CESC_20110701

July 1, 2011

Power Sector

POWER SECTOR July 1, 2011

Fuel Security is the Theme

– Key Differentiator & Determinant of Profitability –

Our Top Picks are: “CESC, NTPC & Tata Power”

Why do we like the power sector? The BSE Power Index has underperformed by 23.3% to Sensex over past 12 months due to near-term concerns i.e. unavailability of coal, lower merchant rates and deteriorating financial condition of State Electricity Boards (SEBs). This underperformance offers an opportunity amid historically low valuation, assured returns in regulated business model, likely tariff hike by the distribution companies (DISCOMs), coal asset acquisitions, and allocation of coal blocks, which we believe would improve the sector al outlook and the performance of the stocks. Again, the Power Index is trading at 2.07x at 33% discount to its last three years average mean of 3.1x, which provides the margin of safety. We also see a strong demand with restricted supply (demand-supply gap to remain till FY15E), commissioning of 1.1 lakh MW capacity (up 60%) over FY10-15E. Power Deficit to Persist till FY15E despite Rise in Supply With ~110,000MW of generation capacity estimated to be added over FY10-15E, the power deficit would reduce from 10.1% in FY10 to 3.3% in FY15E. While, the power supply is likely to rise at a CAGR of 10.2%, the demand is expected to rise at 8% CAGR. “Fuel Security” is the Theme: Coal Deficit to Continue Over FY10-15E, while the coal demand is likely to rise at CAGR of 10.2%, the output is set to rise at CAGR of 7.2%. Thus the deficit is likely to result in rise in India's coal imports from 35 mn metric tonne (MMT) in FY10 to 134 MMT in FY15E. Merchant Rates at Rs. 3.5/unit levels to yield ~22% RoEs in FY13E The merchant power rates in India have gone up from Rs. 3 per unit in FY06 to Rs. 6 in FY10 due to increased power deficit. However, with new capacities coming up, the merchant rates settling at levels of Rs. 3.5 per unit in FY13E – marking a decline of 40% over FY10-13E – would yield RoEs of ~22%. Differentiating Parameters over the Near -term In our view the best players have huge capacity addition in the near-term providing revenue visibility, execution capability and fuel security. With rising coal deficit, we expect RoE of merchant-based capacities to level down to sustainable levels of 22% from 35-40% current level. We prefer utilities with I. Assured RoEs of regulated business model vs. merchant business model (due to high coal price and lower merchant realization), II. Fuel Linkages, III. Strong Balance Sheet & Execution Track Record, and IV. Low Valuation & Low-risk business models. We initiate coverage with “BUY” recommendation on CESC (Fuel Security, Attractive Valuation), NTPC (Fuel Security, Assured RoE) & Tata Power (Fuel Security, Strong Portfolio). We initiate coverage on Adani Power (Fundamentally Priced-in) & JSW Energy (High Dependence on Imported Coal, Exposure to Merchant Biz) with “HOLD”recommendation.

Theme Report

Exhibit 1: Valuation Summary

Company Rating CMP (Rs) TP

(Rs) MCap (Rs

bn) Core RoE (%) * P/BV (x) P/E (x)

FY11 FY12E FY13E FY11 FY12E FY13E FY11 FY12E FY13E Adani Power Hold 110 117 239 19.2 44.8 28.1 3.8 2.8 2.2 46.7 10.0 9.6 CESC Buy 299 381 37 7.1 8.1 11.5 1.0 0.8 0.7 12.6 9.6 7.1 JSW Energy Hold 67 75 109 20.5 20.9 19.6 1.9 1.6 1.4 13.1 9.1 10.8 NTPC Buy 187 218 1541 19.5 20.9 20.4 2.3 2.1 1.8 18.3 16.0 13.8 Tata Power Buy 1308 1503 310 17.4 19.4 19.8 2.2 1.9 1.6 15.1 12.0 10.6 Source: Karvy Institutional Research, * Core RoE is based on operational assets and adjusted for CWIP

Analyst Contact Rupesh Sankhe +91-22-22895022 rupesh.sankhe@karvy.com

Adani Power Hold CMP 110 Target Price 117 Upside 6% MCap (Rsbn/US$mn) 239/5342 52 Week High/Low (Rs) 145/105 Avg. Daily Volume ('000) 735 Bloomberg Code ADANI IN

CESC Buy CMP 299 Target Price 381 Upside 27% MCap (Rsbn/US$mn) 37/831 52 Week High/Low (Rs) 433/252 Avg. Daily Volume ('000) 114 Bloomberg Code CESC IN

JSW Energy Hold CMP 67 Target Price 75 Upside 12% MCap (Rsbn/US$mn) 109/2443 52 Week High/Low (Rs) 136/64 Avg. Daily Volume ('000) 1,329 Bloomberg Code JSW IN

NTPC Buy CMP 187 Target Price 219 Upside 17% MCap (Rsbn/US$mn) 1541/34348 52 Week High/Low (Rs) 222/165 Avg. Daily Volume ('000) 2,432 Bloomberg Code NTPC IN

Tata Power Buy CMP 1,308 Target Price 1,503 Upside 15% MCap (Rsbn/US$mn) 310/6919 52 Week High/Low (Rs) 1468/1132 Avg. Daily Volume ('000) 249 Bloomberg Code TPWR IN

July 1, 2011

Power Sector

Table of Contents Industry Page No. Demand-supply gap to reduce, but power deficit to continue till FY15 3-6

• Power demand to increase in line with economic growth

• Low per capita consumption of power indicates high growth potential

• Power supply to increase substantially led by private sector

• Capacity addition dogged by numerous execution challenges

• Power deficit to reduce

Fuel security - Key Determinant of Profitability 7-12

• Coal deficit in power sector to continue

• Domestic coal shortage to see surge in imports

• Inadequate infrastructure a constraint for coal imports

• Private power generators acquire coal mines abroad

• Fuel Security-key to profitability

• CESC, NTPC and Tata Power best placed in terms of fuel security

Merchant Power settling at levels of Rs. 3.5/unit in FY13 yields RoEs of ~22% 13-17

• Players with capacities coming up in near term, to benefit from high merchant rates

• Poor financial position of SEB's a major concern for merchant power generators

Valuation Methodologies-FCFE Model 20

Companies Covered • Adani Power 31-45

• CESC 46-60

• JSW Energy 61-75

• NTPC 76-88

• Tata Power 89-109

July 1, 2011

Power Sector

Demand-Supply Gap to Narrow Down by FY15E Our View: While the long-term fundamentals remain intact; the power deficit would persist till FY15E, despite narrowing of demand-supply chasm Power Demand Power demand to increase in line with economic growth The elasticity of electricity demand to GDP growth has been declining from the 7th Plan and hit a low of 0.7x in the 10th Plan due to increased share of the service sector in GDP. However, we expect elasticity of electricity to rise from 0.7x in the 10th Plan to 1.0x going ahead due to higher share of industrial and infrastructure sectors in GDP. The demand for power is largely understated in India, as reflected in load shedding & peak deficit. In our opinion, rural electrification programme, higher outlay in manufacturing and infrastructure would drive the demand further.

Exhibit 2: Electricity Consumption Pattern

Source: Industry, Karvy Institutional Research

Exhibit 3: Electricity demand vs. GDP growth

Source: Industry, Karvy Institutional Research Low per capita power consumption shows high growth potential India's per capita power consumption of 704 units per annum is miniscule compared to the power consumption of many developed countries that indicates the high growth potential of the sector. The National Electricity Policy envisages a rise in per capita consumption of power to 1,000 units by 2012, with rising affluence and shift from traditional forms of energy. The expansion of the manufacturing sector in India would boost overall power demand.

Substantial investments to bolster T&D segment In order to increase the per capita power consumption, the Government has scaled up investment in the T&D segment. As per the Power Ministry, the earmarked investment for 11th & 12th Plan period is Rs. 1,400 bn & Rs. 2,400 bn, respectively with a view to improving the power availability.

Exhibit 5: Significant investments in the Power T&D (Rs. bn)

22 2220 1711 10

FY10 FY14EIndustrial Domestic Agriculture Commercial & Others

6th Plan 7th Plan 8th Plan 9th Plan 10th Plan 11th Plan 12th Plan

Transmisision Distribution R&M

11th Plan Est 12th Plan Est

Exhibit 4: India's Per Capita Power Consumption

Source Industry: Karvy Institutional Research

FY2005 FY2006 FY2007 FY2008 FY2012E

(kwh) (Govt. Target)

July 1, 2011

Power Sector

Execution has improved in the 11th Plan There has been slippage in power capacity addition target in the last three Five-Year Plans. The situation has improved in the current plan (FY07-12), and we expect ~62% (vs. 51.5% in 10th Plan) of planned capacity to be achieved in the plan period. The total capacity addition during the current plan period is estimated at 49,000MW. We expect fundamental execution issues related to land acquisition, obtaining various clearances and fuel security to persist and expect substantial spill-over from the 11 th Plan to be completed in FY13E and FY14E.

Exhibit 6: Capacity addition as Percentage of Target

10,000

20,000

30,000

40,000

50,000

7th Plan 8th Plan 9th Plan 10th Plan 11th Plan (E)

Capacity added As a % of Target

(MW) (%)

July 1, 2011

Power Sector

Power Supply Private Sector to Augment Power Supply Currently, the central and state utilities have a dominant share in the country’s overall generation capacity. Going ahead, we see a paradigm shift in the participation of the private sector players in power generation. The fillip has originated from the Electricity Act 2003 and National Tariff Policy 2006. The private sector, which contributed a mere 11% to installed capacity in FY10, is expected to account for ~55% of the total capacity addition planned over FY10-15E. Private sector participation has been increasing on attractive returns, increased flexibility and availability of funding options and high merchant power rates that has been the catalyst. Installed capacity is set to increase from 159, 398MW in FY10 to 270,929MW in FY15E.

Exhibit 7: Power Capacity Addition (FY10-15E) – (MW) FY10 FY11E FY12E FY13E FY014E FY15E Central Sector

DVC 3,544 1,000 2,600 550 550 - Neyveli 2,490 750 - 1,000 - NHPC 5,175 812 1,430 2,050 - - NTPC 31,494 1,490 2,500 4,280 5,350 3,980 Nuclear Power Corporation 4,340 600 1,000 600

Satluj 1,500 412 Others 5,410 Total - Central sector 53,953 4,652 7,530 7,480 7,312 5,380 State Sector 73,984 6,413 3,723 3,500 3,500 3,500 Private Sector Adani Power 660 660 2,640 1,980 Adhunik - - - - 540 - Avantha 191 - - 1,200 - CESC 1,200 - - 1,200 1,200 1,600 China Light & Power (CLP) - - - - 1,320 - Essar Power 515 - - - -

GMR 823 768 2,000 1,370 1,670 GVK 900 - 330 540 - 370 Indiabulls - - - - 1,350 1,350 JP Power Ventures 700 - 1,500 - 660 660 JSPL 1,000 - - 1,920 1,520 1,620 JSW Energy 995 945 1,200 - 270 1,500 KSK Energy 144 718 - 730 1,500 1,500 Konaseema 280 - - - - - Lanco Infratech 1,321 1,500 700 720 1,312 Reliance Infra 940 Reliance Power 300 300 1,260 2,640 730 730 Sterlite Energy - 600 600 - 660 1,320 Tata Power 3,104 613 1,325 1,200 2,000 - Torrent Power 1,647 - - 1,000 1,000 Others 16,741 - - - - - Total – Private Sector 31,461 5,336 10,323 12,210 16,040 14,632 Total Addition 1,59,398 16,401 21,576 23,190 26,852 23,512 Total capacity 1,59,398 175,799 1,97,375 2,20,565 2,47,417 2,70,929 Source: CEA, Karvy Institutional Research

Bottleneck in Equipment supply eases : Point to excess capacity in relation to power capacity We believe aggressive power equipment capacity by BHEL (20GW) and the new private players such as L&T (4GW) will create excess capacity to handle the requirements of power sector. Chinese & Korean companies have also entered Indian power equipment market to tap huge opportunities in the segment. During the 10 th Plan, India has achieved only 50% planned capacity, as the shortage of equipment capacity was the major reason. By FY14E, we expect Indian BTG capacity to be at 41,000MW per annum against requirements of 26,000MW.

July 1, 2011

Power Sector

Exhibit 8: Equipment Capacity Expansion Plans (In MW) Companies Global Players Boilers Turbines Likely to be commissioned Existing Capacity Total Capacity

BHEL NA 5,000 5,000 FY13 15,000 20,000 L&T Mitsubishi 4,000 4,000 FY11-12 - 4,000 JSW Toshiba - 3,000 FY12-13 - 3,000

Bharat Forge Alstom - 5,000 FY12-14 - 5,000 Gammon Ansaldo - 2,000 - - 2,000 Thermax Babcock 3,000 - - - 3,000

BGR Hitachi 4,000 4,000 FY12-13 - 4,000 Source: Industry, Karvy Institutional Research

Also, we do not expect any constraints from generation (EPC) contracts and transmission business as many players have entered in these business.

Exhibit 9: Constraints from Generation No constraint Moderate High Generation - - BTG ü - - EPC ü - - Ash handling ü - - Coal Handling ü - - Cooling towers ü - - Chimany ü - - Dimeneralised plant ü - - Fuel oil system - ü - Transmission - - Substation ü - - Transmission lines ü - - Source: Karvy Institutional Research

Expect the power deficit to narrow by FY15E We estimate ~110,000MW of generation capacity to be added over FY10-15E and this would reflect in higher power supply that would increase at a CAGR of 10.2% exceeding demand by a CAGR of 8% during the mentioned period. However, the power deficit would reduce from 10.1% in FY10 to 3.3% in FY15E.

Exhibit 10: India Power Deficit Particulars FY10 FY11E FY14E FY15E Total capacity (MW) 159,398 175,799 247,417 270,929 Effective capacity (MW) 117,955 130,091 173,192 189,650 Eff. cap/Total cap 0.74 0.74 0.7 0.7 PLF (%) 75 75 75 75 Total generation (bn units) 775 855 1,138 1,246 Growth (%) 10 12 10 Total availability (bn units) 746 812 1,081 1,184 Total demand (bn units) 830 897 1,133 1,224 GDP Growth (%) 8.0 8.5 8.5 8.5 Power Demand Elasticity to GDP growth 0.9 0.95 0.95 0.95 Electricity demand growth (%) 7.2 8.1 8.1 8.1 Deficit (bn units) 84 85 52 41 Deficit (%) 10.1 9.5 4.6 3.3 Source: Karvy Institutional Research

July 1, 2011

Power Sector

Fuel Security – A Concern & Key Determinant of Profitability Our views on key issues

I. Coal deficit to continue II. Too much environmental concerns and regulatory approvals

resulting in project delays III. Coal Linkages is the key: Most private firms acquire overseas

mines to meet the shortfall IV. Coal Imports to Surge due to Domestic Coal Shortage V. Coal Imports: Inadequate infrastructure a constraint VI. Cost Pressure Significant – Leeway for hike in domestic coal

prices VII. Alternate fuels: gas-based power firms face availability, infra

bottlenecks VIII. RoE Sensitivity to Coal Prices & Tariffs – Levelling of Tariffs

I. As most upcoming capacities are coal-based, coal deficit in power sector would continue Presently, coal-based plants account for ~60% of India's power generation capacity. This scenario is expected to continue given a major portion of the upcoming capacity is also based on coal. According to our estimates, the power sector would require additional coal supply of ~446MT over the next five years at a 10.2% CAGR, while the coal production is expected to increase by 7.2% CAGR over the next five years.

Exhibit 11: Power sector – Demand & Supply for Coal (MTPA) (FY10-15)

Particulars FY10 FY11E FY12E FY13E FY14E FY15E Demand 401 437 481 529 587 652 Growth - 9 10 10 11 11 Domestic supply 366 384 413 445 480 518 Growth - 5 8 8 8 8 To be imported 35 53 68 84 107 134 Imports (%) - 12 14 16 18 21

Source: CEA, Karvy Institutional Research

Note: The actual quantity of coal imported would be lower adjusted for the difference in calorific value.

July 1, 2011

Power Sector

II. Ongoing environmental concerns - “Go” & “No-go” zones In a recent move, the MoEF has classified coal fields under two categories i.e. “go” zones and “no-go” zones. A “no-go” zone refers to the coal mines situated in densely forested areas, where mining operations are strictly prohibited. On the other hand, if a coal field is situated in a “go” zone, the Ministry considers mining proposals for approval or rejection based on their suitability. However, the projects in the “go” zones also have to go through the environmental and forest clearance process before getting the approval. The MoEF has classified 203 coal blocks measuring 3.5 lakh hectares under the “no-go” zone.

Too much regulatory approvals required The Indian coal industry is a highly regulated industry, which gives it a monopolistic character. Currently, only government-controlled companies are allowed to sell coal in open market. As part of the coal reforms, the Indian Government has allocated 201 coal blocks to public and private companies for captive use since 2003, but only 25 of them are operational. Further, the output has been very low, as most of these captive blocks have recently started operations due to delays on the procedural front; and problems related to mining approvals, land acquisition and rehabilitation issues.

III. Coal Linkages is the Key: Most private power producers hunt for overseas coal assets to meet the shortfall The major private power generating companies of India such as Tata Power, Reliance Power and JSW Energy have acquired coal mines abroad to meet their fuel requirements. Tata Power has acquired 30% stake in the coal mines of Bumi Resources, which will provide 12.3 MTPA of coal for its Mundra project. Through its acquisition of SACMH, JSW Energy was also looking for acquisition of CIC Energy, which was however could not be materialized. CESC has picked up a 4.8% stake in an Australia-listed mining company i.e. Resource Generation for $10 mn.

NTPC plans to set up a new entity for acquiring coal assets abroad to secure fuel supplies for its coal-based plants.

Exhibit 14: Acquisition of Coal Mines by Indian Power Companies Company Location of Mine Description Year GMR Energy Indonesia 100% stake in Trinity Coal 2009 Adani Power Indonesia Adani Enterprise acquired stake in mine and tie -up 2008 GMR Infra South Africa Stake in Homeland Energy 2008 Reliance Power Indonesia 100% stake in 3 mines 2008 Tata Power Indonesia 30% stake in 2 mines of Bumi Resources 2007 JSW Energy South Africa Acquisition of 100% stake in SACMH 2010 Source: Karvy Institutional Research

Exhibit 12 : Of the 201 captive blocks allotted, only 25 are operational

Year Power Iron &

Steel Others

Total blocks

allotted Produc-

tion 1993 1 - - 1 - 1994 1 - - 1 - 1995 1 - - 1 - 1996 1 3 2 6 - 1997 - - - 0 2 1998 4 - - 4 1 1999 - 2 - 2 - 2000 - 1 - 1 - 2001 1 1 - 2 - 2002 1 - - 1 1 2003 11 7 3 21 1 2004 4 - 1 5 3 2005 7 16 1 24 1 2006 21 14 18 53 2 2007 25 7 20 52 4 2008 10 10 4 24 10 2009 1 - 2 3 - Total blocks

89 61 51 201 25

Exhibit 13: Thermal coal imports (mtpa)

Source: Karvy Institutional Research

107134

FY10 FY11E FY12E FY13E FY14E FY15E

CAGR 31.6%

July 1, 2011

Power Sector

IV. Coal Imports to Surge due to Domestic Coal Shortage – Coal Demand to grow at a CAGR 10.2% over FY10-15E, against a production estimate of a CAGR of 7.2% over the same period A major portion of domestic coal is sold at notified prices (not market driven) and is available at high discount to imported coal even after adjusting for the difference in quality. However, the coal-based power plants face the problem of inadequate domestic coal supply owing to delays in procurement of coal linkages, obtaining environment clearances and other regulatory approvals for conducting mining operations (both Coal India and captive coal blocks), hurdles in expansion and logistical and infrastructural issues.

In FY10, the domestic coal supply fell short of demand by 35 MT. We expect the coal shortage to become acute going ahead, with demand set to outpace supply. Coal demand, which increased at a CAGR of 8% over FY03-09, is expected to spike and record a CAGR of 10.2% over FY10-15E. On the other hand, the domestic coal production is expected to rise at a CAGR of 7.2% during the mentioned period leading to higher deficit.

Against this background, we estimate India's coal imports to grow from 35 MMT in FY10 to 134 MMT in FY15E, registering a CAGR of 31.6%. New Castle Coal Index has gone up from $24 per tonne in FY03 to $192 per tonne in FY08. Hence, we believe that the coal-based power generators with secure coal access (by way of long-term import contracts or captive coal mines abroad) are better placed than the rest. Indonesia and South Africa together account for more than 95% of India's thermal coal imports due to the locational advantages. Indonesia accounts for lion's share of India’s coal imports at 80%.

Exhibit 16: Forecast for Coal Demand & Production (MTPA) FY10 FY11 FY12E FY13E FY14E FY15E

Coal Demand 534 579 634 693 764 842 Growth (%) 8 9 9 10 10 Power 401 437 481 529 587 652 Growth (%) 9 10 10 11 11 Based on domestic coal 366 384 413 445 480 518 Based on imported coal 35 53 68 84 107 134 Cement 30 32 35 38 42 46 Growth (%) 7 9 9 11 10 Other Industries 103 110 118 126 135 144 Growth (%) 7 7 7 7 7 Domestic Coal Production 534 579 634 693 764 842 Growth (%) Available for power 366 384 413 445 480 518 Growth (%) 5 8 8 8 8 Available for Cement & others 98 101 105 110 114 119 Growth (%) 4 4 4 4 4 Shortage Power 35 53 68 84 107 134 Other Industries 35 41 47 54 63 72

Exhibit 17: Imports Requirement Sensitivity Coal Production growth (%)

4 5 6 7 8Imports (FY12E) 81 76 72 68 63 Coal Production growth (%) 4 5 6 7 8Imports (FY13E) 82 78 73 68 64

Exhibit 15: International Coal Price Trends (US$/Tonne)

100150200250

Mccloskey New Castle Coal

July 1, 2011

Power Sector

Our View: Coal imports will not resolve the problem of domestic coal shortage, as we foresee a lot of challenges. The problem is compounded by the country's inability to handle imported / domestic assets, as the actual capacity additions are expected to be lower for handling incremental coal imports of 446MT. At the same time, the coal import is also fraught with policy risks. We believe that a steep rise in coal imports will put pressure on India’s port handling capacity and the associated inland rail / road transportation. V. Key Issues for Coal Imports: Poor Infrastructure a Major Constraint Port Capacity: We estimate India's coal imports to grow from 35 MMT in FY10 to 134 MMT in FY15, registering a CAGR of 31.6%. The coal handling capacity of major ports is 47 MTPA, with a total capacity addition of 67 MTPA, which will take total port capacity to 114 MTPA. Indian ports just have adequate capacity to handle existing level of coal imports. The issue has also been flagged in the mid-term appraisal of the 11th Plan, as per which by the end of the current Plan, the imported coal will account for 11.7% of the estimated demand, as against 7% projected earlier. This will rise further to over 20% by the terminal year of 12th Plan (2012-17). Despite this visible demand, the investments in the ports sector have been low, projected at Rs. 406.47 bn during the 11th Plan, which is less than half of the original target of Rs. 879.95 bn.

Rail network: In FY10, 46.3% of the coal was transported through railways and the balance mainly through roads (28.7%) and Merry Go-round Systems (MGR) (19%). The expected demand of around 681 MTPA in FY15E from 401 MTPA in FY11 will require additional transportation capacity. Higher demand growth from commodities as against capacity addition delays in railways network will pose significant challenges to efficient distribution. As per the Memorandum of Understanding (MoU) signed with the Coal Ministry, Coal India’s rake requirement for FY11E was 185 per day, as against the average railways rake supply of 155 per day. However, if the Railways fail to provide the required number of rakes, then Coal India will be forced to cut its production targets set in the MoU.

Exhibit 18 : Inadequate Supply of Railway Rakes (Rakes per day) FY08 FY09 FY10 FY11E FY12E FY13E FY14E FY15ETarget 156 163 165 185 204 226 248 271Availability 153 156 155 155 164 174 185 196Shortfall 3 8 10 30 39 52 64 75Source: CIL, Karvy Institutional Research

VI. Significant Cost Pressure; Leeway for hike in domestic coal prices Since the deregulation of coal pricing in 2000, Coal India (CIL) has revised the notified coal prices in India only five times till date. As a result, the price of notified coal has increased at a 4.9% CAGR over FY2000-2010. The Company has kept prices for linkage coal significantly lower than the landed cost of coal, even after adjusting for the ash content. Over the years, CIL’s prices have traded at a discount of 36-69%, as compared to international prices. This is because coal prices in India can have a significant impact on the power sector, which accounts for ~80% of CIL’s sales volume. CIL predominantly controls the Indian coal market, accounting for ~82% of the total coal production, followed by Singareni Collieries Company (SCCL). Moreover, the power sector operates within a government-regulated RoE regime that warrants lower coal prices to keep power cost under control.

July 1, 2011

Power Sector

CIL ups prices by 12% in Feb’11 for non-regulated sectors Coal India has hiked price of premium grades of coal, A & B, to the international price and will now be offered at a 15% discount on the global spot prices. The benchmark price will be decided through a complex formula involving calorific value of the coal, as well as on the basis of Indonesian coal spot prices. Rest of the grade, C to F, will now be 30% dearer than the earlier notified price. The hike has been for non-regulated sector , while power, fertilizer and defense have been left out of the hike, which consumes approximately 80% of CIL’s coal.

We believe that the coal price of grade A & B likely to increase annually to cover inflation, rising wage & dearness allowance hikes etc., but other grades (C-grade) consumed by the power sector will be under government control.

VII. Alternate Fuels: Gas-based power firms face availability, infra bottlenecks

The estimated requirement of gas is much higher than estimated availability

The contribution of gas to India's total installed power generating capacity was 10.3% (17,456MW) as on March 31, 2011. In FY11, the gas-based plants accounted for 12.5% of the actual power generation of the country. Currently, from the total availability of natural gas of 160 MMSCMD, ~40% is being supplied to the power sector. Further, from the 55 MMSCMD of APM gas available, 24.5 MMSCMD is being supplied to the power sector. In the Jul’10 meeting of the Empowered Group of Ministers (EGoM), total gas allocation of 91.6 MMSCMD was finalised, with 43.1 MMSCMD being allocated to the power sector (31.2 MMSCMD on firm basis and 12 MMSCMD on fallback basis). Moreover, 10 MMSCMD of gas was allocated to the captive power plants on fallback basis. However, by the end of the 11th Five Year Plan, the total gas requirement is expected to be 129 MMSCMD, which is much higher than the estimated availability.

Non-utilization of allocated gas reflects poor gas trunk pipeline grid hampering power generation

One of the issues affecting the power sector is the non-utilization of allocated gas primarily impacted by inadequate pipeline infrastructure. The present gas trunk pipeline grid is only around 10,000 km in length. Several pipeline systems have been proposed, which are currently in the authorization process as per the legal framework of the PNGRB Act, 2005.

Exhibit 19: Power Sector - Gas Requirement

FY2008 FY2009 FY2010 FY2011E FY2012E

(mmscmd)

July 1, 2011

Power Sector

VIII. RoE Sensitivity to Coal Prices & Tariffs

Until 2003, all power companies earned regulated returns as specified by the CERC regulations (base RoE as 15.5% with incentives). However, current industry dynamics provided players opportunity to generate super normal profits. During FY07-FY10, the private players expose to merchant business generated RoE in excess of 70-80%, but given the fall in merchant realisation and higher coal prices we expect RoE to settele at 22%.

We believe that the high demand for coal has increased the coal price, which are significantly higher than domestic coal linkage. The companies who got linkage would get advantage in securing higher RoE.

Exhibit 20: Illustration of RoE at Various Coal Prices & Tariffs Linkage Coal Imported Coal Captive Coal

Capacity (MW) 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000 1,000

Units Generated (MU) at 85% PLF 7,446 7,446 7,446 7,446 7,446 7,446 7,446 7,446 7,446

Tariff (Rs/unit) 2.5 3 3.5 2.5 3 3.5 2.5 3 3.5

Coal cost (Rs. per MT) 1,900 1,900 1,900 3,798 3,798 3,798 1100 1100 1100

Calorific Value 3,500 3,500 3,500 5,235 5,235 5,235 3,500 3,500 3,500

Heat rate 2,450 2,450 2,450 2,450 2,450 2,450 2,450 2,450 2,450

Coal required in kg per unit 0.7 0.7 0.7 0.5 0.5 0.5 0.7 0.7 0.7

Coal cost per unit of generation 1.33 1.33 1.33 1.78 1.78 1.78 0.77 0.77 0.77

O&M and other costs 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27 0.27

Cash cost of generation (Rs. per unit) 1.60 1.60 1.60 2.05 2.05 2.05 1.04 1.04 1.04

Depreciation 0.32 0.32 0.32 0.32 0.32 0.32 0.32 0.32 0.32

Interest 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51 0.51

PBT 0.07 0.57 1.07 -0.37 0.13 0.63 0.63 1.13 1.63

Tax 0.02 0.17 0.32 -0.11 0.04 0.19 0.19 0.34 0.49

PAT per unit 0.05 0.40 0.75 -0.26 0.09 0.44 0.44 0.79 1.14

Project cost (Rs. in crore) 4,500 4,500 4,500 4,500 4,500 4,500 4,500 4,500 4,500

RoE (%) 2.6 20.0 37.3 -13.0 4.4 21.8 22.1 39.4 56.8

July 1, 2011

Power Sector

Key Issues for the Power Sector I. Poor financial health of SEBs: A major concern for merchant power firms Most State Electricity Boards (SEBs) suffer from high technical and commercial losses, irrational power tariffs and inefficient T&D infrastructure. So, the power sector subsidy continues to be the largest component of the state government subsidies. The reforms initiated so far have not yielded any significant results due to lack of political will and support from the state governments. According to estimates by the Planning Commission, the T&D losses of the DISCOMS estimated to be about Rs. 680 bn in FY10, as against Rs. 450 bn in FY09, registering a rise of 55% on YoY basis. At FY08 tariff levels, the 13th Finance Commission believes this could be as high as Rs. 686 bn in FY11E and move up to Rs. 1,161 bn by FY15E.

In our view if the financial health of the SEBs does not improve, it would prevent them from purchasing power at competitive rates, which could cap the merchant power rates and affect the merchant power players negatively.

The projected aggregate losses of state T&D utilities at the 2008 tariffs are given in the following Exhibits.

Exhibit 21: Net Losses of state T&D utilities (Rs. crore)

Source: 13 th Finance Commission, Karvy Institutional Research

Exhibit 22: Cash Losses of SEBs (Rs. in crore) FY07 FY08 FY09

Gujarat 208 -38 222

Maharashtra -653 -949 -2632 Punjab -1187 -693 -142

Rajasthan -299 -2167 -7325 Tamil Nadu -901 -3108 -6640

Uttar Pradesh -4612 -2985 -7168 Source: 13 th Finance Commission, Karvy Institutional Research

These financial projections assume a reasonable reduction T&D loss in each state. As against the enormous financial losses indicated above, the subsidies in 2007-08 stood at Rs. 169.5 bn. Thus, there is a large and burgeoning uncovered gap.

The key reasons for the increasing gap can be summarized as follows: I. Absence of timely tariff hikes has increased the gap and has impaired

utility operations further. Some states have not raised tariffs for the past eight to nine years in spite of increasing deficits,

II. Higher T&D losses III. Higher cost of short-term purchased to reduce load shedding, as several

utilities have not planned capacity addition as per the demand requirements thereby relying on short-term purchases at high rates (an average of Rs. 7.31 per kWh, as compared to Rs. 4.52 per kWh in 2007-08).

Tariff increase requirements to bridge the gap, even in the better performing states, are as much as 7% per annum on an average (considering the 2007-08 subsidy levels). In some of the poorly performing states, the increase in requirements is as much as 19% per annum, which is indeed difficult to achieve, which pose a high risk to their financial stability.

(68643)(80319) (88170)

(98664)(116089)

-140000-120000

-100000

-80000

-60000-40000

-20000

FY10-11 FY11-12 FY12-13 FY13-14 FY14-15

July 1, 2011

Power Sector

Exhibit 23: Total Financing Requirements of Power Sector (Rs. crore)

Source: 13th Finance Commission

Exhibit 24: Losses Estimates for Maharashtra SEB (Case Study)

FY09 FY10 FY11E FY12E FY13E FY14E FY15E

Power Purchase (MU) 79,745 84,641 85,862 87,107 88,377 89,672 90,993 Within state 54,170 61,031 62,252 63,497 64,767 66,062 67,383 Outside state 25,575 23,610 23,610 23,610 23,610 23,610 23,610 Inter-state Transmission Losses (MU) 1,240 1,145 944.4 944.4 944.4 944.4 944.4 (as a % of power purchased) 5 5 4 4 4 4 4 Available for Distribution (MU) 78,505 83,496 84,917 86,162 87,432 88,728 90,049 Distribution Losses 17,648 15,196 14,436 14648 14,863 15,084 15,308 (as a % of power distributed) 22 18 17 17 17 17 17 Power Sold (MU) 57,796 62,696 70,481 71,515 72,569 73,644 74,740 Average realization per unit (Rs) 3.69 3.87 3.99 4.11 4.23 4.36 4.49 Total sales (cr) 21,327 24,263 28,095 29,362 30,688 32,077 33,531 Cost of supply per unit 4.01 4.36 4.53 4.67 4.81 4.95 5.1 Total revenue expenditure 23,199 27,323 31,959 33,400 34,910 36,490 38,144 Cash Losses (cr) -1,872 -3,060 -3,864 -4,039 -4,221 -4,412 -4,612 Source: Industry, Karvy Institutional Research

II. Merchant Power: We expect rates to decline as capacity addition softens – Settling at levels of Rs. 3.50 per unit in FY13 yields RoEs of ~22% I. Merchant Power – Tariffs to Decline 40% over FY10-13E The merchant power rates in India have gone up from Rs. 3 in FY06 to Rs. 6 in FY10 due to increased power deficit. With new capacities getting operational, the merchant rates are expected to decline by 40% over FY10-13E, settling at healthy levels of Rs. 3.5 per unit in FY13E and yielding RoEs of ~22%. Further, seasonal factors and events such as elections would play a crucial role in determining the prices. An analysis of the merchant power rates show that historically the summer months (Mar-Jun) witness heavy demand from both the domestic and industrial segments, resulting in load shedding and upward push in the merchant power rates, as the distribution utilities attempt to procure power at higher prices to meet the increased demand.

