Focused Energy Report –

XXXI

Monthly Report – December 2014

Energy Desk

GAIL (India) Ltd.

1

Table of Contents

Energy Prices 3 I.

Under-Recoveries on Petroleum Products 3 II.

Country Analysis - Azerbaijan 4 III.

A. Energy Mix .............................................................................................................................................................................................. 4

B. Oil and Gas Resources ....................................................................................................................................................................... 4

1. Natural Gas Exploration and production .............................................................................................................................. 5

C. Export Market........................................................................................................................................................................................ 6

D. SWOT Analysis ...................................................................................................................................................................................... 7

E. Key trends of oil and gas sector .................................................................................................................................................... 7

Company Analysis- CAIRN India 8 IV.

A. Portfolio of Cairn India ...................................................................................................................................................................... 8

B. SWOT Analysis ...................................................................................................................................................................................... 8

C. Strategy ................................................................................................................................................................................................... 9

D. Potentials in its E&P fields ............................................................................................................................................................... 9

E. Future Investments ............................................................................................................................................................................. 9

F. Financials .............................................................................................................................................................................................. 10

Russia’s new Energy Ally China 11 V.

A. The Deal ............................................................................................................................................................................................... 11

B. Russia Move towards East ............................................................................................................................................................. 11

C. Financing Challenge Sees Pivot from Japan to China ........................................................................................................ 11

D. Impact of Deal ................................................................................................................................................................................... 12

Accelerated Depreciation benefit for wind energy and its impact on the Renewable Energy VI.

Industry 13

A. Comparison between Wind and Solar ..................................................................................................................................... 14

B. RPO targets for the states & REC trading for the Nov-14 ............................................................................................... 14

1. State-wise Solar RPO targets .................................................................................................................................................. 15

2. REC trading for the Nov-14 ..................................................................................................................................................... 16

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Executive Summary

The Focused Energy Report for the month of November 2014 reviews the Energy Prices taking

in consideration the comparison with last month. There’s decrease of around 21.75% in the WTI

oil prices, the prices of natural gas Henry Hub have increased by 5.38% and around 22.39%

decrease is there for crude oil prices of Brent.

Crude is in downward trend which is good for India as a net importer of crude. The fall in prices

is due to slowdown (less consumption) in China, over supply of Shale oil, OPEC’s refusal for

output cut.

The next discussion in the report is about “Azerbaijan”. Azerbaijan, one of the oldest oil

producing countries in the world, is an important oil and natural gas supplier in the Caspian

Sea region, particularly for European markets. Azerbaijan has a substantial gas resource base. In

2013, Azerbaijan exported about 240 Bcf, mainly shipping it via the South Caucasus Pipeline. In

this section we discus about its current Energy mix, Natural Gas resources, SWOT analysis,

export market and key trends of its oil and gas market.

In the next section “CAIRN India” is covered which one of the largest non-state exploration

and production companies is operating in the country. Its roots are in UK-based Cairn Energy,

formed in 1979 and becoming an investor in the Indian upstream oil sector in the late 1990s.

Cairn has now been operating in India for more than 15 years and has played an active role in

developing the oil and gas resources in the country. Ravva in eastern India was the first

offshore oil and gas field to be developed, followed by the Lakshmi gas field in western India

It’s being analysed wrt portfolio, SWOT analysis, potentials, financials, strategy and future

investments

In this section there is a discussion about “Russia’s New Energy Ally China.” Russia's new gas

deal with China has likely been accelerated by geopolitical pressures from the West owing to a

continued impasse in Ukraine. It also notes a shift in Gazprom's gas strategy in Asia-Pacific, as

practical funding needs arising from sanctions push the Russian gas firm away from its initial

target of the Japanese LNG market and towards the Chinese gas pipeline market. It is seen as

Lending Squeeze Pushes Gazprom to Asia. The details of the deal, Russia Move towards East,

Financing Challenge Sees Pivot from Japan to China with impact of the deal are covered.

In the last section there is a discussion about benefit from Accelerated Depreciation for wind

energy and its impact on the Renewable Energy Industry. New wind capacity additional peaked

in 2011-12 at about 3,200 MW which fell sharply to 1,700 MW the next year as AD benefits were

removed which the govt. removed citing its maturation. But after reintroduction of AD (80%) in

2014, investment momentum has shift again to wind due to policies and attractive tariffs. The

discussions contains Comparison between Wind and Solar industries and RPO targets for the

states & REC trading for the Nov-1.

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ENERGY PRICES I.

WTI Crude Oil ($/barrel) BRENT Crude Oil ($/barrel) Natural Gas ($/mmbtu)

Particulars Sep.2014 (Final) Oct. 2014 (Estimated)

JCC Crude Oil ($/b) 106.22 100.7

Average International FOB Price & Exchange rate:

UNDER-RECOVERIES ON PETROLEUM PRODUCTS II.

(A) Product-wise Under-recovery of Public Sector Oil Marketing Companies(OMCs):

*additionally, a subsidy of Rs 0.82/Litre on PDS kerosene & Rs 22.58/Cylinder on Domestic LPG is provided by the

Government.

