sheet Y/E Mar, Rs mn FY14 FY15e FY16e FY17eCash & bank 523,895 531,826 594,763 689,716Debtors 82,411 87,387 100,042 112,948Inventory 55,680 55,454 64,984 73,368Loans & advances 77,594 77,594 77,594 77,594Other current assets 54,375 57,658 66,008 74,524Total current assets 793,956 809,918 903,390 1,028,149Investments 37,749 37,749 37,749 37,749Gross fixed assets 408,970 458,970 528,970 598,970Less: Depreciation ‐263,022 ‐285,052 ‐310,443 ‐339,193Add: Capital WIP 45,053 45,053 45,053 45,053Net fixed assets 191,001 218,971 263,580 304,830Total assets 1,042,424 1,086,355 1,224,437 1,390,445

Current liabilities 616,028 667,941 729,512 808,001Total current liabilities 616,028 667,941 729,512 808,001Non‐current liabilities 2,351 2,351 2,351 2,351Total liabilities 618,379 670,291 731,863 810,352Paid‐up capital 63,164 63,164 63,164 63,164Reserves & surplus 360,881 352,900 429,411 516,929Shareholders’ equity 424,045 416,064 492,574 580,093Total equity & liabilities 1,042,424 1,086,355 1,224,437 1,390,445 Source: Company, PhillipCapital India Research Estimates

Cash Flow Y/E Mar, Rs mn FY14 FY15e FY16e FY17ePre‐tax profit 228,795 227,228 279,417 319,620Depreciation 19,964 22,031 25,391 28,751Chg in working capital 3,625 43,881 31,036 48,684Total tax paid ‐74,846 ‐77,258 ‐95,002 ‐108,671Cash flow from operating activities 177,539 215,882 240,842 288,383Capital expenditure ‐41,349 ‐50,000 ‐70,000 ‐70,000Chg in investments ‐13,799 0 0 0Cash flow from investing activities ‐55,149 ‐50,000 ‐70,000 ‐70,000Free cash flow 122,390 165,882 170,842 218,383Debt raised/(repaid) ‐9,063 0 0 0Dividend (incl. tax) ‐211,427 ‐157,951 ‐107,905 ‐123,430Other financing activities ‐364 0 0 0Cash flow from financing activities ‐220,855 ‐157,951 ‐107,905 ‐123,430Net chg in cash ‐98,465 7,930 62,937 94,953 Valuation Ratios

FY14 FY15e FY16e FY17ePer Share data EPS (INR) 25.3 23.7 29.2 33.4 Growth, % (7.7) (6.3) 23.0 14.4 Book NAV/share (INR) 67.1 65.9 78.0 91.8 FDEPS (INR) 25.3 23.7 29.2 33.4 CEPS (INR) 29.9 27.2 33.2 37.9 CFPS (INR) 13.9 20.7 24.1 30.8 Return ratios Return on assets (%) 14.1 14.1 16.0 16.1 Return on equity (%) 37.7 36.0 37.4 36.4 Return on capital employed (%) 32.8 35.5 40.4 39.2 Turnover ratios Asset turnover (x) (4.2) (4.5) (5.1) (5.9)Sales/Total assets (x) 0.6 0.7 0.7 0.7 Sales/Net FA (x) 3.8 3.6 3.5 3.3 Working capital/Sales (x) (0.5) (0.5) (0.5) (0.5)Receivable days 43.7 43.7 43.7 43.7 Inventory days 29.5 27.7 28.4 28.4 Working capital days (183.5) (195.0) (183.9) (181.7)Liquidity ratios Current ratio (x) 1.3 1.2 1.2 1.3 Quick ratio (x) 1.2 1.1 1.1 1.2 Interest cover (x) 256.3 1,971.3 2,806.1 3,539.4 Total debt/Equity (%) 0.4 0.4 0.3 0.3 Net debt/Equity (%) (123.1) (127.4) (120.4) (118.6)Valuation PER (x) 14.8 15.8 12.9 11.3 PEG (x) ‐ y‐o‐y growth (1.9) (2.5) 0.6 0.8 Price/Book (x) 5.6 5.7 4.8 4.1 EV/Net sales (x) 2.7 2.5 2.1 1.8 EV/EBITDA (x) 11.0 11.2 8.2 6.6 EV/EBIT (x) 12.5 12.9 9.3 7.5



NTPC (NTPC IN) Slowing capacity addition + Uncertainty on incentives =Neutral INDIA | POWER | Initiating

28 April 2015

Investment Rationale We initiate coverage on NTPC with a neutral rating and a target price of Rs 160. Stringent tariff norms under new regulation will ensure RoE trajectory likely to be lower over next few years. Coupled with slowing capacity addition we expect NTPC’s earnings growth to remain weak over the next few years. New tariff norms limit scope for RoE’s: Implementation of CERC tariff norms 2015‐19 has significantly altered earnings trajectory for NTPC. Tightening of operational parameters, removal of tax arbitrage and transition from PAF based incentive mechanism to PLF based mechanism will significantly impact incentive earnings for NTPC. We note due to huge capacity addition from private sector, NTPC’s share in overall generation will reduce thus impacting its PLF and savings. Consequently we expect core RoE’s under new tariff regulation to decline to 17‐18% as against 22‐24%, it accrued under earlier norms. Pace of capacity addition to drop: NTPC has commissioned 7GW during FY13‐15. We expect capacity addition of 10.7GW during 12th plan lower than NTPC’s target of 14GW as slower pace of captive mine expansion coupled with limited availability of indigenous fuel will lead to slippages. Thus we expect capacity addition of 4.7GW during FY15‐17E, however we do note that 12GW capacity equipment order already tendered lends visibility for 13th plan.

Coal blocks cancellation – delay 13thplan.The SC in September,2014 has cancelled four coal blocks allotted to NTPC. NTPC was not exposed to private competition under e‐auction; however these blocks have been re‐allotted to NTPC. The cancellation does not impact capacity addition expected in 12th plan; however it does raise possibility of delay in capacity addition in 13th plan pending clarity on fuel supply.

Earnings and Valuations: We believe during FY15‐17E, operational parameters more than capacity addition would be key to earnings of NTPC. With capacity addition of 3.5GW (parent) during FY15‐17E, we expect NTPC’s regulated equity to achieve 4% CAGR during FY15‐17E and subdued earnings CAGR of 4% during the same period as RoE‘s drop with implementation of new tariff norms. At CMP of Rs 150, NTPC trades at 1.3X FY17 P/B. We value NTPC at 1.8x FY17E regulated asset base and cash and liquid assets to arrive at target price of Rs 160.

Key risks to our Neutral call: 1) Major changes in tariff regulation2) Better than expected operational parameters leading to higher incentive earnings complete 3) NTPC loses all de‐allocated mines.

Neutral CMP RS 150 TARGET RS 160 (+7%) COMPANY DATA O/S SHARES (MN) : 8245MARKET CAP (RSBN) : 1228MARKET CAP (USDBN) : 19.552 ‐ WK HI/LO (RS) : 169 / 114LIQUIDITY 3M (USDMN) : 17.6PAR VALUE (RS) : 10 SHARE HOLDING PATTERN, % PROMOTERS : 75.0FII / NRI : 10.5FI / MF : 12.1NON PROMOTER CORP. HOLDINGS : 0.3PUBLIC & OTHERS : 2.2 PRICE PERFORMANCE, %

1MTH 3MTH 1YRABS ‐1.6 5.8 22.9REL TO BSE 0.9 12.0 2.9 PRICE VS. SENSEX

Source: Phillip Capital India Research KEY FINANCIALS Rs mn FY15E FY16E FY17ENet Sales 732,489 801,747 836,639EBIDTA 160,997 184,031 200,381Net Profit 82,499 93,181 100,729EPS, Rs 10.0 11.3 12.2 PER, x 15.0 13.3 12.3 EV/EBIDTA, x 12.6 11.8 11.5 P/BV, x 1.5 1.4 1.3 ROE, % 10.2 10.8 11.0 Debt/Equity (%) 118.4 129.2 138.1

Source: PhillipCapital India Research Est. Ankur Sharma(+ 9122 6667 9759) [email protected] Hrishikesh Bhagat(+ 9122 6667 9986) [email protected]

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NTPC INITIATING COVERAGE

Capacity addition target of 14GW during 12th plan; decent visibility in the 13th plan Capacity addition target for 12th plan stands at 14GW NTPC targets to add 14GW of capacity during the 12th plan. It has already added ~7GW of capacity during FY13‐15 including 4.1GW/1.8GW/1.3GW during FY13/FY14/FY15 respectively, implying addition of 7GW in remaining 12th plan. We estimate 3.4GW capacity addition during FY16‐17E as we expect execution to slip. NTPC’s current capacity addition estimate has incorporated 1.32GW Barh I, even as project faces headwinds due to issue with Russian equipment supplier TPE. Diplomatic compulsion has made termination of contract of equipment supplier difficult. We expect this project to slip to the 13th plan. Further amongst bulk tender projects, we expect only 800 MW Unit 1 of Kudgi to commission in 12th plan and balance in 13th plan. List of projects expected to commissioned and estimated to be commissioned during the 12th plan (MW) FY13 FY 14 FY15E FY16E FY17EVallur JV (1000 MW) 500 ‐ ‐ ‐ ‐ Indira Gandhi JV (1500 MW) 500 ‐ ‐ ‐ ‐ MAUDA TPP (1000 MW) 1,000 ‐ ‐ ‐ ‐Rihand III (1000 MW) 500 500 ‐ ‐ ‐Sipat Stage I (1980 MW) 660 ‐ ‐ ‐ ‐Vindhyachal Stage 4 (1000 MW) 1,000 ‐ ‐ ‐ ‐Barh ‐ II (1320 MW) ‐ 660 660 ‐ ‐MTPS 110 ‐ ‐ ‐Vallur Phase II JV (500 MW) ‐ 500 ‐ ‐ ‐Muzaffarpur JV (390 MW) ‐ ‐ 195 195 ‐Kol Dam ‐ ‐ 400 400 ‐Bongaigaon (750 MW) ‐ ‐ ‐ 500 250Nabinagar TPP JV (1000 MW) ‐ ‐ ‐ 500 250 Tapovan Vishnu Garh ‐ ‐ ‐ ‐ ‐Barh ‐ I (1980 MW) ‐ ‐ ‐ ‐ ‐Kudgi (2400 MW) ‐ BT ‐ ‐ ‐ ‐ 800Vindhyachal Stage 5 (500 MW) ‐ ‐ ‐ 500 ‐Solar PV (Andaman & Nicobar) 5 ‐ ‐ ‐ ‐Solar PV(Dadri) 5 ‐ ‐ ‐ ‐Ramagundam Solar PV ‐ 10 ‐ ‐ ‐Talcher Solar PV ‐ 10 ‐ ‐ ‐Faridabad Solar PV ‐ 5 ‐ ‐ ‐Unchahar Solar PV ‐ 10 ‐ ‐ ‐Rajgarh Solar PV ‐ 30 20 ‐ ‐Singrauli Solar PV ‐ ‐ 15 ‐ ‐Singrauli Hydro PV ‐ ‐ ‐ 8 ‐ Standalone 3,170 1,225 1,095 1,408 1,050 JV 1,000 610 195 695 250 Total 4,170 1,835 1,290 2,103 1,300

Source: Company, PhillipCapital India Research

The capacity addition in 12th plan isexpected to grow ~1.1x from the 11th

plan despite revising the targetcapacity for few times. The positivefor NTPC is capacity addition isexpected to be front ended assuringaddition of the projects within the12th plan even if there are slippages



NTPC’s capacity to grow at CAGR of 5% during 12th Plan Targetted capacity addition in 12th plan ~14GW

Source: Company, PhillipCapital India Research Estimates Actual vs Planned Plan Actual Planned Achievement(%)XII 10698* 14228 75%XI 9610@ 9220 104%X 7155 9370 76%IX 2700 5300 51%

*PhillipCapital India Research Estimates @In XIth plan NTPC was able to exceed capacity addition as target was revised to 9.2 GW post mid‐ term review The key difference in XIIth plan is NTPC’s capacity addition has been largely front ended as compared to earlier. Additional ~ 22GW of projects are under construction, 5GW under awarding process and ~20GW feasibility report approved provides visibility in the 13th plan NTPC has 22GW of capacity under construction including 4GW capacity expected to commission during 12th plan. We expect large part of bulk tender projects awarded in FY13 to commission in 13th plan, thus lending long term growth visibility for NTPC. Gross fixed assets grow aided by increased commissioning (Rsbn) Type Capacity NTPC/JVSolapur Coal 1320 NTPCMouda II Coal 1320 NTPCKudgi Coal 1600 NTPCLara Coal 1600 NTPCGadarwara Coal 1600 NTPCLataTapovan Hydro 171 NTPCNabhinagar Coal 1980 JVMeja Coal 1320 JV


Along with the 11GW under construction projects estimated to commission in the 13th plan NTPC also has 5GW of capacity under awarding process and has feasibility report prepared for 18GW of capacity providing better visibility on the future capacity addition plans.