II. Capacity Additions to Soften Rates We expect a substantial portion of the uncompleted capacity addition of the 11th Plan to be commissioned in FY13E and FY14E, resulting in a fall in demand for merchant power beyond FY14E. Further, the weak financial position of SEBs, which is not likely to show any major improvement over the next few years, would restrict their ability to buy mer chant power and in turn keep the prices low. Accordingly, for FY12E and FY13E, we have assumed average merchant power rates of Rs. 4 per unit and Rs. 3.5 per unit , respectively and expect it to settle at lower levels of Rs. 3.5 per unit, as newer capacities come up.

7588088529 93604 101271

115637

020000400006000080000

100000120000140000

FY10-11 FY11-12 FY12-13 FY13-14 FY14-15

July 1, 2011

Power Sector

Exhibit 25: Merchant Power Rates vs. Power Deficit (FY06-14E)

Our View: Huge Capacity Addition in Inter-Regional Transmission & Open Access would improve Regional Imbalances Currently, inter -regional power transmission capacity is 22,000MW, which is expected to increase to 37,000MW by FY12E. Power Grid Corporation of India (PGCIL) has envisaged capital expenditure of Rs. 1,000 bn in the 12 th Plan period, as against Rs. 550 bn in the 11 th Plan. PGCIL has identified seven high-capacity transmission corridors to generate power from projects coming up in the eastern and southern states, which would facilitate transfer of electricity to the power-starved northern and western regions. In our view this capacity addition would bring proper flow of electricity.

Exhibit 26: Inter-Regional Transmission Capacity (MVA) Regions FY07 FY12E FY17EER-SR 3,130 3,630 7,830ER-NR 3,430 12,130 18,030ER-WR 1,790 6,490 16,990ER-NER 1,260 2,860 2,860NR-WR 2,120 4,220 14,420WR-SR 1,720 2,720 9,020NER-NR-NR-WR 0 6,000 6,000132/110KV 600 600 600Total (MVA) 14,050 38,650 75,750Source: CEA, Karvy Institutional Research

It may be noted that a fall in the merchant power rates is at a much higher rate than the fall in deficit.

While assuming merchant tariffs, we factor in following parameters: 1. Demand-Supply dynamics (Peak deficit from 10% to 3.3% in FY15E)

(Refer Exhibit # 10) 2. Capacity addition pace under merchant route/Untied capacity

(10,500MW) 3. The long-term prices of around Rs. 2.8-3.3 per unit arrived during the

recent Case-1 bids. (Refer Exhibit # 29) 4. The peak unscheduled inter-change (UI) charges of Rs. 7 per kWh

charged in the case of over-withdrawal and withdrawal of power at lesser frequency should act, as the ceiling for merchant power in normal circumstances.

5. IEX Price trend 6. CERC intervention to regulate prices in the past.

Accordingly, for FY12E and FY13E, we have assumed average merchant power rates of Rs. 4 per unit and Rs. 3.5 per unit respectively, and expect it to settle at lower levels of Rs. 3.5 per unit till FY15E.

024681012

Merchant Rates (LHS) Power Deficit (RHS)

(%)Merchant rates to decline 40% from FY10

July 1, 2011

Power Sector

We do not believe there will be any significant decline in our merchant tariffs assumption of Rs. 3.5 per unit in FY13, due to the following factors:

1. The power traded through exchanges is only around 1.5% of the total power traded in India.

2. Bilateral tariffs are more stable taking commercial risks into consideration for internal ROEs calculation.

3. SEBs merchant power purchase is just 10% of the total power distributed coupled with lower cost via merchant route for private consumers.

4. Domestic fuel shortage should lead to an increasing use of the high cost imported fuel, leading to an increase in the overall cost of power produced.

5. Increase in fuel cost will lead to increase in tariff to more than Rs. 3 per unit by FY14E.

Exhibit 29: Tariffs determined through competitive bids Project MW Fuel type Company Date of award Bid Sasan UMPP 3,960 Captive Coal Mine Reliance Power Jul 07 1.2 Mundra UMPP 4,000 Imported Coal Tata Power Dec 06 2.26 Krishnapatnam 3,960 Imported Coal Reliance Power Nov 07 2.33 Tilaiya UMPP 3,960 Captive Coal Mine Reliance Power Jan 09 1.77 Anpara 1,200 Coal Linkage Lanco Infratech Jun 06 1.56 Bhaiyathan 1,600 Captive Coal Mine Indiabulls Mar 08 0.81 ajjar 1,320 Coal Linkage China Light & Power Mar 08 3 Talwandi 1,980 Coal Linkage Sterlite Energy Jul 08 2.86 Rajpura 1,320 Coal Linkage Lanco Infratech Feb 09 3.31 Bara 1,980 Coal Linkage Jaiprakash Associates Feb 09 2.97 Karchana 1,320 Coal Linkage Jaiprakash Associates Feb 09 3.03

Exhibit 27: Volume (MUs) Traded Below & Above Rs. 4 / kWh in Mar’11

Source: CERC

3.77-3.93 4.07-7.42

Exhibit 28: Volume (MUs) Traded Below & Above Rs. 4 / kWh in Apr’11

Source: CERC

3.17-3.85 4.04-5.65

July 1, 2011

Power Sector

Short-term Tariffs Trend: Directionally Moves Northwards

After hovering between Rs. 2.5-3.5 per unit in FY11, the merchant tar iffs have started to move up to Rs. 4-4.5 per unit in Q4FY11 on higher demand. Some southern states have shown Rs. 7-8 per unit as per the IEX in Mar’11.

Contract Volume & Prices in Apr’11

The reported short-term contract volume was 9,324.62 MUs in Apr’11, as against 1,410.05 MUs in Mar’11. In Apr’11, 96% of total volume has been contracted at above price of Rs. 4 per kWh. The contracts are well-spread throughout the month and in a range of Rs. 3.17 per kWh to Rs. 5.65 per kWh. The contracts reported were mostly for one-month period of power delivery.

In the beginning of Apr’11, the OTC contract prices were fairly close to the Indian Power Exchange (IEX) spot prices, while Power Exchange of India (PXIL) had higher spot prices. The minimum price in the exchanges during 28 th March – 1st May was Rs. 2.83 per kWh (IEX,24th Apr’11), while that in the OTC market was Rs. 3.17 per kWh. The maximum price at the exchange reached Rs. 11.03 per kWh (PXIL, 3rd Apr’11) and in the OTC market it was Rs. 5.65 per kWh.

Subsequently the PXIL prices came down in the month and converged with the OTC contract and the IEX spot prices. In Apr’11, the OTC contracts mostly are for a delivery period of a month. In the month under review, the contracts entered above Rs. 4 per kWh were 47 out of total 60 contracts.

Cumulative Volume up Significantly

In Apr’11, the cumulative volume traded above Rs. 4 per kWh was 8,961 MU, as against 1,311 MUs in Mar’11, which is 96% (as against 93% in Mar’11) of total OTC contracts for Apr’11. The forward curve for the next three month from 13th May’11 to 5th Aug’11 shows upward sloping on month on month basis.

For May’11 delivery, the power price is Rs. 4.74 per kWh, which dropped to Rs. 4.21 per kWh on 1st Jun’11. For Jun’11 delivery, the price drops to Rs. 4.02 per kWh and remain there till end of the month of Jun’11. For the 1st July, the price rises to Rs. 4.56 per kW h and remains at that level till 30th July, as against Rs. 3.49 in Mar’11 contracts thereby showing some strength.

For power delivery in Aug’11, the price rises to further to Rs. 4.58 per kWh, thereby showing some strength. This forward curve made in Apr’11 is based on 100 contract prices reported by the traders.

Exhibit 30: Price of short term transactions of electricity, April 2011

Source: CERC

01234567

Exhibit 31: Three-Month Forward Curve Power Prices (13th May – 5th Aug 2011)

Source: CERC

13-May-11 13-Jun-11 13-Jul-11

Rs / Unit

Rs/KWH

July 1, 2011

Power Sector

However, Price Underperformance Provides Opportunity

The BSE Utilities Index has underperformed the BSE Sensex by 23.3% over the past 12 months. The key premises for this underperformance have been:

I. Cut in the production estimate of Coal India – coal availability, II. Deteriorating financial condition of SEBs leading to sharp corrections in

merchant prices, and III. Lower PLF & SEBs Blackout.

Stocks with higher merchant power exposure have corrected significantly, given the rise in coal costs. The companies with coal resources have performed better due to higher valuations of their reserves.

At current valuations the sector is looking cheap relative to its historical valuation multiples (BSE Utilities Index is trading at 2.07x at a 33% discount to its last three years average mean of 3.1x). At the trough valuations, the sector traded at its lowest historical P/BV of 1.8x recorded in FY09.

Whilst the reforms encouraged private sector participation in power generation, aggressive expansion undertaken by the developers have pushed valuations from 1.5x P/BV in FY05 to ~5x in Peak (2008) on the back of high merchant prices, which were at Rs. 5-7 per unit, and core RoE ranging from 18-35%). But, the concerns over higher coal prices, coal unavailability, lower merchant rates resulted in valuation erosion to 1.5-3x P/B.

With sustainable RoE of 22%, we believe current valuation at 1.7X P/B, EV/EBITDA 8-9X gives margin of safety.

Exhibit 32: Price Performance of Power Stocks – Absolute & Relative to the Sensex Absolute Return (%) Relative to Sensex Return (%) Company 1M 3M 6M 12M YTD 1M 3M 6M 12M YTD BSE Power Index 3.5 (2.7) (11.4) (16.6) (12.8) 1.2 (0.5) (3.7) (23.3) (4.0) Adani Power (4.0) (2.1) (15.7) (11.7) (16.0) (6.4) 0.1 (8.0) (18.3) (7.1) CESC 11.6 (3.0) (17.3) (19.7) (17.3) 9.2 (0.8) (9.5) (26.3) (8.4) JSW Energy (3.2) (6.0) (28.3) (45.6) (32.8) (5.6) (3.7) (20.6) (52.2) (23.9) NTPC 10.1 (1.8) (6.5) (6.3) (7.7) 7.7 0.5 1.2 (12.9) 1.1 Tata Power 6.2 (3.8) (4.6) (1.8) (6.3) 3.8 (1.6) 3.1 (8.4) 2.6

Source: Bloomberg

Exhibit 33: One Year Forward-P/B- BSE Power Index

Source: Bloomberg

Apr-06 Apr-07 Apr-08 Apr-09 Apr-10 Apr-11

July 1, 2011

Power Sector

Exhibit 34: Tata Power vs. Sensex

Exhibit 35: Adani Power vs. Sensex

Exhibit 36: JSW Energy vs. Sensex

Exhibit 37: CESC vs. Sensex

Exhibit 38: NTPC vs. Sensex

859095

100105110115120

Sensex Tata Power

80859095

100105110115120

Sensex Adani Power

5060708090

100110120130

Sensex JSW Energy

60708090

100110120130

Sensex CESC

80859095

100105110115120

Sensex NTPC

July 1, 2011

Power Sector

Valuation Methodology – Free Cash Flow-To-Equity (FCFE) is a Preffered Choice

Most of the private sector players do not have much operating capacity in place, despite having a large portfolio of upcoming projects, as:

I. Most of these projects are expected to take a minimum of 2-3 years to get fully operational, thus making the cash flows from these projects back-ended.

II. These plants will also take time to stabilize and would report lower PLFs in the initial years.

III. Besides, these plants would face fuel shortage in the initial years, which would also contribute to low PLFs and lower revenues.

Why we prefer FCFE Methodology – The logic

I. P/BV methodology to value power utilities is not appropriate due to their huge capital work in progress, which suppresses RoE considerably in the near term, although they would improve substantially when the plants get operational. II. Similarly, the EV/MW methodology method has its own drawbacks, as it fails to take into account the asset quality and the difference in fuel sources. III. Earnings based multiples like P/E and EV/EBITDA too are not suitable as valuations will fall significantly with a surge in earnings post commissioning of new capacities. IV. The Free Cash Flow-To-Equity (FCFE) methodology has been used to value the companies covered in this report, which we believe is best suited considering the substantial capital investment involved and long-term nature of the power business resulting in cash flows over a long period. This methodology also captures the effects of all variables such as capital cost of the project, fuel cost, merchant tariff potential, etc.

Our assumptions for the cost of equity differ from project to project considering the risks involved in project execution. We have assumed 10% of the gross block as terminal value for each project. Further, in certain cases, we have provided discounts in the range of 25-75%, based on project milestones achieved.

We believe that going ahead the merchant power prices would temper once the power deficit reduces on the back of capacity addition. With most of the private sector players betting big on merchant power capacities, fuel supply at fixed prices will be critical in determining the profitability of a company.

Thus, the companies that have secure fuel supply linkages or captive coal blocks would be better placed than those relying on spot coal imports. This is because the spot rates of imported coal fluctuate substantially based on global demand and supply, exposing the players to the risks of high coal costs.

July 1, 2011

Power Sector

Rationale we follow while cherry picking Fuel Security: We expect the coal shortage to become acute going ahead, with the demand set to outpace the supply. We estimate India's coal imports to grow from 35 MMT in FY10 to 134 MMT in FY15E, registering a CAGR of 31.6%. This leads us to the belief that coal-based power generators that will secure coal access (in the form of long-term import contracts or captive coal mines abroad) are better placed than others.

Operational Assets & Near-term Capacity Addition: We believe that the companies with operational assets and exposure to the merchant power business will continue to gain from high merchant rates till FY13E. We assume merchant rates of Rs. 4 per KWh in FY12E, declining to Rs. 3.5 per KWh in FY13E, and remaining at this level until FY15E; and 2% hike thereafter, as the recent competitive bids have already set a price band of about Rs. 2.8-3.2 per KWh. We expect merchant rates to be at a premium of at least 10-15% to long-term PPA rates considering the risks associated with the business.

Merchant Business with Captive Coal Blocks or Fuel Linkages: The critical factor for power utilities to generate higher RoE is linked to fuel-security. In this context, the merchant business with captive coal blocks even at Rs. 3.5 per unit can generate RoE in excess of 50% on account of lower fuel cost. Merchant business that are dependent on spot coal, would earn RoE in the range of 0-10%, as higher spot rate (imported or e-auction) would lower PLF thereby increasing fixed cost.

RoEs of 22% are sustainable; we prefer companies with assured RoE: In the global context, the power utilities are generating RoE (10-14%) slightly higher than the cost of equity and trading between 1-5-2X P/B. We believe at Rs. 3.5 per unit, imported coal-based plant will yield a RoE of 22%, which is sustainable in our view considering the risk associated with business model. In our opinion, certain key factors such as the quantum of near-term capacity addition providing revenue visibility (and ability to profit out of high merchant rates), execution capability and fuel security would distinguish the top players from the rest. We prefer companies with assured RoE, Fuel Secured at current valuation.

July 1, 2011

Power Sector

Scorecard Analysis We have evaluated the companies under coverage to assign score, based on different parameters. We have assigned 5 points to each parameter to arrive at aggregate score. Based on our analysis on a scale of 100 points, Tata Power scores the highest (82 points) due to strong operational assets, robust financials, while JSW Energy scores the lowest (60 points) on account of higher exposure to merchant business, excessive dependence on imported coal etc.

Exhibit 39: Scorecard Analysis

Adani Power CESC JSW Energy NTPC Tata Power

PROJECT PORTFOLIO Operational and near term Capacities - Generation 4 3 3 5 5 Operational and near term Capacities - Distribution 1 3 5 1 3 FUEL SECURITY Secure fuel linkages 3 5 1 5 5 Imported Coal 4 4 2 4 5 Domestic Coal 3 4 2 5 4 Captive Mines - Allocation of Coal Blocks 3 4 2 3 2 New Mining Laws Impact 3 4 3 4 3 Coal Acquisition 4 2 2 4 5 Power Capacity constraints 5 4 3 4 5 Rail Capacity constraints 4 4 3 3 4 Cost Dynamics Impact on Coal Input Costs 3 4 1 5 5 REVENUES Near-term visibility 4 4 4 4 5 Portfolio Tariffs 3 4 3 4 5 Merchant Power Exposure 3 2 4 1 1 Merchant Power tariffs 3 2 4 1 1 Merchant Sales/Total Sales 3 2 4 1 1 Incentives on higher PLF based Tariffs 2 3 2 5 4 ADEQUATE FUNDING FOR GROWTH PLANS Generation of Cash Flows 3 4 3 5 5 Funding Gaps 3 3 3 4 4 Debt Servicing Obligations 3 4 3 5 5 Financials 3 3 3 4 5 Composite Score 3 4 3 4 5 5 = Excellent; 4 = Good; 3 = Average; 2 = Below Average; 1 = Very Poor

July 1, 2011

Power Sector

Our Top Picks are best placed in terms of Fuel Security Fuel shortage being a major concern, the companies have attempted to address the same by initiating measures such as acquiring coal mines abroad, entering long-term fuel supply agreements for imported coal or getting allotment of captive coal blocks. We like, CESC, NTPC and Tata Power on fuel security.

Adani Power: The Company has planned to operate its plants through a mix of domestic and imported coal. It has signed a 15-year FSA with its promoter company AEL to procure 15.1 MTPA of coal to its projects located in Mundra at US$36 per tonne (CIF) with an average GCV of 5,200 kcal per kg. Additionally, APL has obtained / or is in the process of obtaining domestic linkage for its Mundra complex and Tiroda project. However, we have concerns on the availability and quality of coal. CESC: The Company has increased generation capacity by over 25%. It depends on domestic coal for most of its fuel requirements. About 50% of its coal requirements are met through Integrated Coal Mining (ICML), which is a group company, 40% is linkage from Eastern Coalfields & Bharat Coking Coal (Coal India arms), while the balance is imported from Indonesia.

JSW Energy: The Company has a major portion (65% at the end of FY13) of its capacity is based on imported coal, which would be subject to the vagaries of spot coal in the short term.

NTPC: The Company has secured coal linkages for 90% of its existing projects. It has 33,194MW of capacity, of which 15,740MW is under construction. NTPC has signed PPAs for a cumulative capacity of 1 lakh MW, which provides assured off-take for its future projects. Being a central public utility, NTPC is governed by the regulated return model.

Tata Power: The Company has secured fuel linkage for its upcoming plants - Mundra UMPP would be fueled by 12.3 MTPA of coal that it would receive from the coal mines of Bumi Resources. It has also obtained 100% fuel linkage for its 1,050MW Maithon Project in JV with Damodar Valley Corporation (DVC). Besides, the Company has stakes in two different JVs, which have been allotted the Mandakini and Tubed coal blocks.

Road Ahead: we see many positives over the long-term despite the underperformance Given the aggressive capacity expansion by the private players on the commissioned over FY10-15, the private sector – which contributed mere 11% to installed capacity in FY10 – is expected to account for ~65% of the total capacity addition planned over FY10-15E.

Strong Net Sales Growth (50+ Growth) Over the next 3-4 years, we expect the power companies to report strong net sales growth in the range of (13-200%) on the back of higher incremental capacity addition and low base effect.

Coal Acquisition & Allocation of Coal Blocks In the light of high coal deficit, we expect the companies will continue to see coal assets for acquisition. We expect some of the coal blocks lying in the “no-go” areas – which could not be used for mining – may be shifted to the go-areas to expedite clearance for power projects. The companies, which have made significant investments in blocks in “no-go” areas, could be given priority.

Our Top Picks are:, CESC, NTPC & Tata Power

Ex. 42: Net Sales Growth (FY10-13)

Adani Power

JSW Energy

Tata Power

NTPC Cesc

Exhibit 41: Capacity addition Private Sector (FY10-15)

FY11 FY12 FY13 FY14 FY15

Private PlayersTotal Capacity additionPrivate capacity %

(MW) (%)

Exhibit 40: Fuel Security

100120

Adani Power

Tata Power

JSW Energy

NTPC CESC

July 1, 2011

Power Sector

Exhibit 43: Comparative Analysis of Companies under Coverage Company Reco Key Arguments Key Concerns Key Financial Highlights Valuation

Adani Power CMP: 110

HOLD Strong near term revenue visibility due to 3,960MW operational capacity in FY12E

Long -term fuel security a major concern. Cancellation of coal linkage(30% to Mundra 2640 MW.

Topline to grow at a CAGR of 200% over FY10-13E

Trading at 2.2x FY13E Book value

Early commissioning of plants to result in more merchant Power till FY13E

Net Profits to grow at 143% FY10-13E

SOTP based value of Rs. 117

CESC CMP: 299

BUY Regulated business model / Improving retail business

Huge expansion plans to increase its generation capacity to 5,745MW from the current 1,125MW are expected to propel its growth going ahead.

Recovery in retail business a key trigger. Net profit to grow at CAGR of 50% from FY10-13E

SOTP-based Target price of Rs. 381

JSW Energy CMP: 67

HOLD A major portion (70%) of JSWEL's FY12E capacity would operate on imported coal. High exposure on merchant power rates.

High imported coal price. Merchant Exposure

Top-line to grow at a CAGR of 44% over FY10-13E

Net Profits to grow at 11% FY10-13E

NTPC CMP: 187

BUY Impressive project Portfolio backed by sound execution skills. Regulated model

Execution delays, Availability of coal

Pretax RoE at 23%.Net profit to grow at 11% CAGR over FY11-13E.

Tata Power CMP: 1,308

BUY Impressive project Portfolio backed by sound execution skills

New Mining laws in Indonesia could restrict exports

Topline to grow at a CAGR of 19% over FY10-13E

Trading at 1.6 x FY2013E Book value

Bumi acquisition provides a derivative play on coal

SOTP-based Target price of Rs. 1,503

Adequately -funded growth Plans

Source : Karvy Institutional Research

Exhibit 44: Global peer’s Comparison

Mkt Cap P/E (x) P/B (x) ROE (%)

(US$ mn) FY11E FY12E FY13E FY11E FY12E FY13E FY11E FY12E FY13E

India Adani Power 5,380 46.7 10.0 9.7 3.8 2.8 2.2 8.5 32.0 25.7

CESC 7,67 12.6 9.6 7.1 1.0 0.8 0.7 6.3 6.3 7.9 JSW Energy 2,427 13.1 9.1 10.8 1.9 1.6 1.4 15.4 18.9 13.7 NTPC 33,409 18.3 16.0 13.8 2.5 2.3 1.8 13.0 13.7 14.2 Tata Power 6,739 15.1 12.0 10.6 2.2 1.9 1.6 15.6 17.1 15.4 Global

Exelon Corp* 26,693 10.1 13.6 13.7 1.8 1.7 1.7 18.7 12.9 12.7 Southern Co * 32,370 15.1 14.2 13.4 1.8 1.7 1.6 12.7 12.9 12.3 Dominion Resources 25,559 14.1 13.5 12.8 2.0 1.9 1.8 14.4 14.4 14.8 Nextera Energy INC* 23,178 12.3 11.7 11.0 1.5 1.4 1.3 12.3 12.1 12.0 Rwe AG* 36,115 9.2 9.0 10.5 1.6 1.5 1.3 17.0 16.3 13.3 Endesa SA* 32,860 10.5 9.8 9.0 1.2 1.2 1.1 11.9 12.7 11.7 Enel SPA* 60,501 9.4 9.1 8.9 1.1 1.0 1.0 11.8 12.0 11.5 Tokyo Electric 8,704 7.3 (2.5) (47.8) 0.2 0.3 0.4 3.2 5.9 8.0 Chubu Electric 16,606 18.1 13.7 12.3 0.8 0.8 0.8 4.5 5.9 6.7 Kansai Electric 19,440 12.5 11.5 10.1 0.8 0.8 0.8 6.8 7.2 7.9 Hong Kong

Hongkong Electric 14,816 13.6 13.2 13.0 1.9 1.8 1.7 15.0 14.2 14.0 CLP Holdings 19,626 14.9 14.2 13.2 1.9 1.8 1.7 12.8 13.2 12.3 China Resources 8,399 11.7 9.6 8.9 1.4 1.3 1.2 12.7 14.0 13.5 China

Datang Intl Power 9,877 13.6 11.6 8.9 1.1 1.0 0.9 8.1 8.4 8.8 Huadian Power Intl 3,460 86.8 20.1 16.3 0.7 0.7 0.6 1.3 3.2 4.0

Source : Bloomberg & Karvy Institutional Research, * Fiscal year end Dec, CY10

July 1, 2011

Power Sector

Key Challenges Affecting Power Sector Players

Exhibit 45: Key Risks & Challenges

Land Acquisition • Location of a plant is the key for successful operation of a plant. • In many cases, the state governments take the onus of procuring the land

under the Land Acquisition Act, which provides compulsory acquisition if it is in public interest.

• The land acquisition process is time-consuming and on an average takes 30 months to complete.

• The acquisition process could meet legal and other obstacles, if the owner of the land objects to compulsory acquisition on the grounds that the land is used for agricultural purpose or when the proposed area to be acquired is excessive.

• The main bone of contention lies in arriving at a suitable compensation for the owners of the land.

Environment Clearance • The Ministry of Environment & Forest (MoEF) issues the environment clearance certificate on recommendation of the Expert Appraisal Committee based on the Environment Impact Analysis prepared by the project developer, which is generally a time-consuming process.

• The issues related to environment clearance arise relating to rehabilitation of the affected people, use of forest land and coastal area for projects. Generally, the projects on forest land require forest clearance, which again is time-consuming. Further, the developer needs to pay the NPV of the expected loss arising from the use of forest land.

• The companies also face hurdles in developing captive coal blocks situated in the forest areas.

Fuel Supply Agreement • Obtaining uninterrupted fuel supply is of paramount importance as fuel shortage would result in low PLF and in a worst-case scenario cripples the entire project. Further, the failure to enter into a fuel supply agreement (FSA) at fixed prices might result in cost escalation affecting profitability.

• Generally, it takes 25-30 months to achieve coal linkage, as it is a long drawn process. The project developer has to apply to the coal ministry for linkage, which then allots the linkage from CIL and its subsidiaries based on various considerations such as plant location, size, etc. Similarly, the allocation of captive blocks is time consuming, as it involves getting a number of regulatory approvals. Obtaining gas linkages also takes a lot of time.

Equipment • Power equipment generally consist of two major portions i.e. BTG (Boiler, Turbine & Generator) and BOP.

• India is currently facing shortage in BTG and BOP equipment. To certain extent, the BTG shortage is met through Chinese imports and capacity expansion at BHEL – current capacity of 15,000MW, which is set to rise to 20,000MW per annum by FY12 – as wells as capacity addition by the new players.

July 1, 2011

Power Sector

Exhibit 46: Valuation Summary: Relative & Comparative Valuations

APL CESC JSW Energy NTPC Tata Power

Current Capacity MW 1980 1,225 1990 33,033 3,100 Under Construction Capacity MW 5,940 1,200 1,150 19,440 5,416 Current +UC Capacity MW 7,920 2,425 3,140 59,473 8,516 Pipeline Capacity MW 8,580 4,640 7,800 16,110 5,600 Total Capacity MW 16,500 7,065 11,210 75,583 14,074 FY10 MW 660 975 995 31704 2,945 FY11E MW 1,980 1,100 1,400 34044 3,127 FY12E MW 3,960 1,225 2,740 38364 5,990 FY13E MW 6,600 1,225 3,140 43814 8,516 CAGR over FY10-13E (%) 115.40% 7.9% 46.7% 11.4% 42.6% Share Price Rs. 110 299 67 187 1,308 Market Cap Rs. in bn 239 37 109 1541 310 FY13 Enterprise value Rs. in bn 489 87 185 2155 554 EV/MW based on FY2013 capacity Rs. in mn / MW 74 71 67 56 65 No of shares 2180 125 1640 7241 247

Earning Matrix (EPS) FY10 0.8 12.4 4.5 10.6 82.9 FY11E 2.4 23.7 5.1 10.8 87 FY12E

11.0 31.4 7.3 11.7 109.3

FY13E 11.5 42.3 6.2 13.6 124

RoE (%) FY10 4.2 3.4 23.2 13.6 18.0 FY11E 8.5 6.3 15.4 13.0 15.6 FY12E 32.0 6.3 18.9 13.7 17.1 FY13E

25.7 7.9 13.7 14.2 16.7

Source: Company & Karvy Institutional Research

July 1, 2011

Power Sector

New Tariff Norms (FY09-14) – Favorable for Power Sector As per the current CERC Tariff Regulations, RoE is fixed on pre-tax basis, for which the base rate of 15.5% would be grossed up through the applicable tax rate for the company. Further, the companies are also eligible for incentives for exceeding the prescribed level of operational efficiencies with respect to the Plant Availability Factor (PAF). On the flip side, the companies are also penalized for not meeting certain operation criteria with regard to plant heat rate and auxiliary consumption. While the regulations have provided for higher RoE for thermal power projects, the regulations have provided for a higher normative O&M expenses. Exhibit 47: New & Old Regulations at a Glance Parameter Old Norm New Norm RoE (%) 14 15.5 Efficiency Incentive 80% PLF 85% PAF GSHR 300/330/350MW 2450 Kcal/KWh 2,425 Kcal/KWh 600/660MW NA 2,425 Kcal/KWh Auxiliary Consumption (%) 200MW 9 8.5 500MW and above 7.5 6 – 8.5 Maintenance Spares 1% of Capital cost 20% of Normative O&M expenses Operation & Maintenance Cost 10.95 lakh/MW (500>MW) 13 lakh/MW Depreciation 3.6%+AAD 5.28% Refinancing Gains Not to be retained Generators can Retain 33% of gain Source: CERC RoE at 15.5%: The CERC has specified a Pre-Tax RoE of 15.5% for the tariff period 2009-14, as against a Post-Tax RoE of 14% in the previous tariff period (FY04-09). It allowed rate of RoE of 16% and 14% for the tariff period 2001-04 and 2004-09, respectively. Further, it has allowed an additional RoE of 0.5% for projects commissioned after April 2009 within specific timelines. We believe the additional RoE will act as an incentive for a project developer to achieve time-bound milestones. This is expected to be positive for central sector as from 2009-10 onwards as the player would earn 15.5% RoE. Depreciation Rate: The CERC has removed the concept of AAD, while increasing the depreciation rates applicable for projects. As against a deprecation rate of 3.6% for thermal power projects and 2.57% for hydel projects, the CERC has increased the depreciation rate to 5.28%, which we believe will result in the lowering of tariff of a project during the initial years. The 5.28%depreciation rate will require a debt repayment period of 13-14 years. Incentives linked to PAF as against PLF: Under the new regulations for 2009-14, the CERC has raised the normative annual PAF for the full recovery of fixed charges from 80% to 85% thermal generating stations. This is a positive for plants that are operating at lower PLFs on certain issues compared to their availability. Other Key Regulatory Developments Open Access in Inter-State Transmission: The CERC has notified regulations for medium-term (3-12 months) and long-term open access (12-25 years). Grid connected utilities can seek either medium-term or long-term access to system. Any generating plant having installed capacity of at least 250MW and any bulk consumer having at least a load of 100 MW can seek connectivity to interstate transmission system. This regulation has benefited merchant players to bridge the demand-supply deficit and earn higher realization. Promotion of Renewable Energy: The CERC has notified tariff regulations for determination of tariffs for projects being setup on renewable energy sources. The regulations has also specified that minimum renewable purchase standards be set at 5% for total power purchases for FY10 and should be increased by 1% each year for ten years. CERC has notified higher RoE for the project pre-tax 19% for first 10 years and pre-tax 24% from 11th year onwards which makes sector more attractive.

July 1, 2011

Power Sector

Exhibit 48: New CERC Norms Parameter FY09-14 FY04-09 Remarks NTPC Tata Power Adani Power JSW Energy CESC RoE 15.50% 14% Positive Operates under regulated business model (100%). It has

benefited by 150 bps due to new tariff norms. Fixed cost recovery is based on plant availability factor as against PLF is profitable for NTPC as the Company has higher plant availability.

Operates under MERC regulations. But all SEBs adhere to CERC regulations.

Does not have projects under regulated tariff. Most of its projects are under Case-1 bidding.

Its portfolio is mix of merchant business & Case1 bidding.

Its 1,000MW (90%) operates under regulated tariffs of WBEDCL.

Efficiency Incentive

85% PAF 80% PAF Negative With proposed increase in Availability norm from 80% to 85%, the quantum of energy/availability for incentive is reduced. Moreover, with Income Tax on incentive to be borne by NTPC, effective rate of incentive has reduced. Existing regulation provides 25p/kWh on Scheduled PLF. With new proposal the effective rate for will be 21.5 p/kWh for coal stations

- Neutral Neutral -

Depreciation 5.28% 3.6%+AAD Neutral The depreciation rate at 5.28% will require a debt repayment period of 13-14 years; the higher return on equity will partly offset the impact of the abolition of AAD which were providing higher cash-flows in the initial years.