(B) The OMCs have reported the following under recovery during 2013-14 & of 2014-15:

Price on 3rd

Nov. 2014 Price on 1st Dec. 2014 Change % Change

Brent crude oil 85.86 70.15 -15.71 -22.39%

WTI crude oil 80.54 66.15 -14.39 -21.75%

Henry Hub Natural Gas 3.87 4.09 0.22 5.38%

Particulars Unit 28th

November 2014 Fortnight

(13- 28 -Nov-14)

Crude Oil(Indian Basket)

- In US Dollar

- In Indian Rupees

($/bbl)

(Rs/bbl)

70.29

4355.87

71.40

4421.09

Exchange Rate (Rs/$) 61.97 61.92

Product Unit Under-recovery (eff. 1st Dec. 14)

Diesel (Rs/Litre)

PDS Kerosene* (Rs/litre) 25.69

Domestic LPG* (Rs/Cylinder) 279.91

Product 2013-14

(Rs/Crore)

2014-15 (H1)

(Rs/Crore)

Diesel 62,837 11,656

PDS Kerosene 30,575 14,857

Domestic LPG 46,458 24,597

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35.97%

61.35%

0.02% 2.66%

Energy Mix 2013 - Azerbaijan

Oil

Natural Gas

Coal

Hydro electric

COUNTRY ANALYSIS - AZERBAIJAN III.

Azerbaijan, one of the oldest oil producing countries in the

world, is an important oil and natural gas supplier in the

Caspian Sea region, particularly for European markets.

Although traditionally it has been a prolific oil producer,

Azerbaijan's importance as a natural gas supplier will grow

in the future as field development and export

infrastructure expand. The conflicting claims over the

maritime and seabed boundaries of the Caspian Sea

between Azerbaijan and Iran continue to cause

uncertainty, with Iran challenging Azerbaijan's

hydrocarbon exploration in offshore areas claimed by both

sides.

Oil and gas production and exports are central to

Azerbaijan's economy. The country's economy is heavily

dependent on its energy exports, with more than 90% of

total exports accounted for by oil and gas exports,

according to data from the International Monetary Fund.

A. Energy Mix

Natural gas accounted for about 61% of

Azerbaijan's total domestic energy

consumption in 2013. Oil accounted for

36% of total energy use, and hydropower

contributed a marginal amount. Overall,

Azerbaijan is a net energy exporter. The

country swaps small volumes of natural

gas with Iran—the Nakhchivan exclave

receives all of its natural gas from Iran,

because it is not connected to Azerbaijan's

pipeline network.

B. Oil and Gas Resources

Azerbaijan has a substantial gas resource base, although reserves estimates vary significantly. According to the

US Energy Information Administration (EIA), proved reserves stand at 980bn cubic metres (bcm); although the

Azeri Ministry of Industry and Energy estimates 2.2trn cubic metres (tcm). Oil reserves are slightly more limited, at

around 7bn barrels (bbl), according to the EIA; state sources put this figure at 11bn bbl. BP, which has a strong

presence in Azerbaijan, and other independent sources offer resource estimates broadly consistent with those of

the EIA.

There is significant upside potential for Azerbaijan's reserves base. The US Geological Survey (USGS) estimated

mean volumes of technically recoverable, conventional, undiscovered petroleum resources in the Caspian Sea

area at 19.6bn bbl of crude oil, 6.9tcm of natural gas and 9.3bn bbl of natural gas liquids (NGLs). The bulk of

these resources are thought to lie in the South Caspian basin, offshore Azerbaijan, Turkmenistan and Iran,

although a maritime boundary dispute between the three countries has limited exploration in the south of the

basin.

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Table: Proven Oil and Gas Reserves (Azerbaijan 2012-2017) ( e/f = BMI estimate/forecast. Source: EIA, BMI)

Items 2012 2013 2014f 2015f 2016f 2017f

Proven oil reserves, bn bbl 7 7 6.7 6.3 6 5.7

Proven oil reserves, mn bbl 7,000.00 7,000.00 6,677.30 6,345.60 6,005.00 5,660.70

Proven oil reserves, % y-o-y 0 0 -4.6 -5 -5.4 -5.7

Reserves to production ratio (RPR),

years

20.7 22 20.6 19 17.6 16.4

Natural gas proven reserves, tcm 0.8 1 1 1.1 1.1 1.2

Natural gas proven reserves, bcm 849.5 991.1 983.5 1,065.90 1,098.10 1,180.80

Natural gas proven reserves, % y-o-y 0 16.7 -0.8 8.4 3 7.5

Natural gas reserves-to-production

ratio, years

49 55.3 56.1 60.5 61.6 68.3

The vast majority of the reserves are associated with the Shah Deniz field. Discoveries of the Absheron and Umid

formations between 2010-11 added a further 15 Tcf of resources estimated in place.