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Plan wise Estimated capacity addition (GW)

NTPC has ~ 22GW of capacity under construction estimated to commission in initial years of 13th plan

NTPC also has 5GW of capacity under awarding process and feasibility report prepared for 20GW



Coal based capacity to drive the growth (GW)

Source: Company, PhillipCapital India Research Estimates Better commercialization in FY13‐14 due to slippages NTPC commercialized 4.8GW of capacity during FY13, 2.7GW in FY14 and 1.2GW in FY15. Better commercialization than commissioning was mainly led by higher slippages/delays in the previous years. The gap between the commissioning and commercialization of a capacity for NTPC is ~6‐8 months. We expected pace of commercialization to slow down as limited progress over captive mines, limited indigenous fuel availability as well as lower demand will reduce pace of capacity addition. Commercialization (Consol) has been higher than the commissioning


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Commissioning Commercialisation

NTPC’s coal based capacity would drive the capacity addition growth. The hydro capacities would also start contributing from FY15. The gas based capacity would remain stagnant which is a positive for NTPC looking at the macro environment where most of the gas based capacity are non operating or operating at a lower PLF due to lower availability of the gas

The better commercialization thancommissioning In FY13 and FY14 wasled by higher slippages/delays in thecommissioning in the previous years.



Fuel availability A) FSA with Coal India 25GW tied up for capacity commissioned till FY09 with 90% trigger levels NTPC has FSA for 25GW of its capacity with Coal India with 90% trigger levels. Coal India has supplied coal for these capacities at more than 100% levels. With requirement for coal supply substantially increasing, CIL may reduce the supply levels. However we believe that it would continue to supply coal to NTPC above 90% as it helps to avoid the penalty and add to incentives earning of Coal India. The gap between 100% requirement and actual supply widens

Source: Company, PhillipCapital India Research Estimates NTPC’s 9GW of standalone capacity has entered into FSA with Coal India as per President’s directive NTPC has signed FSA with Coal India for 9GW (post 2009) of its coal based capacity, assuming that these projects needs to be supplied coal at 80% requirement of 85% PLF, then the cumulative coal requirement for these projects come to 33mton. We expect that there would be lesser requirement as we estimate slower pace of capacity addition. Additional coal requirement for new FSA’s

Commissioning Capacity

(MW) Coal req.

(Avg) Coal req.

(Full) Coal req.

(Cum)CIL commitment

(%)Approxsupply

FY10 990 2.54 5.07 3FY11 1,990 5.1 10.2 10FY12 1,820 4.66 9.33 20FY13 3,160 8.1 16.19 33 8FY14 500 1.28 2.56 42 65 14 FY15 ‐ ‐ ‐ 43 65 15 FY16 500 1.28 2.56 43 67 29 FY17 43 75 33


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Capacity Domestic supply actual At 100% requirement The domestic coal supply has increased YoY but it has come down as % of 100% requirement of average commercial capacity. This is mainly due to lower off take from the SEB’s despite more than 100% availability of the ACQ coal for plant under FSA till FY09



B) Captive mines to commission production in FY16; 4 new mines allocated taking overall reserves to 5bn ton

The development on captive mines has been significantly disappointing. NTPC was awarded 8 coal blocks during 2004‐2007; however none of the blocks have commenced production. Off the 8 block, 2 blocks Bhahmini and ChichroPastim were deallocated in 2011 due to lack of progress. Pakrih Barwadih mine was allotted to NTPC in 2004; however production is yet to see light of day. Production was delayed due to delayed clearances. Also mine was subjected to de‐allocation along with ChhatiBariatu, ChatiiBariatu (South) and Kerandari block in FY13 and was re‐allocated again. In 2010, NTPC appointed Thiess Minecs as MDO, however due to delay in development of mine the contract was cancelled recently. NTPC intends to reappoint MDO. Further, the production got delayed due to law and order issue in Jharkand state. We expect PakrihBarwadih to commence operation in FY17. The Chatti‐Bariatu block also faced similar problems even as mine has all statutory clearances in place and mine developer and operator (MDO) has been appointed. In Kerandari, the company is seeking a fresh forest clearance after the earlier one lapsed. The Dulanga block ran into a Go No‐Go controversy and in Talaipalli, the appointment for MDO is still awaited with the previous developer, Singareni Collieries, exiting project. Although these blocks were again de allocated due to SC ruling in September 2014 however government has again realloted to NTPC. We expect NTPC to commence operation at Chhati Bariatu in FY16 and expect NTPC to achieve peak production of 53 mn ton in FY22. Captive mines

Capacity Environmental

clearance Forest

Clearance Land

acquisition MDO Pakri Barwadih 15 Received Received Done In process Chatti‐Bariatu 7 Received Received Done appointed Kerandari 6 Received Stage I received Done In process Talapalli 18 Received Received Done In process Dulanga 7 Received Stage I received Done In process

Source: Company, PhillipCapital India Research Estimates NTPC allocated 4 new mines that would help reducing dependency on Coal India NTPC has been allocated 4new captive mines for 8 GW of its upcoming capacity. The combine reserves of these mines stands at ~2bn tonne and the peak capacity is estimated ~40m tone. These mines would start contributing in the 13th plan but it provides visibility on the domestic coal availability and at the same time reduces the dependency on the Coal India. Allocation of 4 new mines takes to proved reserves to 5bn ton Reserves Capacity GCV estimated Status CommissioningBanai 629 12 3200‐5400 exploration in process 13th planBhalmuda 550 14.4 3600‐5400 unexplored 13th planChandrabila 550 10.8 3200‐5400 unexplored 13th planKudanali‐Laburi 266 7.8 3200‐5400 unexplored 13th plan

Source: Company, PhillipCapital India Research .

We expect mines to commence production earliest by FY16 and to reach peak capacity by FY22.



Import to fulfill the shortfall NTPC currently has FSA for FY09 capacity with 90% trigger level (~125mton). It has also entered for post FY09 capacity at 80% trigger level at 85% PLF. We note in FY13, NTPC had planned to achieve 33mn tonne coal production from captive mines and target has been reduced to 13mn tonne in FY14. We expect contribution from captive coal to overall fuel mix to gain traction in 13th plan. Lower captive coal availability coupled with limited supply from CIL would increase dependence on imports for NTPC. Pre ACQ quantity may come down to the trigger level (90%) FY13 FY14 FY15E FY16E FY17EDomestic ‐Annual Contracted Quantity(ACQ)for pre FY09 133.8 131 125.0 118.8 118.8 ‐LOA/MOU ‐ 65% supply post signing FSA's in July 8.0 14 15.0 29.0 32.5 ‐Captive ‐ 50% of target ‐ ‐ ‐ 1.2 3.0 ‐Others ‐ Bilateral/E auction 2.3 4.8 4.8 4.8 4.8Total domestic 146.0 150 144.8 153.7 159.0Imported 9.0 10.8 15.2 22.9 23.6Total 153.0 160.6 159.9 176.6 182.6

Source: Company, PhillipCapital India Research Estimates The imported coal mix is expected to increase for NTPC. We estimate that the imported coal consumption as % of domestic coal consumption would increase from ~3‐4% in FY07 to 10‐12% during the latter part of the 12th plan. Import as % of domestic supply would increase


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Lower generation growth/PLF major concern We analyzed the macro changes that might have impacted the NTPC’s generation growth. This is important as we see a structural shift wherein NTPC may not be able to see higher PLF’s and this could cap the incentives under new tariff regulations wherein incentives are linked to PLF. A) Emergence of the private sector: NTPC’s generation during FY11‐14 was CAGR 2%. The subdued growth was driven by the decline in the gas based generation. Also coal based generation during the same period reported CAGR of 4.2% as against all India average of 10%. We note NTPC’s generation share of the overall coal based generation has declined from 36% in 2011 to 30% in FY14. PLF came off from 91% in FY10 to 82% in FY14 lowest in last 10 years. 11th plan also saw the higher addition of the Private capacity with capacity increasing almost 2.5x contributing to the overall generation growth. Consequently private sector coal based generation witnessed CAGR of 64% during FY11‐14 and share of private sector increased to 24% in FY14 from 7% in FY11. Further in the 12th plan as per CEA estimates more than half of the 88GW estimated to be added by private Players. We believe that higher contribution from private sector would reduce higher dependency on NTPC. However, we do not expect NTPC’s PLF to substantially decline led by the low cost but there may be a structural shift were NTPC’s PLF would range from 80%‐85% instead of historic average 90% and above. 60% capacity contributed by the state…. ……..Central sector pie increases

… Pvt. Sector increases it base by 2.5x: As per CEA guidance Pvt sector would add more than 50% of capacity


Central31,899 30%

State62,460 60%

Pvt10,643 10%

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Central45,121 36%

State69,521 56%

Pvt9,927 8%

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Central59,683 34%

State82,405 47%

Pvt34,086 19%

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Central78,676 22%

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B) Lower off take from SEB’s impacting overall demand scenario Demand from the SEB’s has declined in the recent past. Newly commissioned capacities in the power sector are operating at lower PLF’s due to lower offtake from the SEB’s. Also discoms are reluctant to purchase the high cost power and have also reduced supply in the pockets with higher commercial losses. Further the FRP initiated in 2013 and that was adopted by 7 states did not succeed as anticipated as states failed to meet conditions. During the recent elections in the 5 states also power demand did not showed any increase which could be possibly due structural shift in the demand pattern as discoms become more responsible. This could be negative for overall generation companies and especially for NTPC with its high standards of 85‐90% of PLF. Demand growth declining… … Deficit down to 4.5%


Higher dependency on Northern and Western states… State Region % of total revenuesUP North 13.7%Delhi North 13%Maharastra West 8%AP South 8%Gujarat West 6%MP West 6%Bihar East 5%T Nadu South 5%Haryana North 5%Orrisa East 4%Kerala South 4%Punjab North 3%Others 21%Source: Company, PhillipCapital India Research Estimates C) Changes in macro environment to reduce the PLF’s by 2‐5 ppt for NTPC We believe that due to the changes in the macro environment 1) substantial capacity addition and Private Sector becoming more dominant 2) SEB’s reducing power purchase to reduce loses would impact the NTPC’s generation by 5‐10 ppt over next few years. Although NTPC would be beneficiary led by its low cost generation and might able to maintain relatively better PLF’s as compared to its peers but they would come down from historic average of 85‐90% to 80‐85%.

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Generation & Growth

Source: Company, PhillipCapital India Research Estimates Generation loss for NTPC due to back down from SEB’s

Source: Company, PhillipCapital India Research Estimates PLF declined despite higher availability:


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New tariff regulation limits RoE expansion CERC released tariff regulation for 2015‐19. We note with the aim of bringing efficiency CERC has tightened operational parameters in line with draft regulations. We highlight below the key changes that were introduced in tariff regulation over past few years. 2004‐09 2009‐14 2015‐19 Capital Cost Capital expenditure based on actual

cost incurred Capital cost based on actual cost and allowed for truing up. Norms allowed for IDC due to delay, as pass through subject to prudence check.

As per new norms IDC and IEDC due to delay on account of uncontrollable factor shall be allowed as part of Capital cost.

Tax gross up NA Norms allowed utility to recover corporate tax rate from beneficiaries even if actual incidence of tax was lower due to MAT rate.

RoE gross up at effective tax rate based on actual tax paid

Sharing of financial gains due to controllable factors

NA Saving on account of SFO to be shared with beneficiaries in ratio of 50:50

Sharing of all gains due to controllable factors between Gencos and discoms in ratio of 60% and 40% respectively.

Incentives Rs0.25/Kwh for generation above 80% PLF

Based on PAF over and above normative PAF at 85%

Rs0.50Kwh for generation above 85% PLF

Energy charges Calculated on "as received basis" Calculated on "as fire basis" CapitalStructure Debt : Equity = 70%:30% Debt : Equity = 70%:30% Debt : Equity = 70%:30% RoE 14% 15.5% 15.5%

Working capital components Cost of Coal 1.5 mnths (pit head)‐1.5 months

(non‐pit had) 1.5 mnths (pit head)‐2 months (non‐pit had)

15 days (pit head)‐30days (non‐pit had)

Cost of SFO 2 months 2 months 2 months Maintenance Spares 1.5% of capital cost 20% of O&M 20% of O&M Receivables Two Months of capacity charges and

energy charges Two Months of capacity charges and energy charges

Two Months of capacity charges ( excluding RoE) component and energy charges

O&M expenses 1 month 1 month 1 month Interest on working capital SBI PLR SBI PLR/SBI base rate plus 350 bps Bank rate as on April 2014 Escalation in O&M expenses 4.00% 5.72% 6.35% Water Charges Water charges allowed as O&M Water charges to be recovered

separately SHR 2450 kcal/kwh 2425 kcal/kwh 2375 kcal/kwh Auxilary Consumption 9 8.5 7.75 SFO Consumption 2 ml/kwh 1 ml/kwh 0.5 ml/kwh (pit head) Fixed cost recovery 80% PAF for fixed cost recovery 85% PAF for fixed cost recovery 83% PAF for fixed cost recovery Special allowance NA Special allowance in lieu of R&M at

Rs 0.5mn/MW/year and escalation at 5.72%

Special allowance in lieu of R&M at Rs 0.75mn/MW/year and escalation at 6.35%




The regulation for 2015‐19 has once again introduced PLF based incentive and tightened operational parameters thus impacting incentive earnings of NTPC. Also removal of tax arbitrage coupled with introduction of incentive sharing norms will limit scope for RoE expansion. We estimate core RoE to reduce from 20‐22% under earlier tariff regime to 17‐18% under new regulation. Although NTPC has appealed in high court against CERC for reversal of norms, we do not expect significant changes. Key highlights of regulations: A) Introduction of Controllable and Uncontrollable factors

The commission has specified controllable and uncontrollable factors in determination of capital cost Controllable factors: variation in capex due to time/cost overrun due to land acquisition issue, delay in execution by contractors appointed. Uncontrollable factors viz. Force majeure events and Change in law. We believe the introduction of controllable factors in determination of capital cost has introduced the risk of under‐recovery in upcoming projects in case CERC does not allow increased in capex.