- Neutral Neutral -

Refinancing gains Generators can Retain 33% of gain

Not to be retained

Positive Regulators has allowed retention of 33% of the benefits, if any, arising out of re-financing of loans earlier utilities have to passed it entirely to the beneficiaries.

- Neutral Neutral -

Operation & Maintenance cost

13 lakh/MW

10.95 lakh/MW (500>MW)

Marginally Positive

Increased in O&M on account of expected increase in wages - - - -

Station Heat Rate 2425 2450 (300/330/350 MW)

Marginally Negative

Tighter norms will reduce incentive - - - -

Higher RoE for Transmission Lincencee

15.5% 14% Positive NTPC does not have transmission network Higher RoE for Transmission business to benefit TATA Power to some extent of Rs 15 cr.

July 1, 2011

Power Sector

ANNEXURE Reforms – Attract Higher Investments in Power Sector Prior to implementation of the Electricity Act 2003, the two impediments that prevented entry of private sector players into the power generation segment were the requirement of licenses to generate power and single buyer model for power generation companies. However, the Electricity Act 2003 eliminated both the need for licensing and the single buyer model, while providing the necessary impetus for increased participation by the private sector players. The Act also targets to address the problem of payment security faced by the private players, which prevented them from putting up generation capacity. National Tariff Policy – Additional Fillip for Private Participation As per the National Tariff Policy (NTP), it is essential to attract adequate investments in the power sector by providing appropriate RoI, as the budgetary resources of the central and state governments are incapable of providing the requisite funds. As per the NTP, it is also equally necessary to ensure availability of electricity to the different categories of consumers at reasonable rates for achieving the objectives of rapid economic development of the country. Balancing the requirement of attracting adequate investments to the sector and ensuring reasonable charges for the consumers is the critical challenge for the regulatory pr ocess. Multiple Revenue Models The Indian power companies enjoy the benefit of adopting a multiple revenue models with each providing unique advantages. The companies can earn RoEs ranging from 15.5% to as high as 75%. Till recently, the power generation companies in India operated only under the fixed RoE-based business model. Fixed RoE-based Business Model: The central public sector utilities continue to function as per this model for a major portion of their output. As per the current CERC Tariff Regulations, the RoE is fixed on pre-tax basis, for which the base rate of 15.5% would be grossed up through the applicable tax rate for the company. The companies are also eligible for incentives in case they exceed the prescribed level of operational efficiencies with respect to the PLF. However, on the flip side, the companies are penalized if they do not meet certain operational criteria with regard to plant heat rate and auxiliary consumption. The companies can also pass through the fuel cost. Exhibit 49: CERC Tariff Regulations (FY10-14) Parameter Old Norm New Norm RoE (%) 14 15.5 Efficiency Incentive 80% PLF 85% PAF GSHR 300/330/350MW 2450 Kcal/KWh 2,425 Kcal/KWh 600/660MW NA 2,425 Kcal/KWh Auxiliary Consumption (%) 200MW 9 8.5 500MW and above 7.5 6 - 8.5 Maintenance Spares 1% of Capital cost 20% of Normative Operating expenses Refinancing Gains Not to be retained Generators can Retain 33% of gain Source: CERC

Advantages of fixed RoE model: The biggest advantage of the RoE model is that it ensures stable cash flows and assured returns to the utilities. The power plants operating under the fixed RoE model have assured off-take due to the long-term PPAs, which generally last for 25 years and hence enjoy revenue certainty. Competitive Bidding: Under competitive bidding, the power utilities select the suppliers through a bidding process wherein the power generator quoting the lowest tariff is preferred. The mega power projects (MPPs) and ultra mega power projects (UMPP's) adopt the competitive bidding route, wherein the low cost bidder is selected to execute the project.

July 1, 2011

Power Sector

Exhibit 50: Power Business Models Business Model Returns Upside Value Drivers Major Players Regulated Normative

RoE Saving on Norms, Operational Utilities like

PAF Incentive Efficiency NTPC, NHPC Captive Power PPA driven Merchant Sales,

Saving Trading Jindal Steel &

Power (JSPL) Plant on agreed terms, PAF Capabilities + Incentive Operational Efficiency Merchant Market

driven No cap on returns Trading

Capabilities JSPL, Adani Power

Case 1 Bid driven PAF Incentives Control on Capital Adani Power and Fuel Costs Case 2 Bid driven PAF Incentives Control on Capital

and fuel costs Tata Power, Reliance Power

Source: Company, Karvy Institutional Research Merchant Power: The merchant power business has a revenue model that is different from the regulated model and competitive business models. The merchant power plants are not tied-up with long-term PPAs and hence, the Independent Power Producers (IPPs) experience off-take risks. The merchant plants depend on redundancies in the existing transmission system to evacuate power. Thus, to ensur e large volumes of power evacuation, dedicated transmission systems are required. Private sector players like Adani Power and JSW Energy, who are developing merchant power plants, are also developing their own transmission networks. According to our estimates, the overall merchant power capacity addition is expected to be around 10,000-12,000MW in the 11th Plan period (FY07-12). Presently, the sale of power under the merchant route appears to be an attractive option, considering the power deficit prevalent in the country. Exhibit 51: Relative economics of a 1,000MW plant (Rs. in mn) Tariff -based plant Merchant power plant Units Generated (MU) 29,784 29,784 Units Sold (MU) 27,848 27,848 Tariff (Rs. per unit) 2 5 Revenue (Rs mn) 5,5700 13,9240 Operating Cost 2,2010 2,3680 Operating Profit 3,3690 11,5560 Depreciation 9360 9360 EBIT 2,4330 10,6200 Interest 14850 14850 PBT 9480 9,1350 Tax 1890 3,1050 Tax Rate (%) 20 34.0 PAT 7590 6,0300 Equity 4,5000 4,5000 RoE (%) 16.8 134

Source: Karvy Institutional Research Right Business Model – Key Determinant of Profitability With each of the three business models having their own risk return profile, profitability of the companies primarily hinge on their revenue mix and the level of fuel security. While most public sector generators like NTPC and NHPC operate almost entirely under the regulated return model, there is a huge difference in the revenue off-take profile of the IPPs. While an IPP like Tata Power has limited exposure to merchant power, APL and JSW Energy have more than 30% of their FY12E operational capacity under the merchant route.

July 1, 2011

Adani Power

POWER July 1, 2011

Adani Power Bloomberg: ADANI IN Reuters: ADAN.BO HOLD

Recommendation CMP: Rs 110 Target Price: Rs 117 Upside: 6%

Stock Information Market Cap. (Rs bn / US$ mn)239/5342 52-week High/Low (Rs) 145/105 Shares Outstanding (mn) 2180 3m ADV Rs mn 93.1/USDmn 2.1 Beta 0.69 Sensex 18,846 Nifty 5,647

Stock Performance (%) 1M 3M 12M YTD Absolute (4.9) (2.5) (13.4) (15.7) Rel. to Sensex (6.7) 0.6 (19.9) (7.5)

Performance

Source: Capitaline, Karvy Institutional Research

1 year forward P/B

16,000 17,000 18,000 19,000 20,000 21,000 22,000

Sensex (LHS) Adani Power (RHS)

50 70 90

110 130 150 170 190

2.5x3x

3.5x4x

Strong, but priced-in Fundamentals Adani Power (APL) is expected to have 6,600MW power capacity by FY13E, which will make the Company one of the largest private sector players. Out of 13.2GW capacity, APL has tied-up 51% in Case-I bids, while the balance is untied. APL is largely dependent on Indonesian coal having entered into long-term off-take agreements, which ensures stability. However, we believe cheaper fuel price and strong operational asset are priced-in, which validate our “HOLD” recommendation. Long-term Fuel Security – A Major Concern The Company is planning to fuel its plants with Indonesian coal procured from its promoter Adani Enterprises (AEL). However, in our view the long-term fuel security still remains a concern considering the likely disruptions of coal supply due to lower production in Bunyu mines, and new laws restricting exports from Indonesia. Again, the Fuel Supply Agreement (FSA) with AEL is only for 15 years, as against the total plant life of over 30 years. PPA Structure with Risks related to Pricing & Availability The Power Purchase Agreement (PPA) structure renders APL prone to risks associated with fuel pricing and availability, as most of its under-construction capacity has been tied-up through fixed tariffs having no fuel-escalation clause. Out of 9.2GW capacity, long-term PPAs have been contracted for 7.8GW , while 1.4GW will be available on merchant basis. Thus any variations in fuel costs will have a direct impact on project profitability. Pre-PPA sales to result in high merchant volumes till FY14E As the projects in Mundra are expected to be commissioned ahead of the schedule, well before the start of commitment to supply under long-term PPAs, the power generated during the lag time can be sold through merchant route. Mundra to account for 60% value of proposed 6,600MW capacity APL's total capacity, which currently stands at 1,980MW, is set to increase to 6,600MW by FY12E. It enjoys good medium- to near-term revenue visibility due to huge operational capabilities. Given the low fuel cost from AEL’s captive mine at CIF of US$36 per tonne, Mundra projects seem to be very profitable. As per our valuation, Mundra projects constitute 60% value on account of cheap fuel supply agreements with AEL. Stock Fairly -priced – Limited Upside from CMP APL has been traded at premium to other players on account of higher RoE. However, at the CMP the stock is trading at P/BV of 2.8x and 2.2x its FY12E and FY13E and EV/EBITDA of 7.7 x FY13E, which we believe fairly valued. We have arrived at an SOTP-based value of Rs. 117 for the stock. We initiate coverage on the stock with a “HOLD” recommendation. Exhibit 1: Key Financials Y/E March (Rs mn) FY09 FY10 FY11 FY12E FY13ENet Sales - 4,349 21,352 75,716 121,920 EBIDTA (55) 2,438 12,205 45,909 63,308 Net Profit (55) 1,700 5,132 23,946 25,011 EPS (Rs) - 0.8 2.4 11.0 11.5 PER (x) - 141.1 46.7 10.0 9.6 EV/EBITDA (x) - 136.9 29.9 9.2 7.7Source: Company , Karvy Institutional Research

Initiating Coverage

July 1, 2011

Adani Power

Company Background

Adani Power (APL) is promoted by Adani Enterprises, which is the flagship company of Adani Group. APL is currently in the process of commissioning 6,600MW of power, which is in various stages of development.

While the Company is developing all the projects coming up at Mundra on its own, the Tiroda project is developed by APML. All of the Company's upcoming projects are coal-fired, with the 1,320MW Mundra-I project based on subcritical technology and the other projects based on supercritical technology.

The Company is procuring equipment for its power plants from various Chinese manufacturers such as Dongfang and Shanghai Electric.

Company Financial Snapshot Consolidated Profit & loss

Rs mn FY11 FY12E FY13E

Net revenues 21,352 75,716 121,920 EBIDTA 12,205 45,909 63,308 Interest 2,366 10,054 19,546 Depreciation 1,886 6,288 12,745 Profit before Tax 8,132 29,906 31,237 Provision for tax 3,000 5,960 6,225 Adjusted Net Profit 5,132 23,946 25,011 Reported Net Profit 5,132 23,946 25,011 Profit & Loss Ratios EBIDTA Margins (%) 57.2 60.6 51.9 PAT Margins (%) 24.0 31.6 20.5 EV/Sales (x) 17.1 5.6 4.0 EV/EBIDTA (x) 31.4 9.3 7.2 PER (x) 46.7 10.0 9.6

Consolidated Cash Flow

EBIT 1,032 3,962 5,056 (Inc)/Dec in Working Capital 1,010 (7,456) (35,576) Cash Flow from Operations 2,042 (3,494) (30,520) Other Income 180 340 220 Depreciation 1,886 6,288 12,745 Interest Paid 2,366 10,054 19,546 Dividends Paid 0 436 436 Tax Paid 3,000 5,960 6,225 Net cash from Operations 9,474 19,584 8,653 Capital Expenditure (2,541) (13,350) (9,856) Free Cash Flows 6,932 6,235 (1,203) Inc/(Dec) in LT borrowing 3,000 10,952 5,550 Cash from Financial Activities 3,000 10,952 5,550 Opening Cash 1,165 1,110 1,830 Closing Cash 11,098 18,296 6,177 Change in Cash 9,932 17,186 4,347

Consolidated Balance Sheet

Shareholders’ funds 62,911 86,857 107,508 Total Loans 135,705 245,220 300,715 Deferred Tax Liability Total Liabilities 199,639 333,100 409,247 Net block 98,897 181,708 268,063 Investments 0.7 0.7 0.7 Net Current Assets 20,552 26,805 17,134 Total Assets 199,639 333,100 409,247 Balance Sheet Ratios

RoCE (%) 5.7 14.9 13.6 RoE (%) 8.5 32.0 25.7 EV/Sales (x) 17.1 5.6 4.0 Debt/Equity (x) 2.0 2.6 2.7

Shareholding pattern (FY11)

Source: Company

FIIs19%

Promoters74%

Public6%

Segment wise break-up (FY11)

Source: Company

Power Business

Others1%

July 1, 2011

Adani Power

Outlook & Valuation: Why we have “HOLD” Recommendation on the Stock? With limited upside from CMP, despite factoring cheap fuel, we believe APL should trade at premium to other power players on account of:

I. Most profitable power projects; Cheaper fuel supply agreements with AEL

II. Higher near-term capacity addition from 300MW in FY09 to 6,600 MW by FY13E

III. Fuel Security: Concerns on Coal – Quality, Availability & Calorific Value; Change in Indonesian Mining Laws a risk to fuel supplies

IV. Long term PPA exposes fuel price risk; mismatch between Fuel Supply Agreements and asset life a concern

V. Mundra Phase-II PPA a swing factor; Mundra a cash cow for APL with the power offtake agreement in place

VI. Merchant profitability high contribution to FY12-13E earnings, various moving parts expose to near-term earnings volatility

At the CMP, Adani Power is trading at P/BV of 2.8x and 2.2x its FY12E and FY13E and EV/ EBITDA of 7.7x FY13E. We have arrived at an SOTP-based value of Rs. 117 for the stock by valuing 9,240MW of capacity under the FCFE Valuation methodology. Out of the projects valued, 1,980MW is operational and 7,260MW is under construction at Mundra, Tiroda and Kawai. We have also valued the 1,320MW Tiroda expansion project. We have not valued 8,580MW of projects which are on the pipeline, which are in pre-development stages.

Exhibit 2: SOTP Valuation Project Details

Capacity

(MW) COD Cost of

Equity (Ke)

Value Method

Equity Value

(Rs mn)

Stake %

Milestone Discount

APL’s Value

(Rs mn)

Per share value

Mundra Phase I,II & III 2,640 Operational 14% FCFE 11,0297 100 0 110,297 51 Mundra Phase IV 1,980 Operational 14% FCFE 47,284 100 0 54,119 22 Tiroda Phase I 1,980 Under

construction 14% FCFE 46,692 74 0 34,552 16

Tiroda Phase II 1,320 FY15 14% FCFE 43,968 74 50% 16,268 7 Kawai Rajasthan 1,320 FY15 14% FCFE 17,907 74 50% 6,626 3 Cash & investment in hand FY11

11,098 - - 11,098 5

Terminal value 28,000 - - 28,000 13 Total (Rs Per Share) 251283 117 Source: Company and Karvy Institutional Research

Adani Power is trading at P/B of 2.2x & P/E 9.6x based on FY13E, which at discount 37% to its historical average (FY09-FY11) of 3.5X P/B respectively. Adani Power has traded at P/B of 4.2x during FY09-10 when merchant realization were higher.

Exhibit 3: 1 Year-Forward P/E

Source: Bloomberg, Karvy Institutional Research

Exhibit 4: 1 year-Forward P/B

100150200250300

15x20x

110130

4xMax 72.9 Min 9.8 Mean 31.3

Max 4.2 Min 2.6 Mean 3.5

July 1, 2011

Adani Power

Investment Rationale • Long-term Fuel Security Remains a Major Concern • FSAs for duration less than economic life – A Concern

• Long-term PPA Exposes Fuel Price Risk

• PPA with GUVNL for Mundra Phase-II – a Swing Factor • Pre-PPA sales to result in high merchant volumes till

I. Long-term Fuel Security Remains a Major Concern APL has planned to operate its plants through a mix of domestic and imported coal. It PL has signed a 15-year FSA with its promoter company, AEL to procure 15.1 MTPA of coal to its projects located in Mundra at US$36 per tonne (CIF) with an average GCV of 5,200kcal per kg. AEL in turn would source coal from its 100%-owned arm PT Adani Global, which has entered into agreements to exclusively mine coal in Bunyu Island, Indonesia. Earlier, APL has obtained domestic linkage for its Mundra Projects (30% of requirements) & Tiroda Project , which has cancelled by the coal ministry. The reserves at Bunyu are estimated at 150 mn tonne (MT), while the Mundra plant when fully commissioned would require 15 MTPA of coal. Though the output in these mines may be ramped up to 7 MTPA, we have concerns on the availability and quality of coal. Again, the Gross Calorific Value (GCV) of coal found in Bunyu is likely to be lower than 5,000kcal per kg, below APL's estimate of 5,200 kcal. However, AEL’s recent 100% acquisition in the Galilee coal tenement in Australia which would take 5-6 yrs for ramp up & ‘Coal Purchase Rights’ for 60% of PT Bukit Assam concessions in South Sumatra provides potential coal supply for the remaining under developments planned capacity but again pricing is the issue. AEL has access to 8 bn tonne of coal reserves in Australia and Indonesia. AEL controls over 50% of market share in overall coal trading in India.

Exhibit 6: Coal Supply Matrix (MTPA) Coal Supply Matrix 2009 2010 2011 2012E 2013E 2014E 2015E Mundra 0 7.4 7.4 17.4 17.4 17.4 17.4 Indonesia - 7.4 7.4 7.4 7.4 7.4 7.4

MCL - 0 0 6.4 6.4 6.4 6.4 Domestic Linkage - 0 0 3.6 3.6 3.6 3.6 Other Domestic Linkage (assumed) - 0 0 0 0 0 0 Tiroda 0 0 0 14.2 14.2 14.2 14.2 South Eastern Coalfields (Grade F) - - - 2.5 2.5 2.5 2.5

Western Coalfields (Grade E) - - - 2.2 2.2 2.2 2.2 Other Domestic Linkage (approved) - - - 4.5 4.5 4.5 4.5

Other Domestic Linkage (applied) - - - 5 5 5 5

Exhibit 5: Annual Coal Requirement (MTPA)

FY09 FY10 FY11 FY12 FY13 FY14 FY15Indonesia Domestic

July 1, 2011

Adani Power

II. Fuel Supply Agreements for duration less than economic life – A Concern AEL has agreed to supply Mundra plant with 4.6 MTPA of coal from Bunyu Islands (Indonesia) at US$36 per tonne CIF with 10% hike after five years. The agreement is for 15 years from commissioning, while the PPA with Gujarat Vidyut Nigam (GUVN) is for 25 years. The reserves at Bunyu Island are estimated at 150 mn tonne (MT), which is suffice for only 10 years. So APL would need to make new fuel supply arrangements to ensure continuity of operations. Again, as it has been found that the GCV of coal imported from Bunyu is lower than the APL’s expectation, APL would need to import South African coal, resulting in higher cost of power generation. As the PPA with GUVNL does not allow passing the power at a higher cost, APL’s profitability would come under pressure, in case the quality of Bunyu coal continues to remain low. Again, if the strip ratio rises due to geographical reasons, AEL will not be able to supply coal at low prices. Unfavourable Changes in Indonesian Mining Laws may Hit Supply: Export of minerals constitutes a major portion of Indonesia's GDP. However, various factors such as declining reserves and low reserve-to-production ratio have forced the country to review its export policies. Major unfavorable changes in Indonesia's mining laws, which curtail the export of coal, would have a severe affect on fuel availability for APL's projects. Exhibit 7: Project-wise Availability & Requirement

Project Capacity Demand (MTPA)

Details of Contract

Mundra- I & II

1,320 MW

3.7 @6,000 Kcal per kg

15-year FSA with AEL to supply 4.6mtpa of coal with GCV of 5,200 kcal per kg +Domestic coal linkages recommended

Mundra- III

1,320 MW

4.06@5,200 kcal per kg

15-year FSA with AEL to supply 4.04mtpa of coal with GCV of 5,200 kcal per kg + Domestic coal linkages recommended

Mundra - IV

1,98 MW 5.81@5,200 kcal per kg

15-year FSA with AEL to supply 6.5mtpa of coal with GCV of 5,200 kcal per kg Letter of intent received from Mahanadhi coal fields MCL to supply coal with GCV of 4,000 kcal per kg

Tiroda - I 1,980 MW

6.18@4,895 kcal per kg

The company has a tapering linkage. Earlier captive coal block allocation at Lohari West has been cancelled. The company is expected to get new captive block allocated in lieu of the cancelled block.

Source: Company, Karvy Institutional Research

Cancellation of Lohara Coal-blocks for Tiroda Project: APL had been allocated coal blocks at Lohara West and Lohara Extension for the Tiroda project. However, the allocation got cancelled by the Ministry of Environment & Forest (MoEF), citing its proximity to the tiger reserve. However, the Company has got a tapering linkage in lieu of the cancelled coal block allocation in the interim period and is expected to be allotted another coal mine in lieu of the Lohara mine.

July 1, 2011

Adani Power

III. Long-term PPA Exposes Fuel Price Risk

The major portion (51%) of generating capacity has been tied-up under Case-I bidding. Out of the 13.2GW capacity, long-term PPAs have been contracted for 7.8GW. Out of the long-term PPAs, 4.7GW (3.4GW from Mundra & 1.3GW from Tiroda) are under Case-I bidding expose to fuel price risk. Thus, any variations in fuel costs will have a direct impact on profitability.

The long-term PPAs at fixed tariffs are expected to ensure steady revenues in the long-term. Moreover, the PPAs entered into by APL under such Case-I bids are at levelised tariffs ranging from Rs. 2.35-3.24 per unit .

Exhibit 9: Projects Details

Projects Capacity Off-take Levelised Tariff PPA Term Procurer Mundra I & II 1,320 1,000 2.89 25 GUVNL Mundra III 1,320 1,000 2.35 25 GUVNL Mundra-IV 1,980 1,424 2.94 25 UHBVNL/DDBVNL Tiroda 1,980 1,320 2.64 25 MSEDCL Tiroda Expansion 1,320 1,200 3.24 25 MSEDCL Kawai 1,320 1,200 3.24 25

Chindwara 1,320 660 25 RRUVNL Dahej 2,640 25 MP GOVT Total 13,200 7,804

IV. PPA with GUVNL for Mundra Phase-II – a swing factor In Feb’11, APL entered into a 25-year PPA for supply of 1,000MW of power from its 1,320MW Phase-II capacity in Mundra for a flat rate of Rs. 2.35 per kWh, subject to certain conditions. As the Mogra-II coal block has been designated as a ‘No-Go Area’ by the MoEF, APL intends to terminate the PPA, which entails a cost of Rs. 1 bn. Although the Gujarat Electricity Regulatory Commission (GERC) ruled against APL on its plea to terminate the PPA, opining that under Case-I bids the source of fuel is not identified, and the onus of fuel availability lies solely with APL, the Company has challenged this ruling in the Appellate Authority.

Out of proposed 6,600MW capacity, Mundra to account for 50% value: APL's total capacity, which currently stands at 1,980MW, is set to increase to 6,600MW by FY13E. With ~4,000MW of capacity in operation by FY12E, the Company enjoys good near-term visibility. The healthy cash inflows generated by the Company would help it fund its future capex.

Exhibit 10: Capacity Addition Highest in Pvt Space (MW)

Source: Company , Karvy Institutional Research

Exhibit 11: APL’s Installed Capacity (MW)

46203400 3100 2900

20001200

FY10 FY11E FY12E FY13E

Exhibit 8: Rs.0.5 fall in merchant price to earnings sensitivity

10,000

15,000

20,000

FY12E FY13ECurrent Revised % Change

(Rs mn) (%)

July 1, 2011

Adani Power

Exhibit 12: Details of projects to be operational by FY13E Project Mundra - I & II Mundra - III Mundra – IV Tiroda Location Gujarat Gujarat Gujarat Maharashtra Installed Capacity 1,320MW 1,320MW 1,980MW 1,980MW Procurement Status BTG & BOP EPC contracts entered EPC contracts entered BTG & BOP contracts

entered Type Coal fired Coal fired Coal fired Coal fired Technology 15-yr FSA with AEL

to supply 4.6 MTPA of coal with GCV of 5,200 kcal/kg + domestic coal linkages recommended

15-yr FSA with AEL to supply 4.04 MTPA of coal with GCV of 5,200 kcal/kg + Domestic coal linkages recommended

15-yr FSA with AEL to supply 6.5 MTPA of coal with GCV of 5,200 kcal per kg. LoI secured from Mahanadhi Coalfields to supply coal with GCV of 4,000 kcal per kg

APL has a tapering linkage. Coal block allocation at Lohari West has been cancelled. APL may get new block allocated in lieu of cancelled block.

Power Off-take Long -term PPA for 1,000MW with GUVNL

Long -term PPA for 1,000MW with GUVNL, merchant sale of up to 221MW of surplus power entered with AEL

Long -term PPA for 1,424 MW (2X715MW) with UHBVNL and DHBNNL

Long -term PPA for 1,320MW with MSEDCL

Merchant Capacity 320MW 320MW 320MW 320MW Expected date of commissioning

Commissioned Unit #1 commissioned, Unit #2 to be commissioned in Q3FY12

Q4FY12 Q1FY13

Project Cost Rs. 43.5 bn Rs. 57.96 bn Rs. 89.6 bn Rs. 92.63 bn Source: Company, Karvy Institutional Research

Exhibit 13: Under-developments Projects Project Water

AvailabilityLand acquisition Environment

clearance Equipment Fuel

Arrangement Off-take Financial

Dahej Sea Water 100% land acquired TOR approved

Pending Linkage applied Not Tied-up Pending

Kawai (1320) Available Land acquired Completed Pending Pending Rajasthan Govt Pending Tiroda II(1320) Available 75% land acquired Pending

Pending Pending MSEDCL 1200 75%

Bhadreshwar Sea Water Land acquired TOR approved

Pending Linkage applied Not Tied-up Pending Chhindwara Pench River 100% land acquired TOR approved

Pending Linkage applied 40% capacity with MP Pending

Power Off-Take Arrangement 2,640MW Mundra- I & II: APL has entered into a long-term PPA with GUVNL for the sale of power, under which GUVNL would buy 1,000MW power from MPP- I & II for 25 years from the date of commercial operations of the plant. The tariff for the contracted power ranges from Rs. 2.81 per unit in the first year to Rs. 3.42 per unit in the last year, with a levelised tariff of Rs. 2.89 per unit and consists of capacity charges (at 80% PLF) and energy charges. Again, for power sold above base PLF of 80%, MPP-I & II is entitled to an incentive of Rs. 0.25 per unit for the power generated and sold. The rest portion of power generated from this plant will be sold on merchant basis. Mundra-III: APL had entered into a long-term PPA with GUVNL for the sale of power. Under the PPA, GUVNL was to buy 1,000MW of power at Rs. 2.35 per unit. However, APL wanted to pull out of the PPA as it could not execute the coal supply agreement with GMDC for the supply of coal. Its stance was that coal supply by GMDC from the Morga coal block to the project was a condition precedent for the PPA and, hence, APL is well within its rights to cancel the PPA. However, in a setback to APL, Gujarat Electricity Regulatory Commission has directed it to honour its PPA signed with GUVNL at the earlier determined rate. Thus, APL will have to utilize imported coal at a higher-than-expected cost to fulfill its obligation and supply power at the

July 1, 2011

Adani Power

earlier agreed price, which would impact its margins considerably. The rest portion of the power generated from this plant will be sold on merchant basis. We have arrived at a per share value of Rs. 51 for Mundra-I, II & III. Valuation: We have arrived at a value of Rs. 51 for Mundra – I, II & III.

Exhibit 14: Financial & Valuation of 2,640MW Mundra I, II & III (Rs mn) FY2012E FY2013E FY2014E FY2015ECapacity 2,640 2,640 2,640 2,640Sales Volume (Mn units) 17,536 19,357 19,357 19,357Competitive 5,442 13,403 15,768 15,768Merchant 12,094 5,954 3,589 3,589Realization Per Unit (Rs) 3.92 3.20 2.78 2.87Net Sales 65,927 60,723 54,038 55,853Operating Expenses 26,183 30,224 31,599 33,037EBITDA 39,744 30,499 22,440 22,815Depreciation 4,595 4,595 4,957 4,957Interest 6,255 6,455 6,248 5,452PBT 28,894 19,448 11,235 12,406Tax 9,598 6,460 3,732 4,121PAT 19,296 12,988 7,503 8,285FCFE 18,653 8,929 5,581 5,653PV 18653 7832 4294 3815NPV (Explicit Period FY12-37) 1,10,296 Per Share 51 Source: Karvy Institutional Research

Mundra IV: APL has entered into long-term pow er PPAs with UHBVNL and DHBVNL for the sale of 1,424MW of electricity. The PPAs are for a term of 25 years from the date of commercial operation of the power project. Under the PPAs, UHBVNL and DHBVNL are entitled to get 712MW of electricity each at a tariff ranging from a maximum of Rs. 3.26 per unit to a minimum of Rs. 2.35 per unit during the terms of the off-take agreements. We have arrived at a value of Rs. 22 per share from Mundra IV.

Valuation: We have arrived at a value of Rs. 22 for Mundra-IV.

Exhibit 15: Financial & Valuation-1,980MW Mundra-IV (Rs mn) FY2012E FY2013E FY2014E FY2015ECapacity 1,320 1,980 1,980 1,980Sales Volume (Mn units) 2,652 11,906 14,293 14,293Competitive 1,000 9,235 11,235 11,235Merchant 1,652 2,672 3,058 3,058Realization Per Unit (Rs) 4 3 3 3Net Sales 9,789 36,177 41,716 41,987Operating Expenses 3,624 17,332 21,683 22,668EBITDA 6,165 18,845 20,033 19,319Depreciation 2,110 422 422 422Interest 381 622 549 475PBT 3,674 17,801 19,062 18,422Tax 82 2,793 3,430 3,436PAT 3,592 15,008 15,632 14,985FCFE (4,846) 1,984 3,950 4,087PV (4,846) 1,741 3,039 2,759PV (FY2012-36E) 54,119Per Share 22Source: Karvy Institutional Research

July 1, 2011

Adani Power

V. Pre-PPA sales to result in high merchant volumes till FY14E The Mundra projects are likely to be commissioned 6-12 months before the start of the long-term PPAs. Power generated during the lag time can be sold under the merchant route. APL's merchant volumes are set to grow from 1,172MU in FY10 to 11,628MU in FY12. Merchant volumes are expected to remain at a high 13,635MU in FY13E as well. Further, if APL is able to terminate the disputed GUVNL contract, merchant sales would increase to 40% of 6,600MW. Beyond 6.6GW, APL is also setting up ~2,640MW projects that are based on bidding. Overall, APL will have ~24% of the capacity as merchant post FY14E. As a result, we expect APL to post healthy OPMs of 62% and 55%, respectively in FY12E and FY13E, respectively. Exhibit 17: Merchant vs. PPA

This will also result in volatility in earnings during these years (Rs. 0.5/kWh change in merchant tariff impacts FY13 earnings by 20%).The merchant volumes should stabilize at 23% levels once all long term PPAs start to kick in. No funding concerns for under developments projects: APL’s power portfolio for its fuel security (50% coal tied up), long-term off-take arrangements (60% of portfolio) and high RoE generation capability (tariffs of Rs. 2.35-3.24/ kWh). Notably, Case-I bid PPAs offer steady near-annuity cash flows over the long-term, with merchant sales providing medium-term fillip to earnings. We estimate internal accrual once all the projects get commercial operation by FY12-13E are expected to meet funding needs for the large development pipeline. The Company’s next phase of capacity addition involves construction of Tiroda 1,980MW, Dahej 2,640MW, Kawai 1,320MW Ratnagiri-II project, 1,320MW Chidawra project. These under-construction & under developments projects would require equity contribution of over Rs. 85 bn over FY12-16E. The operating cash flows generated would be sufficient to fund the equity contribution of under-construction projects, thereby requiring no equity dilution.