1. Natural Gas Exploration and production

Almost all of Azerbaijan's natural gas is produced in two offshore fields—the ACG complex and Shah Deniz. The

Shah Deniz natural gas and condensate field started producing in late 2006, making Azerbaijan a net gas

exporter. The ACG field provides associated gas to the Azerigaz system for domestic use via an undersea gas

pipeline to Sangachal Terminal at Baku. The Sangachal Terminal, located south of Baku, is one of the world's

largest integrated oil and gas processing terminals. It receives, stores, and processes both crude oil and natural

gas from the ACG fields and from Shah Deniz, then ships these hydrocarbons through the South Caucasus

Pipeline (SCP) for export.

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The Shah Deniz field, discovered in 1999, is one of the world's largest gas and condensate fields. According to

BP, the operator of the development, it has approximately 40 Tcf of natural gas in place. It is located on the deep

water shelf of the Caspian Sea, in water depths of up to 1,600 feet. According to BP, the field produced about

346 million cubic feet per day of natural gas and about 53,740 bbl/d of condensate in 2013.

Shah Deniz Stage I development includes a fixed offshore platform, two subsea pipelines to bring the

hydrocarbons ashore, and a new onshore gas-processing terminal adjacent to the existing oil terminal at

Sangachal, near Baku. According to BP, since the start of Shah Deniz production in late 2006 until the end of

2013, Shah Deniz produced about 1.7 Tcf of natural gas and 100 million barrels of condensate.

Shah Deniz Stage 2, or Full Field Development (FFD), will have peak capacity of 565 Bcf (in addition to the 315 Bcf

in Phase I) according to BP, making it one of the largest gas development projects in the world. Operators expect

it to start producing in 2017 and supply European markets with natural gas in 2019. The development of Shah

Deniz FFD is currently in the front-end engineering and design (FEED) phase. Transportation of Shah Deniz gas

from the Caspian Sea to Europe will require enhancement of the existing pipelines and development of new

infrastructure.

C. Export Market

In 2013, Azerbaijan exported about 240 Bcf, mainly shipping it via the South Caucasus Pipeline. Volumes of

natural gas are also exported to Russia via the Gazi-Magomed-Mozdok pipeline. A small volume of natural gas is

shipped to Iran via the Baku-Astara pipeline. In exchange, Iran ships natural gas to Nakhchivan, Azerbaijan's

exclave situated between Iran and Turkey. The exclave is wholly dependent on natural gas supplied by Iran.

Most of Azerbaijan's natural gas is destined for Turkey, but the country supplies a small volume to Greece via the

Turkey-Greece interconnector. Under a previous arrangement, Turkey was re-exporting Azerbaijani natural gas to

Greece, but a new agreement allows Azerbaijan to directly export volumes to the European Union. The Shah

Deniz FFD will result in increased exports to the European Union once the needed infrastructure is completed.

South Caucasus Pipeline (SCP) The main conduit for Azerbaijan's natural gas exports is the SCP, also known as the Baku-Tbilisi-Erzurum (BTE)

pipeline, which runs parallel to the BTC oil pipeline for 429 miles, before landing in Erzurum, Turkey. The 42-inch

pipeline began exporting in 2007, and it has the capacity to transport about 300 Bcf of natural gas. The

government plans to add a new parallel pipeline to the existing line across Azerbaijan and Georgia, as well as two

new compressor stations in Georgia. Once upgraded, the pipeline's capacity will increase to more than 700 Bcf.

At the Georgia-Turkey border, the pipeline will link to TANAP and TAP.

Gazi-Magomed-Mozdok Pipeline This 150-mile pipeline transports natural gas from Azerbaijan to Russia under an agreement signed by SOCAR

and Gazprom in 2009. Prior to 2007, this pipeline transported natural gas from Russia to Azerbaijan, but the

agreement allowed the pipeline flow to be reversed, making Azerbaijan an exporter of natural gas to Russia. Gas

exports to Russia began in 2010 at approximately 35 Bcf per year.

Baku-Astara Pipeline As a result of tensions with Armenia, Azerbaijan began a swap deal with Iran that provides natural gas to

Azerbaijan's geographically separate Nakhchivan exclave in late 2006. Azerbaijan ships natural gas into Iran via

the Baku-Astara Pipeline, and Iran then delivers the gas via the Salmas-Nakhchivan pipeline. Iran receives a 15%

commission on transit fees.

TANAP and TAP

The Trans Anatolian Natural Gas Pipeline (TANAP) will transport the Shah Deniz natural gas through Turkey. This

56-inch pipeline will run from the Georgia-Turkey border to the Turkey-Greece border. The Trans Adriatic

Pipeline (TAP) will link to TANAP and transport Azerbaijan's natural gas exports through Greece and Albania to

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Italy. BP announced in June 2013 that the Shah Deniz consortium selected TAP to deliver approximately 35 Bcf of

natural gas to the European Union.

D. SWOT Analysis

Strengths

Strategic location bridging Asian and

European demand markets

Strong gas production growth outlook

Expanding midstream transnational

infrastructure opening access to markets

Weaknesses

Bearish oil production growth outlook

Chronic rig shortage a threatening upstream bottleneck

Limited domestic consumption growth outlooks

Opportunities

Development of Shah Deniz II, with estimated

gas production capacity of up to 25bcm.