B) PLF incentives now to be earned on generation: NTPC earlier used to earn incentive on the availability above 85% but now it has been linked to the generation. NTPC is able to maintain higher PAF levels even as PLF’s have declined due to back down from discoms. We have assumed that some of the NTPC’s older plant would be able to maintain higher PLF’s but the PLF of other and newly commissioned plant would be below 85%. Thus we expect transition from PAF to PLF would impact core RoE by 100‐150bps.

Estimated PLF’s for the projects FY10 FY11 FY12 FY13 FY14 FY15 FY16e FY17eBadarpur 83 74 77 74 67 53 80 80Barh II 61 60 60Bongaigaon 60 60Dadri 98 84 89 82 83 77 85 85Farakka 76 81 70 64 72 73 72 72Kahalgaon 67 71 65 72 71 76 78 78Korba 97 93 79 90 91 88 88 88Kudgi 60Mauda 17 26 55 60Ramagundem 96 89 93 91 87 89 88 88Rihand 96 93 92 87 84 81 88 88Simhadri 98 96 94 84 84 86 96 96Singrauli 94 97 89 93 92 83 88 88Sipat 93 96 95 75 73 83 90 90Talcher 90 92 91 94 93 94 94 94Talcher 93 85 83 82 83 90 88 88Tanda 94 93 88 84 93 82 88 88Unchahar 96 93 90 93 86 83 90 90Vindhyachal 96 94 90 90 87 79 90 90

Source: Company, PhillipCapital India Research Estimates C) Savings on the fuel: NTPC due to its superior operational performance is able to maintain better than the normative SHR thus aiding NTPC to save on the fuel. The normative SHR has been reduced from 2425kcal/kwh to 2375kcal/kwh; and would hence reduce savings for NTPC. We estimate that reduction in SHR would have substantial impact on the additional gains of NTPC. We estimate lower savings to impact RoE by 300bps. D) O&M escalation increased, water charges allowed as pass through: Under new regulation, O&M escalation has been increased to 6.35% from current level of 5.72%. Further water charges have been separately allowed as pass through.



We estimate ~ Rs 5bn reduction in under recovery led by pass through of water charges. E) No more arbitrage on RoE gross up: NTPC grossed up the RoE on the corporate tax and the actual tax payment is on the MAT rate. Hence it is able to make arbitrage on the difference between the corporate and MAT rate. As per the draft regulation NTPC would be able gross up the Roe at effective tax rate based on the actual tax paid. This we believe would be a major blow to NTPC and would have the impact of ~300‐350bps on NTPC’s profit. Core RoE


5%

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30%


Core RoE

We estimate NTPC’s core RoE to decline with implementation of new tariff norms.



Strong balance sheet to support the growth NTPC has the strongest balance sheets among its peers providing confidence on the growth prospect of the company. A) Lowest Debt Equity among peers: NTPC’s debt /equity ratios lowest among the peers and it has been able to maintain it in a narrow range despite robust capex incurred by the company. The other utilities have been impacted due to higher leverage and had to dilute equity or monetize asset to meet their further capex requirement. NTPC debt/equity stood at 0.8x and would help it in meeting its growth requirement (20GW of capacity under construction). We note strong balance sheet also opens up opportunity of inorganic growth for NTPC. NTPC has indicated it is evaluating ~ 8‐9GW of opportunities. Assuming 4GW opportunities materializes and acquired project accrue similar RoE as existing projects, the accretion to SOTP would be Rs 2‐3 per share. D:E of major utilities

Source: Company, PhillipCapital India Research Estimates B) Debtor days: NTPC has been able to maintain debtor days down to 30‐35 lower than normative 60 days period that regulation grants; implying timely recovery of dues. NTPC has been able to achieve 100% realization of dues. Most of the discoms have maintained LC equal to or more than 10% of billing as per OTSS agreement. NTPC has resorted to regulation/diversion of power supply to third party at the risk and cost of defaulting utilities in case of non‐payment of dues. Debtor days stable stood at 30‐35 days Debtors days


0

2

4

6

8

10

NTPC NHPC JSW Reliance JPVL PWGR Adani

FY11 FY12 FY13 FY14

‐

10

20

30

40

50

60

FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14

Debtor days

NTPC stands out among its peers on comparing the D:E. Most of the utilities have opted for equity dilution or looking for asset sell to improve its balance sheet



C) Regulated earnings ensure stable cash flow and dividend payout NTPC accrue regulated earnings based on CERC norms that ensure steady EBITDA of 24‐26% and also generate robust cash flow of ~ Rs 150bn aided by steady capacity addition. Further with variable cost pass through, risk of fuel under recovery is unlikely case of NTPC like private players. We expect NTPC to maintain its FY14 payout of 43%. EBITDA margins (%)

Source: Company, PhillipCapital India Research Estimates Cash flow from operations


5%

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20%

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30%


EBIDTA margin

(300)(250)(200)(150)(100)(50)‐50

100 150 200


Cashflow from Operation (Rs bn) Cash flow from investments (Rs bn)

Cash flow from Financing (Rs bn)

Regulated business ensuring stable margins

Aiding steady cash generation



Dividend payout

Source: Company, PhillipCapital India Research Estimates 1year forward band charts


Phillip Capital vs consensus estimates

____________PC Estimates____________ ____________Consensus____________ ____________Deviation____________(Rs mn) FY15E FY16E FY17E FY15E FY16E FY17E FY15E FY16E FY17ESales 743,023 810,272 884,614 809,671 897,891 999,892 ‐8% ‐10% ‐12%EBITDA 169,127 188,152 208,679 187,427 210,113 235,824 ‐10% ‐10% ‐12%PAT 90,930 96,871 103,705 94,538 99,680 109,178 ‐4% ‐3% ‐5%EPS 11.0 11.7 12.6 11.5 12.1 13.2 ‐4% ‐3% ‐5%


We believe during FY16‐17, operational parameters more than capacity addition would be key to earnings of NTPC. With capacity addition of 3.5GW (parent) during FY15‐17E, we expect NTPC’s regulated equity to achieve 4% CAGR during FY15‐17E and subdued earnings CAGR of 4% during the same period as RoE‘s drop with implementation of new tariff norms. We value NTPC at 1.8x FY17E regulated asset base and cash and liquid assets to arrive at target price of Rs 160. We initiate overage with neutral rating. At CMP of Rs 150, NTPC trades at 1.3x FY16E P/B. Key risks to our call are major changes in tariff regulation, better than expected operational parameters leading to higher incentive earnings .

5%

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35%

45%


Dividend payout

8x

12x

16x20x

20

70

120

170

220

270

320

Apr/08 Apr/09 Apr/10 Apr/11 Apr/12 Apr/13 Apr/14

Rs P/E Band

1.5x

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2.5x

3x

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100

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300

350


Rs P/BV Band

NTPC has been able to maintain steady dividend payout.



SOTP Description FY17 Regulated Equity (Parent) Rs mn 411,005 Regulated Equity (Parent) Rs 50 Multiple x 1.8 Value Parent Rs mn 724,120 Value Parent Rs 88 Regulated Equity (JV) Rs mn 49,814 Regulated Equity (JV) Rs 6 Multiple x 2 Value JV Rs mn 87,764 Value JV Rs 11 Cash Rs mn 202,524 Cash Rs 25 OTSS Bonds Rs mn 32,884 OTSS Bonds Rs 4 Value of equity Rs mn 1,047,291 CWIP 35 Value of equity 160



Financials

Income Statement Y/E Mar, Rs mn FY14 FY15e FY16e FY17eNet sales 716,027 732,489 801,747 836,639Growth, % 11 2 9 4Total income 716,027 732,489 801,747 836,639Raw material expenses ‐458,297 ‐487,783 ‐527,811 ‐540,933Employee expenses ‐38,680 ‐36,624 ‐41,691 ‐43,505Other Operating expenses ‐45,439 ‐47,085 ‐48,214 ‐51,819EBITDA (Core) 173,612 160,997 184,031 200,381Growth, % 10.5 (7.3) 14.3 8.9 Margin, % 24.2 22.0 23.0 24.0 Depreciation ‐41,422 ‐47,561 ‐52,495 ‐55,866EBIT 132,190 113,435 131,536 144,516Growth, % 7.3 (14.2) 16.0 9.9 Margin, % 18.5 15.5 16.4 17.3 Interest paid ‐24,066 ‐31,012 ‐44,531 ‐49,652Pre‐tax profit 139,176 109,984 118,106 127,932Tax provided ‐29,299 ‐27,485 ‐24,924 ‐27,203Profit after tax 109,877 82,499 93,181 100,729Net Profit 109,877 82,499 93,181 100,729Growth, % 9.3 (24.9) 12.9 8.1 Net Profit (adjusted) 109,877 82,499 93,181 100,729 Unadj. shares (m) 8,245 8,245 8,245 8,245 Wtdavg shares (m) 8,245 8,245 8,245 8,245 Balance Sheet Y/E Mar, Rs mn FY14 FY15e FY16e FY17eCash & bank 153,114 163,690 174,043 202,415Debtors 52,201 53,401 58,450 60,994Inventory 53,734 54,969 60,166 62,785Loans & advances 158,933 162,587 177,960 185,705Other current assets 109,987 112,516 123,154 128,514Total current assets 527,968 547,163 593,774 640,412Investments 97,579 107,579 117,579 127,579Gross fixed assets 1,169,921 1,208,146 1,291,636 1,368,636Less: Depreciation ‐448,812 ‐496,374 ‐548,869 ‐604,735Add: Capital WIP 448,887 671,230 807,740 950,740Net fixed assets 1,169,995 1,383,002 1,550,506 1,714,641Total assets 1,795,542 2,037,743 2,261,859 2,482,631 Current liabilities 239,072 242,687 257,898 265,560Total current liabilities 239,072 242,687 257,898 265,560Non‐current liabilities 698,317 986,783 1,143,783 1,300,783Total liabilities 937,389 1,229,470 1,401,680 1,566,343Paid‐up capital 82,455 82,455 82,455 82,455Reserves & surplus 775,699 725,819 777,724 833,834Shareholders’ equity 858,153 808,273 860,179 916,288Total equity & liabilities 1,795,542 2,037,743 2,261,859 2,482,631 Source: Company, PhillipCapital India Research Estimates

Cash Flow Y/E Mar, Rs mn FY14 FY15e FY16e FY17ePre‐tax profit 139,176 109,984 118,106 127,932Depreciation 41,422 47,561 52,495 55,866Chg in working capital ‐5,585 ‐5,003 ‐21,047 ‐10,604Total tax paid ‐24,278 ‐24,485 ‐21,924 ‐24,203Cash flow from operating activities 150,735 128,058 127,629 148,991Capital expenditure ‐210,962 ‐260,568 ‐220,000 ‐220,000Chg in investments 10,022 ‐10,000 ‐10,000 ‐10,000Cash flow from investing activities ‐200,939 ‐270,568 ‐230,000 ‐230,000Free cash flow ‐50,205 ‐142,510 ‐102,371 ‐81,009Debt raised/(repaid) 90,241 285,466 154,000 154,000Dividend (incl. tax) ‐55,459 ‐42,296 ‐41,276 ‐44,619Other financing activities ‐140 0 0 0Cash flow from financing activities 34,641 243,170 112,724 109,381Net chg in cash ‐15,563 100,659 10,353 28,372 Valuation Ratios