Exhibit 19: Equity requirement (Rs mn) Project Capacity Total cost Debt Equity Equity already deployed Equity to be deployed Mundra Phase I,II 1,320 43,500 34,800 8,700 - - Mundra III 1,320 57,960 46,368 11,592 - - Mundra IV 1,980 89,600 71,680 17,920 - - Tiroda 1, 980 92,630 64,841 27,789 17,660 10,129 Kawai 1, 320 59,400 41,580 17,820 6,610 11,210 Chindwara, MP 1320 66,000 46,200 19,800 - 19,800 Dahej 1, 980 99,000 69,300 29,700 - 29,700 Tiroda II 1, 320 66,000 46,200 19,800 4,660 15,140 Total 1,2,540 5,74,090 4,20,969 1,53,121 28,930 85,979 Source: Company, Karvy Institutional Research

PPA (% of total) Merchant (% of total)

Exhibit 16: Pre-PPA Schedule Projects COD PPA Start

DateGap

MonthsMundra III

U1 Sep-11 Aug - 12 11

U2 Jan-12 Feb-13 13

U3 May-12 Feb-13 9

Tiroda I U1 Apr-12 Aug -12 5

U2 May-12 Aug -12 3

U3 Jun-12 Aug -12 2

Exhibit 18: Cash Flow to remain healthy

10,000

15,000

20,000

25,000

FY10 FY11 FY12 FY13

Cashflow from Operation Net Debt/Equity

(Rs mn) (x)

July 1, 2011

Adani Power

Exhibit 20: Financial Assumption

Estimates Growth (%) Comments FY10 FY11E FY12E FY13E FY11E FY12E FY13E Operational Parameters Capacity (MW) 121 1980 3960 6600 1536 100 67 Expecting Mundra & Tiroda to come on stream Sales Volume (MU) PPA 450 3504 6442 29,113 - 84 352 Company has signed PPA with GUVNL. Merchant 412 2992 13,746 11,498 - 359 -16 Merchant to contribute till FY12 (Pre -PPA ) Competitive - - - - - - - JV's (MW) - - - - - - - Gross generation (MU) Commercial generation (MU) 862 6985 21,707 43,858 710 211 56 Volumes to track capacity growth Energy sold (MU) - 6496 20,188 40,610 - 211 55 Aux. consumption (%) 7 7 7 7 0 0 0 Remain unchanged Avg PLF (%) 89 40 63 76 - - - PLF improvements as plants get stablised. Avg PAF (%) 95 95 95 95 0 0 0 Tariffs Avg realization (Rs/unit) PPA 2.6 2.6 2.6 2.6 - 1 -2 PPA signed with GUVNL at Rs 2.23 Merchant 5.5 4.5 4.5 4.1 - -1 -8 Merchant rates to come down Competitive Blended 3.5 3.9 3.0 - 11 -22 Fuel cost Avg Fuel Cost (Rs/unit) 0.8 0.8 0.9 1.0 - 13 11 Avg cost to remain lower on cheaper fuel cost Imported Coal (MT) 1.0 3.2 9.8 15.2 218 207 55 Contract with AEL Domestic Coal (MT) 0.0 0.0 0.0 4.8 - - - Financial Forecasts Sales (Rs mn) 4,349 21,352 75,716 121,920 391 255 61 Sales to track capacity growth Operating Expenses (Rs mn) 1,911 9,147 29,807 58,612 379 226 97 EBIDTA (Rs mn) 2,438 12,205 45,909 63,308 401 276 38 EBIDTA margin (%) 56.1 57.2 60.6 51.9 2 6 -14 Margins to fall on account of lower merchant

realization Net Interest Expense (Rs mn) 376.73 2366.4 10054 19546 528 325 94 Higher on asset capitalization Avg. Interest rate (%) 11% 11% 11% 11% 0 0 0 PAT (Rs. mn) 1,700 5,132 23,946 25,011 817 99 4 PAT margin (%) 39.1 24.0 31.6 20.5 -39 32 -35 To fall on account of lower merchant realization

& higher depreciation costs. EPS (Rs.) 0.8 2.4 11.0 11.5 202 367 4 Cash Flow Forecast (Rs. mn) CFO (a) 9,502 9,474 19,584 8,653 0 107 -56 To remain healthy on the back capacity

commissioning CFI (b) 7,968 2,541 13,350 9,856 -68 425 -26 FCF(a-b) 1,534 6,932 6,235 -1,203 352 -10 -119 CFF - © 9,561 3,000 10,952 5,550 -69 265 -49 Total Changes in cash (a+b+c) 1,109 9,932 17,186 4,347 -10 73 -75 To improve on the back of operating assets. Source: Company, Karvy Institutional Research

July 1, 2011

Adani Power

Karvy vs. Consensus We are lower than consensus at the topline & bottomline level, as we expect lower merchant realization. Exhibit 21: Karvy vs. Consensus Karvy Consensus Difference (%) Revenue (Rs. in mn)

FY12E 75,716 73,017 3.6 FY13E 121,920 1,32,948 (8.2)

EBIDTA (Rs. in mn) FY12E 45,909 45,814 - FY13E 63,308 74,064 (14)

PAT (Rs. in mn) FY12E 23,946 22,891 4.6 FY13E 25,011 31,010 (19.3)

Source: Bloomberg & Karvy Institutional Research

Exhibit 22: Revenue Assumption Consolidated FY11 FY12E FY13E FY14E FY15E Capacity (MW) 1,980 3,960 6,600 6,600 6,600 Sales Volume (MU)

PPA 3,504 6,942 31,901 36,730 36730 Merchant 2,992 11,628 8,709 11,438 11438

Total 6,496 18,570 40,610 48,167 48,167 As a % of total

PPA (% of total) 53.9 37.4 78.6 76.3 76.3 Merchant (% of total) 46.1 62.6 21.4 23.7 23.7

Tariff PPA 2.6 2.7 2.8 2.8 2.8 Merchant 4.5 4.5 4.1 3.6 3.6

Blended 3.5 3.8 3.1 3 3 Coal Requirement

Imported Coal (MT) 3.2 9 15.2 16.3 16.3 Domestic Coal 0.0 0.0 4.8 7.5 7.5

Total 3.2 9.0 20.0 23.8 23.8 As a % of total

Imported Coal 100 100 76 68.6 68.6 Domestic Coal 0.0 0.0 24 31.4 31.4

Source: Bloomberg , Karvy Institutional Research

Downside & Upside Risks In our view, the key downside risks are:

I. Lower availability and/or poor quality of imported coal from AEL,

II. Increase in the price of spot imported coal, and III. More than anticipated fall in merchant power rates in the long

In our view, the key upside risks are: I. Speedy execution of projects, and II. Higher than expected rates in the near to medium term.

July 1, 2011

Adani Power

Financial Overview Profitability to peak in FY13E

APL is set to witness a stupendous rise in its end-capacity of 660MW in FY10. Its capacity – which currently stands at 1,980MW – is likely to touch 3,960MW in FY12E and 6,600MW in FY13E. As a result of this huge capacity addition, APL's topline is likely to soar from Rs. 4,349 mn to Rs. 121,920 mn over FY10-13E. We estimate APL’s earnings would peak in FY13E with the commissioning of all under construction projects.

Exhibit24: Topline Set To Grow at CAGR of 200% (FY10-13)

Operating Margins to contract post-FY13E

We expect APL to enjoy healthy operating margins in excess of 50% till FY13E due to high volume of merchant sales. However, the margins are likely to show a substantial decline (870 bps) in FY13E due to higher PPA sales in its overall sales volume.

Exhibit 25: Robust Growth in Ops Profits & Healthy Ops Margins

100000

150000

FY10 FY11 FY12 FY13Net Sales (Rs mn) Growth (%)

FY10 FY11 FY12 FY13Operating profits (Rs mn) OPM (%)

(Rs mn)

Ex 23: Merchant Profits / Total Profit

FY11 FY12 FY13Profits Merchant profits(%)

(Rs mn) (%) (%)

July 1, 2011

Adani Power

Bottomline to witness Robust Growth with Strong Operating Performance

APL's bottomline is expected to grow from Rs. 1700 mn in FY10 to Rs. 25011 mn in FY13E, primarily driven by growth in its operational profit. APL's interest and depreciation costs are also set to surge post the commissioning of plants.

Exhibit 26: Net Profit to grow at 143% CAGR FY10-13E

Return Ratios – RoE to peak in FY13E

We estimate Return-on-Equity (RoE) would peak in FY13E, and would decline subsequently capex in FY10-11 will get capitalized.

Exhibit 27: Healthy Return Ratios

10,000

15,000

20,000

25,000

30,000

FY10 FY11 FY12 FY13Net Profits (Rs mn) NPM (%)

FY10 FY11 FY12 FY13

ROCE (%) ROE (%)

(Rs mn)

July 1, 2011

Adani Power

Exhibit 28: Profit & Loss Statement Y/E March (Rs mn) FY09 FY10 FY11 FY12E FY13E

Net revenues 0 4,349 21,352 75,716 121,920 % Growth - - 391 255 61 Raw Material 0 1,667 7,213 25,435 49,573 Staff 0 46 322 0 0 Operating Expenses 55 198 1,612 4,373 9,039 Operating expenses 55 1,911 9,147 29,807 58,612 EBIDTA (55) 2,438 12,205 45,909 63,308 % Growth - - 400 276 38 EBIDTA margin (%) - 56.1 57.2 60.6 51.9 Other income 0.0 319 180 340 220 Interest 0.0 377 2,366 10,054 19,546 Depreciation 0.0 353 1,886 6,288 12,745 Profit Before Tax (55) 2,027 8,132 29,906 31,237 % Growth - - 301 268 4.4 Provision for tax 0.0 327 3000 5960 6225 Effective tax rate (%) 0.0 16.1 36.9 19.9 19.9 Adjusted Net Profit (55.4) 1,700 5,132 23,946 25,011 % Growth - - 202 366 4.4 Net Margin (%) - 39.1 24.0 31.6 20.5 Reported Net Profit (55) 1,700 5,132 23,946 25,011 % Growth - - 202 366 4.4

Exhibit 29: Balance Sheet Y/E March (Rs mn) FY09 FY10 FY11E FY12E FY13E

Equity capital 18,420 21,800 21,800 21,800 21,800 Reserves & surplus 4,467 35,980 41,111 65,057 85,708 Shareholders funds 22,887 57,780 62,911 86,857 107,508 Minority 699 1,023 1,023 1,023 1,023 Long Term Loans 49,897 105,705 135,705 245,220 300,715 Total Loans 49,897 105,705 135,705 245,220 300,715 Deferred tax liability 0 120 0 0 0 Total Liabilities 73,483 164,664 199,639 333,100 409,247 Gross block 3,472 28,549 101,460 190,560 289,660 Depreciation 104 678 2,564 8,852 21,597 Net block 3,368 27,871 98,897 181,708 268,063 Capital WIP 65,889 127,691 80,190 124,587 124,049 Investments 0 1 1 1 1 Inventory 0 2,658 2,513 6,321 15,395 Cash 5,585 11,654 11,098 18,296 6,177 Loans & advances 4,163 9,406 9,406 9,406 9,406 Current Assets 9,749 23,718 23,017 34,023 30,978 Other current liabilities 5,620 14,617 2,465 7,218 13,845 Curre nt Liabilities 5,620 14,617 2,465 7,218 13,845 Net current assets 4,129 9,101 20,552 26,805 17,134 Deferred expenditure 97 0 0 0 0 Total Assets 73,483 164,664 199,639 333,100 409,247 Source: Company , Karvy Institutional Research

July 1, 2011

Adani Power

Exhibit 30: Cash Flow Statement (Rs mn) FY2009 FY2010 FY2011E FY2012E FY2013E EBIT (5.5) 208 1,031 3,962 5,056 (Inc)/Dec in working capital 5,042 7,916 1,009 (7,456) (35,575) Cash flow from operations 5,037 8,124 2,041 (3,494) (30,519) Other income 0.0 319 179 340 220 Depreciation 0.0 353 1,885 6,288 12,745 Interest paid 0.0 377 2,366 10,054 19,546 Dividends paid 0 0 0 436 436 Tax paid 0.0 327 3,000 5,960 6,225 Net cash from operations 5,037 9,502 9,474 19,584 8,653 Capita l expenditure (4,475) (7,967) (2,541) (13,349) (9,856) Free Cash Flows 562 1,534 6,932 6,235 (1,203) Inc/(Dec) in LT borrowing 3,978 5,580 3,000 10,951 5,549 Inc/(Dec) in Equity capital 852 3,425 0.0 0.0 0.0 Others 0.0 554 0.0 0.0 0.0 Cash from financial activities 4,831 9,561 3,000 10,952 5,550 Opening Cash 192 558 1,165 1,109 1,829 Closing Cash 5,585 11,653 11,098 18,296 6,177 Change in Cash 5,393 11,095 9,932 17,186 4,347 Source: Company , Karvy Institutional Research

Exhibit 31: Key Ratios (%) FY2009 FY2010 FY2011 FY2012E FY2013E Raw Material Cost / Sales - 38 34 34 41 Manpower Cost / Sales - 1 2 0 0 Operating & Other cost / Sales - 5 8 6 7 Revenue Growth - 435 391 255 61 EBIDTA Margins - 56.1 57.2 60.6 51.9 PAT Margins - 39.1 24.0 31.6 20.5 ROCE (0.1) 1.8 5.7 14.9 13.6 ROE (0.3) 4.2 8.5 32.0 25.7 Core ROCE 0.0 15.3 15.4 26.5 21.6 Core RoE 0.0 19.1 19.2 44.8 28.1 Source: Company , Karvy Institutional Research

Exhibit 32: Valuation Parameters FY2009 FY2010 FY2011 FY2012E FY2013E EPS (Rs) (0.0) 0.8 2.4 11.0 11.5 PER (x) - 141.1 46.7 10.0 9.6 Book value per share 12 27 29 40 49 P/B (X) 8.9 4.2 3.8 2.8 2.2 EV/EBIDTA (x) - 136.9 29.9 9.2 7.7 Fixed assets turnover ratio (x) 0.0 0.3 0.3 0.5 0.5 Debt/Equity (x) 1.9 1.6 2.0 2.6 2.7 EV/Sales (x) - 76.8 17.1 5.6 4.0 Source: Company & Karvy Institutional Research

June 30, 2011

POWER July 1, 2011

CESC Bloomberg: CESC IN Reuters: CESC.BO BUY

Recommendation CMP: Rs 299 Target Price: Rs 381 Upside (%) 27%

Stock Information Market Cap. (Rs bn / US$ mn) 37/831 52-week High/Low (Rs) 433/252 Shares Outstanding (mn) 125 3m ADV Rs mn 31.3/USDmn 0.7 Beta 0.96 Sensex 18,846 Nifty 5,647

Stock Performance (%) 1M 3M 12M YTD Absolute 7.1 (3.8) (20.6) (18.2) Rel. to Sensex 5.2 (0.7) (27.1) (10.1)

Performance

1 Year Forward P/B

225275325375425475

16,000 17,000 18,000 19,000 20,000 21,000 22,000

Sensex (LHS) CESC (RHS)

200400

Correction is Overdone – Expect Stock to Rise The stock price of CESC has corrected almost 17% since Jan’11, while the BSE Power Index corrected by 13% during the same period. We believe that the correction is overdone and stock is currently trading at attractive levels and trading below its book value. Looking forward, we believe that CESC’s earnings from power business – being used to fund losses of its retail arm i.e. Spencer's – would decline as its retail business has started showing positive EBITDA at the store levels. Stable & Regulated Biz with Assured RoE CESC operates under regulated business model, which provides the Company with strong and steady income flow. Currently, CESC caters mainly to Kolkata region and with a capacity of 1,225MW with assured RoE at 15.5% & RoE of 15% on distribution. We expect the equity base of the regulated business to grow to Rs. 34 bn by FY14E from Rs. 26 bn in FY11. Capacity seen at 2,450MW by FY14E – Four Mega Power Projects in the Offing With commissioning of 600MW capacity each at Chandrapur (Maharashtra) & Haldia (West Bengal), CESC would touch 2,450MW capacity mark by FY14E from 1,250MW currently. It plans to sell 500MW-300MW power from Chandrapur on merchant basis & 200MW power from Haldia – as merchant in FY14E, but we believe it is still long away. Loss in Retail Biz to Decline – Profits Expected by FY14E CESC’s retail business has been incurring losses, which peaked in FY09 at Rs. 2.5 bn. It has closed 60 loss making stores over FY09-11 to reduce loss. We expect the losses in its retail business to reduce from Rs. 1.4 bn in FY11 to Rs. 710 mn in FY13E & Rs. 70 mn profits in FY14E. We expect CESC would register positive EBITDA by FY13E – with the rerating of its power business – as it would cease to fund retail business out of its income from core business. Outlook & Valuation At its current price, the stock is trading at 0.7x FY13 BV, which in our view does not reflect the strength in its core assured RoE power business, progress on expansion and the expected turnaround of retail business. We expect peak value to be created for CESC in FY14-15E, when its future projects would start commercial production. We have valued power business on FCFE methodology to arrive at Rs. 296 per share. Valuing Spencer's on EV/sales basis, we have assigned Spencer’s EV/sales ratio of 0.4x FY12E sales. Thus, the total value of its retail business works out to Rs.22 per share. Valued CESC’s mall in Central Kolkata and land in Mulajore on NAV basis, we have arrived at a price of Rs. 8 per share for its realty business. We initiate coverage on the stock with a “Buy” recommendation. Exhibit 1: Key Financials Y/E March (Rs. in mn) FY09 FY10 FY11 FY12E FY13E Net Sales 41,083 42,662 49,420 58,757 65,885 EBIDTA 2,250 4,308 7,520 7,963 8,661 Net Profit 763 1,564 2,980 3,938 5,309 EPS (Rs) 6.1 12.4 23.7 31.4 42.3 PER (x) 49.4 24.1 12.6 9.6 7.1 EV/EBITDA (x) 22.9 14.2 8.3 9.7 10.4 Source: Company , Karvy Institutional Research

Initiating Coverage

June 30, 2011

Company Background CESC is generating and distributing power in Kolkata and Howrah since 1899. It is the sole distributor of electricity within an area of 567 square kms of Kolkata & Howrah serving 2.3 mn consumers, which includes domestic, industrial and commercial users. CESC owns and operates four thermal power plants generating 1,225MW power. These are Budge Budge Generating Station (750MW), Southern Generating Station (135MW), Titagarh Generating Station (240MW) and New Cossipore Generating Station (100MW). More than 50% of the coal requirement is sourced from captive mines. CESC owns and operates the T&D system comprises of 474 kms circuit of transmission, and 85 distribution stations; 3,837 kms circuit of HT lines further linking distribution stations with LT substations, large industrial consumers and 9,867 kms circuit of LT lines connecting the LT substations to LT consumers.

Company Financial Snapshot Consolidated Profit & loss Rs. in mn FY2011E FY2012E FY2013E

Net revenues 49,420 58,757 65,885 EBIDTA 7,520 7,963 8,661 Interest 2,990 2,571 2,339 Depreciation 3,160 3,364 3,614 Profit before Tax 3,510 4,818 6,072 Provision for tax 530 880 763 Adjusted Net Profit 2,980 3,938 5,309 Reported Net Profit 2,980 3,938 5,309 Profit and Loss Ratios EBIDTA Margins (%) 15.2 13.6 13.1 PAT Margins (%) 6.3 7.4 8.1 EV/EBIDTA (x) 8.3 9.7 10.4 PER (x) 12.6 9.6 7.1 P/B(X) 1.1 0.8 0.7

Consolidated Cash Flow Rs. in mn FY2011E FY2012E FY2013E

EBIT 4,360 4,598 5,048 (Inc)/Dec in working capital 415 5,212 39 Cash flow from operations 4,775 9,810 5,087 Other income 2,140 2,791 3,363 Depreciation 3,160 3,364 3,614 Interest paid 2,990 2,571 2,339 Tax paid 530 880 763 Net cash from operations 6,555 12,514 8,961 Capital expenditure 7,486 28,376 20,941 Free Cash Flows (931) (15,862) (11,980) Cash from Financial Activities 1,540 9,977 11,917 Opening Cash 11,680 12,290 6,405 Closing Cash 12,290 6,405 6,342 Change in Cash 610 (5,885) (63)

Consolidated Balance Sheet Rs. in mn FY2011E FY2012E FY2013E

Shareholders funds 47,006 62,644 67,365 Total Loans 41,300 50,484 62,968 Deferred tax liability 14,490 14,490 14,490 Total Liabilities 102,796 127,619 144,823 Net block 79,846 80,539 79,209 Investments 4,170 4,374 4,374 Net current assets 5,810 5,417 5,294 Total Assets 102,796 127,619 144,823 Balance Sheet Ratios

ROCE (%) 8.5 7.0 6.6 ROE (%) 6.3 6.3 7.9 Debt/Equity (x) 0.9 0.8 0.9 EV/Sales (x) 1.3 1.2 1.2

Revenue split by product FY11

Source: Company

Power Segment,

Retail segment,

Shareholding pattern (March 2011)

Source: Company

FIIs19%

MFs17%

Promoters53%

Public11%

June 30, 2011

Outlook & Valuation As the stock trades at significant discount to fair-value and its peers, we prefer CESC as a safe bet at the current valuation on account of:

I. “Low Risk-Low Return” model of regulated power business – Strong cash-flows aid execution in expansion plans

II. Doubling Capacity by FY14 – Significant improvement in operational assets

III. Fuel linkages in Place IV. Recovery in Spencer’s retail business – We see a break-even in FY14E

At the CPM, the stock trades at 0.8 x FY12E and 0.7x FY13E P/ABV, respectively (adjusted book value is networth adjusted for the revaluation reserve of Rs. 16.2 bn in the books), and 7.4x EV/EBIDTA of FY12E and 7.7x FY13E, which we believe is at a significant discount to its fair value. Going forward, we expect discount to narrow due to improving financials of Spencer’s and capacity addition. Key Triggers for further valuation spikes:

I. Lower losses in retail business II. Part or full divestment of stake in retail business III. Substantial progress in under developments projects than

anticipated We have arrived at a SOTP-based target price of Rs. 381 for the stock, by independently valuing CESC’s power business, investments and other JVs. We have valued power business on FCFE methodology to arrive at Rs. 296 per share, Spencer's on EV/sales basis ratio of 0.4x FY12E sales. Thus, the total value of its retail business works out to Rs. 19 per share. We have valued CESC’s mall in Central Kolkata and land in Mulajore (35 acres) on NAV basis and have arrived at a price of Rs. 8 per share for its real estate business. Our “Buy” recommendation on the stock implies 27% upside form current levels.

Exhibit 2: SOTP Valuation Project Capacity COD Cost of

Equity Val

method Stake% Milestone

Discount CESC's

Value Rs per

share Kolkata License area 1250 Operational 14% FCFE 100 0 28,193 225 Chandrapur 600 Under construction 14% FCFE 100 0 5291 42 Haldia 600 Under construction 15% FCFE 100 0 3643 29 Spencer - - EV/Sales 95 0 2427 19 Real Estate - - NAV 100 0 966 8 Cash on books (Adjusted for(FY11)

7189 58

Total Rs. per share 381 Source: Karvy Institutional Research

CESC is trading at P/B of 0.7x & P/E 7.1x based on FY13E, which at significant discount at 50% & 73% to its historical average of 1.4X P/B & 26.9X P/E respectively. CESC has traded at P/B of 1.5-2x during FY09-11, when earning growth of 4% during FY09-11. We expect earning CAGR growth of 33% during FY11-13E.

Exhibit 3: 1 Yr. Forward P/E

Exhibit 4 : 1 Year Forward P/B

25125225325425525625725825

200400

2xMax 77.3 Min 8.1 Mean 26.9

June 30, 2011

Investment Rationale • Strong cash flows from the Regulated Business with Assured

Returns – expansion plans can get executed without sweat • Signigifcant Expansion in Operational Assets - Doubling Capacity

by FY14E • Valuation of Operational /Construction Assets • Fuel Linkages • Retail business to Breakeven in FY14E – Valued at Rs.19/- per

share • Real-estate business …expected to see activity – Valued at Rs. 8/- per

I. Strong cash-flows from the Regulated Business with Assured Returns – Expansion plans can get executed without sweat We believe that the regulated business model provides CESC with steady income flow. CESC with a capacity of 1,225MW (1,600MW peak load) has assured Return-on-Equity (RoE). We expect the equity base of the regulated business to grow to Rs. 34 bn by FY14E from Rs. 26 bn in FY11. This should provide the Group with sufficient additional cash and equity to execute its existing expansion plans. The Company’s next phase of capacity addition involves the construction of 132-MW facility in Orissa and 600MW facility in Jharkhand, and 1,320MW facility in Balagarh. These under-construction & under-developments projects would require equity contribution of over Rs. 41 bn over FY12-14E. The operating cash flows generated expected to be Rs. 31 bn over the same period thereby requiring fund raising. Exhibit 6: Funding Requirement (FY12-14E)

Parameters Rs mnConstruction 15000Under developments 20000Distribution 750Total Power Business 35750Retail (Losses + Capex) 5500Total Funding requirements 41250Cash in hand + Internal accrual (FY12-14) 33000Net funding requirements 8250Source: Company , Karvy Institutional Research

Exhibit 7: Operational Project Details

Projects Capacity (MW)Operational Budge Budge 750New Cossipore 100Titagarh 240Southern 135Total 1225Source: Company, Karvy Institutional Research

Exhibit 5: Cashflow to remain healthy

10,000

15,000

FY2010 FY2011E FY2012E FY2013ECashflow from Operation Net Debt/Equity

Rs mn (X)

June 30, 2011

Demand pattern in the Licence Area The current peak demand in the Kolkata license area is 1,500MW, which has been rising by 5-7% annually over the past few years. As a result, the Budge Budge generating station is operating consistently at above a 100% PLF. CESC meets Kolkata power demand largely through its own generating stations. However, during peak load, CESC buys power from WBSEB and other sources, while during off-peak hours it sells power to maintain high PLFs at generating stations. Its power business has been driven by robust demand in Kolkata and steady growth in customer base over past 10 years. Its operating performance has improved steadily over the years, with its PLF improving from 72% in FY01 to 98% in FY11. We believe that CESC will see significant expansion beyond West Bengal once its Chandrapur & Haldia plants become operational in FY14E. CESC has 3.3GW new projects in the pipeline in Orissa, Jharkhand and Bihar. We have not included them in our valuation as these projects are still under developments stages. However, we believe that on commissioning, these projects would provide upside to CESC’s earnings post FY15E.

II.Signigifcant Expansion in Operational Assets - Doubling Capacity by FY14E We believe that CESC will see significant expansion beyond West Bengal once its Chandrapur & Haldia plants become operational in FY14E, as it intends to transform from a regional to a national player in the Indian power utilities. To begin with, CESC plans to commission at Chandrapur (Maharashtra) & Haldia (West Bengal) – 600MW. The project pipeline includes:

• Orissa: For 1.3GW project in the state – having high probability for 12 th Plan coal linkages – substantial land has been acquired,

• Jharkhand: For 1GW project in the state – with a captive coal mine – the land acquisition has commenced,

• Bihar: For 1GW project in the state, land acquisition has started, and • West Bengal: For 1.3GW expansion in Haldia, the TOR has been

approved.

Exhibit 8: Projects Details

Project Land acquisition

Environment clearance

Equipment Fuel Arrangement

Off-take Financial

Chandrapur (600)

Land acquired

Completed Order placed

Linkage 50% MSEDCL,50% Merchant

Haldia Phase1 (600)

Land acquired

Completed Order Placed

70% linkages 75% state & 25% merchant

Achieved

Orissa 1320 Land acquired

Completed Not placed Awaiting for linkage

50% MSEDCL,50% Merchant

Not achieved

Balagarh 1320 Land acquired

Pending Not achieved

Jharkhand 600

Land acquired

Pending Not achieved

June 30, 2011

III. Valuation of Operational / Construction Assets A. Kolkata License Area (1,250MW) - (Operational & valued @ Rs. 225)

Exhibit 9: Financials & Valuation for Kolkata License Area FY12E FY13E FY14E FY15E

Capacity 1225 1225 1125 1125 Sales Volume (mn units) 8,554 8,628 8,195 8,151 Net Sales 43,691 46,684 47,885 50,343 Operating Expenses 33,101 36,348 37,284 39,445 EBITDA 10,589 10,336 10,600 10,898 Depreciation 2,928 3,116 3,304 3,481 Interest 2,267 2,074 2,020 2,019 PBT 7,661 7,220 7,296 7,417 Tax 791 683 678 670 PAT 4,389 4,225 4,339 4,446 FCFE 3,388 3,214 3,680 4,220 PV 3,389 2,819 2,832 2,848 NPV (Explicit Period FY12-20E) 28,193 CESC's stake (%) 100% Per Share 225

B. Haldia Power Project – Under Construction – Commissioning FY15E – Valued at Rs. 29 per share

The 600MW Haldia Power Project (Phase-I) had been delayed due to land-acquisition issues, and is set to start construction in Sept’11 and CoD is expected by May’14. CESC has already secured environmental and other clearances including water consumption for the project, while the coal linkage has also been obtained. Given that Haldia Phase–I has been classified as a coastal project, CESC can use only 70% of available coal linkage from Mahanadi Coalfields, and 30% of the required coal would have to be imported.

Exhibit 11: Financials & Valuation for Haldia Project FY15E FY16E FY17E FY18E

Capacity (MW) 600 600 600 600Sales Volume (mn units) 4,336 4,730 4,730 4,730Realization Per Unit (Rs) 2.9 3.0 3.0 3.1Net Sales 11,641 12,972 13,019 13,068Operating Expenses 7,435 8,111 8,111 8,111 EBITDA 3,945 4,569 4,616 4,663 Depreciation 1,175 1,282 1,282 1,282 Interest 430 620 590 561 PBT 2,340 2,668 2,744 2,821 Tax 466 532 547 562 PAT 1,874 2,136 2,197 2,259 FCFE (969.0) 1,928.1 2,158.0 2,218.7 PV (482) 834 811 725 NPV(Explicit Period FY15-40) 3,643 CESC's stake (%) 100% Per Share 29.0

Exhibit 10: Sensitivity Analysis Ke/Terminal Growth

1% 2% 2.5% 3% 3.5%

12% 252 267 273 285 252 13% 230 242 246 256 230 14% 213 222 225 232 213 15% 198 205 208 214 198 Source : Karvy Institutional Research

June 30, 2011

C. Chandrapur-Dhariwal Infrastructure: Under Construction – Commissioning FY14E - Valued at Rs. 42 per share The plant is located 150 kms from Nagpur and has secured land totaling 450 acres from MIDC, received water linkages, and received LoA from Coal India for supply of coal. The plant has signed a PPA for 300MW with MSEDCL on a cost-plus basis, allowing CESC to sell the balance 300MW through Case-I bids / power exchange / traders. The plant has also achieved financial closure, and the BTG and BOP orders have been given to Shanghai Electric and Punj Lloyd, respectively.

Exhibit 12: Financials & Valuation for Chandrapur-Dhariwal Infrastructure FY14E FY15E FY16E FY17E

Capacity (MW) 600 600 600 600Sales Volume (mn units) 2,819 4,257 4,730 4,730Realization Per Unit (Rs) 3.5 3.4 3.4 3.5Net Sales (Rs mn) 8,969 13,345 14,846 15,012Operating Expenses (Rs mn) 6,473 9,547 10,541 10,541EBITDA 2,294 3,498 3,971 4,133Depreciation 1,011 1,102 1,102 1,102Interest 354 553 547 524PBT 929 1,842 2,321 2,506Tax 180 356 449 484PAT (Rs mn) 750 1,486 1,873 2,022FCFE (1,615) 830 1,635 1,977PV (839) 378 653 693NPV (Rs mn) 5,291CESC's stake (%) 100Per Share 42

IV. Fuel Linkages CESC has increased generation capacity by over 25%. It depends on domestic coal for most of its fuel requirements. About 50% of its coal requirements are met through Integrated Coal Mining (ICML), which is a group company, while 40% is linkage from Eastern Coalfields & Bharat Coking Coal (Coal India arms), and the balance is imported from Indonesia.

Exhibit 13: Coal Supply Matrix Fuel Requirements FY10 FY11 FY12 FY13 Imported Coal (MT) 0.48 0.48 0.48 0.48 Domestic Coal (MT) 4.63 5.26 6.14 6.23 Total Fuel requirements 5.10 5.73 6.62 6.70

Supply Arrangements ICML (Captive mines) 2.55 2.87 3.31 3.35 Eastern coalfields (Linkage) 2.0 2.3 2.6 2.7 Imported Coal 0.51 0.57 0.66 0.67 Source: Company, Karvy Institutional Research

June 30, 2011

V. Retail Business to Breakeven in FY14E – Valued at Rs. 19 per share CESC forayed into retail business with acquisition of Spencer’s Retail in 2007, and currently it holds 94.70% in Spencer’s, which loss declined 36% to around Rs. 1.4 bn in FY11, as against Rs. 2.2 bn loss in FY10. Spencer’s has about 216 stores with total area of 8.9 lakh square feet. Notwithstanding several steps CESC has taken to curtail losses mainly closing small unviable stores and changing product mix, the retail business is likely to continue to register loss in FY12E and FY13E. Its retail arm is expected to register about Rs. 1.1 bn loss in FY12E and Rs. 700 mn loss in FY13, while it is likely to post Rs. 70 mn profit in FY14E helped by the restructuring initiatives taken by the Company. Its gross margins expected to improve by 400 bps from 14% to 18% on the back of increased sales from the high margin non-food segment. We expect Spencer’s to breakeven only by FY14E on the back of increase in volumes and margin expansion. The Government is mulling a proposal to allow Foreign Direct Investment (FDI) in multi-brand retail. In case the Government allows FDI in multi-brand retail and any strategic partner stake sale in CESC’s retailing business, it would be a big positive trigger for CESC.

Retail Business – Spencer’s – Key Assumption

Exhibit 14: Spencer’s Key assumption FY12E FY13E FY14ENo. of Stores* 218 256 293 Area (mn square feet) * 1.27 1.79 2.16 Sales 12,901 17,171 23,076 Sales per square feet 10,028 10,212 10,860 Gross Margin 2,097 2,974 4,445 Gross Margin per square feet 1,630 1,769 2,092 Employee Cost 949 1,116 1,269 Employee Cost per square feet 737 664 597 Rental Cost 732 957 1,089 Rental Cost per square feet 569 569 512 EBITDA (905) (438) 870 EBITDA per square feet (703) (261) 409

June 30, 2011

VI. Realty Business expected to see activity – Valued at Rs. 8 per share CESC formed CESC Properties, a 100%-owned subsidiary in Apr’07. Land was leased by CESC to CESC Properties for 30 years. The Company has got huge land bank due to closure of its age old plant at Mulajore and office spaces in and around Kolkata. The Company has a land bank of 35 acres after closing down its Mulajore plant, which it intends to develop as a commercial or residential property in the future. It has got another 3 acres of land in central Kolkata in which it is planning to construct a mall of 4 lakh square feet construction area.