Range of major gas projects under

development, including Absheron, Umid and

ACG Deep Gas

Sustained exploration activity, testing high

prospective offshore plays, such as Zafar-

Mashal and Shafag-Asiman

Threats

Heavy economic dependency on oil and gas

revenue, creating structural macroeconomic

vulnerability

Poor regional cooperation and ongoing

maritime disputes in the Caspian Sea.

E. Key trends of oil and gas sector

The country boasts substantial, prospective and underexplored area, in particular offshore in the South

Caspian basin. Interest in exploration remains strong.

Oil output decreased in the first half of 2014, according to reports by SOCAR. In part this could stem

from planned maintenance works.

The gas sector is set for strong growth, driven in large part by development of the Shah Deniz II, which

reached FID in 2013.

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COMPANY ANALYSIS- CAIRN INDIA IV.

Cairn India is one of the largest non-state exploration and production companies operating in the country. Its

roots are in UK-based Cairn Energy, formed in 1979 and becoming an investor in the Indian upstream oil sector

in the late 1990s. Cairn has now been operating in India for more than 15 years and has played an active role in

developing the oil and gas resources in the country. Ravva in eastern India was the first offshore oil and gas field

to be developed, followed by the Lakshmi gas field in western India, which was discovered in 2000 and

commenced production in 2002.

In January 2004, Cairn added the Mangala oil field in Rajasthan to its assets and this, along with the other

discoveries in Rajasthan, has become the core upstream development in India. On January 9 2007, Cairn India

Limited was listed on the Bombay Stock Exchange and the National Stock Exchange of India. In FY2010-11, Cairn

Energy agreed to sell a substantial part of its shareholding in the Indian subsidiary to Vedanta Resources and

Twin Star Holdings (a wholly owned subsidiary of Vedanta Resources). Cairn India is now part of the Vedanta

Group, a globally diversified natural resources company with wide-ranging interests in aluminium, copper, zinc,

lead, silver, iron ore and others.

During the period, Cairn established 1.2bn boe of Rajasthan hydrocarbons in-place. An additional 0.6bn boe has

been discovered and is either currently undergoing testing or is awaiting testing. The company has also extended

a significant existing gas play, with multi-tcf potential, in and around the Raageshwari Deep gas (RDG) field.

A. Portfolio of Cairn India

Cairn India is the operator of the Rajasthan block with a 70% participating interest and its JV partner ONGC has a

30% participating interest.

The Rajasthan block consists of three contiguous development

areas:

Mangala, Aishwariya, Raageshwari and Saraswati (MARS)

fields;

Bhagyam and Shakti fields; and

Kaameshwari West fields.

The Mangala, Bhagyam and Aishwariya (MBA) fields in the

northern area of the block are currently under development with

over 81 development wells already drilled on Mangala, of which

65 have been completed for initial production. Mangala

production has ramped up to the currently approved plateau rate

of 125,000b/d. In addition, Bhagyam has the potential to produce

40,000b/d and Aishwariya another 10,000b/d.

With a resource base of 7.3bn barrels of oil equivalent (boe) in

place, Cairn India believes that production potential from these

fields could now exceed 300,000b/d. Any increase in production

is subject to regulatory approval. The Mangala Processing

Terminal is designed to process crude from the MBA fields and has a capacity to process 205,000b/d of crude;

and has been designed with sufficient flexibility to be later expanded to process more crude. Four processing

trains are being built to ensure that Cairn is able to produce and process the approved peak plateau production.

B. SWOT Analysis

Strengths

Highly prospective exploration portfolio.

Major oil discoveries.

Dramatic medium-term production growth.

Good relationship with ONGC and state.

Weaknesses

Lack of immediate output growth.

Need for ongoing, high-level investment.

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Opportunities

Strong domestic energy demand growth.

Untapped oil and gas potential.

Plenty of unexplored territory.

Threats

Rising investment requirement.

Changes in national energy policy

C. Strategy

Cairn India's strategy is to establish commercial reserves from strategic positions in high-potential exploration

plays in order to create and deliver shareholder value. In order to do this, the company focuses on material

positions that are capable of providing significant growth through exploration.

The strategic focus is on maintaining low operating costs and sustaining production in existing fields. Upholding

the current production volumes from its existing assets in Ravva and Cambay is one of Cairn's key objectives.

Both of these assets have benefited from revised gas prices and improved oil production. The completion of the

4D seismic in Ravva and the infill drilling programme in Cambay will ensure that these assets continue to

produce for an enhanced period of time.

Cairn India is unlikely get more than five years of extension for its Barmer block, with the Directorate General of

Hydrocarbons (DGH) rejecting its proposal for a 10-year contract extension up to 2030. Around 13 PSCs are

expiring between 2019 and 2025. These include the Panna Mukta Tapti fields held by ONGC, Reliance Industries

and BG. There is likely to be a policy decision by the government on handling of extensions for these fields.

Cairn India believes that there are significant reserves in Rajasthan. It is in the process of assessing how advanced

technologies can be used to help increase recovery from this resource base, harnessing hydraulic fracture

stimulation techniques. Laboratory studies have indicated that the early application of EOR techniques on the

Mangala and Bhagyam fields is expected to extend the production plateau and ultimate reserves for these fields.