FY14 FY15e FY16e FY17ePer Share data EPS (INR) 13.3 10.0 11.3 12.2 Growth, % 9.3 (24.9) 12.9 8.1 Book NAV/share (INR) 104.1 98.0 104.3 111.1 FDEPS (INR) 13.3 10.0 11.3 12.2 CEPS (INR) 18.3 15.8 17.7 19.0 CFPS (INR) 14.5 12.2 11.7 14.1 Return ratios Return on assets (%) 7.4 5.3 5.7 5.6 Return on equity (%) 12.8 10.2 10.8 11.0 Return on capital employed (%) 8.5 6.1 6.4 6.3 Turnover ratios Asset turnover (x) 0.6 0.5 0.5 0.5 Sales/Total assets (x) 0.4 0.4 0.4 0.4 Sales/Net FA (x) 0.7 0.6 0.5 0.5 Working capital/Sales (x) 0.2 0.2 0.2 0.2 Receivable days 26.6 26.6 26.6 26.6 Inventory days 27.4 27.4 27.4 27.4 Payable days 105.8 102.7 104.0 105.4 Working capital days 69.2 70.2 73.7 75.2 Liquidity ratios Current ratio (x) 2.2 2.3 2.3 2.4 Quick ratio (x) 2.0 2.0 2.1 2.2 Interest cover (x) 5.5 3.7 3.0 2.9 Total debt/Equity (%) 78.3 118.4 129.2 138.1 Net debt/Equity (%) 60.4 98.2 108.9 116.0 Valuation PER (x) 11.3 15.0 13.3 12.3 PEG (x) ‐ y‐o‐y growth 1.2 (0.6) 1.0 1.5 Price/Book (x) 1.4 1.5 1.4 1.3 EV/Net sales (x) 2.5 2.8 2.7 2.7 EV/EBITDA (x) 10.1 12.6 11.8 11.5 EV/EBIT (x) 13.3 17.9 16.5 15.9



Power Grid Corporation (PGCILIN) Increased focus on capitalization INDIA | UTILITIES | Initiating Coverage

28 April 2015

Investment Rationale We initiate coverage on Power Grid Corporation of India Ltd (PGCIL) with a BUY rating and a target price of Rs 176 based on FY17e estimates. PGCIL is play on transmission capex offering steady earning quality and is relatively immune to problems faced by sector. We believe PGCIL is well placed to capitalize on under investment in transmission sector. Focus shifts to increased capitalization: Based on investment approvals of Rs1025bn and cumulative order awards of Rs925bn till FY15, we expect strong capex and capitalization over the 12th plan. Our analysis of the Rs1,100bn capex in the 12th plan (of which Rs820bn linked to generation projects) reveals that ~65% of these projects will commission by FY17; therefore a high likelihood of PGCIL achieving its target capex. We note transmission projects involves multiple beneficiary, implying 65% of project commissioning is satisfactory achievement. Thus we build Rs1,100bn of capex in our estimates in line with the management expectation and led by capitalization of Rs1015bn, we expect CAGR 22% growth in regulated equity over FY13‐17e. Insulated from the problems in the power sector: PGCIL is insulated from fuel risks that brought the power sector to its knees. Being a transmission utility, it bears no risk of shortage of fuel and fuel pricing. While it certainly bears a degree of risk for payment collections from transcos and discoms, however PGCIL’s receivables are covered under LC ensuring timely collection. Also, in the recent past it has curtailed power supply to discoms where payments have been delayed to ensure timely payments. Equity dilution sufficient to meet 12th plan capex: PGCIL diluted 13% equity in FY14 to meet the revised capex target of Rs 1.1tn as compared to Rs 1tn previously. PGCIL raised Rs 53bn; this combined with operating cash flows of Rs 100‐120bn during FY15‐17 leads us to believe that PGCIL would be able to meet its equity requirements. The capex of PGCIL would remain stable during FY14‐17 but operating cash flows will increase led by increase in regulated equity base; hence we believe that PGCIL would be able to meet its equity requirement without further dilution in the 12th plan. Earnings and Valuations: We model a 19% CAGR in EPS over FY14‐17E and expect regulated asset base to grow at a CAGR of 21% on back of higher capex and capitalization. The stock currently trades at 1.7x Y17e P/B and 10x FY17e EPS. We value stock at 1.6x regulated equity and add liquid assets to arrive at target price of Rs 176. We initiate coverage with BUY rating on the stock. Key risks to our BUY call: Key risks to our BUY call are: a) Weaker than expected capitalization due to right of way and/or delay In generation projects that leads to a further dilution of equity to fund the ongoing capexprogramme, b) RoE’s may shrink as the mix changes in the 13th plan to competitive bid projects, c) flattening of capex in the 13th plan which would lead to lower growth in earnings. In our view, however it is too early to take a call on the same and we await more clarity on new projects being bid out to understand the potential impact on PGCIL.

BUY CMP RS 150 TARGET RS 176 (+18%) COMPANY DATA O/S SHARES (MN) : 5262MARKET CAP (RSBN) : 763MARKET CAP (USDBN) : 12.352 ‐ WK HI/LO (RS) : 159 / 102LIQUIDITY 3M (USDMN) : 6.4PAR VALUE (RS) : 10 SHARE HOLDING PATTERN, % PROMOTERS : 57.9FII / NRI : 27.9FI / MF : 7.7NON PROMOTER CORP. HOLDINGS : 2.6PUBLIC & OTHERS : 3.9 PRICE PERFORMANCE, %

1MTH 3MTH 1YRABS ‐1.4 ‐2.4 38.5REL TO BSE 1.1 3.8 18.4 PRICE VS. SENSEX



60

80

100

120

140

160

Apr‐11 Jun‐12 Aug‐13 Oct‐14Power Grid BSE Sensex


POWER GRID CORPORATION INITIATING COVERAGE

Strong capex and capitalization to continue backed by strong investment approvals and orders Our investment thesis for PGCIL is based on the premise that capex and capitalization would continue to remain strong over the 12th plan. We believe India‘s massive under investment in transmission capacity (~40 GW inter regional transmission capacity) and robust capacity addition of 88 GW expected in 12th plan will require investment in evacuation facility. We believe PGCIL is well placed to capitalize on this opportunity and estimate robust pace of capitalization to continue driven by: a. Investment approvals by the board of 93% of targeted spending of Rs1.1tn in

the 12th plan done by March’15. We however, do note that board approvals have slowed down over the past few years (ordering in FY13 at Rs126bn and Rs78bn in FY14); this could be due to lack of clarity on generation projects likely to be commissioned in the last few years of the 12th plan and the 13th plan. An increased focus on capitalization has also meant that both investment approvals and ordering have started to slow down. We expect ordering to pick up led improved clarity on 13th plan

Investment approvals by the board slows down as focus shifts to commissioning (Rsbn)

Source: Company, PhillipCapital India Research FY15 Includes 196 bn pertaining to 13th plan b. 90% of the orders have already been placed. PGCIL has already placed orders

worth Rs972bn – 90% of its targeted capex in the 12th plan by FY14. The focus has now shifted to execution of these orders on a timely basis – to ensure the same, PGCIL has introduced new bidding norms for vendors to weed out the weak players and also restricted new orders to vendors who have not completed 50% of existing order backlog. Further with focus on execution, PGCIL has ensured payment to vendors only on erection.

260

135

211

430

126

78

242

‐

100

200

300

400

500


Rs bn



Ordering and capex incurred by PGCIL – FY03‐15e

Source: Company, PhillipCapital India Research Estimates We expect capitalization to stabilize at ~Rs200‐250bn during FY15‐17E each year as orders placed in earlier years are commissioned and move from CWIP into fixed assets. During FY07‐14E PGCIL’s GFA grew 19% CAGR, however lead by focus on capitalization we expect GFA to grow 19.5% CAGR during FY14‐17E. We expect accrual to CWIP to reduce as capitalization improves. Gross fixed assets grow aided by increased commissioning (Rsbn)

Source: Company, PhillipCapital India Research Estimates Gap between capitalization and capex to reduce (bn)


0

50

100

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300

FY03 FY04 FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15

Capex Orders

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GFA Capitalisation

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Q113 Q213 Q313 Q413 Q114 Q214 Q314 Q414 Q115 Q215 Q315

Capex Capitalisation



c. Analysis of Rs1, 100bn of spending on individual projects reveals that 65% of the generation projects are largely on track. PGCIL is targeting capex of Rs 1, 100bn in the 12th plan that will earn a regulated return of 15.5% ROE. Of this Rs 1,100bn, Rs820b is towards evacuation of power from new generation capacity,Rs180b for strengthening of existing transmission systems and Rs 100bn for competitive bid projects, new projects allocated by GoI, Green energy corridor, intrastate projects etc.

Our analysis of the Rs1,100bn capex in the 12th plan (of which Rs820bn linked to generation projects) reveals that ~64% of these projects would commission by FY17; implying a higher likelihood of PGCIL achieving its target capex. Planned Capex in 12th plan of Rs1, 100bn; ~50% towards HCTC for IPP’s Description RsbnCentral government generation schemes 250UMPP – Sasan, Mundra, Krishnapatnam 90HCTC corridors – IPP 480Grid Strengthening 180Others 100Total planned capex (Rsbn) 1,100

Source: Company, PhillipCapital India Research Our analysis highlights that: a. Two of the three UMPP’s (12GW of total capacity for the 3 UMPP’s) have started

generation with a substantial portion of the transmission works for each of these lines also getting completed. However, the likelihood of Krishnapatnam getting commissioned within the 12th plan is extremely low.

b. Of the central government projects scheduled to commission in the 12th plan, we expect ~70% of the projects to be commissioned within the 12th plan. PGCIL intends to spend Rs250bn on these transmission projects.

c. We estimate that 64% of the total generation capacity envisaged to be evacuated via the HCTC’s should get commissioned by FY17.We note captive coal based capacity of IPP’s linked to these transmission corridor stands at 4.5GW and could speed up if coal auction takes place in time.

Status and expected completion of HCTC linked generation projects Description Planned % commissioned by FY17 % delayed of total HCTCIPPs Total 58,973 64% 36%HCPTC I, Orissa 10,090 53% 8%HCPTC II, Jharkhand 4,540 38% 5%HCPTC III, Sikkim 2,162 72% 1%HCPTC IV, MP and Chhattisgarh 4,370 49% 4%HCPTC V, Chhattisgarh 15,485 76% 6%HCPTC VI, Andhra Pradesh 4,320 86% 1%HCPTC VII, Tamil Nadu 2,520 100% 0%HCPTC VIII,Tamil Nadu 3,960 33% 4%HCPTC IX, Various Regions 11,526 68% 6%




Relatively insulated from the problems in the power sector PGCIL is relatively insulated from the problems currently plaguing the power sector. The three key issues hurting the power sector are those of lack of fuel supply, delayed payments from customers, (State discoms) and non ‐ remunerative PPA’s signed with customers that need to be revised. PGCIL is not exposed to any fuel risk as it is a transmission utility that earns a fixed post tax return of 15.5% on its regulated equity. As we highlight below, PGCIL has been able to efficiently collect its receivables on a timely basis. It allows 2 month of credit (60 days is the billing/collection cycle) and its debtor days are currently at 41 days of sales. Payments beyond 2 months attract a surcharge of 18%. Debtor collection remains very impressive with Rs6bn >60days The average monthly billing by PGCIL to its customers is ~Rs12bn. However, its debtors as of Dec’14 stood at Rs 21bn, of which 4bn are outstanding for more than six months. We note PGCIL is relatively well placed on receivables front as compared to other utilities that have faced payment delays. Further receivables to PGCIL are covered by letter of credit pursuant to one time settlement scheme. In the past, PGCIL has also curtailed supplies to discoms where payments have been delayed as was done with BSES Rajdhani and BSES Yamuna in March’ 13 on delays in release of payments to PGCIL. Debtor days lower than normative

Source: Company, PhillipCapital India Research Estimates Delayed capacity will not derail transmission capex Although we do acknowledge the reforms under taken in power sector such as signing of FSA, compensatory tariffs for unremunerative PPA, automatic pass through of imported coal cost in lieu of domestic shortage, FRP to address weak discom financials, however we expect health of sector to improve gradually. Even though liberal environmental clearance norms will aid coal output, however limited evacuation facility will delay pace of capacity addition. The delayed capacity addition does not impact PGCIL as under Bulk Power Transmission Agreement (BPTA) signed with IPPs, as per which IPPs are under obligation bear the transmission charges as approved by CERC from the effective date of LTA.

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84

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Debtor days

Transition from Postage Stamp to PoC method for tariff calculation lead to higher receivables as same was challenged by few states.