For valuing the mall, we have assumed a conservative rental of Rs. 70 per square feet per month, occupancy rate of 80% and capitalization rate of 12%. Accordingly, the mall property NAV works out to Rs. 1.3 bn, which translates into Rs. 7.2 per share of CESC after considering a 30% share to power consumers and holding company discount of 25%.

The Mulajore land bank of 35 acres would be developed in the future. We have assumed Rs. 250 per square feet for valuing the land bank. Accordingly, the value of the land comes to Rs. 229 mn. We expect the mall to generate Rs. 230 mn cash per year from FY13E.

CESC Properties – Key Assumptions

Exhibit 15: CESC Properties – Key Assumptions Mall - Central Kolkata Square feet area (in mn) 0.4 Occupancy Rate (%) 80% Occupancy area (mn square feet) 0.32 Rental per square feet (Rs per month) 65 Annual revenue (Rs. mn) 250 Capitalization rate 12% Value of property (Rs mn) 2,080 Development and other expenses 40% Net Asset Value (Rs. mn) 1,248 Per share value (Rs.) 10 CESC's share (at 67%) Rs.(A) 6.7Mulajore land Area (in Acres) 35 Total Square feet 1,524,600 Value (Rs per square feet) 150 Total land value (Rs mn) 229 Rs per share of CESC 1.8 CESC's share (Rs) (B) 1.2 Total value of real estate 984 per share (Rs) (A+B) 8Source: Company, Karvy Institutional Research

June 30, 2011

Exhibit 16: Financial Assumption Estimates Growth (%) Comments FY10 FY11E FY12E FY13E FY11E FY12E FY13E

Operational Parameters Capacity (MW) 975 1100 1225 1225 12.8 11.4 0.0 We expect Installed capacity to remain at the

same level Sales Volume (MU) 8,696 9,027 9,384 9,755 3.8 4.0 4.0 Volumes to grow at 4% on PLF

improvements PPA 8,696 9,027 9,384 9,755 3.8 4.0 4.0 100% PPA with Kolkata licence area Merchant 0 0 0 0 No merchant based Capacity JV's (MW) 0 0 0 0 100% stake in operational projects Gross generation (MU) 7,299 8,275 9,342 9,424 13.4 12.9 0.9 We expect FY12 volumes to be higher on

account of stabilization of Budge Budge plant Commercial generation (MU)

6,676 7,573 8,554 8,628 13.4 13.0 0.9 We expect same level of aux. consumption

Energy sold (MU) 8,374 8,688 9,045 9,416 3.7 4.1 4.1 Aux. consumption (%) 9 9 9 9 0.0 0.0 0.0 We don’t expect any improvement Avg PLF (%) 97 89 95 105 - - - PLF to improve on higher fuel availability Avg PAF (%) 94 95 95 95 - - - PAF to remain at the same level Tariffs Avg realisation (Rs/unit) 4.97 5.20 5.43 5.74 4.5 4.5 5.7 Avg realization to improve on account of

recent tariff revision by WBSEB PPA 4.97 5.20 5.43 5.74 4.5 4.5 5.7 100% PPA with Kolkata licence area Fuel cost Avg Fuel Cost (Rs/unit) 1.3 2.0 2.3 2.5 50.8 16.7 8.1 Fuel costs to gone up on rising coal prices Imported Coal (MT) 0.48 0.48 0.5 0.5 0.0 0.0 0.0 No additional requirements of imported coal Domestic Coal (MT) 4.63 5.26 6.1 6.2 13.6 16.8 1.4 Domestic cola expected to gone up on higher

generation Financial Forecasts Sales (Rs mn) Power 33,144 39,370 46,464 49,523 18.8 18.0 6.6 We expect 14% CAGR growth in sales on

account of 7% volume & 5.5% higher tariff Retail 9,518 10,048 12,293 16,362 5.6 22.3 33.1 We expect reta il business to grow at 22%

CAGR on account of higher per sq ft revenue & increase in trading area.

Total Sales 42,662 49,418 58,757 65,885 15.8 18.9 12.1 Consolidated sales to grow at 16% CAGR driven by higher capacity & trading area.

Operating Expenses (Rs mn)

38,354 41,900 50,795 57,224 9.2 21.2 12.7 We expect operating expense grow at higher pace tan sales on account of higher fuel cost

EBIDTA (Rs mn) 4,308 7,520 7,963 8,661 74.6 5.9 8.8 We expect growth in EBITDA higher than sales growth on better operating performance in retail business

EBIDTA margin (%) 10.1 15.2 13.6 13.1 50.7 -10.9 -3.0 We expect margins to improve mainly because of higher retail business

Net Interest Expense (Rs mn)

2,614 2,990 2,571 2,339 14.4 -14.0 -9.0 Net interest expenses to come down of loan repayment

Avg. Interest rate (%) 10 11 11 11 1.5 0.9 0.8 Interest cost to go up marginally on higher interest on working capital

PAT (Rs. mn) 1,564 2,980 3,938 5,309 90.6 32.2 34.8 PAT to grow at a CAGR of 50% on account of higher capacity & lower losses from retail business.

PAT margin (%) 4 6 7 8 64.5 11.2 20.2 PAT margins to see improvement on lower losses.

EPS (Rs.) 12 24 31 42 90.6 32.2 34.8 EPS to grow on lower losses of retail business & capacity additions.

Cash Flow forecast CFO (a) 3,620 6,555 12,514 8,961 81.1 90.9 -28.4 CFO to improve on the back of capitalization

of power asset CFI (b) 13,342 7,486 28,376 20,941 -43.9% 279.1% -26.2% Capex for Chandrapur & Haldia projects FCF(a-b) (9722) (931) (15862) (11980) CFF - © 8,329 1,540 9,977 11,917 -81.5% 547.7% 19.4% Debt financing for Chandrapur & Haldia

projects Total Changes in cash (a+b+c)

(1393) 610 (5885) (63)

June 30, 2011

We are above consensus estimate on topline for FY12E due to higher PLF assumption; however we are in-line with consensus for FY13E.

Exhibit 17: Karvy vs. Consensus Karvy Consensus Difference (%) Revenue (Rs. mn)

FY12E 58,757 56,668 3.6 FY13E 65,887 63,959 3.0

EBIDTA (Rs. mn)

FY12E 7,963 8,737 (8.8) FY13E 8,661 11,836 (26.8)

PAT (Rs. mn)

FY12E 3,938 3,428 14.8 FY13E 5,309 5,128 3.5

Source: Bloomberg , Karvy Institutional Research

Key Risks: • Execution risks for power projects under development, which could

affect the Company’s revenues.

• Higher than expected losses in the retail business; if it persists could affect valuations.

June 30, 2011

Financial Overview Our View: Topline to Register Healthy Growth on the back of Capacity Addition We expect 15% revenue CAGR over FY10-13E helped by capex for Budge Budge Unit-III, hike in average tariffs to compensate for rising fuel costs and 21% CAGR growth in retail business.

Exhibit 18: Topline Growth at CAGR of 15%

Exhibit 19 : Segment-wise Revenue Breakup

Operating Margins to improve over FY10-13E

CESC’s operating margins to show gradual improvements from 10% in FY10 to 14% in FY13E, on account of higher margins in retail business. We expect its gross margins to improve by 500 bps from 13% to 18% on the back of increased sales from the high margin non-food segment.

Exhibit 20: Operating Margins

Exhibit 21: Operating Performance (%)

20,000

40,000

60,000

80,000

FY2010 FY2011 FY2012E FY2013E

Net revenues % Growth

1000020000

5000060000

FY2010 FY2011 FY1012E FY1013EPower Segment Retail Segment

(Rs mn)

10,000

FY2010 FY2011 FY2012E FY2013E

Operating Profits OPM %

FY10 FY11 FY12E FY13E

Power margins (%) Spencer Retail (%) Consolidated Margins (%)

Rs mn (%)

June 30, 2011

Bottomline Performance to Improve We expect consolidated PAT of Rs. 4.4 bn and Rs. 5.4 bn for FY12E and FY13E, respectively, helped by reducing retail losses. We expect the losses in its retail business to reduce from Rs. 1.4 bn in FY11 to Rs. 700 mn in FY13E & Rs. 70 mn profits in FY14E.

Exhibit 22: Bottomline Performance

Return Ratios to Improve We estimate Return-on-Equity (RoE) would improve on account of capitalisation of asset and lower losses from retail business.

Exhibit 23: Return Ratios to Improve

FY2010 FY2011 FY2012E FY2013ENet profits NPM (%)

FY2010 FY2011 FY2012E FY2013E

ROCE (%) ROE (%)

June 30, 2011

Exhibit 24: Profit & Loss Statement Y/E March (Rs mn) FY09 FY10 FY11 FY12E FY13E Net revenues 41,083 42,662 49,420 58,757 65,885 % Growth 14% 4% 16% 19% 12% Raw Material 13,959 17,399 20,930 35,627 41,462 Staff 5,183 5,450 5,640 6,810 7,540 Operating Expenses 12,705 11,536 8,660 1,846 1,385 Other expenditure 6,986 3,969 6,670 6,511 6,837 Operating expenses 38,833 38,354 41,900 50,795 57,224 EBIDTA 2,250 4,308 7,520 7,963 8,661 % Growth -48 91 75 6 9 EBIDTA margin (%) 5.5 10.1 15.2 13.6 13.1 Other income 2,202 2,558 2,140 2,791 3,363 Interest 2,088 2,614 2,990 2,571 2,339 Depreciation 2,158 2,514 3,160 3,364 3,614 Profit Before Tax 206 1,739 3,510 4,818 6,072 Provision for tax -557 175 530 880 763 Effective tax rate (%) -270 10 15 18 13 Reported Net Profit 763 1,564 2,980 3,938 5,309 % Growth -71 105 91 32 35 Net Margin (%) 1.9 3.7 6.0 6.7 8.1 Share in Associate profit (Net) - - 10.0 10.0 10.0 Extra-Ordinary Inc/(Exp) - - (210) - - Adjusted Net Profit 763 1,563 2,780 3,948 5,318 % Growth - 105 78 42 35 EPS (Rs) 6.1 12.4 23.7 31.4 42.3 % Growth -71 105 91 32 35 DPS (Rs) 4 4 4 4 4 Source: Company, Karvy Institutional Research

Exhibit 25: Balance Sheet Y/E March (Rs mn) FY09 FY10 FY11 FY12E FY13E Equity capital 1,256 1,256 1,256 1,256 1,256 Reserves & surplus 43,749 44,127 45,750 61,389 66,109 Shareholders funds 45,005 45,383 47,006 62,644 67,365 Minority 0 9 20 20 20 Short term Loans 8,234 11,594 13,454 13,804 17,654 Long Term Loans 23,124 28,062 27,826 36,660 45,294 Total Loans 31,358 39,665 41,300 50,484 62,968 Share appln money 5 10 - - - Deferred tax liability 8,206 8,959 14,490 14,490 14,490 Total Liabilities 84,574 94,017 102,796 127,619 144,823 Gross block 98,422 120,857 123,065 127,122 129,406 Depreciation 39,053 42,407 43,219 46,583 50,197 Net block 59,369 78,450 79,846 80,539 79,209 Capital WIP 13,515 4,422 9,700 34,019 52,676 Investments 4,343 4,374 4,170 4,374 4,374 Inventory 3,776 3,739 4,080 7,644 7,865 Debtors 4,257 5,176 5,820 6,301 6,704 Cash & Bank Bal 13,074 11,680 12,290 6,405 6,342 Loans & Advances 3,310 2,971 3,050 4,000 4,500 Current Assets 24,417 23,566 25,240 24,350 25,411 Sundry Creditors 3,914 4,483 5,450 6,686 6,844 Other current liabilities 13,749 13,597 12,110 10,434 11,459 Provision for dividend 500 500 500 500 500 Other provisions 749 749 1,370 1,313 1,313 Current Liabilities 18,911 19,329 19,430 18,933 20,116 Net deferred tax 1,745 2,463 3,210 3,210 3,210 Net current assets 5,505 4,238 5,810 5,417 5,294 Deferred expenditure 98 71 60 60 60 Total Assets 84,574 94,017 102,796 127,619 144,823 Source: Company, Karvy Institutional Research

June 30, 2011

Exhibit 26: Cash Flow statement (Rs mn) FY2009 FY2010 FY2011 FY2012E FY2013E

EBIT 93 1,795 4,360 4,598 5,048 (Inc)/Dec in working capital 4,117 (457) 415 5,212 39 Cash flow from operations 4,209 1,338 4,775 9,810 5,087 Other income 2,202 2,558 2,140 2,791 3,363 Depreciation 2,158 2,514 3,160 3,364 3,614 Interest paid 2,088 2,614 2,990 2,571 2,339 Tax paid (557) 175 530 880 763 Net cash from operations 7,038 3,620 6,555 12,514 8,961 Capital expenditure 13,786 13,342 7,486 28,376 20,941 Free Cash Flows (6,748) (9,722) (931) (15,862) (11,980) Inc/(Dec) in LT borrowing 7,172 4,938 (236) 8,834 8,634 Inc/(Dec) in ST borrowing 1,523 3,359 1,860 350 3,850 (Inc)/Dec in investments 956 31 (204) 204 - Others - - 120 589 (567) Cash from Financial Activities 9,651 8,329 1,540 9,977 11,917 Opening Cash 10,170 13,073 11,680 12,290 6,405 Closing Cash 13,073 11,680 12,290 6,405 6,342 Change in Cash 2,903 (1,393) 610 (5,885) (63)

Exhibit 27: Key Ratios (%) FY2009 FY2010 FY2011 FY2012E FY2013E

Raw Material Cost / Sales 34.0 40.8 42.4 45.3 47.8 Manpower Cost / Sales 12.6 12.8 11.4 11.6 11.4 Operating & Other cost / Sales 30.9 27.0 17.5 18.5 17.3 Revenue Growth 14.2 3.8 15.8 18.9 12.1 EBIDTA Margins 5.5 10.1 15.2 13.6 13.1 PAT Margins 2.0 4.1 6.3 7.4 8.1 ROCE 3 5.1 8.5 7.0 6.6 ROE 2 3.4 6.3 6.3 7.9 Core RoCE 6.1 7.6 10.3 11.1 12.3 Core RoE 3.0 4.0 7.1 8.1 11.5 Source: Company, Karvy Institutional Research

Exhibit 28: Valuation Parameters FY2009 FY2010 FY2011 FY2012E FY2013E EPS (Rs) 6.1 12.4 23.7 31.4 42.3 PER (x) 49.4 24.1 12.6 9.6 7.1 Book per share 360 363 376 501 539 P/B(x) 1.20 1.19 1.13 0.77 0.70 EV/EBIDTA (x) 22.9 14.2 8.3 9.7 10.4 Fixed assets turnover ratio (x) 0.7 0.5 0.6 0.7 0.8 Debt/Equity (x) 0.7 0.9 0.9 0.8 0.9 EV/Sales (x) 1.3 1.4 1.3 1.3 1.4 Source: Company, Karvy Institutional Research

July 1, 2011

JSW Energy

POWER July 1, 2011

JSW Energy Bloomberg: JSW.BO Reuters: JSW IN HOLD

Recommendation CMP: Rs 67 Target Price: Rs 75 Upside: 12%

Stock Information Market Cap. (Rs bn / US$ mn)109/2443 52-week High/Low (Rs) 136/64 Shares Outstanding (mn) 1640 3m ADV Rs mn 99.3/USDmn 2.2 Beta 0.72 Sensex 18,846 Nifty 5,647

Stock Performance (%) 1M 3M 12M YTD Absolute (4.6) (6.7) (46.7) (32.9) Rel. to Sensex (6.4) (3.6) (53.1) (24.8)

Performance

1 year forward P/B

16,000 17,000 18,000 19,000 20,000 21,000 22,000

Sensex (LHS) JSW Energy (RHS)

Initiating Coverage

Merchant Power Player with High Fuel Risks JSW Energy (JSWEL) stands lower in our fuel security theme due to its high exposure to merchant market and excessive dependence on imported coal. Our view also factors cancellation of mine allotted to Sungi Belati (SB) that was supposed to supply 2 MTPA of coal at US$36 per MT (FoB) and sharp rise in spot prices in global markets. We believe that this will further increase JSWEL’s exposure to imported coal.

High Exposure to Merchant Power Leading to Earnings Volatility Out of JSWEL’s total capacity of 3,140MW, 55% would be under the merchant route which would make JSWEL susceptible to merchant rates. In our opinion the merchant rates would soften further on the back of incremental capacity and back-out of the SEBs. We assume merchant rates of Rs. 4 per KWh in FY12E, declining to Rs. 3.5 per KWh in FY13E, and remaining at this level until FY15E, and would rise 2% thereafter.

Excessive Dependence on Spot Imported Coal – Pricing Risk Ahead A major chunk of JSWEL's FY13E capacity (65%) would operate on imported coal. Given the huge demand from India & China, the spot coal prices are likely be above US$120 per tonne till FY14E. We believe high fuel cost dents the IRR of the projects to 19%.

Capacity Growth to taper off beyond FY12E We expect JSWEL to hike capacity to 3,140MW in FY13E from 2,000MW currently. The next major rise in capacity will not take place until FY15E, when we expect addition of 300MW from West Bengal-I and Phase-I of 1,320MW from Ratnagiri-II. Again, the visibility on JSWEL’s pipeline projects is low, as these projects still await certain clearances. The cash-flow from 3.1GW (operational by FY12E) capacity suggests potential need for equity dilution of 15-20% in FY14-15E for total capex of Rs. 413 bn provided all the projects go on stream.

Valuation At the CMP, JSWEL is trading at 1.6x and 1.4x its FY12E and FY13E P/BV, respectively, and at EV/EBITDA of 7.4x on FY13E. We have arrived at a fair price of Rs. 75 for JSWEL by valuing 7,960MW of capacity under the FCFE methodology.

Our fair price implies an upside of 12% from the CMP, and we initiate coverage on the stock with a “HOLD” recommendation.

Exhibit 1: Key Financials Y/E March (Rs mn) FY2009 FY2010 FY2011E FY2012E FY2013E Net Sales 18,350 23,551 42,944 68,327 71,855 EBIDTA 5,318 12,134 15,641 26,762 24,885 Net Profit 2,766 7,455 8,418 12,051 10,179 EPS (Rs) 5.1 4.5 5.1 7.3 6.2 PER (x) 13.2 14.7 13.1 9.1 10.8 EV/EBITDA (x) 17.4 14.9 10.9 7.0 7.4

July 1, 2011

JSW Energy

Company Background JSW Energy – a part of the JSW Group having presence in the steel, power, cement, aluminium, software and infrastructure sectors – is the first independent power producer to be set up in Karnataka. The Company was formed in 1994 as a JV between the Jindal Group & Belgium-based Tractebel SA under the name Jindal Tractebel Power Company. It commenced its commercial operations on January 18, 2000. Following the exit of Tractebel SA, the Company's shares were fully owned by the Jindal Group.

JSWEL has proven execution capabilities, which stand to its advantage. It has so far implemented five separate projects with a total generation capacity of 1,150MW, with project management oversight for most of the projects being performed internally.

Company Financial Snapshot Consolidated Profit & Loss Rs. in mn FY2011E FY2012E FY2013E Net revenues 42,944 68,327 71,855 EBIDTA 15,641 26,762 24,885 Interest 4,325 6,953 7,778 Depreciation 2,668 6,303 6,888 Profit before Tax 9,979 15,856 13,219 Provision for tax 1,562 3,805 3,040 Adjusted Net Profit 8,065 11,751 9,829 Reported Net Profit 8,418 12,051 10,179

Profit and Loss Ratios EBIDTA Margins (%) 36.4 39.2 34.6 PAT Margins (%) 19.6 17.6 14.2 EV/EBIDTA (x) 10.9 7.0 7.4 PER (x) 13.1 9.1 10.8 P/B 1.9 1.6 1.4

Consolidated Cash Flow Rs. in mn FY2011E FY2012E FY2013E EBIT 12,973 20,459 17,997 (Inc)/Dec in working capital (2,564) 7,907 (1,241) Cash flow from operations 10,409 28,365 16,755 Other income 1,332 2,350 3,000 Depreciation 2,668 6,303 6,888 Interest paid 4,325 6,953 7,778 Dividends paid 1,434 1,434 1,434 Tax paid 1,562 3,805 3,040 Net cash from operations 7,440 25,126 14,742 Capital expenditure (28,368) (13,364) (11,026) Free Cash Flows (20,928) 11,762 3,716 Cash from Financial Activities 24,658 (9,547) (3,350) Opening Cash 6,048 9,778 11,992 Closing Cash 9,778 11,993 12,359 Change in Cash 3,730 2,215 366

Consolidated Balance Sheet Rs. in mn FY2011E FY2012E FY2013E Shareholders’ funds 16,401 16,401 16,401 Total Loans 96,376 92,128 89,128 Deferred tax liability 1,562 1,562 1,562 Total Liabilities 155,427 161,795 167,529 Net block 64,385 134,003 130,115 Investments 4,842 9,842 9,842 Net current assets 9,120 3,427 5,024 Total Assets 155,427 161,795 167,529 Balance Sheet Ratios

ROCE (%) 9.2 12.9 10.9 ROE (%) 15.4 18.9 13.7 Debt/Equity (x) 1.5 1.2 1.0 EV/Sales (x) 4.0 2.8 2.6 Debt/Equity(X) 1.5 1.2 1.0

Revenue Split by Product FY11

Source: Company

Operator fee1%

Power business

Project management

fees4%

Shareholding Pattern FY11

Source: Company

FIIs11%

Promoters77%

Public6%

July 1, 2011

JSW Energy

Outlook & Valuation Why we have “HOLD” Recommendation on the Stock? We believe that JSWEL should trade at a discount to Adani Power & Tata Power due to:

I. High exposure to imported spot coal & merchant sales II. Capacity growth to taper off beyond FY12E III. Low IRR of the Projects

During FY10-11, JSWEL reported strong performance on the back of higher merchant realization, which enables the Company to enjoy higher valuation. However, we believe that the growth momentum will slow down beyond FY12E due to:

I. Lower Merchant Realization, II. Slowdown in Capacity Addition, and III. Higher Fuel Cost.

At the CMP, JSWEL is trading at 1.6x and 1.4x its FY12E and FY13E P/ BV, respectively, and at EV/EBITDA of 7.4x on FY13E. We have arrived at an SOTP-based target price of Rs. 75 for the stock by independently valuing 7,960MW of capacity and the other businesses valued at book value. We initiate coverage on the stock with a “HOLD” recommendation that implies 12% upside from the current levels.

Exhibit 2: SOTP Valuation Project Details Capacity

(MW) Date of

Commissioning

Cost of Equity

Val method

Equity Value

(Rs mn)

Stake %

Milestone Discount

JSWEL Value

(Rs mn)

Per share value

Vijayanagar I &II 860 Operational 14% FCFE 29,160 100 0 29,160 17.9 Ratnagiri I 1200 Operational 14% FCFE 21,480 100 0 21,480 13 Barmer I 1050 Operational 14% FCFE 20,984 100 0 20,984 13 Ratnagiri II 3200 FY16 15% FCFE 18,168 100 50% 9,084 5.5 West Bengal 1600 FY15 15% FCFE 13,588 74 50% 6,794 4.1 Cash & investment in hand FY11E 14,620 9 Terminal value of the projects (10% of Capital Cost)

20,179 12

Total (Rs Per Share) 13,031 75 Source: Company , Karvy Institutional Research

JSW Energy is trading at P/B of 1.4x & P/E 10.8x based on FY13E, which at significant discount at 48% & 35% to its historical average of 2.7x P/B & 16.5x P/E respectively. In the last 2 yrs JSWEL has traded at P/B of 3-3.5x on account of higher RoE from merchant business.

Exhibit 3: One Year-Forward P/E

Exhibit 4: One Year-Forward P/B

25456585

105125145165185

4xMax 23.5 Min 9.4 Mean 16.5

July 1, 2011

JSW Energy

Investment Rationale • High exposure to merchant power leading to earnings volatility • Pricing risk ahead – Excessive dependance on spot imported coal • Valuation of operational and under-construction assets

• Issues pertaining to Indonesian coal supplies & PPA with MSEDCL • Captive Lignite Mines: Major positive for RWPL, but regulated RoE • Capacity growth to taper off by FY12E

• Healthy operational cash flows from FY12 to FY15E – Equity dilution expected if all development projects go on stream – but unlikely

• Other businesses creating insignificant current value

I. High Exposure to Merchant Power Leading to Earnings Volatility JSWEL is set to hike its capacity to 3,140MW by FY13E-end from 1,730MW currently. Out of the total capacity of 3,140MW, 54% would be under the merchant route that will enable it to high exposure merchant rates, which expected till FY13E. As per our estimates, JSWEL ’s imported coal constitutes 83% in FY11, and we expect imported spot coal to constitute 70% of total fuel consumed in FY12. The biggest risk with JSWEL’s projects is the lack of fuel on a long-term basis, causing the Company to have significant exposure to imported coal. We expect JSWEL to source majority of coal from South Africa the FOB price is currently US$100 per tonne, leading to a landed cost of US$138 per tonne and fuel cost at Rs 2.6 per unit thereby putting significant pressure of operating performance. We estimate FOB price at US$115 per tonne in FY12. We assume merchant rates of Rs. 4 per KWh in FY12, declining to Rs. 3.5 per KWh in FY13, and remaining at this level until FY15 & 2% hike thereafter as the recent competitive bids have already set a price band of about Rs. 2.7-3.2 per KWh. We expect merchant rates to be at a premium of at least 10-15% to long-term PPA rates considering the risks associated with the business.

Exhibit 7: Operational Matrix Consolidated FY2011 FY2012E FY2013E FY2014E FY2015ECapacity (MW) 1400 2740 3140 3140 3140Sales Volume (MU) Competitive 0 1364 2046 2273 2273 PPA 2836 9020 10425 11282 11282 Merchant 5927 8854 10286 10042 10042Total 8764 19238 22757 23596 23596As a % of total Competitive - 7 9 10 10 PPA 32 47 46 48 48 Merchant 68 46 45 43 43Source: Company, Karvy Institutional Research

Exhibit 6: Avg Realization v/s Fuel cost

Realization Per Unit (Rs) Fuel cost per unit

Gross margin per unit

Exhibit 5: Rs.0.5 per unit fall in merchant price to earnings sensitivity

10,000

15,000

20,000

FY12E FY13E

Current Revised % Change

Rs mn (%)

July 1, 2011

JSW Energy

II. Pricing Risk Ahead – Excessive Dependence on Spot Imported Coal A major chunk of JSWEL's FY13E capacity (65%) would operate on imported coal, which would be a mix of Indonesian coal from SB (based on RB Index) and coal bought on spot basis. The huge reliance on imported coal leaves JSWEL open to pricing risk, as 55% of its FY13E capacity is based on merchant rates. Currently, at US$120 per tonne, the global spot coal prices not likely to decline significantly.

We are of the view that high dependence on the imported coal and lower merchant realizations leading to low IRRs of operational projects.

Exhibit 9: Coal Requirement & Supply * mn tonne FY12E FY13E FY14E Vijayanagar-I (260 MW)

Coal requirement 0.8 0.8 0.8 Supply arrangement - JSWSL 0.8 0.8 0.8 Vijayanagar-II (600 MW)

Coal requirement 1.8 1.8 1.8 Supply arrangement Imported under contract from Sungai Belati (SB)

Supply from SACMH 0.3 0.3 0.3 Purchase under spot basis 1.5 1.5 1.5 Raj West I (1050 MW)

Coal requirement 4.4 6.2 6.2 Supply arrangement

Tapering linkage from MCL & SECL 0.3 0 - Supply from SACMH

Captive lignite mines 1.5 2.7 6.2 Imported under contract from SB 0 0 0 Purchase under spot basis 2.6 3.5 0 Ratnagiri I (1200 MW)

Coal requirement 0 0 1.11 Supply arrangement - SB 0 0 1.11 Purchase under spot basis 3.0 3.3 4.1 Total Requirements 10.0 12.1 14.0 Imported under contract from Sungai Belati 0 0 0 Spot 7.1 7.8 5.9 Domestic 2.9 4.3 8.1

Exhibit 8: Spot vs. Long-term Coal Arrangement

62.5 71.0 64.7

20.8 0.00.0

16.729.0 35.3

FY11E FY12E FY13ESpot Sungai Belati Domestic

July 1, 2011

JSW Energy

III. Valuation of Operational / Under-construction Assets

1. Vijayanagar-I (Operational since 2000) & II (Operational since Sept’09) – Valued @ Rs. 17.8 per share

Exhibit 10: Financials & Valuation for Vijayanagar I & II (Rs. in mn) FY12E FY13E FY14E FY15ECapacity (MW) 860 860 860 860Sales Volume (Mn units) 6,656 6,656 6,586 6,586 Realization Per Unit (Rs) 3.99 3.81 3.74 3.75 Net Sales (Rs mn) 25,934 24,802 24,094 24,137 Operating Expenses (Rs mn) 19,309 20,605 19,525 20,032 EBITDA 6,624 4,197 4,569 4,106 Depreciation 1,659 1,659 1,659 1,659 Interest 1,748 1,575 1,351 1,162 PBT 3,217 963 1,558 1,284 Tax 641 192 310 256 PAT 2,576 771 1,247 1,028 FCFE 1,521 433 1,120 1,012PV 1,521 380 861 683NPV (Explicit period FY12-29E) 29,160 Per Share 17.8

2. Ratnagiri-I (1,200MW) – Expected to be commissioned by FY12E – A mix of PPA & Merchant play – Valued @ Rs. 13 per share

Exhibit 11: Financials & Valuation of Ratnagiri-I (Rs. mn) FY12E FY13E FY14E FY15E Capacity 800 1,200 1,200 1,200 Sales Volume (Mn units) 5,455 8,182 9,091 9,091 Realization Per Unit (Rs) 3.8 3.6 3.8 3.7 Net Sales 20,273 28,595 33,392 32,479 Operating Expenses 12,672 19,616 22,347 23,127 EBITDA 7,600 8,979 11,045 9,351 Depreciation 1,543 2,315 2315 2,315 Interest 991 2,361 4,030 3,780 PBT 5,064 4,302 4,699 3,255 Tax 979 831 908 629 PAT 4,085 3,470 3,791 2,626 FCFE (1,291) 1,508 2,995 2,362 PV (1,291) 1,323 2,305 1,595 NPV (Explicit period (FY13-37) 21,480 Per Share 13 IRR 18%

July 1, 2011

JSW Energy

3. Raj West Power – Valued @ Rs. 13 per share

Exhibit 12: Financials & Valuation of Raj West Power FY13E FY14E FY15E

Capacity 1,080 1,080 1,080Sales Volume (Mn units) 7,918 7,918 7,918Realization Per Unit (Rs) 2.38 2.36 2.34Net Sales 18,441 18,261 18,124Operating Expenses 7923 8,207 8,502EBITDA 10,517 10,053 9,621Depreciation 2,297 2,297 2,297Interest 3,841 3,568 3,296PBT 4,378 4,187 4,027Tax 846 809 778PAT 3,532 3,377 3,248FCFE 4,515 3,258 3,125PV 3,960 2,507 2,109NPV(Explicit Period FY12-36) 20,984Per Share 13

Source: Company and Karvy Institutional Research

4. Assets under pipeline

Exhibit 13: Projects under pipeline Project Water

Availability Land acquisition

Environment clearance

Equipment Fuel Arrangement Off-take Financial Tie-up

Ratnagiri-II (3,200MW)

Sea Water Acquired Pending Pending Imported coal to be source from SACMH

50% with MSEDCL & balance to be tied-up.

Pending FY16

Chhattisgar (1,320MW)

Mahanadi river

Partly acquired

Pending Pending JSWEL has an 11% interest in a consortium that has been allotted a coal block from Utkal A – Gopalprasad (West) West mines near Talcher, Orissa, from the Ministry of Coal on November 29, 2005.

Up to 35% to state. Balance to be tied up

Pending FY15

W.Bengal (1,600 MW)

Pending Acquired Pending Bids Invited Captive mines Mix Pending FY15

Jharkhand (1,620 MW)

Pending Pending Pending Pending Applied for linkage Pending Pending FY16

Raj West (270 MW)

Allocation available

Available Pending Pending Applied for linkage 100% merchant

Pending FY15

Kutcher (240 MW)

- In progress Completed Pending - 12% free power & balance merchant

Completed FY16

July 1, 2011

JSW Energy

IV. Issues Pertaining to Indonesian Coal Supplies & PPA with MSEDCL JSWEL had signed 300MW PPA with Maharashtra State Electricity Distribution Company (MSEDCL) for sale of power at levelised tariff of ~Rs. 2.7 per kWh for 25 years. It also signed fuel supply contract with PT Sungai Belati for supply of ~2 MTPA coal with GCV of 4,300-4,500 @ base price of US$36 per tonne. As per the Management, JSWEL had first priority over other customers for supply of coal from the mines. However, following the cancellation of SB mine license by the Indonesian Supreme Court, PT Sungai Belati has invoked a force majeure clause in the FSA. Separately, JSWEL has approached Maharashtra Electricity Regulatory Commission (MERC) for permission to hike power tariff after the MSEDCL refused its request. According to JSWEL’s Management, the FSA for coal supply was one of the principal agreements in PPA with MSEDCL and invoking of force majeure clause in FSA has led to force majeure in PPA.