An EOR pilot programme in Mangala is already in progress. Further work is also planned to determine the best

method of extracting the oil from the potentially productive Barmer Hill formation.

Appraisal of the extensive potential in the huge Rajasthan block lies in numerous prospects and leads in a

number of reservoirs in the vicinity of Cairn India's existing discoveries. Cairn India has identified more than 35

prospects in the licence area and it is building a comprehensive inventory, based upon analysis of the 2D and 3D

seismic data and various wells.

D. Potentials in its E&P fields

Recent exploration drilling and the proximity of the Raageshwari deep gas field indicate the presence of a larger

multi-trillion cubic feet gas resource base, comprising the Raag Deep, Guda Deep and Guda South structures.

'RDG (Raageshwari Deep Gas) field is estimated to hold 1-3tcf (28-75bcm) of gas in-place with an estimated

recovery factor of over 50%,' the company said in a corporate presentation. Cairn currently sells 8-9mn cubic feet

per day of gas from the Raageshwari Deep gas field, which it plans to more than double to 22mn cfd by the end

of the current fiscal year and take it to 90mn cfd by FY16.

An additional un-risked prospect inventory potential of 3bn boe has been identified by Cairn India, to be drilled

up in future exploration campaigns, beginning in FY16. A significant shift from exploration to appraisal drilling is

underway in the current financial year, to accelerate reserves conversion and monetisation. All seven new

exploration and appraisal wells drilled in the first quarter of the FY14/15 financial year encountered

hydrocarbons, opening up important new discoveries and adding significant potential resources.

E. Future Investments

The firm is looking to invest more than USD3bn over the next three years. For this, an extension in the

production-sharing contract (PSC) is crucial. In April 2013, it had written to the petroleum ministry that the PSC

should be extended in the first instance till 2030, since the block had commercial production potential till 2040.

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The current PSC for the Rajasthan block is valid till May 14, 2020. The rejection of an additional 10-year term

comes on recommendations of DGH. 'According to DGH, the Rajasthan asset is primarily a crude oil-producing

block. So, the PSC can be extended for only five years. An extension for 10 years is generally allowed for gas

fields,' an official said.

A panel set up by the Indian environment ministry has approved Cairn India's plan to increase oil output at its

Rajasthan fields to 300,000b/d from 200,000b/d. Cairn India and its partner ONGC expect the production from

their Barmer fields in Rajasthan to rise to 300,000boe/d by 2016. The company claims it has a potential of

producing 15mn cubic feet per day of gas, which supports its claim for a 10-year PSC extension.

Cairn India is actively exploring for hydrocarbons in basins throughout India. In addition to the exploration

potential in Rajasthan, it has identified a number of leads and prospects in India, where Cairn has an interest in

other blocks. This diversification allows Cairn India to drill a large number of potential prospects with high

geologic risk, as well as explore for and drill smaller potential accumulations that carry less risk.

In addition, Cairn believes that India has significant under-explored potential, with 26 basins covering a

sedimentary area of 3.14mn sq km. As well as developing its existing exploration portfolio, Cairn is seeking out

new exploration opportunities through organic growth, acquisition and by participating in NELP rounds.

F. Financials

In the first quarter of the 2014/15 financial year, Cairn India reported revenues of INR4,483 crore (USD750mn), up

10% tear-on-year (y-o-y). EBITDA rose 3% to INR3,120 crore and post-tax profits reached INR2,720 crore.

Average daily gross operated production was 217,869boe/d (226,597boe/d including internally consumed gas)

during the quarter. Rajasthan production was 183,164boe/d, in line with FY15 guidance.

Revenues (group):

INR187,620mn (FY13/14)

INR175,241mn (FY12/13)

Net profit (group):

INR124,320mn (FY13/14)

INR 116,063mn (FY12/13)

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RUSSIA’S NEW ENERGY ALLY CHINA V.

Russia's new gas deal with China has likely been accelerated by geopolitical pressures from the West owing to a

continued impasse in Ukraine. It also notes a shift in Gazprom's gas strategy in Asia-Pacific, as practical funding

needs arising from sanctions push the Russian gas firm away from its initial target of the Japanese LNG market

and towards the Chinese gas pipeline market. It is seen as Lending Squeeze Pushes Gazprom to Asia.

A. The Deal

Gazprom has reached another milestone as Russia and China signed a framework agreement for yet another gas

supply deal that would see the delivery of 30bn cubic metres (bcm) of gas to China per year. Signed on the

sidelines of the Asia-Pacific Economic Cooperation (APEC) summit in November 2014, the two countries agreed

to finalise the sale by 2015. This new agreement will see gas delivered via the 'western route' - from West Siberia

into China - and complements 38bcm of gas to be delivered via the 'eastern route' - from East Siberia into China

- as part of an earlier Sino-Russian gas deal signed in May 2014.

The western route is based on a 2,600-km pipeline that would carry gas from a compressor station south of Novy

Urengoi in the Yamal-Nenets Autonomous Okrug along an existing pipeline corridor and across Russia’s

Republic of Altai to the Chinese border.