Equity dilution adequate to meet 12th plan equity requirements PGCIL has capex plan of Rs 1.1tn in 12th plan. It has already incurred cumulative capex of Rs 587bn till 3QFY15. Hence it would incur additional capex of Rs 600bn during FY15E‐17E period implying equity requirements of Rs 180b. Also there would be some additional equity infusion required in the projects were higher debt was deployed during FY12‐13 to bring it to normative rate of 70:30. We estimate PGCIL to generate operational cash flows of Rs 100‐150b during FY15‐17e; additionally it raised ~ Rs 54bn in FY14 through FPO. Hence we believe that even after maintaining the dividend payout ratio at current rates (unlikely to reduce) it would be able to meet its equity requirement at least for the 12th plan Cash flow calculation for dilution purposes Cash flow calculation for dilution purposes FY15e FY16e FY17eCash flow from operations 121,841 131,238 150,215 Less: Dividends (18224) (22710) (26583)Less: Debt repayment (36796) (43531) (56184)Add: Cash available 44,175 40,398 75,437 Cash available after financing activities 110,996 105,395 142,885 Equity commitment needed for funding capex 72,000 67,500 67,500 Shortfall/(Surplus) if any (vs target capex) (38,996) (37,895) (75,385)

Source: Company, PhillipCapital India Research Estimates Net D:E ratio

Source: Company, PhillipCapital India Research Estimates PGCIL net Debt to Equity ratio would improve post the fund raising undertaken in FY14. We expect the net Debt to equity ratio to increase during FY15‐17 led by the nature of the business (capex intensive) but we estimate that it would stabilize ~ 2.3‐2.4:1 due to 1) flat growth in capex: Flat capex target during FY15‐17; , 2) Better capitalization: We estimate PGCIL to continue the capex and capitalization ratio it had in FY12‐13 and 3) Increase in regulated equity: The regulated equity rising every year would help in improving the operating cash flows and with capex stabilizing it would be positive for PGCIL.

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FY04 FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15E FY16E FY17E

IPO

FPO

FPO

Net D:E ratio stabilises reduces the risk of

further dilution



Payout ratio at ~ 30%; suboptimal leading to strain on balance sheet Since its listing PGCIL has maintained average dividend payout of 30% leading to total outgo of Rs 70bn. We note PGCIL’s dividend policy has placed unnecessary strain on its capital structure. As a promoter it is necessary for government to respect PGCIL’s equity and also consider its growth plan. Higher dividend payout although helped GoI in short term to meet its budget shortfall, however in long run it has led to equity shortfall for PGCIL leading to dilution on consistent basis. A much rational approach would be to create value and accrue higher proceeds through disinvestment at higher value. We note based on our profit assumption, overall dividend payout could be ~Rs 70bn over FY15‐17E at 30% payout. Payout ratio maintained at 30%; Yield improves

Source: Company, PhillipCapital India Research Estimates Higher dividend payout leading to dilution Date Issue Price Amount (Rsbn) Comment FY08 52 20 IPO Funding FY08‐11 17 Dividend Paid FY11 90 38 FPO proceeds FY11‐13 33 Dividend Paid FY14 90 54 FPO proceeds FY14 15 Dividend Paid


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Marginal Impact under new norms The tariff regulation 2015‐19 has tightened operational parameters for regulated utilities; however its impact on transmission utilities is relatively lower as compared to generation utilities. Under new norms, normative availability factor for fixed cost recovery and incentive has been raised and also O&M norms tightened. Escalation allowed under new tariff regulation is lower as compared to earlier norms

FY10 FY11 FY12 FY13 FY14 FY15 FY16 FY17 FY18 FY19Sub station 765kV 7.34 7.76 8.20 8.67 9.17 8.44 8.72 9.01 9.31 9.62escalation 5.7% 5.7% 5.7% 5.8% ‐7.9% 3.3% 3.3% 3.3% 3.3%400kV 5.24 5.54 5.86 6.19 6.55 6.03 6.23 6.44 6.65 6.87escalation 5.7% 5.7% 5.7% 5.7% ‐7.9% 3.3% 3.3% 3.3% 3.3%220kV 3.67 3.88 4.10 4.33 4.58 4.22 4.36 4.51 4.66 4.81escalation 5.7% 5.7% 5.7% 5.7% ‐7.9% 3.3% 3.3% 3.3% 3.3%132kV and Belo 2.62 2.77 2.93 3.10 3.27 3.02 3.12 3.22 3.33 3.44escalation 5.7% 5.7% 5.7% 5.7% ‐7.9% 3.3% 3.3% 3.3% 3.3%

Source: Company, PhillipCapital India Research Estimates Similarly O&M norms are tightened for other components of transmission system viz AC/HVDC lines and HVDC station. Normative Transmission Availability Factor

__________2010‐14__________ _________2015‐19_________TAF for fixed cost

recovery TAF for incentiveTAF for fixed cost

recovery TAF for incentiveAC system 98 98 98 98.5HVDC bi‐pole links 92 92 95 96HVDC back‐to‐back stations 95 95 95 96

Source: Company, PhillipCapital India Research Estimates The transmission availability norms have been tightened under new regulation for HVDC bi‐pole links and norms for incentive recognition are higher as compared to old regulation. Further new regulation has capped incentive to maximum transmission availability of 99.75%. Due to removal of STOA income coupled with tightening of norms, we expect PGCIL to accrue core RoE of 16% as against 17‐19% under earlier norms. Core RoE


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Competitive bid to change the mix in 13th plan Acquiring competitive bid projects with decent RoE’s remains the key: PGCIL would need to acquire the projects through competitive bid process in the 13th plan instead of nomination basis. It would impact the share of PGCIL in the central transmission projects (earlier had a monopoly). Secondly the RoE’s would also reduce if competition remains intense. We note through tariff based competitive bidding 7 projects were won by PGCIL. These include 1) Vemagiri A Transmission Sytem,2) Vizag Transmission System,3)NRSS XXXI (A) 4)Nagapatinam‐Madhugiri Project 5) Unchahar Transmission 6) Gadarwara transmission and 7) Vindhyachal V transmission. The Vemagiri project has been put on hold on CERC orders due to lack of clarity over gas based plants associated with the projects. Talcher II and North Karanpura Transmission that were earlier awarded to Reliance Transmission are now awarded to PGCIL on cost plus basis. Also ATS Associated with project of Nagarjuna Power is awarded to PGCIL on cost plus basis. Also additional TN HVDC line was awarded to PGCIL on nomination basis. List of Projects Awarded Project Developer No. of bidders (L1) L2 L3East North Interconnection transmission project Sterlite Technologies 8 1,188 1,676 2,400Jabalpur Transmission project Sterlite Transmission Projects 33 1,421 1,441 1,499Bhopal Dhule Transmission Co Ltd Sterlite Transmission Projects 22 1,995 2,185 2,449Nagapattinam‐Madhugiri PGCIL 22 987 1,529 2,082Patran Transmission Co. Ltd. Techno Electric and Engineering 7 274 398 595Transmission System for Part ATS of RAPP U‐7 & 8 Sterlite Grid 10 365 523 385Eastern Region System Strengthening Scheme‐VII Sterlite Grid 7 589 1,624ERSS VI EsselInfraprojects Ltd 10 1,174 1,295 1,480Talcher‐II Transmission Co Ltd PGCIL 1,440 North Karanpura Transmission Co Ltd PGCIL 2,580 Raichur Sholapur Transmission Co Ltd Patel Engg, Simplex Infra & BS Transcomm 35 293 315 316Vemagiri A Transmission System Ltd PGCIL 1,197 Vizag Transmission Ltd PGCIL 14 2,311 2,590 3,888Kudgi Transmission Ltd L&T IDPL 11 1,796 2,130 2,186NRSS XXiX Sterlite Grid 6 4,377 4615 NANRSS XXXI (A) PGCIL 7 594 598 818NRSS XXXI (B) EsselInfraprojects Ltd 7 887 963 987Unchahar Transmission PGCIL 6 167 296Vindhyachal V PGCIL 8 2109 2182 2646Gadarwara STPS (Part A) PGCIL NA NA NA NAGadarwara STPS (Part B) PGCIL NA NA NA NA

Source: Company, PhillipCapital India Research Estimates Our analysis of Vizag Transmission, Unchahar Transmission, Nagapatinam ‐Madhugiri and NRSS XXXI (A) imply weak RoE due to competitive pressure. We get a negative value from these projects however PGCIL management indicate that they would be able to earn decent RoE’s from the same led by better execution capability and operational efficiency. However we do note that competitive landscape has changed significantly since the time first project was awarded in 2010. The number of participants has reduced from 20+ to 7‐8. We note these projects form very small proportion of extant projects. Thus it is too early to take call on competitive bid projects and their contribution is very negligible to impair RoE in 12th plan.



Project Analysis Vemagiri Vizag Nagapattinam‐Madhugiri

Cost of project INRm 13,000 12,777 10,250 D:E 4.0 4.0 4.0 Debt INRm 10,400 10,222 8,200 Equity INRm 2,600 2,555 2,050 O&M exp % 12.0 12.0 12.0 Escalation % 5.0 5.0 5.0 Debt repayment No. of years 15 15 15.0 Depereciation % 4.0 4.0 4.0 Interest rate % 7.0 7.0 7.0 Expected CoD Year FY16 FY16 FY16 Discounting factor % 13.0 13.0 13.0 NPV INRm (2,213) 2,209 (1,595)

Source: Company, PhillipCapital India Research Estimates Flattish capex growth estimated in 13thplancapex v/s 2x growth in previous 5 year plans The total transmission capability expected in the 13th plan is ~ Rs 2.3tn out of which the inter‐state capex estimate is ~ Rs 1.35tn. Hence even if PGCIL is able to win 70% of the same it would have flattish capex growth due to higher base during 13th plan as compared to capex of almost doubling in the previous 5 year plans. PGCIL has under taken various new initiatives which may help in increasing the capex target and improve the growth visibility however there is lack of clarity on the same. However we note 13th plan capex could be higher as investment in transmission sector would be skewed towards high value 765kV and HVDC. Capex almost grew 2x in every 5 year plan


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Other potential opportunities for PGCIL to drive the growth in 13th plan • Green Energy Corridor: PGCIL has prepared a detail report on Green Energy

Corridor with investment capability of ~Rs430bn to upgrade and develop the transmission system for adequate supply of renewable energy. Green Energy Corridor opportunity for interstate transmission network stands at Rs224bn. These projects can be taken up on bidding basis, as no new projects can now be awarded to PGCIL on nomination basis. However, the Ministry of Power can include the scope of such work under "urgent/important" projects and can override provision to hand over the work to PGCIL. Currently, there is no visibility on the same. The project already has Euro1b loan from kfw Bankengruppe (banking group) under consideration. The approval of the project is expected in FY15. It could be a big boost for PGCIL if the project is awarded to it on nomination basis.

• Telecom: PGCIL diversified into Telecom business under the brand name

‘POWERTEL’ to expand its revenue stream by installing overhead optic fibre network using OPGW (Optical Ground Wire), leveraging its existing countrywide transmission infrastructure. It has an all India Broad Band Telecom Network of about 29,640 km, providing connectivity to all metros, major cities, towns, State capitals including remote areas of North‐Eastern Region, Jammu & Kashmir etc. and covering about 317 Points of Presence (PoPs) across the country. Key projects undertaken under this arm include National Knowledge Network with the purpose to provide a unified high speed network backbone for educational institutions in India and National Optical Fiber Network (NOFN) to provide connectivity to all Gram panchayats in India

• JV with states: PGCIL has entered in to JV’s with two states –Bihar and Odhisa

with share of 50%. Total planned capex for 2 JVs is estimated at Rs88bn at normative D:E ratio equity requirement would be ~Rs 26bn limiting PGCIL scope of investment to INR13b (50%). PGCIL is also under process to form JV’s with other states. It would benefits the state also in 1) Better execution visible from PGCIL track report, 2) Operational synergy as it has the broader network set up throughout the country 3) Financial synergy as most of the SEB’s are already going through restructuring process or suffering from poor financial conditions hence JV would help in getting loans. Hence the JV structure provide good growth opportunities however we expect only the financially distressed SEB’s to form JV’s with PGCIL.

• Other opportunities: Smart Grid pilot project developed in Pondicherry, Desert

Power assessing potential in states like J&K, HP, Gujarat and Rajasthan. Residuals of High speed transmission corridor projects. Distribution opportunities in various states. Although these all opportunities are at nascent stage and needs further clarity.