V. Captive Lignite Mines: Major positive for RWPL with regulated RoE Raj West Power (RWPL) – a WOS of JSWEL – is implementing the 8X135MW lignite-based thermal power plant in Bhadresh village in Barmer district of Rajasthan at a total estimated cost of Rs. 60.85 bn. The project is expected to be fully commissioned in FY12 in phases. Barmer Lignite Mining Company (BLMCL) will meet the entire fuel requirement of the power plant. The entire fuel requirement for 1,080MW Raj West-I plant will be met by Kapurdi and Jalipa mines, which JSWEL is developing jointly with Rajasthan State Mines & Minerals. The Raj West-I project when fully operational have an annual coal requirement of 6.2 MTPA. Currently, 270MW (Units I&II) of Raj West-I is operational, while the entire project is expected to be operational by FY12E.

VI. Capacity Growth to taper off beyond FY12E We expect JSWEL to hike capacity to 3,140MW in FY12 from 2,000MW currently. We do not expect any capacity addition in FY12-14E. As regards the 8,930MW capacity that will remain under construction/development, none of the projects have secured financial closure or placed BTG/EPC orders. The next major increase in capacity will not take place until FY15E, when we expect the addition of 300MW from West Bengal-I and Phase-I- 3,200MW from Ratnagiri, while other players like Tata Power, Adani Power and CESC to hike capacity significantly. Exhibit 14: Cumulative Installed Capacity (MW)

VII. Healthy Operational Cash Inflows from FY12E-FY15E – Expect Equity Dilution if all under-development projects go on stream, which is unlikely JSWEL, with 3,140MW of operational capacity by FY13, is likely to enjoy healthy cash inflows going ahead. Its next phase of capacity addition involves the construction of 240MW Kutehr hydel project, 3,200MW Ratnagiri-II project, 1,320MW project in Chhattisgarh and 1,600MW project in West Bengal. These

27403140 3140 3140

100015002000250030003500

FY2011 FY2012 FY2013 FY2014 FY2015

July 1, 2011

JSW Energy

under-construction projects would require equity contribution of over Rs. 117 bn over FY12-15E. The operating cash flows generated would be expected to be Rs. 78 bn over the same period, which would not be sufficient to fund the equity contribution of under-construction projects, thereby requiring equity dilution of around 15-20% in FY14-15E provided all the projects come on stream, but we believe JSWEL might phase it out in such a way that equity contribution won’t be required at one go. Exhibit 16: Equity Requirement (Rs. mn) Project Expected

Commissioning Date

Total Cost

Equity Cost

Already Deployed

To be Deployed

BLMCL (JV with RSMML)

- 7500 900 - 900

Kutehr (240 MW)

FY16 1,9500 5850 800 5050

Chhattisgarh (1320 MW)

FY16 6,5000 1,9500 350 1,9150

West Bengal(1600 MW)

FY16 9,2000 2,7600 2800 2,4800

Ratnagiri-II(3200 MW)

FY16 15,0000 4,0000 - 4,0000

Jharkhand(1620 MW)

FY17 7,9500 2,3850 - 2,3850

Total 41,3500 11,7700 3950 11,3750

VIII. Other Business Models Creating Insignificant Current Value

1) Expansion Across Power Value Chain

JSWEL has foot prints in the other segments of the power value chain such as coal mining, power transmission, equipment manufacturing and power trading. It is also developing the Jalipa and Kapurdi coal mines in JV with RSMML for its Raj West-II power project. It has also entered into a JV with MSEDCL for constructing two 1,200MW, 400KV transmission lines. The total cost of the project is estimated at Rs. 5.8 bn out of which Rs. 2.91 bn has already been spent.

2) JV with Toshiba Corp for Steam Turbines & Generators Biz in India

JSWEL holds 75% stake in Toshiba JSW Turbine & Generator (TJTGL) – a JV between JSW Group & Toshiba Corporation – that will manufacture and market steam turbines and generators (TG) in India. The JV would have a total investment of US$250 mn with an initial capitalization of US$50 mn. The JV will manufacture and market mid-to large-size steam turbines and generators, ranging in size from 500MW to 1,000MW for highly efficient supercritical thermal power plants in India. Keihin Operations – Toshiba's power equipment production facility in Yokohama – will support Toshiba JSW in ramping up manufacturing, and in working toward establishing an independent production scale of 3,000MW per year. While the Blade shop equipment installation is 75% complete, the manufacturing of TG sets is likely to begin in FY12.

Exhibit 15: Cash Flow / Debt Equity

FY2010 FY2011E FY2012E FY2013ECash flow from OperationNet Debt/Equity

(Rs mn) (%)

July 1, 2011

JSW Energy

Exhibit 17: Key Financial Assumption Estimates Growth Comments FY10 FY11 FY12E FY13E FY11 FY12E FY13E

Operational Parameters Capacity (MW) 860 2,000 3,140 3,140 133 57 0 No major capacity addition expected Sales Volume (MU) PPA 1,505 3,250 6,730 12,111 116 107 80 Raj west & Ratnagiri to add PPA sales Merchant 3,511 6,815 8,247 8,725 94 21 6 Ratnagiri 50% based on merchant based Competitive 0 1,976 2,039 2,039 - 3 0 25% capacity of Ratnagiri based on

competitive JV's (MW) - - - - - - - Gross generation (MU) - - - - - - - Commercial generation (MU)

5,426 12,947 18,297 24,596 139 41 34 Volume driven by capacity addition

Energy sold (MU) 5,016 12,041 17,016 22,875 140 41 34 Driven by higher volumes Aux. consumption (%) 7 7 7 7 0 0 0 Unchanged Avg PLF (%) 72 47 67 89 -35 41 34 PLF to improve as plant take time to

stabilize. Avg PAF (%) 95 95 95 95 0 0 0 Unchanged Tariffs Avg realisation (Rs/unit) PPA 4.1 3.3 3.1 3.1 -19 -6 -1 Lignite mining of raj west to start in FY12 Merchant 4.86 4.25 4 3.8 -13 -6 -5 We expect merchant rates to come down Competitive 0 3.4 3.5 3.6 Ratnagiri projects to be based on

competitive bidding Blended 4.62 3.95 3.65 3.43 -14 -8 -6 On lower merchant rates Fuel cost Avg Fuel Cost (Rs/unit) 1.9 1.9 2.1 1.7 3 7 -17 We expect increase in imported coal prices Imported Coal (MT) 0.8 4.7 7.1 7.8 488 51 10 Higher requirements on account of higher

capacity Domestic Coal (MT) 0.8 0.96 2.9 4.3 20 202 48 Raj West is based on lignite mining Financial Forecasts Sales (Rs mn) Sales (Rs mn) 23,551 42,944 68,327 71,855 82 59 5 Driven by capacity addition Total Sales 23,551 42,944 68,327 71,855 82 59 5 Higher volume to drives earnings Operating Expenses (Rs mn)

11,417 27,303 41,565 46,970 139 52 13 Higher fuel cost

EBIDTA (Rs mn) 12,134 15,641 26,762 24,885 29 71 -7 EBITDA to track capacity addition but FY13 lower as capacity slows down

EBIDTA margin (%) 51.5 36.4 39.2 34.6 -29 8 -12 Lower merchant rate & higher fuel cost lower margins

Net Interest Expense (Rs mn)

2,837 4,325 6,953 7,778 52 61 12 On account of higher capacity

Avg. Interest rate (%) 4 4 8 9 25 68 16 To increase on asset capitalization PAT (Rs. mn) 7,455 8,418 12,051 10,179 11 46 -16 To track capacity addition however FY13

profits lower on lower realization PAT margin (%) 30.8 18.8 17.2 13.7 -39 -8 -20 Lower merchant rate & higher fuel cost

lower margins EPS (Rs.) 4.5 5.1 7.3 6.2 13 43 -16 Higher fuel cost & lower realization to

dent profitability Cash Flow forecast (Rs mn) CFO (a) 4,094 7,440 25,126 14,742 82 238 -41 To increase in FY12 on earnings CFI (b) 35,727 28,368 13,364 11,026 -21 -53 -17 Lower capex FCF(a-b) -31,633 -20,928 11,762 3,716 -34 -156 -68 capex program for upcoming projects CFF - © -35,931 -24,658 9,547 3,350 -31 -139 -65 positive operating cash-flow Total Changes in cash (a+b+c)

4,298 3,730 2,215 366 -13 -41 -83 No major capex

July 1, 2011

JSW Energy

Karvy vs. Consensus Our estimates for Sales & PAT for FY13E are lower than consensus on account of lower PLF assumption. Exhibit 18: Karvy v/s Consensus

Karvy Consensus % difference Revenue (Rs mn) FY12E 68,327 74,053 (7.7) FY13E 71,855 77,535 (7.3) EBIDTA (Rs mn) FY12E 26,762 32,281 (17) FY13E 24,885 29,849 (17) PAT (Rs mn) FY12E 12,051 13,324 (9.5) FY13E 10,179 11,562 (12) Source: Bloomberg & Karvy Institutional Research

Key Risks 1. Project delays 2. Operational issues at Raj West 3. Risk of high coal prices 4. Lower than expected merchant realisations

July 1, 2011

JSW Energy

Financial Overview Growth to peak in FY13E thereafter to remain subdued till FY16E

The commissioning of RWPL and Ratnagiri plants is expected to boost JSWEL's topline from FY11E. The Company's sales volume is likely to grow from 5,016MU to 22,757MU at a 58.6% CAGR over FY10-13E with the commissioning of Ratnagiri & Raj west plants. We expect JSWEL to register a 44% CAGR in net revenue over FY11-13E thereafter to remain muted till FY16E.

Exhibit 20: 44% Topline CAGR over FY10-13E

Operating Margins to Shrink in FY13E despite Rise in FY12E

JSWEL's operating margin is expected to improve to 39% in FY12E due to high proportion of merchant sales in its overall capacity. However, its operating margin is likely to shrink in FY13 to 34% due to low merchant power rates.

Exhibit 21: Operating Margins to Shrink

20,000

40,000

60,000

80,000

FY2010 FY2011 FY2012E FY2013ENet Sales (Rs mn) Growth (%)

10.0 20.0

5,000 10,000

15,000

20,000

25,000

30,000

FY2010 FY2011 FY2012E FY2013EOperating Profits (Rs mn) OPM (%)

Rs mn (%)

Exhibit 19: Merchant Profit / Total Profit

10,000

15,000

20,000

FY11 FY12 FY13Total Profits (Rs mn)Merchant Profits (Rs mn)Merchant Profits (%)

July 1, 2011

JSW Energy

Net Profit – Volatility on Merchant Power Sales

JSWEL's net profits is expected to improve from Rs. 8,418 mn in FY11 to Rs. 10,179 mn in FY13E, due to commissioning of capacity However net profit to down in FY13E from FY12E on account of lower merchant realization, higher interest, and depreciation costs. We expect 50 paisa per unit to impact 40% profits.

Exhibit 22: Net Profit growth at CAGR of 11%

Return Ratios to Decline; RoE is expected to Fall by 520 bps We expect RoE to improve from 15.4% in FY10 to 18.9% in FY12. However, the RoE is likely to witness degrowth by 520 bps in FY13E to 13.7% on account of lower merchant realization and capex for future projects.

Exhibit 23: Return Ratios to Decline

10,000

15,000

FY2010 FY2011 FY2012E FY2013E

Net Profits (Rs mn) NPM(%)

FY2010 FY2011 FY2012E FY2013E

RoCE (%) RoE (%)

Rs mn (%)

July 1, 2011

JSW Energy

Exhibit 24: Profit & Loss Statement

Y/E March (Rs. mn) FY2009 FY2010 FY2011 FY2012E FY2013E

Net revenues 18,350 23,551 42,944 68,327 71,855 % Growth 42 28 82 59 5 Raw Material 11,969 10,158 25,056 38,057 42,293 Staff 271 311 486 825 1,238 Operating Expenses 793 948 1,762 2,683 3,439 Operating expenses 13,033 11,417 27,303 41,565 46,970 EBIDTA 5,318 12,134 15,641 26,762 24,885 % Growth (39.3) 128.2 28.9 71.1 (7.0) EBIDTA margin (%) 29.0 51.5 36.4 39.2 34.6 Other income 171 742 1,332 2,350 3,000 Interest 1,209 2,837 4,325 6,953 7,778 Depreciation 602 1,361 2,668 6,303 6,888 Profit Before Tax 3,677 8,678 9,979 15,856 13,219 % Growth (52) 136 15 59 (17) Provision for tax 912 1,223 1,562 3,805 3,040 Effective tax rate (%) 24.8 14.1 15.7 24.0 23.0 Adjusted Net Profit 2,185 7,249 8,065 11,751 9,829 % Growth (64) 232 11 46 (16) Net Margin (%) 11.9 30.8 18.8 17.2 13.7 Extra-Ordinary Inc/(Exp) 581 206 352 300 350 Reported Net Profit 2,766 7,455 8,418 12,051 10,179 % Growth (56) 170 13 43 (16) EPS (Rs) 5.1 4.5 5.1 7.3 6.2 Source: Company, Karvy Institutional Research

Exhibit 25: Balance Sheet

Y/E March (Rs. mn) FY2009 FY2010 FY2011 FY2012E FY2013E

Equity capital 5,466 16,401 16,401 16,401 16,401 Reserves & surplus 9,331 31,402 40,364 50,980 59,715 Shareholders funds 14,797 47,802 56,765 67,381 76,115 Minority interest 152 152 724 724 724 Long Term Loans 59,272 78,701 96,376 92,128 89,128 Total Loans 59,272 78,701 96,376 92,128 89,128 Deferred tax liability 815 1,161 1,562 1,562 1,562 Total Liabilities 75,035 127,817 155,427 161,795 167,529 Gross block 11,691 36,839 74,152 150,073 153,073 Depreciation 5,349 6,714 9,767 16,070 22,959 Net block 6,342 30,125 64,385 134,003 130,115 Capital WIP 79,251 86,026 77,080 14,523 22,549 Investments 1,705 14,344 4,842 9,842 9,842 Others 1,692 6,428 12,985 9,950 10,924 Cash 1,751 6,048 9,778 11,992 12,358 Loans & Advances 1,958 3,852 6,977 1,632 1,888 Current Assets 5,400 16,328 29,741 23,574 25,171 Other current liabilities 17,663 19,006 20,622 20,147 20,147 Current Liabilities 17,663 19,006 20,622 20,147 20,147 Net current assets (12,262) (2,678) 9,120 3,427 5,024 Total Assets 75,035 127,817 155,427 161,795 167,529 Source: Company, Karvy Institutional Research

July 1, 2011

JSW Energy

Exhibit 26: Cash Flow Statement Y/E March (Rs mn) FY2009 FY2010 FY2011 FY2012E FY2013E

EBIT 4,715 10,773 12,973 20,459 17,997 (Inc)/Dec in working capital 12,692 (4,928) (2,564) 7,907 (1,241) Cash flow from operations 17,408 5,845 10,409 28,365 16,755 Other income 171 742 1,332 2,350 3,000 Extra-ordinary income 581 206 352 300 350 Depreciation 602 1,361 2,668 6,303 6,888 Interest paid 1,209 2,837 4,325 6,953 7,778 Dividends paid 0 0 1,434 1,434 1,434 Tax paid 912 1,223 1,562 3,805 3,040 Net cash from operations 16,641 4,094 7,440 25,126 14,742 Capital expenditure (52,155) (35,727) (28,368) (13,364) (11,026) Free Cash Flows (35,514) (31,633) (20,928) 11,762 3,716 Inc/(Dec) in LT borrowing 36,545 19,430 17,675 (4,248) (3,000) (Inc)/Dec in investments (1,497) (12,293) 9,503 (5,000) 0 Inc/(Dec) in Equity capital 318 27,255 0 0 0 Others (1,050) 1,540 (2,519) (299) (350) Cash from financial activities 34,316 35,931 24,658 (9,547) (3,350) Opening Cash 2,949 1,751 6,048 9,778 11,993 Closing Cash 1,751 6,048 9,778 11,993 12,359 Change in Cash (1,199) 4,298 3,730 2,215 366 Source: Company, Karvy Institutional Research

Exhibit 27: Key Ratios (%)

FY2009 FY2010 FY2011 FY2012E FY2013E

Raw Material Cost / Sales 65.2 43.1 58.3 55.7 58.9 Manpower Cost / Sales 1.5 1.3 1.1 1.2 1.7 Operating & Other cost / Sales 71.0 48.5 63.6 60.8 65.4 Revenue Growth 41.9 28.3 82.3 59.1 5.2 EBIDTA Margins 29.0 51.5 36.4 39.2 34.6 PAT Margins 15.1 31.7 19.6 17.6 14.2 ROCE 8.6 10.6 9.2 12.9 10.9 ROE 17.6 23.2 15.4 18.9 13.7 Core RoCE 18.5 12.4 25.6 20.4 13.6 Core RoE 35.0 27.6 20.5 20.9 19.6 Source: Company, Karvy Institutional Research

Exhibit 28: Valuation Parameters

FY2009 FY2010 FY2011 FY2012E FY2013E

EPS (Rs) 5.1 4.5 5.1 7.3 6.2 PER (x) 13.2 14.7 13.1 9.1 10.8 Book Value/Share 27 29 35 41 46 P/B(x) 2.5 2.3 1.9 1.6 1.4 EV/EBIDTA (x) 17.4 14.9 10.9 7.0 7.4 Fixed assets turnover ratio (x) 1.6 1.0 0.8 0.6 0.5 Debt/Equity (x) 3.8 1.5 1.5 1.2 1.0 EV/Sales (x) 5.1 7.7 4.0 2.8 2.6 Source: Company, Karvy Institutional Research

July 1, 2011

POWER July 1, 2011

NTPC Bloomberg: NTPC IN Reuters: NTPC.BO BUY

Recommendation CMP: Rs 187 Target Price: Rs 219 Upside (%): 17%

Stock Information M.Cap. (Rs bn / US$ mn) 1541/34348 52-week High/Low (Rs) 222/165 Shares Outstanding (mn) 8245 3m ADV Rs mn 417.8 /USDmn 9.3 Beta 0.82 Sensex 18,846 Nifty 5,647

Stock Performance (%) 1M 3M 12M YTD Absolute 11.1 (3.2) (6.4) (6.9) Rel. to Sensex 9.2 (0.1) (12.8) 1.3

Performance

1 year forward P/B

16,000 17,000 18,000 19,000 20,000 21,000 22,000

Sensex (LHS) NTPC (RHS)

100150200250300350400

Defensive Stock with High Fuel Security & Assured RoE National Thermal Power Corporation (NTPC) – India’s largest power generation company – scores well as a defensive growth option with adequate fuel security, capacity expansion, assured RoE, strong balance sheet, high earnings visibility, and lowest cost structure. Fuel Security at its Best – Least Vulnerable to Coal Deficit & Rising Coal Prices NTPC offers some of the best fuel security for its projects in a scenario marked with coal deficit, and rising coal prices. Despite our assumption of significant delays, NTPC expects that the captive mines would produce 47 MTPA of coal by FY17E. NTPC operates (100%) under regulated business model, which entitles the Company to pass on fuel cost to protect from rising coal prices. Less Capacity Additions from 11th Plan Target – Expect Capacity to Ramp Up Out of capacity addition plan of 23GW during the 11th Plan, NTPC has been able to add only 6GW in the first four years (FY08-11). We expect 12,710MW addition of consolidated capacity during 11th Plan leading to 47% slippage from the capacity addition target. However, we believe the slippage in the capacity addition has already been priced-in for NTPC. Going forward, we expect NTPC would add 20GW during FY12-15E. Regulated RoE with Steady Cash-Flow – Core RoE Higher Than CERC Norm NTPC’s pre-tax RoE of 21-27% is one of the highest due to operational efficiency and higher incentives with less risk of higher fuel prices. We expect regulated equity to grow from Rs. 272 bn to Rs. 420 bn by FY13E. We forecast core RoE of 20-21% for FY12-15E. Robust Balance Sheet with Strong Operational Cash-flows NTPC’s balance sheet is strong enough to fund ongoing capex plans, as it plans to spend Rs. 970 bn during FY12-15E period. Its capex would be funded from internal accruals and debt. Given the strength of operational performance and healthy balance sheet, we expect the funding for the ensuing projects would not be a major issue for NTPC in comparison to private players. Outlook & Valuation At 13.0x FY13E P/E and 1.8x FY13E P/B, NTPC trades at a 20-25% discount to the average multiples of its domestic peers. In our view, adequate fuel security and RoE as compared to IPPs, and strong balance sheet command a premium for NTPC’s valuation relative to the average multiples of its peer group. At our price target of Rs. 219, the stock would trade at 16x 1-year forward P/E and 2.1x 1-year forward P/B. We initiate coverage on the stock with “BUY” recommendation. Exhibit 1: Key Financials Y/E March (Rs. mn) FY09 FY10 FY11 FY12E FY13ENet Sales 419,921 463,905 548,740 585,544 683,410 EBIDTA 106,908 126,386 125,616 153,912 193,868 Net Profit 82,012 87,282 91,026 96,150 111,801 EPS (Rs) 9.9 10.6 10.8 11.7 13.6 PER (x) 22.3 19.0 18.3 16.0 13.8EV/EBITDA (x) 16.1 14.0 14.5 13.7 11.5Source: Company , Karvy Institutional Research

Initiating Coverage

July 1, 2011

Company Background NTPC is a diversified power major with presence in the entire value chain of the power generation business. Apart from power generation NTPC has already ventured into consultancy, power trading, ash utilization and coal mining. NTPC became a Maharatna company in May’10, one of the only four companies to be awarded this status. The total installed capacity of the company is 34,194 MW (including JVs) with 15 coal based and 7 gas based stations, located across the country. In addition under JVs, 5 stations are coal based & another station uses naphtha/LNG as fuel.

NTPC has been operating its plants at high efficiency levels. Although the company has 17.75% of the total national capacity, it contributes 27.40% of total power generation due to its focus on high efficiency.

Company Financial Snapshot Consolidated Profit & loss Rs. mn FY2011 FY2012E FY2013E

Net revenues 548,740 585,544 683,410 EBIDTA 125,616 153,912 193,868 Interest 21,490 26,515 36,123 Depreciation 24,856 31,371 41,517 Profit Before Tax 120,496 116,794 135,944 Provision for tax 29,470 20,643 24,143 Adjusted Net Profit 79,579 96,150 111,800 Reported Net Profit 91,026 96,150 111,800

Profit and Loss Ratios EBIDTA Margins (%) 22.9 26.3 28.4 PAT Margins (%) 16.6 16.4 16.4 EV/Sales (x) 3.7 3.6 3.3 EV/EBIDTA (x) 14.5 13.7 11.5 PER (x) 18.3 16.0 13.8

Consolidated Cash Flow

Rs. in mn FY2011E FY2012E FY2013E

EBIT 100,758 122,539 152,350 (Inc)/Dec in working capital (19,176) (24,112) (92,692) Cash flow from operations 81,582 98,427 59,658 Other income 41,228 20,769 19,716 Depreciation 24,856 31,371 41,517 Interest paid 21,490 26,515 36,123 Dividends paid (37,483) (40,327) (46,891) Tax paid 29,470 20,643 24,143 Net cash from operations 122,744 143,737 107,517 Capital expenditure (235,087) (269,791) (267,495) Free Cash Flows (112,342) (126,053) (159,977) (Inc)/Dec in investments 9,821 8,839 7,955 Inc /(Dec) in LT borrowing 133,063 145,110 134,534 Cash from Financial Activities 142,885 153,950 142,490 Opening Cash 144,595 114,052 86,156 Closing Cash 114,052 86,156 103,643 Change in Cash 30,542 27,896 (17,487)

Consolidated Balance Sheet

Rs. in mn FY2011 FY2012E FY2013E

Shareholders’ funds 676,262 732,084 843,885 Total Loans 511,033 656,144 790,679 Deferred tax liability 14,958 14,958 14,958 Total Liabilities 1,202,253 1,403,187 1,649,522 Net block 425,585 605,900 860,753 Investments 144,471 135,632 127,676 Net current assets 179,577 150,931 179,244 Total Assets 1,202,253 1,403,187 1,649,522 Balance Sheet Ratios

ROCE (%) 12.2 11.0 11.3 ROE (%) 13.0 13.7 14.2 Debt/Equity (x) 0.6 0.8 0.8

Source: Company

Power supply97%

Others3%

Shareholding pattern

Source: Company

FIIs4%

Promoters84%

Public4%

July 1, 2011

Outlook & Valuation We believe NTPC’s significant underperformance – due to delays in capacity addition and Lower PLF of some plants on account of fuel shortages – over the past 6 months are largely captured in its current stock price. As the stock is trading at historically low valuation, we prefer NTPC as a safe bet at the current valuation due to: I. Higher Fuel Security – Invulnerable to Coal Deficit & Rising Coal Prices

– fuel supply agreements signed with Coal India. II. The Company would add 20GW during FY12-15 period, despite Less

Capacity Additions from 11th Plan Target III. Regulated RoE led by efficient operations and favorable regulations,

Steady Cash-Flow IV. Robust Balance Sheet with and debt Strong Operational Cash-flows;

Ability to fund capex from internal accruals At the CMP, NTPC is trading at 2.0x and 1.8x its FY12E and FY13E P/ BV, respectively, and at EV/EBITDA of 11.1 on FY13E. We have arrived at an SOTP-based target price of Rs. 219 for the stock by under the FCFE valuation methodology. We initiate coverage on the stock with a “BUY” recommendation that implies a 17% upside from the current levels. The implied target multiples are within the historical long-term averages of the respective multiple.

Exhibit 2: DCF Calculation Y/e 31 Mar (Rs. in mn) FY12E FY13E FY14E FY15E FY16E FY17E FY18E FY19E FY20E FY21EProfit before tax 116,794 135,944 159,280 179,441 202,096 226,607 249,958 276,664 305,294 337,724Depreciation 31,372 41,517 54,210 64,507 73,166 81,900 89,697 97,026 104,824 113,091Tax paid (20,644) (24,144) (27,965) (31,703) (35,878) (40,371) (44,649) (49,522) (54,734) (60,622)Working capital ? 749 (10,826) (10,093) (8,068) (13,076) (14,333) (12,395) (13,928) (14,841) (16,884)Operating cash flow 128,272 142,492 175,432 204,176 226,308 253,804 282,611 310,240 340,543 373,308Capital expenditure (63,506) (88,911) (96,102) (68,693) (69,900) (69,900) (54,900) (62,400) (62,400) (69,900)Free cash flow 64,766 53,581 79,331 135,483 156,408 183,904 227,711 247,840 278,143 303,408Cost of Equity (Ke %) 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3 13.3Discounting factor 1.00 0.88 0.78 0.61 0.54 0.47 0.42 0.37 0.32 0.29Present value 64,766 47,283 61,777 82,160 83,700 86,846 94,894 91,142 90,263 86,888NPV (Explicit period FY12-21) 2,055,201 Investment (FY1 1) 144,471 Cash in hand FY11 114,053 Total Enterprise Value 2,313,725 Debt Outstanding FY11 511,033 Equity Value 1,802,692 No of outstanding shares 8,250 Per share Value 219 Source: Karvy Institutional Research

NTPC is trading at P/B of 1.8x & P/E 13.8x based on FY13E which at significant discount at 28% & 25% to it’s historical average of 2.5X P/B & 18.4X P/E respectively. NTPC has traded at P/B of 3-4x during FY08-09 when earning growth of 7% during FY09-11. We expect earning CAGR growth of 19% during FY11-13E thereby re-rating the stock.

Exhibit 3: 1 Yr. Forward P/E

Exhibit 4 : 1 Yr. Forward P/B

125175225275325

100150200250300350400

4xMax 27.9 Min 12.6 Mean 18.4

July 1, 2011

Investment Rationale • Best placed in terms of fuel security – Least Vulnerable to Coal

Deficit & Risisng Prices • Lower capacity addition in the 11th Plan – Expect Capacity to

Surge • Regulated RoE and firm cash flows; Core RoE higher than

CERC norms • Superior operating performance • Robust balance sheet with strong operational cash flows

I. Higher Fuel Security – Least Vulnerable to Coal Deficit & Rising Prices Despite the instances of coal shortage in a few plants, we believe NTPC is one of the best placed companies in terms of fuel security, as almost all its capacity off-take will continue to be through long-term PPAs. The plants commissioned before Apr’09 are part of supply arrangement with Coal India and are better placed than its forthcoming plants. The FSA with Coal India for new capacities is to the extent of 70% of the requirement, and balance would be blended with imported coal. We see about 16GW of standalone coal-based capacity to be commissioned during FY11-15, which would require about 64MTPA of coal.

Exhibit 5: Fuel Requirement / Supply FY08 FY09 FY10 FY11 FY12E FY13E FY14E FY15E FY16E FY17E

Total coal consumed (mn tonne) 120.2 129.8 136.2 139.8 146.0 164.3 172.4 175.7 199.2 222.6Domestic 120.2 124.4 129.9 127.2 133.7 152.2 160.5 164.1 187.8 211.4Imported 5.4 6.3 12.6 12.3 12.1 11.9 11.6 11.4 11.2Total gas consumed (MMSCMD) 11.8 10.8 13.9 12.5 12.5 17 17 17 17 17Source: Company & Karvy Institutional Research

II. Lower Capacity Addition in 11th Plan Period We believe the slippage in the addition of capacity has already been priced-in for NTPC. During the 10th Plan period, NTPC added 7,200MW of capacity on standalone basis. We expect 12,710MW addition in consolidated capacity in the current plan period leading to 44% slippage from the target.

Exhibit 6: Plans vs. Achievements

Plans Achievement / Expectation

Coal Gas Hydro Total Coal Gas Hydro Total Achievement % FY08 1,000 - - 1,000 1,740

- 1,740 74

FY09 2,320 - - 2,320 1,000

- 1,000 -57 FY10 2,800 - 800 3,600 1,560

- 1,560 -57

FY11 2,820 1,300 - 4,120 2,490

- 2,490 -40 FY12E 8,640 1,300 1,120 11,060 4,320

600 4,920 -56

Total 17,580 2,600 1,920 22,100 11,110

600 12,710 -44

Based on our estimates, the major portion of NTPC’s planned capacity addition during FY10-FY11E is likely to be commissioned in FY12E and FY13E, which will result into higher earnings in FY13E. NTPC’s capacity-addition plan for 11th Plan is 23GW , while in the first four years (FY08-11); the Company has been able to add only 6GW. Going forward, we expect a ramp-up in capacity and expect the Company to add 20GW over the next five years (FY12-15).

July 1, 2011

Expecting lower commercial capacity addition, we expect large capacities to be commissioned in FY13E & FY14E. Exhibit 7: Capacity Addition in 11th Plan (GW)

Exhibit 8: Details of under-construction Projects (MW) FY08 FY09 FY10 FY11 FY12E FY13E FY14E FY15E Standalone Entities 0 1000 1490 1990 2320 4570 4230 4660 Sipat-II unit II 500 0 0 0 0 0 0 Kahalgaon-II Unit II 500 0 0 0 0 0 0 Kahalgaon-II Unit VII 500 0 0 0 0 0 NCTPP-II, Dadri 490 0 0 0 0 0 Sipat-I, Unit I 0 660 Korba-III Unit VII 500 500 NCTPP-II, Unit-II, Dadri 490 Farakka-III 500 Simhadri-II, Unit III 500 Sipat-I, Unit II 660 Sipat-I, Unit III 0 660 Simhadri-II, Unit IV 500 Bongaigaon, Unit I 250 Bongaigaon, Unit II 250 Bongaigaon, Unit III 250 Mauda-I, Unit I 500 Mauda-I, Unit II 500 Barh-II, Unit I 660 Vindhyachal-IV, Unit I 500 Vindhyachal-IV, Unit II 500 Rihand-III, Unit I 500 Rihand-III, Unit II 500 Barh-I, Unit I 660 Barh-I, Unit II 660 Barh-II, Unit II 660 Barh-I, Unit III 660 Joint Ventures 740 0 0 500 2000 1390 500 0 Ratnagiri (Dhabol) JV 740 Indira Gandhi STPP, Unit I 500 Indira Gandhi STPP, Unit II 500 Indira Gandhi STPP, Unit III 500 Nabinagar, Unit I 250 Nabinagar, Unit II 250 Nabinagar, Unit III 250 Nabinagar, Unit IV 250 Vallur - Phase-I, Unit I 500 Vallur - Phase-I, Unit II 500 Vallur - Phase-II 500 Muzzafarpur-II, Unit II 195 Source: Karvy Institutional Research

31 3438

1.5 2.5 5.0 5.3 5.0

FY10 FY11 FY12 FY13 FY14Installed Capacity Capacity Addition

July 1, 2011

III. Regulated RoE with firm Cash-Flow; Core RoE Higher Than CERC Norm NTPC’s core business RoEs stand at about 23% – far higher than the norms of regulated RoE of 15.5%. However, the investments on NTPC’s books depress reported RoE. The Central Electricity Regulatory Commission (CERC) has determined the tariffs for NTPC’s plants for the period from FY09 to FY14. Hence, NTPC’s tariff would be reviewed only after FY14. With NTPC’s increasing capex, we believe a larger portion of its equity will be deployed on capital works in progress (CWIP). However, we do not expect this to affect the core ROE materially , which we forecast to range from 20-21% until FY15E.

Exhibit 9: RoE Trends (%)

Exhibit 10: Regulated Equity Base (Rs mn)

With fuel-supply agreements in place, scheduled imports and captive coalblock development would help NTPC maintain a high plant-load factor and availability. This would enhance its RoE, as stipulated in the new tariff policy for 2009-14.