B. Russia Move towards East

It is seen that Western Tensions Push Russia Further East. A second gas agreement was being considered as

quickly as a month after the conclusion of the first Sino-Russian gas deal. On June 4 2014, Kremlin Chief of Staff

Sergei Ivanov was quoted in RIA Novosti, stating that 'it is very likely that we will soon conclude a contract to

build a western [pipeline]'. However, the speed at which China and Russia agreed on the western route

agreement - a mere five months in contrast to more than eight years taken for the first gas deal - is no doubt

influenced by Gazprom's increasingly uncertain fortune as the impasse between Russia and the West over

Ukraine continues. Not only have the Russian gas behemoth's long-term growth prospects in its primary market

Europe curtailed by the region's uncertain gas demand and continued efforts at diversifying sources of gas and

energy, western restrictions on capital access are also weighing on Gazprom's ability to finance LNG growth

projects.

As President Vladimir Putin peers across the geopolitical landscape, what he sees is a Europe seeking alternative

sources of energy, an America possibly on the cusp of allowing crude oil exports and increasing LNG shipments

to the continent, and a China willing to consider Russia as a source of its energy. It comes as no surprise then

that Gazprom plans to allocate a chunk of its planned $18.1 billion investments next year on R&D for a new gas

pipeline route to China.

C. Financing Challenge Sees Pivot from Japan to China

Russia's standoff with the West has specifically changed Gazprom's eastern pivot from Japan to China. While

China does indeed present a large market opportunity, it had not always been the primary target for the Russian

firm.

Facing pressure from President Vladimir Putin to expand its presence in Asia-Pacific in 2012, Gazprom had eyed

the Japanese LNG market to grow its market share in Asia. The Vladivostok LNG project was hastily decided upon

in February 2013 in hope that it would beat new LNG producers such as North America and East Africa to the

Japanese market by 2018. A final investment decision (FID) to develop the Chayanda gas field - which could

produce 25bcm per year at its peak - and the Power of Siberia pipeline in 2013 was taken to support the

Vladivostok LNG project.

These resources are now being directed towards fulfilling Gazprom's 38bcm gas export obligation to China upon

their completion in 2018. Part of this re-direction is the result of the conclusion of the first Sino-Russian gas deal

12

in May 2014, which was accelerated due to price concessions made by Gazprom as a geopolitical move against

the West. The second is due to the difficulty Gazprom had faced securing Japanese participation and funding in

the Vladivostok LNG project. In August 2014, Japan's decision to freeze funding for new projects in Russia, as

part of G7's sanctions against Russian actions in Ukraine, further killed the prospects of Japanese finance for

Vladivostok in the near term.

This exacerbates an already dire outlook for new sources of finance for Gazprom: traditional Russian state-owned

lenders, including its subsidiary Gazprombank, are restricted from accessing Western capital markets, while

western lenders are also wary of lending to Gazprom despite it being excluded from sanctions. The firm's poor

performance in London is a good indication of the difficulty it faces raising finance overseas in this sanctions

environment.

Western capital restrictions will see Gazprom continue to look eastwards to tap new markets for finance. For

instance, it listed on the Singapore Stock Exchange in June 2014. Together with compatriots Rosneft and Lukoil,

the gas firm is also considering listing on the Hong Kong Stock Exchange, and in local currencies, according to

Economic Development Minister Alexei Ulyukayev.

While this may help alleviate some of Gazprom's financing requirements, these measures will not be sufficient to

help the firm move other long-term growth projects forward.

The new 30bcm gas deal with China further weakens the appeal of Vladivostok LNG unless Japanese

commitment to the project is secured. China's regulatory changes towards the coal industry will not

significantly diminish the role of coal and see a dramatic spike in gas consumption as a result. Hence,

greater dependence on pipeline gas imports will reduce China's LNG import requirement. As one of the

largest LNG demand growth markets, the loss of future Chinese LNG demand also loosens the market,

hitting the appeal and economics of new LNG projects.

Capital alone will be insufficient to move forward the South Stream gas pipeline project, targeted to

export up to 63bcm of gas particularly to Central and Eastern Europe (CEE). As long as the impasse over

Ukraine remains, the European Union (EU) is unlikely to green light a project that entrenches Gazprom's

influence over the CEE gas market.

D. Impact of Deal

Deliveries under the two agreements, if they’re completed, would make China the largest single customer for

Russian gas and could be expanded to a combined 160 billion cu m/year. They would put this new market in

direct competition with European markets for supplies from West Siberia, whose supergiant fields have been the

main source of Russian gas supplies to Europe. Europe has absorbed about 80% of Russian oil and gas exports,

including 160 billion cu m of gas in 2013. With European demand stagnant, Russia has sought new markets in

Asia while European countries have tried to secure supplies from outside Russia.

13

ACCELERATED DEPRECIATION BENEFIT FOR WIND ENERGY AND VI.ITS IMPACT ON THE RENEWABLE ENERGY INDUSTRY

The government has brought back Accelerated Depreciation (AD) on wind investments. Wind Power

development in India started in the early 90s. As per Section 80(J) of Income Tax Act 1961, industries were

allowed 80% depreciation on capital invested. Since then till 2012 (when the benefit was removed), Wind Power

development and growth has always relied primarily on Accelerated Depreciation (AD).