• Consultancy: Under consultancy PGCIL undertake domestic and international

assignments. In domestic PGCIL assist the State Utilities in development of their Transmission & Distribution (T&D) infrastructure. Also it undertake international assignments in more than 15 countries



Earnings and Valuation Strong capitalization to drive earnings We model 19% EPS CAGR over FY15‐FY17 driven by 22% CAGR in the regulated equity from Rs257bn in FY14 to Rs461bn in FY17e as we estimate annual capitalization to grow along with the increase in capex. We estimate core RoE’s to decline to 15.8 % from erstwhile 18% driven by tightening of operating norms and lower STOA income. Growth in regulated equity to drive earnings


Higher RoE led by contribution from new capacity We note that reported ROE in FY13 is at 15% despite 30% of its CWIP (Rs350bn) being funded by equity which does not earn any return. This is possible on account of higher ROE’s being earned in its other segments – namely telecom and consultancy. ROE’s at 16%‐17% despite high CWIP on higher ROE’s in telecom and consultancy


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Cash generation to improve We expect cash generation to improve for PGCIL as capitalization gathers pace and new capacity adds to profits. Accordingly we expect PGCIL to accrue FCFE of Rs 47bn, implying cash flow yield of ~6% (FY17E). FCFE


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Key Risks Synchronization Risk with Generation Projects: Lack of clarity over fuel coupled with issues over PPA due to weak financial health of discoms has resulted in significant delay in capacity addition. This has often led to situation wherein transmission system has come ahead of generation project. Continued delay in generation capex could also put risk on PGCIL’s capex. In order to mitigate this risk, PGCIL has signed agreement with generators to recover transmission charges from generators from the date of actual commissioning of transmission assets. Once PPA’s are signed, then applicable transmission charges are to be paid by respective beneficiaries. Revenue Risk PGCIL’s revenue recognition is based on CERC norms that introduce Point of Connection (PoC) method for collection of transmission charges. States namely Bihar, Odisha, West Bengal, Maharashtra and Jharkhand had challenged the aforesaid sharing methodology in the court of law and final decision is awaited. In terms of interim order of the Delhi High Court, all the above States are however making payment as per said Regulation, but under protest. Also CERC regulation for tariff block 2015‐19 has classified land acquisition as controllable factor implying any cost escalation on account of that would not be allowed as pass through. This could impair RoE under upcoming projects. Tariff based competitive biddings: As discussed earlier, the Tariff based competitive bidding norms introduced has challenged monopoly status of PGCIL and exposed it to competitive risk. However we note competitive intensity has dropped significantly over past few years as private players have faced execution issues due to irrational bid. We note limited maneuverability to accrue incentive in transmission projects as compared to generation projects has reduced participation from private players. Further we note the competitively bid projects would form very small portion of PGCIL’s project portfolio during FY15‐17E. Right of Way: The enactment of Land Acquisition Act and R&R Act (2011) has lead to execution difficulty for PGCIL. Further obtaining forest clearance under Forest (Conservation) Act, 1980 involves a steep and tedious hierarchy. Apart from the legislative framework, social issues like RoW are contributing to prolonged delays in the commissioning of projects.



Valuation At CMP of Rs 150, PGCIL trades at 1.6x FY17 P/B and 10x FY17E. With a 14% EPS CAGR over FY14‐FY17 driven by 22% increase in the regulated equity from Rs213bn to Rs461bn in FY17, PGCIL is our top pick in the power utilities. We value PGCIL at 1.6x regulated book and add cash and liquid assets to arrive at target price of Rs 176.We initiate coverage on the stock with a BUY rating. Key risks include a sharp slowdown in capex and/or capitalization and increase in competition in competitive bidding. SOTP Description FY17E Multiple Value(Rs mn) Per Share Regulated Equity (Operational Project ) 461,244 1.6 753,431 144 Equity in JV project 3,307 1.6 5,402 1 OTSS Bond 3,786 1 2,740 1 Consultancy and Telecom(PAT) 3,487 10 34,873 7 Cash (ex ‐cash held for Consultancy) 37,644 1 7 CWIP‐Equity invested 89,184 1 17 Total value per share 176

Source: Company, PhillipCapital India Research Estimates PGCIL vs 10 years Bond

Source: Company, PhillipCapital India Research Estimates We are marginally above consensus estimates. Description __________PC Estimates_________ ___________Consensus___________ __________Deviations__________(Rs mn) FY15E FY16E FY17E FY15E FY16E FY17E FY15E FY16E FY17ESales 174,387.1 212,132.9 246,404.6 175,631.6 207,565.1 241,790.2 ‐1% 2% 2%EBITDA 150,439.6 184,593.3 214,734.0 150,726.2 179,086.9 209,503.4 0% 3% 2%PAT 51,988.9 64,789.4 75,837.8 51,293.7 61,239.9 71,657.5 1% 6% 6%EPS 9.9 12.4 14.5 9.8 11.7 13.7 1% 6% 6%

Source: Company, PhillipCapital India Research Estimates International Peers Name Mkt Cap P/BV RoE P/E Dividend Yield

(USD bn) FY17 FY17 FY17 FY17Power Grid Corp 12.3 1.6 16.4 10.5 3.0 RedesEnergeticasNacionais 1.7 1.4 10.0 12.9 6.1 Red Electrica Corporacionsa 11.7 3.6 22.6 15.8 4.5 Terna SPA 9.5 2.5 14.6 17.1 4.7


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Financials

Income Statement Y/E Mar, Rs mn FY14 FY15e FY16e FY17eNet sales 151,527 174,387 212,133 246,405Growth, % 19 15 22 16Total income 151,527 174,387 212,133 246,405Raw material expenses 0 0 0 0Employee expenses ‐9,417 ‐10,358 ‐11,912 ‐13,699Other Operating expenses ‐13,323 ‐13,589 ‐15,627 ‐17,972EBITDA (Core) 128,788 150,440 184,593 214,734Growth, % 18.3 16.8 22.7 16.3 Margin, % 85.0 86.3 87.0 87.1 Depreciation ‐39,957 ‐51,277 ‐62,244 ‐72,248EBIT 88,831 99,163 122,349 142,486Growth, % 17.9 11.6 23.4 16.5 Margin, % 58.6 56.9 57.7 57.8 Interest paid ‐31,675 ‐40,412 ‐47,628 ‐54,715Other Non‐Operating Income 5,687 6,055 6,060 6,789Pre‐tax profit 62,843 64,807 80,780 94,560Tax provided ‐17,663 ‐12,818 ‐15,991 ‐18,722Profit after tax 45,179 51,989 64,789 75,838Net Profit 45,179 51,989 64,789 75,838Growth, % 7.3 15.1 24.6 17.1 Net Profit (adjusted) 45,179 51,989 64,789 75,838 Unadj. shares (m) 5,232 5,232 5,232 5,232 Wtdavg shares (m) 5,232 5,232 5,232 5,232 Balance Sheet Y/E Mar, Rs mn FY14 FY15e FY16e FY17eCash & bank 44,175 40,398 75,437 88,952Debtors 15,785 19,111 23,247 27,003Inventory 7,124 9,555 12,786 16,202Loans & advances 50,250 64,499 78,460 91,136Other current assets 42,262 40,611 49,401 57,382Total current assets 159,596 174,175 239,332 280,675Investments 9,987 9,987 9,987 9,987Gross fixed assets 965,037 1,216,955 1,431,738 1,642,658Less: Depreciation ‐233,496 ‐284,773 ‐347,017 ‐419,265Add: Capital WIP 494,767 467,849 478,066 492,146Net fixed assets 1,226,308 1,400,031 1,562,787 1,715,538Total assets 1,395,891 1,584,192 1,812,105 2,006,200

Current liabilities 135,068 171,998 206,321 236,278Provisions 14,924 14,924 14,924 14,924Total current liabilities 149,992 186,922 221,245 251,202Non‐current liabilities 856,128 973,734 1,125,245 1,240,128Total liabilities 1,006,120 1,160,656 1,346,490 1,491,330Paid‐up capital 52,316 52,316 52,316 52,316Reserves & surplus 292,280 326,046 368,125 417,379Shareholders’ equity 389,771 423,536 465,615 514,870Total equity & liabilities 1,395,891 1,584,192 1,812,105 2,006,200 Source: Company, PhillipCapital India Research Estimates

Cash Flow Y/E Mar, Rs mn FY14 FY15e FY16e FY17ePre‐tax profit 62,843 64,807 80,780 94,560Depreciation 39,957 51,277 62,244 72,248Chg in working capital 45,275 18,575 4,205 2,129Total tax paid ‐12,825 ‐12,818 ‐15,991 ‐18,722Cash flow from operating activities 135,249 121,841 131,238 150,215Capital expenditure ‐304,022 ‐225,000 ‐225,000 ‐225,000Chg in investments 1,488 0 0 0Cash flow from investing activities ‐302,534 ‐225,000 ‐225,000 ‐225,000Free cash flow ‐167,285 ‐103,159 ‐93,762 ‐74,785Equity raised/(repaid) 6,019 0 0 0Debt raised/(repaid) 149,820 117,606 151,511 114,883Dividend (incl. tax) ‐15,765 ‐18,224 ‐22,710 ‐26,583Other financing activities 46,768 0 0 0Cash flow from financing activities 194,841 99,382 128,801 88,300Net chg in cash 27,556 ‐3,777 35,039 13,515 Valuation Ratios

FY14 FY15e FY16e FY17ePer Share data EPS (INR) 8.6 9.9 12.4 14.5 Growth, % (5.0) 15.1 24.6 17.1 Book NAV/share (INR) 65.9 72.3 80.4 89.8 FDEPS (INR) 8.6 9.9 12.4 14.5 CEPS (INR) 16.3 19.7 24.3 28.3 CFPS (INR) 24.8 22.1 23.9 27.4 Return ratios Return on assets (%) 5.2 5.2 5.6 5.8 Return on equity (%) 14.8 14.4 16.2 17.0 Return on capital employed (%) 5.8 5.8 6.3 6.5 Turnover ratios Asset turnover (x) 0.1 0.1 0.1 0.2Sales/Total assets (x) 0.1 0.1 0.1 0.1Sales/Net FA (x) 0.1 0.1 0.1 0.2Working capital/Sales (x) (0.1) (0.2) (0.2) (0.2)Receivable days 38.0 40.0 40.0 40.0Inventory days 17.2 20.0 22.0 24.0Payable days 361.3 360.0 355.0 350.0Working capital days (47.3) (80.0) (73.0) (66.0)Liquidity ratios Current ratio (x) 1.2 1.0 1.2 1.2Quick ratio (x) 1.1 1.0 1.1 1.1Interest cover (x) 2.8 2.5 2.6 2.6Total debt/Equity (%) 241.4 250.9 261.8 258.8Net debt/Equity (%) 228.5 240.2 243.9 239.9Valuation PER (x) ‐ 15.1 12.1 10.3 PEG (x) ‐ y‐o‐y growth (3.5) 1.0 0.5 0.6 Price/Book (x) 2.3 2.1 1.9 1.7 EV/Net sales (x) 10.4 9.7 8.5 7.8 EV/EBITDA (x) 12.2 11.3 9.8 8.9 EV/EBIT (x) 17.7 17.1 14.8 13.4



PTC India (PTC IN) Unlocking subsidiary value INDIA | UTILITIES | Initiating Coverage

28 April 2015

Investment Rationale We initiate coverage on PTC with BUY rating and a target price of Rs120.We expect increase in volume driven by commissioning of long term PPAs and a change in earning composition with significant profitability being driven by PFS will be key factors for re‐rating. We note PTC India remains good play on distribution reforms due to its significant volume exposure to discoms. • Strong volume growth: We expect PTC to report 12% CAGR in volumes driven by

commissioning of long term PPAs that would grow to 48 BUs by FY17E. On conservative basis, our volume growth does not factor in capacity expected to commission on captive coal blocks. We expect volume mix to be skewed towards long term as capacity with long term PPA’s are expected to commission during FY15‐17E. Improvement in discoms’ financial and introduction of reforms in distribution segment would further boost volumes of PTC.

• Stable margins: We expect core trading margins to range Rs4.2‐4.5/kwh during FY15‐17E. We note decline in prices in Southern India post grid integration would impact margins in erstwhile tolling project, however higher contribution from long term volumes will lend stability to margins.

• PFS – capitalizing on late mover advantage: Due to its late start, the exposure of PFS to

stressed assets is very low as compared to its peers. We expect PFS to report 28%CAGR in loan book during FY15‐17E. We note PFS has increased its exposure significantly to renewable sector and could be an important beneficiary of government thrust on renewable sector. We expect PFS to report 43% CAGR PAT lead by healthy NIMs.

• Earnings and Valuations: We expect PTC to report earnings CAGR of 12% led by higher contribution of long term volumes in core business, strong growth in subsidiary PFS driven by healthy loan book growth. We believe PTC remains key play on improvement in health of discoms and distribution reforms. PTC India trades at 6x FY17E and 0.6x P/B. We value PTC on SOTP to arrive at target price of Rs120. We initiate coverage with BUY rating on the stock.

• Key risks to our BUY call: : 1) Higher than expected working capital requirement in

business 2) Further deterioration of discoms’ financials 3) Delay in commissioning of capacities with long term PPA 4) Asset quality impairment in PFS.