Exhibit 11: Cost Break-up (Rs per unit)

IV. Superior Operating Performance In terms of operations, NTPC has always been considerably above the national average. The availability factor for coal-based power stations has increased from 89.32% in FY99 to 91.62% in FY11. The PLF has increased from 76.6% in FY99 to 88.29% in FY11. Moreover, NTPC accounts for 20% (27.9GW) of India’s generation capacity and 29% of country’s electricity generation. NTPC has an efficiency-linked incentive-based tariff structure to boost its core business RoE to 24%, which is significantly higher than the allowed RoE of 15.5%. However, higher cash balance & the investments – consisting of 8.5% tax-free bonds issued to NTPC to settle past dues from its customers have depressed NTPC’s reported RoE to 14% levels as the yield from the investments are significantly lower (7-8%).

FY09 FY10 FY11 FY12 FY13 FY14 FY15

0100000200000300000400000500000600000700000

0.14 0.

0.16 0.24

FY12 FY13

July 1, 2011

Exhibit 12: Operational Performance

Exhibit 13: Operational Matrix FY09 FY10 FY11 FY12E FY13E FY14ENameplate capacity (MW) 30,144 31,704 34,044 38,364 43,814 46,294Standalone entity (MW) 27,850 28,840 30,680 33,000 37,060 39,040JV's (MW) 2,294 2,864 3,364 5,364 6,754 7,254Commercial capacity (MW) 29,706 31,704 34,044 38,364 43,814 46,294Standalone entity (MW) 27,412 28,840 30,680 33,000 37,060 39,040JV's (MW) 2,294 2,864 3,364 5,364 6,754 7,254Gross generation (MU) 206,939 218,840 231,795 244,378 272,326 287,123Commercial generation (MU) 206,156 218,439 231,370 243,930 271,827 286,596Energy sold (MU) 193,688 205,091 217,232 229,024 255,216 269,084Aux. consumption (%) 6.4 6.5 6.5 6.5 6.5 6.5Avg PLF (%) 91.1 90.8 88.3 85.8 85.3 85.3Avg PAF (%) 92.5 93.2 95.0 95.5 95.5 95.5Avg realisation (Rs/unit) 2.1 2.2 2.4 2.5 2.6 2.8Avg Fuel Cost (Rs/unit) 1.4 1.4 1.6 1.7 1.7 1.8Source: Company & Karvy Institutional Research

V. Robust Balance Sheet with Strong Operational Cash-flows Positive operating cash-flows, investments and cash balance provide comfort as far as funding for the forthcoming projects of the Company. NTPC plans to spend Rs. 1018 bn capex during FY12-15 period. Low gearing (debt-equity of 0.8 in FY12) and healthy cash balance (Rs. 80 bn at FY12). Given the strength of operational performance and healthy balance sheet, we expect the financing for the forthcoming projects would not be a major issue, in contrast with private independent producers.

Exhibit 14: Strong operating cash-flow Capex FY12E FY13E FY14E FY15E Capex (Rs mn) 269,791 267,495 248,508 232,236Capitalization - RoE business (Rs mn) 211,687 296,371 320,339 228,977Equity portion (30%) 63,506 88,911 96,102 68,693Debt portion (70%) 188,854 187,247 173,956 162,565Total Debt (Rs mn) 699,887 843,391 964,635 10,669,10Repayment 43,743 52,712 60,290 66,682Est. year ending debt 656,144 790,679 904,345 10,002,28Actual Debt 656,144 790,679 904,345 10,002,28Operating cash-flow (Rs mn) 127,805 141,911 174,761 203,281Source: Company , Karvy Institutional Research

FY05 FY06 FY07 FY08 FY09 FY10 FY11 FY12 FY13 FY14 FY15

PLF PAF

50,000

100,000

150,000

200,000

FY10 FY11E FY12E FY13E

Cashflow from Operation (Rs mn)

Net Debt/Equity

(Rs mn) (x)

July 1, 2011

Exhibit 16: Financial Assumption Estimates Growth (%) Comments FY10 FY11 FY12E FY13E FY11 FY12E FY13E

Operational Parameters Capacity (MW) 28,840 30,680 33,000 37,060 6 8 12 We expect higher capacity addition in

FY12-13 Sales Volume (MU) PPA 218,840 231,795 244,378 272,326 6 5 11 Company mainly operates in regulated

business Merchant - - - 150 - - - Competitive - - - - - - - JV's (MW) 2,864 3,364 5,364 6,754 17 59 26 Gross generation (MU) 218,840 231,795 244,378 272,326 6 5 11 Generation growth in line with capacity

growth Commercial generation (MU)

218,439 231,370 243,930 271,827 6 5 11

Energy sold (MU) 205,091 217,232 229,024 255,216 6 5 11 Aux. consumption (%) 7 7 7 7 0 0 0 Unchanged Avg PLF (%) 90.81 88.31 85.81 85.31 -3 -3 -1 We expect lower PLF for new capacity Avg PAF (%) 93 95 95 95 2 1 0 Unchanged Tariffs Avg realization (Rs/unit) PPA 2.2 2.4 2.5 2.6 8 5 5 Regulated tariff based on cost structure Merchant - - 4 3.5 - - (12.5) Small capacity based on merchant Competitive - - - - Blended Fuel cost Avg Fuel Cost (Rs/unit) 1.4 1.6 1.7 1.7 10 5 2 90% linkage from Coal India Imported Coal (MT) 6.30 12.60 12.35 12.10 100 -2 -2 Domestic Coal (MT) 129.9 128.0 134.5 151.7 -1 5 13 Financial Forecasts Sales (Rs mn) 463,905 548,740 585,544 683,410 Sales (Rs mn) Total Sales 463,905 548,740 585,544 683,410 20 5 17 Sales to track capacity addition Operating Expenses (Rs mn)

339,801 425,635 434,402 492,171 25 2 13 Fuel cost expected to remain under control

EBIDTA (Rs mn) 119,449 125,616 146,242 186,047 5 16 27 EBIDTA margin (%) 26.1 22.9 25.3 27.5 -12 11 9 EBITDA margin to improve Net Interest Expense (Rs mn)

18,089 21,491 26,515 36,123 19 23 36 Higher debt requirements

Avg. Interest rate (%) 9 9 8 8 -4 -3 0 Unchanged PAT (Rs. mn) 81,276 79,580 96,150 111,801 -2 21 16 PAT margin (%) 18.8% 16.6% 16.4% 16.4% -12 -1 0 Higher interest EPS (Rs.) 10.6 10.8 11.7 13.6 2 8 16 EPS to show higher growth in FY13 on

Higher Capacity Cash Flow forecast(Rs mn)

CFO (a) 96,130 122,972 144,037 108,100 28 17 -25 Strong operating cash-flow CFI (b) 101,731 235,088 269,791 267,495 131 15 -1 FCF(a-b) (5,601) (112,116) (125,754) (159,395) 1902 12 27 CFF - © 23,722 142,885 153,950 142,490 502 8 -7 Total Changes in cash (a+b+c)

18,121 30,542 27,897 (17,487) 69 -9 -163

July 1, 2011

Sensitivity Analysis Based on sensitivity analysis our upper value for NTPC is Rs 257 at 5% terminal growth & 12% cost of equity, while lower value for NTPC Rs 166 at 2% terminal growth & 14% cost of equity.

Exhibit 17: Cost of Equity vs. Terminal Growth Sensitivity Cost of Equity (Ke) (%)

Terminal Growth (%)

12 12.5 13 13.5 14

2.0% 196 188 175 173 166 3.0% 211 203 189 186 179 4.0% 231 222 207 204 195 4.5% 243 233 217 214 205 5.0% 257 246 230 226 217

Exhibit 18: Cost of Equity & Terminal Growth Assumption

Beta (x) 0.7 Risk free rate (%) 9.0 Market Premium (%) 6.0 Cost of Equity (%) 13.3 Terminal Growth Rate (%) 4.5

Exhibit 19: Karvy vs. Consensus Karvy Consensus Difference in % Revenue (Rs mn)

FY12E 585,544 632,661 (7.4) FY13E 683,410 725,860 (5.8)

EBIDTA (Rs mn) FY12E 153,912 167,122 (7.9) FY13E 193,868 198,724 (2.4)

PAT (Rs mn) FY12E 96,150 991,10 2.9 FY13E 111, 801 111,853 0

We are lower than consensus estimate on the topline for FY12E, as we factor MAT rate (19.93%) to gross-up the regulated RoE thereby lowering tariff.

Key Risks: In our view, the downside risks to our recommendation include:

I. Execution delays, and II. Lower fuel availability leading to lower incentives

July 1, 2011

Financial Overview Net Sales - CAGR forecast of 14% for FY10-13E

We expect net sales to grow at 14% CAGR in FY10-13E on the back of the robust 12.7GW of capacity additions and higher equity base from Rs. 237 bn in FY10 to Rs. 419 bn in FY13E. We estimate 6% rise in tariff and 7% rise in net generation volume over the same period. We use the MAT rate (19.93%) to gross-up the regulated RoE thereby lowering tariff.

Exhibit 20: Topline to grow at 14% CAGR

Operating Margins to Remain Healthy

NTPC’s operating margin is expected to improve from 23% in FY11 to 28% in FY13E due to better operational performance.

Exhibit 21: Robust Growth in Operating Profits & Healthy OPMs

200000

400000

600000

800000

Net sales (Rs mn) Growth %

100000

150000

200000

FY10 FY11 FY12E FY13EEBIDTA EBIDTA Margin (%)

(Rs mn) (%)

July 1, 2011

Net Profit to Improve

Due to the slow pace of execution we estimate the net profit to grow at 11% CAGR over FY10-13E however net profit growth expected to be lower than sales growth on account of higher interest & depreciation costs.

Exhibit 22: Net Profit to lag Capacity Growth

Return Ratios to Remain Healthy

We estimate RoEs to improve by 160 bps by FY13E due to decline in CWIP and deployment of excess cash into projects under development.

Exhibit 23: Return Ratios to Improve

020000

400006000080000

100000120000

FY10 FY11 FY12E FY13EReported Net Profit Growth (%)

ROCE (%) ROE (%)

(Rs mn) (%)

July 1, 2011

(Rs mn) FY09 FY10 FY11 FY12E FY13E

Net revenues 419,921 463,905 548,740 585,544 683,410 % Growth 14% 10% 18% 7% 17% Raw Material 271,107 294,628 353,738 378,061 430,168 Staff 24,631 24,124 27,897 29,471 32,439 Operating Expenses 18,438 21,049 44,000 26,861 29,558 Operating Other Income 1,163.0 2,282.0 2,510.2 2,761.2 2,623.2 Operating expenses 314,176 339,801 425,635 434,394 492,165 EBIDTA 106,908 126,386 125,616 153,912 193,868 % Growth -7 18 -1 23 26 EBIDTA margin (%) 25 27 23 26 28 Other income 44,246 32,286 41,228 20,770 19,717 Interest 19,962 18,089 21,491 26,515 36,123 Depreciation 23,645 26,501 24,857 31,372 41,517 Profit Before Tax 107,547 114,082 120,496 116,794 135,944 Provision for tax 25535 26800 29470 20644 24144 Reported Net Profit 82,012 87,282 91,026 96,150 111,801 % Growth 11 6 4 6 16 Net Margin (%) 20 19 17 16 16 Extra-Ordinary Inc/(Exp) 12,870 6,006 (11,446) 0.0 0.0 Adjusted Net Profit 69,142 81,276 79,579 96,150 111,800 % Growth -8 18 -2 21 16 EPS (Rs) 9.9 10.6 10.8 11.7 13.6

Y/E March (Rs mn) FY09 FY10 FY11E FY12E FY13E

Equity capital 82,455 82,455 82,455 82,455 82,455 Reserves & surplus 491,246 541,920 593,807 649,629 761,430 Shareholders funds 573,701 624,375 676,262 732,084 843,885 Long Term Loans 345,678 377,970 511,033 656,144 790,679 Total Loans 345,678 377,970 511,033 656,144 790,679 Deferred tax liability 16,249 14,958 14,958 14,958 14,958 Total Liabilities 935,628 1,017,303 1,202,253 1,403,187 1,649,522 Gross block 623,530 668,501 772,012 983,699 1,280,069 Depreciation 294,153 320,888 346,427 377,799 419,316 Net block 329,377 347,613 425,585 605,900 860,753 Capital WIP 264,049 321,043 452,620 510,724 481,849 Investments 147,014 154,293 144,471 135,632 127,676 Inventory 32,434 33,477 38,184 40,142 46,851 Debtors 35,842 66,514 75,866 79,757 93,087 Cash & Bank Bal. 162,716 144,595 114,053 86,156 103,643 Loans & Advances 71,082 57,349 65,413 66,595 77,726 Current Assets 302,074 301,935 293,516 272,650 321,308 Other provisions 32,495.0 30,705.0 35,022.4 38,756.1 45,233.6 Current Liabilities 74,391 76,876 78,917 82,964 96,830 Net current assets 195,188 194,354 179,577 150,931 179,244 Total Assets 935,628 1,017,303 1,202,253 1,403,187 1,649,522 Source: Company , Karvy Institutional Research

July 1, 2011

Exhibit 26: Cash Flow statement

(Rs mn) FY2009 FY2010 FY2011E FY2012E FY2013E

EBIT 83,263 99,886 100,759 122,540 152,351 (Inc)/Dec in working capital (122,787) (60,267) (19,176) (24,112) (92,692) Cash flow from operations (39,524) 39,619 81,583 98,428 59,659 Other income 44,246 32,286 41,228 20,770 19,717 Extra-ordinary income 12,870 6,006 (11,446) - - Depreciation 23,645 26,501 24,857 31,372 41,518 Interest paid 19,962 18,089 21,491 26,515 36,123 Dividends paid (34,700) (36,608) (37,484) (40,328) (46,892) Others 12,870 6,006 5,145 - - Tax paid 25,535 26,800 29,470 20,644 24,144 Net cash from operations 30,440 96,130 122,745 143,738 107,518 Capital expenditure (131,351) (101,731) (235,088) (269,791) (267,495) Free Cash Flows (100,911) (5,601) (112,343) (126,054) (159,978) Inc/(Dec) in LT borrowing 73,772 32,292 133,063 145,111 134,535 (Inc)/Dec in investments 13,795 (7,279) 9,822 8,840 7,956 Others (40) (1,291) - - - Cash from Financial Activities 87,527 23,722 142,885 153,950 142,490 Opening Cash 149,332 162,716 144,595 114,053 86,156 Closing Cash 162,716 144,595 114,053 86,156 103,643 Change in Cash (13,384) 18,121 30,542 27,897 (17,487) Source: Company , Karvy Institutional Research

FY2009 FY2010 FY2011 FY2012E FY2013E

Raw Material Cost / Sales 65 64 64 65 63 Manpower Cost / Sales 6 5 5 5 5 Operating & Other cost / Sales 4 5 8 5 4 Revenue Growth 14 10 18 7 17 EBIDTA Margins 25 27 23 26 28 PAT Margins 20 19 17 16 16 ROCE 13.1 12.9 12.2 11.0 11.3 ROE 12.6 13.6 13.0 13.7 14.2 Core RoE 20.9 24.2 19.5 20.9 20.4 Core RoCE 14.9 17.2 16.8 16.4 15.9 Source: Company , Karvy Institutional Research

FY2009 FY2010 FY2011 FY2012E FY2013E

EPS (Rs) 9.9 10.6 10.8 11.7 13.6 PER (x) 22.3 19.0 18.3 16.0 13.8 Book value per share 70 76 82 89 102 P/B 2.7 2.5 2.3 2.1 1.8 EV/EBIDTA (x) 16.1 14.0 14.5 13.7 11.5 Fixed assets turnover ratio (x) 1.3 1.3 1.3 1.0 0.8 Debt/Equity (x) 0.3 0.4 0.6 0.8 0.8 EV/Sales (x) 4.1 3.8 3.7 3.6 3.3 Source: Company , Karvy Institutional Research

July 1, 2011

Tata Power

POWER July 1, 2011

Tata Power Company

Bloomberg: TPWR IN Reuters: TTPW.BO BUY

Recommendation CMP: Rs. 1308 Target Price: Rs. 1503 Upside: 15%

Stock Information Market Cap. (Rs bn / US$ mn)310/6919 52-week High/Low (Rs) 1468/1132 Shares Outstanding (mn) 237 3m ADV Rs mn 314/USDmn 7.0 Beta 0.92 Sensex 18,846 Nifty 5,647

Stock Performance (%) 1M 3M 12M YTD Absolute 6.2 (2.0) (0.0) (4.2) Rel. to Sensex 4.4 1.1 (6.5) 3.9

Performance

1 year forward P/B

16,000 17,000 18,000 19,000 20,000 21,000 22,000

Sensex (LHS) Tata Power (RHS)

1,000 1,500 2,000 2,500 3,000

Power Generation to treble to 8,200 MW by FY13E Tata Power Company (TPC) – India's largest private sector power producer with ~3,000MW of power generation assets – has a notable project portfolio with over 5,000MW of projects under construction resulting in robust 65% CAGR in topline over FY11-13E. Mumbai License Area: TPC to Benefit from Open Access Approvals TPC’s current capacity stands at 2,127MW in Mumbai Licence Area – with under regulated return of 14.5% (71% of current capacity), and 548MW captive power plant with a long-term PPA at RoE 20% – provides visibility steady cash flow. Derivative Play on Coal: Ensures Hedge for Mundra UMPP TPC has 30% stake each in Bumi Resources' (Bumi) two unlisted coal mines i.e. KPC & Arutmin. Further, as per the independent coal supply pact with Bumi, TPC would get coal from these mines for firing its 4,000 Mundra UMPP. When total production at the mines reaches the targeted 100 MTPA, TPC will have net long position of 23 MTPA in Indonesian coal, which would coincide with the Mundra UMPP becoming fully operational. The Mundra UMPP will require 12.3 MTPA of coal, out of which 45% (5.6 MTPA) can be passed on, while the rest 55% (6.7 MTPA) would be subject to price volatility. Debt Service Obligations: to Help Managing Rs. 250 bn Capex Plan TPC has ~6,125MW of projects in the pipeline – entailing total capex of Rs. 250 bn – with equity contribution of ~ Rs. 50 bn. Moreover, TPC would also generate adequate internal accruals owing to total ~8,000MW operational capacity, which is likely to get operational by FY13E. TPC owns substantial investment to the tune of ~Rs. 68 bn, which it can monetize to fund its growth plans.

Outlook & Valuation At the CMP, the stock trades at 1.9x and 1.6x FY12E and FY13E P/BV respectively, and 7.5x FY13E EV/EBITDA. We have arrived at SOTP-based target price of Rs. 1,503 for the stock, by independently valuing TPC’s power business, investments, stake in Bumi and the other JVs. The power generation business has been valued at Rs. 738, while TPC’s stake in Bumi has been valued at Rs. 370 per share. We initiate coverage on the stock with a “Buy” recommendation. Exhibit 1: Key Financials Y/E March (Rs. in mn) FY09 FY10 FY11 FY12E FY13ENet Sales 180,570 189,303 193,482 255,235 321,893 EBIDTA 30,828 37,806 44,349 63,244 80,205 Net Profit 12,987 21,386 22,561 28,399 32,118EPS (Rs) 55 83 87 109 124PER (x) 23.8 15.8 15.1 12.0 10.6EV/EBITDA (x) 13.6 12.5 11.6 8.5 7.1 Source: Company , Karvy Institutional Research

Initiating Coverage

July 1, 2011

Tata Power

Company Background Tata Power Company (TPC) is India's largest private sector power utility with operations across the power value chain. It has ~3,000MW of operational projects and is executing the country's first 4,000MW UMPP at Mundra. It also has projects with 6,125MW capacity under development. TPC has interests in coal mining through its 30% stake in Bumi, apart from allocation of domestic coal blocks to the Company. In the T&D segment, TPC has a presence through its JVs i.e. Powerlinks & NDPL. TPC has 1,100 circuit km (ckm) of transmission network in the Mumbai License Area (MLA) comprising 973ckm of 220 kV/110 kV overhead lines and 124ckm of 220 kV/110 kV underground cables. Its transmission system connects its Trombay and hydel stations to 17 receiving stations spread across the MLA. Thetransmission lines are used by BEST, Rel Infra and TPC’s own distribution business. To meet the growing demand in Mumbai, TPC is in the midst of augmenting its existing transmission capacities.

Company Financial Snapshot Consolidated Profit & Loss Rs. in mn FY11 FY12E FY13E

Net revenues 193,482 255,235 321,893 EBIDTA 44,349 63,244 80,205 Interest 8,102 14,728 17,416 Depreciation 9,802 12,812 18,850 Profit Before Tax 32,317 40,571 47,582 Provision for tax 9756 12171 15464 Adjusted Net Profit 20,596 25,926 26,931 Reported Net Profit 22,561 28,399 32,118

Profit and Loss Ratios

EBIDTA Margin (%) 22.9 24.8 24.9 PAT Margin (%) 10.6 10.2 9.1 Mcap/Sales (x) 1.4 1.1 0.9 RoCE (%) 9.6 12.0 12.8 ROE (%) 15.6 17.1 16.7

Consolidated Cash Flow Rs. in mn FY11E FY12E FY13E

EBIT 34,546 50,432 61,356 (Inc)/Dec in Working Capital (2,662) (6,086) (14,233) Cash Flow from Operations 31,885 44,346 47,122 Other Income 5,872 4,867 3,642 Depreciation 9,802 12,812 18,850 Interest Paid 8,102 14,728 17,416 Dividends Paid 3,341 3,341 3,341 Tax Paid 9,756 12,171 15,464 Net Cash from Operations 26,361 31,785 33,393 Capital Expenditure (68,000) (58,250) (63,323) Free Cash Flows (41,639) (26,465) (29,930) Inc/(Dec) in LT borrowing 50,000 30,000 30,000 Cash from Financial Activities 50,000 30,000 30,000 Opening Cash 23,107 31,468 35,003 Closing Cash 31,468 35,003 35,072 Change in Cash 8,361 3,535 70

Consolidated Balance Sheet Rs. in mn FY11E FY12E FY13E

Shareholders’ Funds 140,334 162,919 186,509 Total Loans 234,469 264,469 294,469 Deferred Tax Liability 4,308 4,308 4,308 Total Liabilities 393,173 448,232 504,392 Net Block 162,923 240,360 255,511 Investments 30,823 30,823 30,823 Net Current Assets 36,751 46,372 58,058 Total Assets 393,173 448,232 504,392 Balance Sheet Ratios

ROCE (%) 9.6 12.0 12.9 ROE (%) 15.6 17.1 15.4 Debt/Equity (x) 1.4 1.5 1.5 EV/Sales (x) 2.7 2.1 1.8

Source: Company

Power business

Coal business34%

Others1%

Shareholding pattern

Source: Company

FIIs23%

MFs29%

Promoters32%

Public16%

July 1, 2011

Tata Power

Outlook & Valuation As the stock is trading at historically low valuation, we prefer Tata Power as a safe bet in private space at the current valuation due to

I. Higher Fuel Security – 30% stake in Bhumi Resources gives net long position in the rising coal deficit & prices.

II. 65% CAGR growth in Capacity addition-Power Generation to treble to 8,200 MW by FY13E & lower merchant portion.

III. Regulated RoE for 40% of asset portfolio ensure Steady Cash-Flow. IV. Robust Balance Sheet with and debt Strong Operational Cash-flows;

Ability to fund capex from internal accruals At the CMP, Tata Power trades at 1.7x and 1.6x FY12E and FY13E P/BV, respectively, and 7x FY13E EV/EBITDA. We have arrived at SOTP-based target price of Rs. 1,503 for the stock, by independently valuing the Company's power business, investments, stake in Bumi and the other JVs. The power generation business has been valued at Rs. 738 per share. The Company's stake in Bumi has been valued at Rs. 370 per share. We initiate coverage on the stock with a “BUY” recommendation that implies 15% upside from the current levels. The implied target multiples are within the historical long-term range of the respective multiple.

Exhibit 2: SOTP Valuation

Project Details Capacity

(MW) COD Cost of

Equity (Ke) Value

method Equity Value

(Rs mn) Stake

% Milestone

Discount Per share

Mumbai License Area 3,000 Operational 14% FCFE 143980 100 0 599

Mundra UMPP 4,000 Under construction 14% FCFE 21,228 100 0 92

Maithon Power JV 1,050 Under construction 14% FCFE 10762 76 0 47

Powerlinks Transmission - Operational - P/E 6329 51 0 27

NDPL - Operational 13% FCFE 17,917 51 0 76

Tata Power Trading - Operational 13% FCFE 705 - 0 3

Indonesian coal mines - Operational - 122,021 30 0 370

Investments - - - 68,431 289

Total Value per share 1,503

Tata Power is trading at P/B of 1.6x & P/E 10.6 based on FY13E, which at significant discount at 24% & 29% to its historical average of 2.1x P/B & 14.9x P/E, respectively. Tata Power has traded at P/B of 2.5-3x during FY09-11.

Exhibit 3: 1-year Forward P/E

Exhibit 4: 1-year Forward P/B

4xMax 30.4 Min 7.8 Mean 14.9

July 1, 2011

Tata Power

Investment Rationale • Capacity to treble by FY13E • Mumbai License Area with steady cash flows • New UMPPs to ensure future cash flows • Established fuel security • Well placed in terms of fuel security for upcoming projects • Adequately funded growth plans • Bluechip investmetns could be monetised • Other business of distribution well-established

I. Capacity to Treble to 8,200MW by FY13E TPC, the country's largest private sector power player with ~3,000MW of power generation assets, has over 5,000MW of projects under construction and expects to commission its flagship projects such as the Mundra UMPP and Maithon Project on scheduled. Work at the first of the UMPPs awarded to the Company at Mundra in Gujarat is progressing well, with 70% of the work completed. First unit of the Mundra UMPP is expected to commence operations in Q2FY12, while the other units would be commissioned in intervals of 4-5 months thereafter. At the Maithon project, close to 100% of completion, the first unit is expected to get commissioned in Q1FY12. Overall, we believe that the Company's massive power capacity addition will drive its growth going ahead. The share of the coal-based plants in the Company's overall capacity is also expected to increase.

Exhibit 5: Existing Capacity Plant Capacity (MW) Fuel type Beneficiary Trombay 1,580 Coal/oil/gas Mumbai Licence Area (1,480MW) Merchant capacity (100MW) Jojobera 428 Coal Tata Steel Belgaum 81 Gas IPP/ Multiple Beneficiaries Khopoli 72 Hydro Mumbai License Area Bhivpuri 75 Hydro Mumbai License Area Bhira 300 Hydro Mumbai License Area Haldia 120 Waste gas Hoogly Metcoke Jamshedpur 120 Production gas Tata Steel Supa 17 Wind Multiple beneficiaries Khandke 50 Wind Multiple beneficiaries Barmanvel 11 Wind Multiple beneficiaries Gadag 50 Wind Multiple beneficiaries Samana 50 Wind Multiple beneficiaries Sadwaghapur 18 Wind Multiple beneficiaries Visapur 28 Wind Multiple beneficiaries Total 2,999 Source: Company

July 1, 2011

Tata Power

Exhibit 6: Projects Under Implementation Project Capacity Fuel Fuel Supply Agreement Off-take % Completion COD

Mundra 4,000 Imported coal Off-take agreement with Indonesian coal for 10.11 MTPA (+20%)

PPAs have been signed for 3,800 MW

85 Unit1 by Sept’11

Maithon 1,050 Coal Linkage Domestic coal 100% linkage sanctioned All units by FY13

FSA with Bharat Coking Coal for 1.65 MTPA

PPA's have been signed for 1,050 MW

95 Unit 1 in FY12, Unit 2-4 months after Unit1

Central coalfields has provided LOA for 1.97 MTPA

FSA with Tata Steel for 0.05-1 MTPA

Dagacchu 126 Hydro NA TPTCL FY13

Mithapur 25 Solar NA 25 years PPA FY12

Lodhivali 40 Diesel NA - FY12

Wind 148 NA - FY12 Source: Company, Karvy Institutional Research

Exhibit 7: Projects in pipeline

Project Fuel Source Capacity Status Phase-I Coastal Maharashtra Imported coal 1,600 Land acquisition in progress

Naraj Marthapur IPP Partially met through Mandakini coal block

660 Land acquisition in progress, Main clearance obtained, environmental clearance process has begun, PPA to be signed

Tiruldih IPP Partially met through Tubed coal block

1,980 To be executed in phases. Land acquisition in progress

Dugar Hydro -Electric Hydro 236 Won Bid for project

Sorik Marapi Geothermal 240 Exploration has commenced

Visapur Wind 88 Advance stages of planning

Solar Solar 10 Under Planning

Phase-II Maithon Phase-II Domestic Coal 1,050 Under Planning

Mundra Phase-II Imported coal 1,600 Under Planning

Kalinganagar Coal/Gas 600 Under Planning

Tamakoshi Hydro 880 Under Planning

Wind Wind 200 Under Planning

Bhivpuri CCGT Gas 450 Under Planning Source: Company, Karvy Institutional Research

Exhibit 8: Year-wise Projected Power Capacity Addition (MW)

2,971 3,127

10,000

FY2010 FY2011E FY2012E FY2013E

July 1, 2011

Tata Power

II. Mumbai License Area with Steady Cash-flow: TPC to Benefit from Open Access Approvals Tata Power has currently 2,127 MW in Mumbai License Area, which are under regulated return at 14.5% (71%), while CPP 548 MW with a long term PPA at RoE 20% provides steady cash-flow. Out of 458MW to be released from its existing allocations, 100MW of this was tied up with BEST and 358MW was expected to be available to be sold under a new long-term PPA and/or in the short-term/trading market. With Rel Infra license to distribute power to Mumbai expiring Aug’11 for 1,500MW, Tata Power is well-placed to outbid others. Maharashtra Electricity Regulatory Commission (MERC) ruling in Oct’09 allowing open access helped TPC, as it witnessed a number of customers willing to shift from Rel Infra’s network to TPC. The MERC has slashed the tariff rates of BEST consumers by 10% to 15%. As for TPC consumers, the households consuming up to 300 units have got 7-19% reduction in rates. However, the tariff for higher slabs for TPC consumers has increased by an average 5% to 8% per unit. The revised power tariffs make it convenient for people consuming 0-100 & 100-300 units every month to migrate to BEST and TPC. This has become an especially profitable proposition for the around 12 lakh low-end consumers. TPC, with this new tariff structure in place from September 1, has emerged as the cheapest power supplier in Mumbai. So far around 70,000 low-end consumers have benefited by the switchover to TPC. TPC-Distribution’s existing demand is met partly from its own generating station at Trombay and hydel power plants in Raigad district of Maharashtra as per the PPA signed between the TPC-Generation (TPC-G) and TPC-D. Capacity available to TPC-D from TPC-G is 647MW under the existing arrangement. TPC-D has planned to procure additional 198MW of capacity from TPC-G from Apr’11. The total capacity available with TPC-D will be at around 845MW considering the additional capacity from TPC-G. TPC- D would face the peak shortfall about 411MW in FY16 after considering the additional capacity available with TPC-D. To meet peak shortfall TPC is doing a capex of Rs. 23 bn.

Exhibit 9: Power Procurement Requirements (MW)

Significant capacity has been tied up in the long-term PPAs / Contracts provide stable cash flows.

FY11 FY12 FY13 FY14 FY15 FY16

Peak Demand (MW) Contarct Power at Bus Bar GAP

July 1, 2011

Tata Power

Exhibit 10: Significant capacity tied up-Long term Model Capacity

(MW) % of overall capacity

Returns Tata Power Projects

Contract (Yrs)

Off-take

Regulated returns

1927 62 Fixed return of equity

Mumbai Operations

Till FY18 Best (1000 MW), TPCTCL(400MW), TATA Power distribution (527 MW)

Renewable 231 7 Fixed Tariff + PLF driven

Wind, Solar 101 MW-Till FY28-29

GUVNL, Tata Power Dist, Tata Motors, BESCOM

CPP 668 21 PPA driven (14-19%)

Jojobera Till 2039 TATA Steel

Jamshedpur Till 2027 TATA Steel

IEL Till 2041 TATA Steel

Merchant 200 6 No cap on returns

Haldia (100 MW)

Unit 8 (100 MW)

MoU/Bilateral 20 1 PPA driven Haldia (20 MW) Till 2018 West Bengal State Electricity Distribution

Exhibit 11: Generation Capacity by Business Model

Business Model TPC's projects FY10 capacity (MW) FY13E capacity (MW) Regulated Mumbai Licence Area, Maithon, 2,122 2,873-3,073 wind-based plants Captive power Jamshedpur (PH6), Jojobera 548 668 Merchant Haldia unit (8), Trombay 200 200-400 Case 1 Haldia unit 20 20 Case 2 Mundra UMPP, Belgaum 81 4,081

III. Ultra Mega Power Projects (UMPPs)

A. Mundra UMPP

Project Status: Coastal Gujarat Power (CGP) – a Special Purpose Vehicle (SPV) owned by TPC – will build, own and operate this 4,000MW ultra mega imported coal and supercritical technology-based power plant. This Rs. 170 bn project is being funded via debt-equity ratio of 75:25 and the equity portion is Rs. 42.5 bn, and we expect the first unit to be commenced by Q1FY13. Fuel Tie-up: The project would require 12.3 MTPA of coal, which would be procured from Kaltim Prima Coal (KPC), Indonesia. Though TPC has 30% stake in KPC, the coal supply agreement is independent of TPC’s stake in the mines. Power Off-Take Agreement: With respect to power off-take, the project is expected to supply power to a number of northern and western states. The levelised tariff for the project is fixed at Rs. 2.26 per unit, which is higher than the three other UMPPs awarded till-date. As per the terms of the Mundra UMPP, half its coal requirement (~6 MTPA) would adhere to CERC-determined escalation clauses, while the other half has been contracted at fixed prices.