New wind capacity additional peaked in 2011-12 at about 3,200 MW, falling sharply to 1,700 MW the next year

as AD benefits were removed. The argument at that time by Government was given that wind industry had

matured, and the focus needed to shift to solar. The decline in wind investment due to withdrawal of AD

coincided with healthy growth of close to 60% in Solar Power in 2012-13 and 2013-14. The market momentum

had definitely shifted in favour of Solar. Market analysis suggests that Wind AD market had an investing capital

of close to 7300 crores. This shifted to Solar AD market which saw increase in investments worth Rs 7500 crores

during 2012-13.These can also be understood from the table and graph below.

After reintroduction of AD

(80%) in 2014, investment

momentum has shift

again to wind due to

policies and attractive

tariffs. Wind tariff in

recent years have become

very attractive and are

close to solar tariff in

many states. In Rajasthan,

Maharashtra and MP,

tariff in the range of Rs. 5,

whereas solar tariffs are

generally in the range of

Rs. 6, leaving a very small gap. With this, there is certainly being a diversion in investments from Solar to Wind

power in the times to come. The Renewable energy sector has seen a drop of 20% in the new capacity addition

during the first half of the fiscal year 2014-15, when compared to previous year. The capacity addition during the

same period in previous year was 1376 MW against the 1094 MW in the current year.

A graph below shows the sector wise capacity addition during the year 13-14 & the year 14-15.

It is easy to notice

that the capacity

addition in the

wind sector has

increased by 7%,

but at the same

time the capacity

additions in other

sectors have

dropped, specially

the solar sector,

which has

witnessed a drop

of 65%.The surge

in capacity

addition in Wind, can be attributed significantly to the recent reinstatement of wind AD, leading to more

confidence among investors.

14

Solar, however, has taken a setback due to the following reasons:

The reinstatement of AD for wind has diverted investors towards wind power.

The difference between wind and solar tariffs are moderate. Solar tariffs are in the range of 6-7 Rs.

per unit where that of wind are the range of 5-6 Rs. per Unit. Capital cost per MW is still significantly

high is case of Solar, when compared to Wind.

The poor performance of REC markets has impacted Solar more than Non-Solar.

Preferential tariffs are prevalent in only a few states, while many states have proposed reverse

bidding scheme for solar power, with power being sold in the range of Rs 5-6. This has not positively

impacted investor confidence.

A. Comparison between Wind and Solar

S.

No

Parameter Wind Solar

1. Preferential tariffs Are existent in all wind states Most states have reverse bidding

schemes

2. Extent of PPA by states Unlimited Generally capped

3. Poor REC market and weak

RPO compliance

Will not significantly affect wind

industry. RPO compliance is relatively

easier due to lower Non-Solar costs.

Uncertainty in timeline of proposed

REC price.

Will significantly affect solar

industry as they rely heavily on

REC markets. RPO compliance is

difficult due to high solar costs.

Uncertainty in timeline of

proposed REC price.

4. Wheeling & Banking

Benefits & open access Well defined in many states Not well defined in many states

5. Anti-dumping duty Wind industry will not be affected Solar costs will go up significantly

6. Forecasting and scheduling Mandatory ( no UI and financial

implications as of now on the projects)

Mandatory (no UI implications on

the projects)

B. RPO targets for the states & REC trading for the Nov-14

Renewable Purchase Obligation Targets

State 10-11 11-12 12-13 13-14 14-15 15-16 16-17 17-18 18-19 19-20 20-21

Andhra

Pradesh 5.00% 5.00% 5.00% 5.00% 5.00%

Arunachal

Pradesh 4.20% 5.60% 7.00%

Assam 1.40% 2.80% 4.20% 5.60% 7.00%

Bihar 1.50% 2.50% 4% 4.50% 5.00%

Chhattisgarh 5.00% 5.25% 5.75% 6.25% 6.75% 7.25%

Delhi 3.40% 4.80% 6.20% 7.60% 9.00%

Gujarat 5.00% 6.00% 7.00% 7.00% 8.00% 9.00% 10.00%

Haryana 1.50% 1.50% 2.00% 3.00% 3.25% 3.50% 3.75% 4.50% 5.00% 5.50% 6.00%

Himachal

Pradesh 10.01% 10.25% 10.25% 10.25% 11.25% 12.25% 13.50% 14.75% 16.00% 17.50%

Jammu

Kashmir 1.00% 3.00% 5.00% 5.00% 6.00% 7.50% 9.00%

Goa & UT 1.00% 2.00% 3.00% 3.00% 3.30% 3.55% 3.95% 4.30% 4.65% 5.10% 5.50%

Jharkhand 2.00% 3.00% 4.00%

Karnataka 10%/7% 10%/7% 10%/7% 10%/7%

15

Bihar has declared solar RPO trajectory - increasing upto 3% by 2022.