BUY (Maintain) CMP RS 75 TARGET RS 120(+50%) COMPANY DATA O/S SHARES (MN) : 296MARKET CAP (RSBN) : 22MARKET CAP (USDBN) : 0.452 ‐ WK HI/LO (RS) : 105 / 65LIQUIDITY 3M (USDMN) : 3.1PAR VALUE (RS) : 10 SHARE HOLDING PATTERN, % PROMOTERS : 16.2FII / NRI : 26.4FI / MF : 36.6NON PROMOTER CORP. HOLDINGS : 7.7PUBLIC & OTHERS : 13.0 PRICE PERFORMANCE, %

1MTH 3MTH 1YRABS ‐2.4 ‐21.2 8.4REL TO BSE 0.1 ‐15.0 ‐11.7 PRICE VS. SENSEX



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PTC INDIA INITIATING COVERAGE

Strong Volume Growth Increase in proportion of long term volumes The short term volume market has witnessed CAGR of 26% during FY07‐14 and PTC has been one of the key beneficiaries of exponential growth in short term market. The overall short term market as percentage of generation has remained constant at 10‐11% of overall generation over past few years. Short Term Volume

Source: CERC PTC has reported 12% volume CAGR during FY04‐14 driven by higher proportion of trade through short term/bilateral contracts. We expect PTC to report 12% CAGR in volume driven by commissioning of long term PPA that would lead to 48 BU by FY17E. We do note that volume growth trajectory during FY13‐14 was impacted as exposure to weak discoms such as TN, UP lead to delay in recovery of dues. In our estimates for FY15‐17E we have not factored in PPA’s with plants that are expected to commission on captive coal blocks. In case, the auction of coal blocks is done speedily, volumes would further increase. Unit sold (including tolling)


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Strong volume growth driven by commissioning of long term PPA. Our volume growth assumption is lower than PTC’s target of 75 BU in FY17 due to delay in commissioning of tied up capacity.



Volume mix We note short term volumes constituted 61% of total volume in FY14 and we expect the contribution to decline to 40% in FY17. The contribution from cross border contracts with Nepal, Bhutan and Bangladesh will further boost volumes. Volume Break up

Source: Company, PhillipCapital India Research Estimates Key capacities expected to contribute to long term volumes Developer Capacity Capacity PPA with PTC)GMR Energy Kamalanga TPS 1050 323JPVL * Karcham Wangtoo HEP 1000 704Hinduja Power Vizag TPS 1040 585Teesta Urja Ltd Teesta Stage III HEP 1200 1056DB Power Baradarha TPS 1200 520Ideal Energy Ideal Energy 540 240Krishna Godavari Power Krishna Godavari Power 144 60ACB India TRN Energy 300 100ACB India Bandakhar TPS 200 250KVK Energy Nilachal TPS (Phase‐II) 700 350

*Earlier sold through short term We have not factored in volume contribution from capacities that are expected to commission on captive coal blocks. These constitute 1.5GW of PTC’s PPA. PPA based on captive mines Company Plant Block Location Plant Capacity (MW) PPA with PTC

Adhunik Power Adhunik TPS Ganeshpur Jharkhand 270 100Adhunik Power Adhunik TPS Ganeshpur Jharkhand 270 100Athena Power Singhitarai TPS Fatehpur/Fatehpur East Chattisgarh 1,200 750Monnet Power Malibrahmani TPS Mandakini Orissa 1,050 600

2,790 1,550

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Going forward, few factors that could contribute to volume growth: Open Access: Currently very few states have allowed open access and even those states that have introduced open access the discoms do not allow consumers seamless transition to open access platforms. We believe open access ` can be a significant volume contributor to PTC. Currently the contribution from open access is very negligible ~ 2BU for PTC. The introduction of competition in distribution segment through separation of “carriage” and “content “could open up significant opportunity for PTC India We do acknowledge the failure in implementation “Open access reforms” in Indian Power sector. However currently at a time when PLF’s across India are at all‐time low due to weak financials of discoms leading to demand suppression, implementation of open access is inevitable

Improvement in discoms financial: The financials’ of discoms have been impacted badly due to political intervention resulting in delayed tariff hike. Higher AT&C losses coupled with higher power purchase cost lead to SEB’s reporting Rs1060bn losses in FY13. We note government has taken few steps such as implementation FRP to improve health of discoms. Further discoms have also taken tariff hike over past few years that would improve financial position and purchasing power.

Tariff hikes Name of state FY12 FY13 FY14 FY15 FY16Andhra Pradesh 4 20 23 5Arunachal Pradesh 19 5 6 ‐ NAAssam ‐ 2 ‐ NABihar ‐ 12 7 ‐ 3Chandigarh ‐ 10 ‐ ‐ ‐Chhattisgarh 14 18 ‐ 21 12Delhi ‐ 21 5 8 NAGujarat 1.5‐3.5 2 6 ‐ 2Haryana 17 18 13 ‐ NAHimachal 10 13 13 ‐ ‐J&K 12 6 9 ‐ NAJharkhand 11 9 ‐ NAKarnataka 6 3 ‐ 10 5Kerala ‐ 30 8 16 NAMadhya Pradesh 11 7 1 ‐ 10Maharashtra 3 17 NAManipur 15 8 ‐ 8 5Mizoram 11 10 ‐ 2Orissa 20 12 2 ‐ 5Punjab 8 12 9 3 NARajasthan 19 10 ‐ NATamil Nadu 11 37 ‐ 15 NATripura 3 21 NAUP 14 9 8 20 NAUttarakhand 3 7 5 ‐ 7West Bengal 11 ‐ ‐ ‐ NA

Source: SERC



Core trading margins seems to have bottomed Intense competition impacted margins As per CERC’s (Fixation of Trading Margin) Regulations, 2010, trading licensees are allowed to charge trading margin up to Rs0.07/kWh in case the sale price >Rs3/kWh, and Rs0.04/kWh where the sale price is <Rs3/kWh. We note however due to intense competitions margins have come down in short term market. In FY14, margins for sale price <Rs 3/kwh was Rs 0.02/kwh and for sale price >Rs 3/kwh the trading margin was less Rs 0.04/kwh. In line with industry volumes, PTC India’s core trading margins were down from Rs 4.7/kwh to Rs 4.2/kwh. We expect higher contribution of long term volumes to add stability to margins Core Trading Margins

A) Tolling Business to boost consolidated margins PTC had entered into tolling arrangement under which it has tied up 350 MW of 600 MW Simhapur TPS (including expansion) and 150 MW of 300 MW Meenakshi TPS. In FY13, PTC altered its tolling arrangement and converted it into long term PPA under which margins was contingent on realization. Since most of this capacity is being sold in Southern market, PTC enjoys higher realizations and consequently higher margins. This arrangement also eliminated fuel risk that PTC was bearing under the earlier arrangement. In FY13, PTC earned EBITDA of Rs 0.8/kwh under tolling arrangement and we expect EBITDA margin of Rs 0.2/kwh during FY15‐17 as realization in Southern India would correct post grid integration. Tolling EBITDA (Rs/kwh)


3.83.6

4.74.4

3.9 4.1

4.8 4.7 4.6


0.80

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Integration of Southern grid will impact margins in erstwhile tolling project



Key Risks Weak Discoms Financials With significant distribution being undertaken through state discoms in most states, PTC’s volumes are driven by discoms’ purchase. Weak financials have significantly impaired purchasing power of discoms and consequently the volumes for PTC. In FY12 PTC did face risks of rising receivables due to delay in recovery of dues from TN and UP leading to higher working capital investments. As on Q315 receivables stood at Rs30bn. Receivables

Source: Company,PhillipCapital India Research Estimates Capital allocation decision We highlight Rs 6bn cash on books of PTC represents 22% of asset. PTC can either increase payout through higher cash or it can invest in business by paying suppliers before due date and earning rebate on power purchase. Further PTC also had intention of acquiring coal mines. We highlight such decision to be beyond core competency and increases business risks. State elections: Empirically state discoms have shown significant exuberance in short term market at time of elections thus providing opportunity to PTC. We note however PTC has been able to manage risks in recent state election as well as general elections and has kept its receivables under check. FY17 will most likely witness election in larger state UP that has historically been suffered from chronic power deficit and hence higher purchases in short term markets. Although based on past experience PTC has reduced its exposure to UP discoms, however this becomes key factor to monitor in near future. UP‐Short Term Purchase (MU)

Source: CERC

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Long term volumes to increase working capital requirement too: We expect working capital investment also to increase as contribution of volumes from long term PPA’s increase for PTC. Thus net working capital days would increase during FY15‐17E. We model Net working Capital days of 18‐20 days during FY15‐17E. Lead by recovery of dues, we expect working capital days to fall in FY15E and expect gradual rise led by increase in contribution of long term volumes. Long Term volumes


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PTC Financial Service (PFS)‐ Late mover advantage PTC Financial services (PFS) is 60% subsidiary of PTC India involved in total financial services to the entities in energy value chain, that includes investing in equity and/or extending debt to power projects in generation, transmission, distribution; fuel sources, fuel related infrastructure. PFS also has strategic investment in IEX and IPP’s such as East Coast Energy TPS, IndBharath Energy. a) Growth driven by loan book growth Although PFS was set up in 2006, it attained “Infrastructure Finance Company” status in FY10. We note delayed entry into lending business has helped PFS to some extent as although it missed infra lending boom during 2007‐11, however it also did not get exposure to risky assets in power sector like banks. We note due to lower base PFS had CAGR 100% in loan book during FY10‐14. As on Dec 2015, PFS had Rs59bn loan book with 38% loan book exposed to renewable and 30% to thermal assets. We model a 27% CAGR in loan book during FY15‐17.We note with new government focus on renewable space; the opportunity for growth is significant. Loan book

Source: Company, PhillipCapital India Research Estimates b) Healthy NIMS We note PFS has been able to maintain healthy NIM’s driven by competitive cost of funds and better yields. Thus NIM’s have gone up from 2.9% in FY11 to 7% in FY14. On back of loan book growth, healthy NIM’s and adjusted for sale of strategic divestments, PFS reported 76% CAGR in PAT during FY11‐14E.We expect 43% CAGR PAT during FY15‐17E led by healthy NIM’s and improvement in yields. NIMS


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Key investments by PFS Over past few years PFS has sold stake in projects where it had equity investment thus leading to value unlocking. In FY14, PFS divested its 16.7% stake in Meenaxi Energy, thus for Rs 2bn. In FY11, PFS divested 14% stake in IEX for Rs 7bn (16x its original investment). PFS investments Rs mnIEX 15.2700 MW Ind Bharat Utkal 10501320 MW East Coast Energy Pvt Ltd 1333.899 MW RS India Wind Energy 611.2Varam Bio 44 Total 3,054

PFS SOTP (FY17) Rs mnABV 19,090 ABV 19,090 Mutiple 1.7Core Business 32,452 Investments 4,254 IEX 5% stake at latest deal value 1,125 Total 37,832 Value 67

Asset Composition


Others24%

Hydro8%

Renewables38%

Thermal30%



Key drivers for a re ‐rating a) Change in business mix: We note for PTC, the overall profitability mix has shifted with significant profit being driven by PFS since FY11. Thus adjusted for one off pertaining to gain on sale of strategic investment, the overall contribution in consolidated PBT has gone up from 19% in FY11 to 33% in FY14. We note FY14 standalone PBT for PTC was also boosted by significantly higher surcharge income which may not be sustainable. Thus, led by strong growth in PFS we expect it to contribute to 69% of consolidated PBT by FY17E. PBT break up

Source: Company, PhillipCapital India Research Estimates b) RoE expansion to continue: We expect RoE expansion to continue lead by strong volume growth in standalone business, expansion of loan book in PFS and increasing spread.

RoE


PFS, 33

PTC‐Standalone,

63

PBT Break up‐FY14

PFS, 69

PTC‐Standalone,

29

PBT Break up‐FY17

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ROE



c) Strong earnings growth We expect PTC to report earnings CAGR of 11% led by higher contribution of long term volumes in core business, strong growth in subsidiary PFS driven by healthy loan book growth and healthy spread in lending business. We have not incorporated liquidation of strategic investments in our numbers. PAT growth

Source: Company, PhillipCapital India Research Estimates Outlook and Valuations: We expect PTC to report earnings CAGR of 9% led by higher contribution of long term volumes in core business, strong growth of subsidiary PFS driven by healthy loan book growth. We believe PTC becomes key play on improvement on improvement in health of discoms and distribution reforms. We value PTC on SOTP basis to arrive at target price of Rs120. Key risks involve: 1) Higher than expected working capital requirement in business 2) Further deterioration of discom financials 3) Delay in commissioning of capacities with long term PPA 4) Asset quality impairment in PFS.