July 1, 2011

Tata Power

Valuation: We have arrived at a value of 92 for the Mundra project. Exhibit 12: Financials & Valuation of Mundra UMPP (Rs mn) FY12E FY13E FY14E FY15E Capacity 667 3,000 4,000 4,000 Sales Volume (Mn units) 3,574 14,933 30,632 30,632 Realisation per Unit (Rs) 2.34 2.40 2.33 2.33 Net Sales 8,330 35,588 71,102 71,102 Operating Expenses 5,707 25,867 53,705 53,905 EBITDA 2,623 9,721 17,397 17,197 Depreciation 1408 4435 8448 8448 Interest 1208 5243 13110 12144 PBT 7.7 42.5 (4,160) (3,394) Tax 1.5 8.5 - - PAT 6 34 (4,160) (3,394) FCFE (4,165) (7,925) (9,507) (3,463) PV (4,165) (6,952) (7,315) (3,463) NPV (Explicit period FY12-FY37E) 21,228 Per Share 92 Source: Company, Karvy Institutional Research

Exhibit 13: Mundra UMPP Details Project capacity 4,000MW (5X800 MW) Ownership structure

Owned by Coastal Gujarat Power – a WOS of TPC

Business model Regulated Customers Gujarat (1,805MW), Maharashtra (760MW), Punjab (475MW),

Haryana (380MW), Rajasthan (380MW) Funding Project cost: Rs. 170 bn Debt/Equity: 75:25 Financial closure completed in Apr’08 - lenders include IFC, ADB Completion Targeted by 2012 Source: Company, Karvy Institutional Research

B. Maithon Power Project Status: The 1,050MW Maithon Project is at an advanced stage of commissioning in the current quarter. The project has been funded at debt equity ratio of 70:30. Fuel Tie-up: The coal requirement for the Maithon Project has been fully secured. Long-term coal linkage has been allotted from the nearby Bharat Coking Coal (BCCL) mines, while the initial supply will be done by Damodar Valley Corporation (DVC). Power Off-Take Agreement: Maithon Project – the 74:26 JV of TPC and DVC – has signed Power Purchase Agreements (PPAs) with DVC, North Delhi Power (NDPL), West Bengal State Electricity Board (WBSEB) and Punjab State Electricity Board (PSEB). Maithon Project has obtained open access from Power Grid Corporation of India (PGCIL) to transmit power through their infrastructure to the power deficit northern states. All the PPAs have been signed and power evacuation arrangement is in place.

July 1, 2011

Tata Power

Exhibit14: Maithon Project Details Project Capacity 1,050MW (2X525MW) Ownership Structure Owned by Maithon Power Business Model Regulated Customers DVC (300MW), NDPL (300MW), WBSEB

(150MW), PSEB (300MW) Funding Project Cost: Rs. 44.5 bn

Debt/Equity: 70:30 Debt Syndication Completed

Completion Phase-I: Q1FY12, Phase-II Q1FY12 Source: Company, Karvy Institutional Research

Exhibit15: Financials & Valuation of Maithon Project (Rs mn) FY12E FY13E FY14E FY15E Capacity 438 1,050 1,050 1,050 Sales Volume (Mn units) 2,107 6,614 7,782 7,782 Realisation Per Unit (Rs) 3.70 2.17 2.00 1.99 Net Sales 7,554 13,768 14,980 14,881 Operating Expenses 2,364 7,096 8,163 8,163 EBITDA 5,190 6,672 6,816 6,718 Depreciation 934 1,602 1,602 1,602 Interest 651 1,819 1,751 1,653 PBT 3,604 3,250 3,462 3,462 Tax 718 647 690 690 PAT 2,886 2,603 2,772 2,772 FCFE (1,708) (353) 1,220 1,562 PV (1708) (310) 1070 1371 NPV (Explicit Period) 10,762 Per Share 47

IV. Established Fuel Security I. Derivative Play on Coal: TPC owns 30% stake in Bumi’s two mines In Mar’07, TPC acquired 30% stake each in the two unlisted coal blocks of KPC & Arutmin mines, along with a related trading company from Bumi Resources (Bumi) for US$1.1 bn. TPC also kept aside US$200 mn to meet the working capital requirements of the mines. Bumi estimates the coal resources of the mentioned mines at ~9.5 bn tonne (BT) of which 2.1 BT would be marketable. The mines are strategically located to serve the important coal markets of Asia, Europe and South America. The mines use the open cut mining method and have captive coal processing facilities including dedicated off-loading coal terminals and port facilities.

July 1, 2011

Tata Power

Exhibit 16: Indonesian mines – Holding Structure

Tata PowerCompany Ltd.

BhivpuriInvestment (Cyprus)

Bhirainvestments (Mauritius)

Arutmin(Indonesia)

KPC(Indonesia)

Bumi Resources(Indonesia)

Indocoal(Cayman Islands)

II. KPC, Arutmin Enjoy Substantial Share in Indonesian Coal Output

KPC & Arutmin – the two subsidiaries of Bumi – combined accounted for a high 28% market share of Indonesia's coal production in 2007. Together the companies are the second largest exporters of thermal coal globally. They sold 54.2 MMT and 53.2 MMT of coal in CY07 and CY08, respectively. TPC is entitled to annual dividend on account of its stake in the mines.

Exhibit 17: KPC & Arutmin (MT) Coal Resource Coal Reserve Total KPC Sangatta 3,447 160 3,607 Melawan - 337 337 North Pinang - 920 920 Bengalon 977 146 146 Total 4,424 1,562 5,987

Arutmin Senakin 411 43 454 Satui 269 84 353 Batulicin 216 25 241 Sub Bituminous 2047 407 2454 Total 2,943 557 3,502

Grand total 7,367 2,119 9,489 Source: Company, Karvy Institutional Research

Exhibit 18: Indonesian Coal Mines: Operating Performance Operating Performance CY09 CY08 Quantity Mined (MT) 63 53 Sales (MT) 58.1 51.5 Average Selling Price (US$ per tonne) 62 73 Production Cash Cost (US$ per tonne) 30 33 EBITDA from Operations (US$) 815 1,131 Source: Company

July 1, 2011

Tata Power

III. TPC to Enjoy Net Long Position of 23 MTPA in Indonesian Coal

TPC would have a net long position of 23 MTPA in Indonesian coal, when total production in the mines reach the targeted 100 MTPA level and the Mundra UMPP becomes fully operational. TPC's share in the total production would be 30 MTPA. The Mundra UMPP would require 12.3 MTPA of coal, of which 45% (5.6 MTPA) can be passed on in the tariff, while the remaining 55% (6.7 MTPA) runs the risk of price volatility. Thus, the Company's net long position on coal would be 23.3 MTPA.

Exhibit 19: TPC - 23 MTPA net long on Indonesian mines Particulars (MTPA) Comments Production of Indonesian mines 100 FY14E production TPC's share (long position) 30 30% of Bumi's production Consumption in Mundra 12.3 Protected by tariff escalation 5.6 Unprotected 6.7 Net Long position 23 Source: Company, Karvy Institutional Research

IV. Dividend from Bumi to Aid Repayment of Debt

TPC acquired stake in the mines through two off-shore Special Purpose Vehicles (SPVs) set up in Mauritius and Cyprus. The acquisition was funded through a mix of debt and equity, with non-recourse debt of US$590 mn to be repaid by May’14 through bullet payments. With the coal price showing upward trend, the Company would enjoy healthy cash flows by way of divided, which would allow it to repay the debt incurred for acquiring the mine.

Exhibit 20: Debt Repayment Schedule Type Loan amount

(US$ in mn) Outstanding (US$ in mn)

Interest rate Maturity Repayment details

Non-Recourse 590 400 1M Libor + 3.25% 14-May Bullet payment of US$175 mn

Recourse 270 270 6M Libor + 0.9% May’14, May’15 Two equal installments at the end of sixth and seventh year

Short-term Recourse 70 70 6M Libor + 3% 10-Jul Bullet payment in Jul’10 Source: Company, Karvy Institutional Research

July 1, 2011

Tata Power

Exhibit 21: Tata Power stake in Bumi Resources - Valued @ Rs.370

KPC ARUTMIN

Estimated Production (MTPA) 69.3 Implied value per tonne (US$) 192.52 Estimated Reserves(mn tonne) 1,600 557 2,157 Assigned value per tonne (US$) 5 5 5 EV for reserves (1) 8,000 2,785 10,785 Estimated Resources 4,400 2,943 7,343 Assigned value per tonne (US$) 0.2 0.2 0.2 EV for resources (2) 880 588.6 1,468.6 Total EV (1+2) 8,880 3,372 12,253 TPC'S stake % 0.3 0.3 0.3 Value for TPC 2,664 1,012 3,676 Holding discount % 0.3 0.3 0.3 Net value for TPC 1,998 759 2,757 Debt at hold co level 764 Net value for TPC

Rs. / US$

44 Equity Value (Rs mn)

87,694

Rs Per share of TPC

370 Source: Karvy Institutional Research

July 1, 2011

Tata Power

Exhibit 22 Secure Fuel Linkage Project Fuel requirement Source of fuel Contract details Term Trombay 3 MTPA of coal Purchase Agreements PT Adaro1 MTPA 5 yrs PT Adaro1 MTPA 10 yrs Samtan 0.65 MTPA Till FY14 Oil 1 MMSCMD of Gas From nearby refineries, delivered

by Gail pipeline

Jojobera Coal West Bokaro coal fields (TATA Steel)

Mahanadi Coalfields (MCL) IEL Furnace and Coke Tata Steel Coal West Bokaro Coal fields (Tata

Steel)

Belgaum Furnace Oil Mundra 12 MTPA of Coal Purchase Agreement Indocoal 10.11 MTPA Till 2021 Maithon 4.5 MTPA of Coal Coal Linkage 1.66 MTPA from Bharat Coking coal 1.98 MTPA from Central Coal Fields 0.05-1 MTPA from Tata Steel Lodhivali DG sets - - - Haldia Hot flue gases Tata Steel - - Source: Company, Karvy Institutional Research

Exhibit 23: Peer Comparison of Coal Reserves

Country

Coal India

Bumi Indonesia

Adaro Indonesia

Shenhua China

SAR Singapore

Resource MT 64,218 7,343 3,444 17,760 1,432 Reserve MT 52,546 2,157 889 11,303 123 Production MT 463 65.3 41 210 9 Mine life yr 113 33 22 54 14 Calorific Value kcal/kg 5,000 5,645 5,200 5,544 6,100 Sales Volume MT 463 65.3 41 213 9 ASP (US$ per tonne ) 24 65 59 59 73 Cash Cost (Excl Royalty) (US$ per tonne ) 18 32.7 30 22 41 Cash profit per tonne (US$ per tonne ) 6 30.4 29 37 32 Net profit per tone (US$ per tonne ) 5 4.9 10 21 15 Market Cap (USD mn) 55,741 7,285 8,890 91,419 2665 EV (USD mn) 45,923 11,341 9870 94406 2847 P/E x 23 21 32 16 22 EV/EBITDA x 13 9 11 7 7 EV/Resources (US $) 0.72 1.54 2.87 5.32 2.0 EV/Reserves (US $) 0.87 5.26 11.1 8.35 23 EV/Production (US $) 99 173 240 449 316 Source: Bloomberg, Karvy Institutional Research

Overall, we believe that TPC's acquisition of stake in the Indonesian coal mines is a good backward integration move, as it will act as a perfect hedge for its power generation business.

July 1, 2011

Tata Power

V. Well-placed in terms of fuel security for upcming projects

TPC has secured its coal requirements for the upcoming projects through multiple routes such as domestic coal linkages, captive coal blocks and equity stakes in Indonesian mines. The Mundra UMPP has assured fuel supply, while for the Maithon project TPC has obtained domestic coal linkage for its entire requirement. TPC is also part of the two JVs, which have been allotted the Tubed and Mandakini coal blocks. Combined these mines have total capacity of 13.25 MT, while TPC accounts for 4.8 MT. TPC's stake in the coal blocks apart from assuring availability of coal also acts as a hedge against any rise in costs.

VI. Adequately-funded Growth Plans

TPC which has ~3,000MW of operational capacity has another ~5,000 of under construction capacity. It also has ~6,125MW of pipeline projects. TPC’s pipeline projects would involve a total capex of Rs. 250 bn, with equity contribution being ~ Rs. 50 bn. We believe that the Company would generate adequate internal accruals to fund its pipeline projects.

VII. Bluechip Investments could be Monetised

TPC owns substantial investments to the tune of ~Rs. 80 bn, which it can monetize to fund its growth plans. For instance, the Company holds 11% stake in Tata Teleservices (TTSL), which we have valued at Rs. 7.94 bn, after providing 50% discount to the TTSL-DoCoMo deal valuation. TPC also holds stake in other Tata group companies such as TTSL & Tata Communication.

Exhibit 26: Investment Details

Holding (%) No. of Shares Basis of Valuation Value (Rs. in mn)

Tata Tele Services 7.4 137,263,174 80% discount on 1779(Maharashtra) CMP of Rs. 16Tata Communication 0.9 2,575,837 At CMP of Rs.184 820Nelco 50 11,099,630 At CMP of Rs.67 595Tata Teleservices 11 711,360,000 50% promoter discount 3,6660

to TTSL-DoCoMo deal valuation

Holding in Tata Communications 4263through Panatone Finvest Holding in TCS 3600Other unquoted investments 21,534Total Value 68,431Per Share Value Rs. 289Source: Company, C-line, Karvy Institutional Research

Exhibit 24: Mandakini, Tubed Coal Blocks Block Reserves TPC's share Other JV partners Status COD (MTPA) (MTPA) Mandakini 7.5 2.5 Jindal Photo Film, Mining plan approved by the MoC acquisition Monnet Ispat & for the coal block is expected by Mar’12 and Energy 6i notifications have already been issued. Mid-2014 Tubed 5.75 2.3 Hindalco Mining plan has been approved and submitted to the Government of Jharkhand; Land acquisition activities are at early stages FY13 Source: Company, Karvy Institutional Research

10,000

15,000

20,000

25,000

30,000

35,000

Net cash from Operation Net Debt/Equity

Rs mn (%)

July 1, 2011

Tata Power

VIII. Other well-established Distribution Business Powerlinks Transmission – Inter-state Distribution of power TPC holds 51% stake in Powerlinks Transmission, a JV with PGCIL that holds the balance 49% stake, to carry out inter -state transmission of power between Bhutan & India. Powerlinks operates under the regulated business model, and as per the CERC regulations, it is eligible for RoE of 15.5% on pre-tax basis. Powerlinks’ net revenue and net profit stood at Rs. 3 bn and Rs. 1.08 bn, respectively in FY10.

Exhibit 27: Powerlinks Transmission Rs mn FY10 FY11 FY12E FY13E Net sales 3000 3230 3470 3730 PAT 1080 1180 1280 1380 PAT Margin (%) 36 37 37 37 PAT 550 600 650 700 Source: Karvy Institutional Research

NDPL – Power distribution in North & North -West Delhi North Delhi Power (NDPL) – a JV between TPC & Delhi Government – distributes electricity in North & North-West Delhi. TPC holds 51% in the JV, while the balance 49% is held by the Delhi Government. NDPL – which was set up in Jul’02 – successfully brought down AT&C losses from 53.4% to 15.2% in FY10, as against the regulated target of 20.4%.

Exhibit 28: NDPL Financials (Rs mn) Sales Revenue FY08 FY09 FY10 FY11 E FY12 E FY13 E FY14 E FY15 E Sales 23,426 25,775 33,927 36,025 37,667 39,682 42,418 45,350 Power purchase cost 17,561 19,053 24,355 25,789 27,068 28,226 30,241 32,777 O&M expenses 2,196 2,528 4,905 5,800 6,090 6,151 6,458 6,781 EBITDA 3,669 4,195 4,667 4,437 4,508 5,305 5,718 5,792 Depreciation 854 1,034 1,159 1,240 1,240 1,090 1,240 1,240 EBIT 2,816 3,161 3,509 3,196 3,268 4,215 4,478 4,552 EBT 2,816 3,161 3,509 3,196 3,268 4,215 4,478 4,552 Minority Interest 1,380 1,549 1,719 1,566 1,601 2,065 2,194 2,230 EAT 1,436 1,612 1,790 1,630 1,667 2,149 2,284 2,321

Source: Karvy Research

July 1, 2011

Tata Power

Exhibit 29: Financial Assumption Estimates Growth (%) Comments FY10 FY11 FY12E FY13E FY11 FY12E FY13E

Operational Parameters Capacity (MW) 2971 3127 5990 8516 5 92 42 Maithon, Mundra to commissioning Sales Volume (MU) PPA 20,565 19,750 34077 49776 22 128 46 Growth will be driven by capacity

addition Merchant - - 2242 - - - - Maithon to have pre-PPA merchant sale Competitive - - - - - - - JV's (MW) - - - - - - - Gross generation (MU) Commercial generation (MU)

20,565 19,750 34077 49776 22 128 46 Driven by capacity addition

Energy sold (MU) 20,565 19,750 34077 49776 22 128 46 Driven by capacity addition Aux. consumption (%) 7 7 7 7 0 0 0 To remain unchanged Avg PLF (%) 88 79 67 59 To remain lower as plant to get stabilized Avg PAF (%) 95 95 95 95 Tariffs Avg realization (Rs/unit) PPA 4.9 5.0 5.2 5.5 - 5 4 Generation, distribution combines Merchant - - 3.70 - Maithon tariff Competitive - - 2.3 2.4 - - - Mundra projects under competitive Fuel cost Avg Fuel Cost (Rs/unit) 1.4 1.4 1.5 1.6 4 7 4 Higher coal prices Imported Coal (MT) 2.2 2.3 10.0 19.4 4 328 95 Higher mainly for Mundra projects

Domestic Coal (MT) 8.9 9.4 12.5 12.5 5 33 0 Financial Forecasts Sales (Rs mn) Power division 138,476 129,620 182,777 238,551 -6 41 31 Growth driven by Maithon, Mundra

projects Coal division 50,827 63,862 72,459 83,342 26 13 15 Growth on higher realization & volumes Total Sales 189,303 193,482 255,235 321,893 2 32 26 Operating Expenses (Rs mn) 151,497 140,874 191,991 241,687 -7 36 26 EBIDTA (Rs mn) 37,806 44,349 63,244 80,205 17 43 27 Growth driven by Maithon, Mundra

projects EBIDTA margin (%) 20.0 22.9 24.8 24.9 15 8 1 To remain the same level Net Interest Expense (Rs mn)

7,818 8,102 14,728 17,416 4 82 18 Debt repayment

Avg. Interest rate (%) 10 10 10 10 0 0 0 PAT (Rs. mn) 21,386 22,561 28,399 32,118 5 26 13 FY13 margins lower on account of

Mundra projects PAT margin (%) 10.3 10.6 10.2 9.1 3 -5 -10 To remain at the same level

EPS (Rs.) 82.9 86.8 109.3 123.6 5 26 13

Cash Flow forecast (Rs mn) CFO (a) 25,754 26,361 31,785 33,393 2 21 5 Commissioning of capacity CFI (b) 70,285 68,000 58,250 63,323 -3 -14 9 FCF(a-b) (44,532) (41,639) (26,465) (29,930) -6 -36 13 CFF - © 55,859 50,000 30,000 30,000 -10 -40 0 Source: Karvy Institutional Research

July 1, 2011

Tata Power

Karvy vs. Consensus We are broadly in line with consensus at the topline level. Our estimates for PAT for FY13E are higher than consensus on higher PLF.

Exhibit 30: Karvy vs. Consensus Karvy Consensus Difference in % Revenue (Rs. in mn)

FY12E 255,231 236447 7.9 FY13E 321,893 286274 12.4

EBIDTA (Rs. in mn) FY12E 63,244 58056 8.9 FY13E 80,205 69479 15.4

PAT (Rs. in mn) FY12E 28,399 23387 18.9 FY13E 32,118 24986 28.5

Key Risks The key risks to our recommendation are:

• Delay in the capacity addition – to affect the Company's revenues

• Any further changes in the Indonesian mining laws would restrict coal exports

July 1, 2011

Tata Power

Financial Overview A. Topline to Register Growth on the back of Capacity Addition TPC is poised to post healthy growth in top-line over FY10-13E primarily on the back of volume growth in the power generation business arising out of the capacity addition at the Mundra & Maithon plants. Accordingly, we expect topline to increase at a CAGR of 19% to Rs. 3,21,893 mn over the afore-mentioned period.

Exhibit31: Segment wise break-up

Exhibit 32: Topline Growth at CAGR of 19%

B. Operating Margin to Improve over FY10-13E We expect TPC to post 24.8% CAGR in operating profit over FY10-13 on the back of higher topline. Its OPM is expected to improve by a marginal 500 bps to 25% over the mentioned period. The Company would not be impacted much by higher imported coal costs, as it would be able to pass-on the hike in Mumbai Licence Area plants as well as the Mundra (50%) & Maithon Projects.

Exhibit 33: Operating Performance

100000

150000

200000

250000

300000

FY10 FY11 FY12E FY13EPower Segment Coal Segment

(Rs mn)

100,000

200,000

300,000

400,000

FY10 FY11 FY12E FY13ENet revenues % Growth

(Rs mn) (%)

20,000

40,000

60,000

80,000

EBIDTA EBIDTA margin (%)

(Rs mn) (%)

July 1, 2011

Tata Power

C. Bottom line performance to be muted but to Peak seen at FY14 However, performance on the bottom line front is expected to be muted going ahead due to higher interest costs and lower other income. Thus, we expect TPC to post a moderate 14.4% CAGR in bottom line over FY10-13E. We expect Company to show strong growth in earning in FY14E, as the plants are expected to get stabilized.

Exhibit 34: Bottom-line Performance

RoE and RoCE to improve on project commissioning As large part of capital would be tied up in work in progress, Tata Power RoCE & RoE were suppressed. However with commissioning of Maithon & Mundra projects we expect significant improvements in RoCE & RoE going forward.

Exhibit35: Return Ratios to Improve

10,000

20,000

30,000

40,000

Reported Net Profit % Growth

(%)(Rs mn)

ROCE (%) ROE (%)

July 1, 2011

Tata Power

(Rs mn) FY09 FY10 FY11 FY12E FY13E

Net revenues 180,570 189,303 193,482 255,235 321,893 % Growth 66% 5% 2% 32% 26% Raw Material 98,274 92,342 96,784 136,368 174,999 Staff 6,437 9,095 10,095 11,811 14,291 Operating Expenses 45,032 50,061 44,090 55,623 66,688 Operating expenses 149,743 151,497 140,874 191,991 241,687 EBIDTA 30,828 37,806 44,349 63,244 80,205 % Growth 54% 23% 17% 43% 27% EBIDTA margin (%) 17.1 20.0 22.9 24.8 24.9 Other income 8,490 6,446 5,872 4,867 3,642 Interest 8,129 7,818 8,102 14,728 17,416 Depreciation 6,565 8,777 9,802 12,812 18,850 Profit Before Tax 22,809 27,509 32,317 40,571 47,582 Provision for tax 11637 6271 9756 12171 15464 Effective tax rate (%) 47.3 22.7 30.2 30.0 32.5 Reported Net Profit 12,987 21,386 22,561 28,399 32,118 % Growth 10% 65% 5% 26% 13% Net Margin (%) 5.7 10.3 10.6 10.2 9.1 Share in Associate profit (Net) 275.7 616.6 0.0 0.0 0.0 Adjusted Net Profit 10,372 19,520 20,596 25,926 29,320 % Growth 28% 88% 6% 26% 13% EPS (Rs) 55 83 87 109 124 % Growth 15% 51% 5% 26% 13% DPS (Rs) 13.5 15.6 14.1 14.1 14.1 Source: Company & Karvy Institutional Research

Y/E March (Rs mn) FY09 FY10 FY11E FY12E FY13E

Equity capital 2,214 2,373 2,373 2,373 2,373 Reserves & surplus 91,415 120,706 137,961 160,546 186,526 Shareholders funds 93,629 123,079 140,334 162,919 188,899 Minority 9,444 12,097 14,062 16,536 19,105 Long Term Loans 141,434 184,469 234,469 264,469 294,469 Deferred tax liability 5,154 4,308 4,308 4,308 4,308 Total Liabilities 249,661 323,953 393,173 448,232 507,009 Gross block 210,399 225,024 247,274 337,524 371,524 Depreciation 68,079 74,549 84,352 97,164 116,014 Net block 142,320 150,475 162,923 240,360 255,511 Capital WIP 63,461 116,927 162,677 130,677 160,000 Investments 32,512 30,823 30,823 30,823 30,823 Cash & Bank Bal. 11,780 23,108 31,468 35,003 35,072 Loans & Advances 27,988 28,305 28,930 33,181 41,846 Other Assets 40,382 49,384 51,273 61,256 83,692 Current Assets 80,150 100,796 111,671 129,441 160,611 Current Liabilities 68,789 75,068 74,920 83,069 99,936 Net current assets 11,361 25,728 36,751 46,372 60,675 Total Assets 249,661 323,953 393,173 448,232 507,009 Source: Company & Karvy Institutional Research

July 1, 2011

Tata Power

Exhibit 38: Cash Flow statement

(Rs mn) FY2009 FY2010 FY2011E FY2012E FY2013E

EBIT 24,263 29,029 34,546 50,432 61,356 (Inc)/Dec in working capital 12,919 4,642 (2,662) (6,085) (14,233) Cash flow from operations 37,182 33,671 31,885 44,346 47,122 Other income 8,490 949 5,872 4,867 3,642 Extra-ordinary income 1,815 148 0 0 0 Depreciation 6,565 8,777 9,802 12,812 18,850 Interest paid 8,129 7,818 8,102 14,728 17,416 Dividends paid 2,987 3,703 3,341 3,341 3,341 Tax paid 11,637 6,271 9,756 12,171 18,081 Net cash from operations 31,300 25,754 26,361 31,785 33,393 Capital expenditure (74,703) (70,285) (68,000) (58,250) (63,323) Free Cash Flows (43,403) (44,532) (41,639) (26,465) (29,930) Inc/(Dec) in LT borrowing 50,298 37,614 50,000 30,000 30,000 (Inc)/Dec in investments (1,260) 2,047 0 0 0 Inc/(Dec) in Equity capital 521 16,198 0 0 0 Cash from Financial Activities 49,560 55,859 50,000 30,000 30,000 Opening Cash 5,623 11,780 23,107 31,468 18,954 Closing Cash 11,780 23,108 31,468 35,003 35,072 Change in Cash 6,157 11,327 8,361 3,535 70 Source: Company & Karvy Institutional Research

FY2009 FY2010 FY2011 FY2012E FY2013E

Raw Material Cost / Sales 54 49 50 53 54 Manpower Cost / Sales 4 5 5 5 4 Operating & Other cost / Sales 25 26 23 22 21 Revenue Growth 66 5 2 32 26 EBIDTA Margins 17.1 20.0 22.9 24.8 24.9 PAT Margins 5.7 10.3 10.6 10.2 9.1 ROCE 11.2 10.1 9.6 12.0 12.8 ROE 11.8 18.0 15.6 17.1 16.7 Core RoCE 15.1 16.2 18.0 20.9 20.6 Core RoE 24.0 24.6 17.4 19.4 19.8 Source: Company & Karvy Institutional Research

FY2009 FY2010 FY2011E FY2012E FY2013E

EPS (Rs) 55 83 87 109 124 PER (x) 23.8 15.8 15.1 12.0 10.6 Book (Rs) 423 519 589 682 749 P/B (x) 3.1 2.5 2.2 1.9 1.6 EV/EBIDTA (x) 13.6 12.5 11.6 8.5 7.1 Fixed assets turnover ratio (x) 0.9 0.7 0.6 0.7 0.7 Debt/Equity (x) 1.4 1.3 1.4 1.4 1.4 EV/Sales (x) 2.3 2.5 2.7 2.1 1.8 Source: Company & Karvy Institutional Research

Institutional Equities Team Rangachari Murlikrishnan, Head – Institutional Equities (022) 22895007 muralikrishnan@karvy.com

Shridhar Iyer, Head - Institutional Sales (022) 22895160 Shridhar.iyer@karvy.com

K. Anant Rao, Head - Sales-Trading & Derivatives (022) 22895196 k.anantrao@karvy.com

Uday Raval, Karvy Inc. USA (212) 2674334 udayr@karvy.com

INSTITUTIONAL RESEARCH Analysts Industry / Sector Desk Phone Email ID Bhuvan Yadav MidCap 040-23312454 bhuvan.yadav@karvy.com Jagadishwar Pasunoori MidCap 040-23312454 jagadishwar.p@karvy.com Naushil Shah IT 022-22895034 naushil.shah@karvy.com Nishith Sanghvi Pharma 022-22895026 nishith.s@karvy.com Paresh Jain Banking 022-22895025 paresh.jain@karvy.com Parikshit Kandpal Infra / Real Estate 022-22895018 parikshit.kandpal@karvy.com Prasun Kumar Cement 022-22895028 prasun.kumar@karvy.com Raghuram Kuchi MidCap 040-23312454 raghuram.kuchi@karvy.com Rahul Sharma Pharma 022-22895021 rahul.sharma@karvy.com Rahul Singh MidCap 040-23312454 rahulsingh@karvy.com Rajesh Kumar Ravi Cement 022-22895030 rajesh.ravi@karvy.com Rupesh Sankhe Power 022-22895022 rupesh.sankhe@karvy.com Sameer Pardikar Telecom 022-22895024 sameer.pardikar@karvy.com Vinay Nair Oil & Gas 022-22895029 vinaynair@karvy.com Yogesh Nagaonkar Auto & Auto Anc. 022-22895020 yogesh.nagaonkar@karvy.com

INSTITUTIONAL SALES Dinesh Bajaj Sales 022-22895012 Dinesh.bajaj@karvy.com Dipesh Jain Sales 022-22895015 dipesh.jain@karvy.com Jigna Haria Sales 022-22895014 jigna.haria@karvy.com Priyanka Ahuja Sales 022-22895016 priyanka.ahuja@karvy.com R. Sriram Sales 022-22895013 sriram.rangarajan@karvy.com

INSTITUTIONAL SALES TRADING Dipesh Upadhyay Sales Trader 022-22895060 dipesh.upadhyay@karvy.com Parag Shah Sales Trader 022-22895066 parag.shah@karvy.com Sriram Jagdish Sales Trader 022-22895068 sriram.jagdish@karvy.com

PRODUCTION

Asim Kumar Mohapatra Editor 022-22895019 asim.mohapatra@karvy.com Tanvir Gabhrani Production 022-22895027 tanvir.gabhrani@karvy.com Vishal Randive Database 022-22895017 vishal.randive@karvy.com

For further enquiries please contact:

research@karvy.com Tel: +91-22-22895000

Disclosures Appendix

Analyst certification

The following analyst(s), who is (are) primarily responsible for this report, certify (ies) that the views expressed herein accurately reflect his (their) personal view(s) about the subject security (ies) and issuer(s) and that no part of his (their) compensation was, is or will be directly or indirectly related to the specific recommendation(s) or views contained in this research report.

Disclaimer

The information and views presented in this report are prepared by Karvy Stock Broking Limited. The information contained herein is based on our analysis and upon sources that we consider reliable. We, however, do not vouch for the accuracy or the completeness thereof. This material is for personal information and we are not responsible for any loss incurred based upon it. The investments discussed or recommended in this report may not be suitable for all investors. Investors must make their own investment decisions based on their specific investment objectives and financial position and using such independent advice, as they believe necessary. While acting upon any information or analysis mentioned in this report, investors may please note that neither Karvy nor Karvy Stock Broking nor any person connected with any associate companies of Karvy accepts any liability arising from the use of this information and views mentioned in this document.

The author, directors and other employees of Karvy and its affiliates may hold long or short positions in the above mentioned companies from time to time. Every employee of Karvy and its associate companies are required to disclose their individual stock holdings and details of trades, if any, that they undertake . The team rendering corporate analysis and investment recommendations are restricted in purchasing/selling of shares or other securities till such a time this recommendation has either been displayed or has been forwarded to clients of Karvy. All employees are further restricted to place orders only through Karvy Stock Broking Ltd. This report is intended for a restricted audience and we are not soliciting any action based on it. Neither the information nor any opinion expressed herein constitutes an offer or an invitation to make an offer, to buy or sell any securities, or any options, futures nor other derivatives related to such securities.

Karvy Stock Broking Limited

Institutional Equities 2nd Floor, Regent Chambers, Nariman Point - Mumbai 400 021.

Regd Off : 46, Road No 4, Street No 1, Banjara Hills, Hyderabad – 500 034.

Karvy Stock Broking Research is also available on: Bloomberg - KRVY <GO>, Thomson Publisher & Reuters.

Stock Ratings Absolute Returns Buy : > 15% Hold : 5-15% Sell : < 5%

CESC_20110701

Documents

Transcript of CESC_20110701

One Flew Over the Cuckoo's Nest

xCDC14a

Star Wars Prequel Trilogy Trivia (Episodes I-III)

How Computer Keyboards Work

Improve the Color Quality Of Your Monitor

Life Is Just A Dream - Or Is It?

Explore The Levels of Creation

How Computer Monitors Work

Chapter-01

Fortran

Bodybuilding - The Rock Hard Challenge (Month 1 Training)

Compressing And Decompressing Folders

Cakes Recipes

Chapter 24

The Best American Humorous Short Stories

Venture Capital

Steve Jobs' Commencement Speech at Stanford

Basic Buffer Overflows Explained

European Colinization of Latin America

Introduction to Six Sigma