HP has declared trajectory of solar RPO going upto 3% and non-solar RPO upto 16% by 2022.

Kerala has kept solar RPO constant at 0.25% while increasing the non-solar RPO to 6.35% by 2022. •

Delhi, J&K, West Bengal and Uttarakhand have declared increasing RPO upto 2016-17.

AP, Jharkhand and Maharashtra have declared their RPO upto FY 2016 but kept the RPO constant for the

last three years.

Other states yet to declare their RPOs beyond 2014-15.

1. State-wise Solar RPO targets

Kerala 3.00% 3.30% 3.63% 3.99% 4.39% 4.83%

Madhya

Pradesh 0.80% 2.50% 4.00% 5.50% 7.00%

Maharashtra 6.00% 7.00% 8.00% 9.00% 9.00%

Manipur 2.00% 3.00% 5.00%

Mizoram 5.00% 6.00% 7.00%

Meghalaya 0.50% 0.75% 1.00%

Nagaland 6.00% 7.00% 8.00%

Orissa 4.50% 5.00% 5.50% 6.00% 6.50% 7.00%

Punjab 2.40% 2.90% 3.50% 4.00%

Rajasthan

(Draft) 6.00% 7.10% 8.20% 9.00% 10.20% 11.40%

Sikkim

Tamil Nadu

(Draft) 9.00% 9.00% 9.00% 9.00% 9.00%

Tripura 1.00% 1.00% 2.00%

Uttarakhand 9.00% 10.00%

Uttar

Pradesh 4.00% 5.00% 6.00%

West Bengal 4.00% 4.50% 5.00% 5.50% 6.00% 7.00% 8.00%

State 10-11 11-12 12-13 13-14 14-15 15-16 16-17 17-18 18-19 19-20 20-21

Andhra Pradesh 0.25% 0.25% 0.25% 0.25% 0.25% 0.25%

Arunachal Pradesh Not regulation issued for RPO by the Power Department

Assam 0.10% 0.15% 0.20% 0.25%

Bihar 0.25% 0.25% 0.50% 0.75% 1.00% 1.25% 1.50% 1.75% 2.00% 2.50% 3.00%

Chhattisgarh 0.25% 0.50%

Delhi 0.10% 0.15% 0.20% 0.25% 0.30% 0.35%

Gujarat 0.50% 1.00%

Haryana 0.00% 0.05% 0.75%

Himachal Pradesh 0.01% 0.25% 0.25% 0.25% 0.25% 0.25% 0.50% 0.75% 1.00% 2.00% 3.00%

Jammu Kashmir 0.10% 0.25%

Goa & UT 0.30% 0.40%

Jharkhand 0.50% 1.00%

Karnataka 0.25%

Kerala 0.25% 0.25% 0.25% 0.25% 0.25% 0.25% 0.25% 0.25% 0.25% 0.25% 0.25%

Madhya Pradesh 0.40% 0.60% 0.80% 1.00%

Maharashtra 0.25% 0.25% 0.50% 0.50% 0.50%

Manipur 0.25% 0.25%

Mizoram 0.25% 0.25%

16

2. REC trading for the Nov-14

REC trading session of Nov -14 was conducted on 26th November 2014. Below is a summary of the result : - The

RECs inventory is piling up and increasing which if seen from the demand point of view is more than the total

RECs cleared in the current financial year. In a recent proposal by CERC, the REC prices are expected to reduce to

half of existing Floor and Forbearance price.

Non Solar REC The demand for Non Solar RECs stood at 196013 RECs. The market was optimistic for Non Solar

RECs. The RECs traded at their floor price of INR 1500. Non-solar demand is picking up but not at the level to

clear the sell bids.

Solar REC The demand for Solar RECs took a hit in this trading session as it stagnated to 1149 RECs. Demand is

clearly on very low side. The Solar RECs Traded at floor Price of 9300 INR.

Market Month/year Type Buy

Bids(REC)

Sell Bids

(REC)

Cleared

Volume(REC)

Cleared

Price(Rs/REC)

IEX

November/2014

Solar 245 2,41,063 245 9300

Non-Solar 93,100 49,46,763 93,100 1500

PXIL Solar 904 2,71,209 904 9300

Non-Solar 1,02,913 55,77,324 1,02,913 1500

Note:

The data and information in the report is sourced from websites and documents available in public

domain and doesn’t purport to be official view of government or any organization. Sincere efforts have

been made to present correct data; however, errors and omissions, if any, are regretted and the same may

please be brought to the notice of Energy Desk for necessary corrective action.

Meghalaya 0.30% 0.40%

Nagaland 0.25% 0.25%

Orissa 0.10% 0.15% 0.20% 0.25% 0.30%

Punjab 0.03% 0.07% 0.13% 0.19%

Rajasthan (Draft) 0.50% 0.75% 1.00%

Sikkim Not regulation issued for RPO by the Power Department

Tamil Nadu (Draft) 0.05%

Tripura 0.10% 0.10%

Uttarakhand 0.03% 0.05%

Uttar Pradesh 0.50% 1.00%

West Bengal 0.25% 0.30% 0.40% 0.50% 0.60%