SOTP based target price Rs mn FY17

Rs mn Rs/share Assumptions Trading Business 7,045 24 PE 6x to FY16E Core EPS PTC energy 174 1 PE 10x to FY16E Core EPS PFS 18,159 61 20% holding company discount to PFS SOTP Athena Energy Ventures ‐ ‐ At book value Teesta Urja 1,907 6 At 1x Krishna Godavari Power 376 1 At book value Cash 7,889 27 At book value Value of PTCIN 120


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Financials

Income Statement Y/E Mar, Rs mn FY14 FY15e FY16e FY17eNet sales 119,774 133,572 151,103 168,281Growth, % 31 12 13 11Total income 119,774 133,572 151,103 168,281Raw material expenses ‐110,014 ‐121,853 ‐137,742 ‐152,677Employee expenses ‐246 ‐186 ‐168 ‐186Other Operating expenses ‐1,475 ‐1,987 ‐2,014 ‐2,057EBITDA (Core) 8,039 9,546 11,179 13,360Growth, % (5.1) 18.7 17.1 19.5Margin, % 6.7 7.1 7.4 7.9Depreciation ‐85 ‐98 ‐94 ‐94EBIT 7,954 9,448 11,085 13,266Growth, % (5.2) 18.8 17.3 19.7Margin, % 6.6 7.1 7.3 7.9Interest paid ‐2,237 ‐4,219 ‐5,391 ‐6,310Pre‐tax profit 6,535 6,101 6,617 7,889Tax provided ‐1,921 ‐2,013 ‐2,184 ‐2,603Profit after tax 4,614 4,088 4,433 5,285Others (Minorities, Associates) ‐863 ‐898 ‐1,205 ‐1,509Net Profit 3,751 3,190 3,229 3,776Growth, % (40.4) (15.0) 1.2 17.0Net Profit (adjusted) 3,751 3,190 3,229 3,776Unadj. shares (m) 295 295 295 295Wtdavg shares (m) 295 295 295 295 Balance Sheet Y/E Mar, Rs mn FY14 FY15e FY16e FY17eCash & bank 6,168 13,639 9,699 11,887Debtors 20,923 16,541 19,422 21,492Loans & advances 49,713 64,662 80,828 98,610Other current assets 733 750 750 750Total current assets 77,536 95,593 110,698 132,739Investments 8,657 8,657 8,657 8,657Gross fixed assets 1,083 1,133 1,183 1,233Less: Depreciation ‐528 ‐627 ‐720 ‐814Net fixed assets 554 506 462 419Total assets 86,747 104,756 119,818 141,815

Current liabilities 11,849 11,420 13,026 12,780Provisions 1,331 1,000 1,000 1,000Total current liabilities 13,180 12,420 14,026 13,780Non‐current liabilities 39,137 54,659 64,659 82,659Total liabilities 52,317 67,079 78,685 96,439Paid‐up capital 2,960 2,960 2,960 2,960Reserves & surplus 26,129 28,528 30,829 33,612Shareholders’ equity 34,430 37,676 41,132 45,375Total equity & liabilities 86,747 104,756 119,818 141,815 Source: Company, PhillipCapital India Research Estimates

Cash Flow Y/E Mar, Rs mn FY14 FY15e FY16e FY17ePre‐tax profit 6,535 6,101 6,617 7,889Depreciation 85 98 94 94Chg in working capital ‐27,331 ‐11,345 ‐17,440 ‐20,098Total tax paid ‐1,836 ‐2,013 ‐2,184 ‐2,603Cash flow from operating activities ‐22,547 ‐7,160 ‐12,913 ‐14,719Capital expenditure ‐94 ‐50 ‐50 ‐50Chg in investments 1,164 0 0 0Cash flow from investing activities 1,070 ‐50 ‐50 ‐50Free cash flow ‐21,476 ‐7,210 ‐12,963 ‐14,769Debt raised/(repaid) 23,083 15,523 10,000 18,000Cash flow from financing activities 22,691 15,473 9,950 17,950Net chg in cash 1,215 8,263 ‐3,013 3,181 Valuation Ratios

FY14 FY15e FY16e FY17ePer Share data EPS (INR) 12.7 10.8 10.9 12.8 Growth, % (40.4) (15.0) 1.2 17.0 Book NAV/share (INR) 98.6 106.7 114.5 124.0 FDEPS (INR) 12.7 10.8 10.9 12.8 CEPS (INR) 13.0 11.1 11.3 13.1 CFPS (INR) (79.2) (27.2) (46.9) (53.1)Return ratios Return on assets (%) 8.3 7.1 7.0 7.1 Return on equity (%) 12.9 10.1 9.6 10.3 Return on capital employed (%) 9.9 8.1 7.9 7.9 Turnover ratios Asset turnover (x) 2.6 2.0 1.9 1.7 Sales/Total assets (x) 1.7 1.4 1.3 1.3 Sales/Net FA (x) 217.7 252.0 312.1 382.0 Working capital/Sales (x) 0.5 0.5 0.6 0.6 Receivable days 63.8 45.2 46.9 46.6 Payable days 35.6 30.1 30.1 26.1 Working capital days 181.4 192.7 212.5 234.4 Liquidity ratios Current ratio (x) 6.5 8.4 8.5 10.4 Quick ratio (x) 6.5 8.4 8.5 10.4 Interest cover (x) 3.6 2.2 2.1 2.1 Total debt/Equity (%) 133.9 173.0 190.8 225.5 Net debt/Equity (%) 112.7 129.7 162.1 193.0 Valuation PER (x) 6.7 7.9 7.8 6.6 PEG (x) ‐ y‐o‐y growth (0.2) (0.5) 6.3 0.4 Price/Book (x) 0.9 0.8 0.7 0.7 EV/Net sales (x) 0.5 0.5 0.5 0.6 EV/EBITDA (x) 7.2 6.9 7.1 7.2 EV/EBIT (x) 7.3 7.0 7.2 7.2



Contact Information (Regional Member Companies)

SINGAPORE Phillip Securities Pte Ltd

250 North Bridge Road, #06‐00 RafflesCityTower, Singapore 179101

Tel : (65) 6533 6001 Fax: (65) 6535 3834 www.phillip.com.sg

MALAYSIA Phillip Capital Management Sdn Bhd B‐3‐6 Block B Level 3, Megan Avenue II,

No. 12, Jalan Yap Kwan Seng, 50450 Kuala Lumpur Tel (60) 3 2162 8841 Fax (60) 3 2166 5099

www.poems.com.my

HONG KONG Phillip Securities (HK) Ltd

11/F United Centre 95 Queensway Hong Kong Tel (852) 2277 6600 Fax: (852) 2868 5307

www.phillip.com.hk

JAPAN Phillip Securities Japan, Ltd

4‐2 Nihonbashi Kabutocho, Chuo‐ku Tokyo 103‐0026

Tel: (81) 3 3666 2101 Fax: (81) 3 3664 0141 www.phillip.co.jp

INDONESIA PT Phillip Securities Indonesia

ANZTower Level 23B, Jl Jend Sudirman Kav 33A, Jakarta 10220, Indonesia

Tel (62) 21 5790 0800 Fax: (62) 21 5790 0809 www.phillip.co.id

CHINA Phillip Financial Advisory (Shanghai) Co. Ltd.

No 550 Yan An East Road, OceanTower Unit 2318 Shanghai 200 001

Tel (86) 21 5169 9200 Fax: (86) 21 6351 2940 www.phillip.com.cn

THAILAND Phillip Securities (Thailand) Public Co. Ltd.

15th Floor, VorawatBuilding, 849 Silom Road, Silom, Bangrak, Bangkok 10500 Thailand

Tel (66) 2 2268 0999 Fax: (66) 2 2268 0921 www.phillip.co.th

FRANCE King & Shaxson Capital Ltd.

3rd Floor, 35 Rue de la Bienfaisance 75008 Paris France

Tel (33) 1 4563 3100 Fax : (33) 1 4563 6017 www.kingandshaxson.com

UNITED KINGDOM King & Shaxson Ltd.

6th Floor, Candlewick House, 120 Cannon Street London, EC4N 6AS

Tel (44) 20 7929 5300 Fax: (44) 20 7283 6835 www.kingandshaxson.com

UNITED STATES Phillip Futures Inc.

141 W Jackson Blvd Ste 3050 The Chicago Board of TradeBuilding

Chicago, IL 60604 USA Tel (1) 312 356 9000 Fax: (1) 312 356 9005

AUSTRALIA PhillipCapital Australia

Level 37, 530 Collins Street Melbourne, Victoria 3000, Australia

Tel: (61) 3 9629 8380 Fax: (61) 3 9614 8309 www.phillipcapital.com.au

SRI LANKA Asha Phillip Securities Limited

Level 4, Millennium House, 46/58 Navam Mawatha, Colombo 2, Sri Lanka

Tel: (94) 11 2429 100 Fax: (94) 11 2429 199 www.ashaphillip.net/home.htm

INDIA PhillipCapital (India) Private Limited

No. 1, 18th Floor, Urmi Estate, 95 Ganpatrao Kadam Marg, Lower Parel West, Mumbai 400013 Tel: (9122) 2300 2999 Fax: (9122) 6667 9955 www.phillipcapital.in

Management (91 22) 2300 2999

Kinshuk Bharti Tiwari (Head – Institutional Equity) (91 22) 6667 9946(91 22) 6667 9735

Research Economics Retail, Real Estate

Dhawal Doshi (9122) 6667 9769 Anjali Verma (9122) 6667 9969 Abhishek Ranganathan, CFA (9122) 6667 9952Priya Ranjan (9122) 6667 9965 Rohit Shroff (9122) 6667 9756

Infrastructure & IT ServicesVibhor Singhal (9122) 6667 9949 Portfolio Strategy

Manish Agarwalla (9122) 6667 9962 Deepan Kapadia (9122) 6667 9992 Anindya Bhowmik (9122) 6667 9764Pradeep Agrawal (9122) 6667 9953Paresh Jain (9122) 6667 9948 Logistics, Transportation & Midcap Technicals

Vikram Suryavanshi (9122) 6667 9951 Subodh Gupta, CMT (9122) 6667 9762Consumer, Media, TelecomNaveen Kulkarni, CFA, FRM (9122) 6667 9947 Metals Production ManagerJubil Jain (9122) 6667 9766 Dhawal Doshi (9122) 6667 9769 Ganesh Deorukhkar (9122) 6667 9966Manoj Behera (9122) 6667 9973 Ankit Gor (9122) 6667 9987

Database ManagerCement Oil&Gas, Agri Inputs Deepak Agarwal (9122) 6667 9944Vaibhav Agarwal (9122) 6667 9967 Gauri Anand (9122) 6667 9943

Deepak Pareek (9122) 6667 9950 Sr. Manager – Equities SupportEngineering, Capital Goods Rosie Ferns (9122) 6667 9971Ankur Sharma (9122) 6667 9759 PharmaHrishikesh Bhagat (9122) 6667 9986 Surya Patra (9122) 6667 9768

Mehul Sheth (9122) 6667 9996

Sales & Distribution Ashvin Patil (9122) 6667 9991 Sales Trader Zarine Damania (9122) 6667 9976Shubhangi Agrawal (9122) 6667 9964 Dilesh Doshi (9122) 6667 9747 Kishor Binwal (9122) 6667 9989 Suniil Pandit (9122) 6667 9745Sidharth Agrawal (9122) 6667 9934 ExecutionBhavin Shah (9122) 6667 9974 Mayur Shah (9122) 6667 9945

Corporate Communications

Vineet Bhatnagar (Managing Director)

Jignesh Shah (Head – Equity Derivatives)

Automobiles

Banking, NBFCs



Disclosures and Disclaimers PhillipCapital (India) Pvt. Ltd. has three independent equity research groups: Institutional Equities, Institutional Equity Derivatives and Private Client Group. This report has been prepared by Institutional Equities Group. The views and opinions expressed in this document may or may not match or may be contrary at times with the views, estimates, rating, target price of the other equity research groups of PhillipCapital (India) Pvt. Ltd. This report is issued by PhillipCapital (India) Pvt. Ltd. which is regulated by SEBI. PhillipCapital (India) Pvt. Ltd. is a subsidiary of Phillip (Mauritius) Pvt. Ltd. References to "PCIPL" in this report shall mean PhillipCapital (India) Pvt. Ltd unless otherwise stated. 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The research analyst(s) preparing the research report is/are resident outside the United States (U.S.) and are not associated persons of any U.S. regulated broker‐dealer and therefore the analyst(s) is/are not subject to supervision by a U.S. broker‐dealer, and is/are not required to satisfy the regulatory licensing requirements of FINRA or required to otherwise comply with U.S. rules or regulations regarding, among other things, communications with a subject company, public appearances and trading securities held by a research analyst account. This report is intended for distribution by PhillipCapital (India) Pvt Ltd. only to "Major Institutional Investors" as defined by Rule 15a‐6(b)(4) of the U.S. Securities andExchange Act, 1934 (the Exchange Act) and interpretations thereof by U.S. Securities and Exchange Commission (SEC) in reliance on Rule 15a 6(a)(2). If the recipient of this report is not a Major Institutional Investor as specified above, then it should not act upon this report and return the same to the sender. Further, this report may not be copied, duplicated and/or transmitted onward to any U.S. person, which is not the Major Institutional Investor. In reliance on the exemption from registration provided by Rule 15a‐6 of the Exchange Act and interpretations thereof by the SEC in order to conduct certain business with Major Institutional Investors, PhillipCapital (India) Pvt Ltd. has entered into an agreement with a U.S. registered broker‐dealer, Marco Polo Securities Inc. ("Marco Polo").Transactions in securities discussed in this research report should be effected through Marco Polo or another U.S. registered broker dealer. PhillipCapital (India) Pvt. Ltd. Registered office:No. 1, 18th Floor, Urmi Estate,95 GanpatraoKadamMarg,Lower Parel West, Mumbai 400013

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