energy & fuel users’ journal oct. – dec. 2014...

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Energy & Fuel Users’ Journal Oct. – Dec. 2014

THE oil price has fallen by more than40% since June, when it was $115 a barrel.It is now below $70. This comes after nearlyfive years of stability. At a meeting in Viennaon November 27,2014, the Organisation ofPetroleum Exporting Countries(OPEC),which controls nearly 40% of the worldmarket, fai led to reach agreement onproduction curbs, sending the price tumbling.Also hard hit are oil-exporting countries suchas Russia (where the rouble has hit recordlows), Nigeria, Iran and Venezuela. Why isthe price of oil falling?

The oil price is partly determined byactual supply and demand, and partly byexpectation. Demand for energy is closelyrelated to economic activity. It also spikes inthe winter in the northern hemisphere, andduring summers in countries which use airconditioning. Supply can be affected byweather (which prevents tankers loading) andby geopolitical upsets. If producers think theprice is staying high, they invest, which aftera lag boosts supply. Similarly, low prices leadto an investment drought. OPEC’s decisionsshape expectations: if it curbs supply sharply,it can send prices spiking. Saudi Arabiaproduces nearly 10m barrels a day—a thirdof the OPEC total.

Four things are now affecting thepicture. Demand is low because of weakeconomic activity, increased efficiency, anda growing switch away from oil to other fuels.Second, turmoil in Iraq and Libya—two bigoil producers with nearly 4m barrels a daycombined—has not affected their output. The

PETROLEUMWHY THE OIL PRICE IS FALLING

market is more sanguine about geopoliticalrisk. Thirdly, America has become the world’slargest oil producer. Though it does notexport crude oil, it now imports much less,creating a lot of spare supply. Finally, theSaudis and their Gulf allies have decided notto sacrifice their own market share to restorethe price. They could curb production sharply,but the main benefits would go to countriesthey detest such as Iran and Russia. SaudiArabia can tolerate lower oil prices quiteeasily. It has $900 billion in reserves. Its ownoil costs very little (around $5-6 per barrel)to get out of the ground.

The main effect of this is on the riskiestand most vulnerable bits of the oil industry.These include American frackers who haveborrowed heavily on the expectation ofcontinuing high prices. They also includeWestern oi l companies with high-costprojects involving drilling in deep water or inthe Arctic, or dealing with maturing andincreasingly expensive fields such as theNorth Sea. But the greatest pain is incountries where the regimes are dependenton a high oil price to pay for costly foreignadventures and expensive socialprogrammes. These include Russia (whichis already hit by Western sanctions followingits meddling in Ukraine) and Iran (which ispaying to keep the Assad regime afloat inSyria). Optimists think economic pain maymake these countries more amenable tointernational pressure. Pessimists fear thatwhen cornered, they may lash out indesperation.

(Published in the Economist dated 08 December 2014)

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The crude oil prices that has nosedived

from the highs of $ 110 per barrel in June

2014 is expected to pump in USD 1.4 trillon

in to the Indian economy, said RajenUdeshi,

president (polyester chain), Rel iance

Industries while addressing an event at

Gandhinagar on Wednesday.

“Today, this money is lying with the

government and the oil companies. I think it

will soon come in to the system and will

change the purchasing power of the people,”

said Udeshi at the inaugural function of a 3-

day pre-Vibrant Gujarat summit titled: India-

Opportunities for Global Investment in

Textiles.

Around June 2014, India was importing

crude at over $ 110 per barrel. Today the

prices of brent crude stand around $ 65. This

dip in prices, Udeshi felt, will benefit the

Indian economy.

“The buying habits of people has

already changed. From a single pair of cloth,

today a person wears 3-4 pairs during the

day. One for a morning jog, office wear,

evening dress and a party wear,” he said

while predicting a huge growth in polyester

fabric in the near future.

Meanwhile, experts from the textile

world who had gathered for the event rued

the “low credibility” that the textile sector has

among lending institutions. “As an industry,

the credibility of the textile sector within the

financial world in India is very low,” said

FALLING CRUDE OIL PRICES WILL PUMP USD1.4 TRILLION IN TO INDIAN ECONOMY

Hrishikesh Mafatlal, chairman and chief

executive, Arvind Mafat lal Group of

Companies.

According to Mafatlal, the share of

funding from both the private and public

sector banks was very low as far as the textile

sector was concerned. “There is a need to

focus energies on product development and

innovation,” he remarked.

Giving reasons for the low

attractiveness of the textile industry among

investors, Sunil Singhania, CIO (Equity

Investments), Reliance Mutual Fund said, “In

the last 50-70 years, very few industries in

the textile sector have created value.” He

gave the example of Bangalore-based Page

Industr ies as one of the few Indian

companies who has created a lot of value in

manufacturing innerwear and leisurewear in

the country.

“Even if one Indian spends only Rs

10,000 on his clothes every year, India is

easily aRs 10 lakh crore market. Most of the

companies have failed to tap this local

market,” he said.

S Uma Shanmukhi, DGM (SME) State

Bank of India minced no words when she

pointed out how her bank has maintained a

“neutral” outlook for the industry. “We are

moderately negative on 100 percent export

oriented units in the garment industry and

moderately positive on the technical textiles,”

Shanmukhi said at the event.

(Source : The Indian Express)

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Low international crude prices have fallen

by almost 40% from their peak levels in six

months’ time, and this is the best time to build

and expand the strategic crude oil reserves in

India which imports nearly 70% of its oil

requirement, according to a new study by the

Associated Chamber of Commerce and

Industry of India (ASSOCHAM).

The current international crude prices of

$60 per barrel presents an excellent opportunity

to build strategic crude oil reserve for India, says

the ASSOCHAM study. This can be done by

enhancing the investment in physical

infrastructure besides signing the forward

contracts with the exporting countries, it says.

The study adds, “It is once in several

decade opportunity for India to scale up its

strategic oil reserves at much higher level than

even three months’ consumption, which itself

is long way to go for us at this point of time.”

In fact, India’s crude oil import bill in

November 2014 when compared to May 2014

shows that India has saved around $3 billion

per month as the prices of fuel in the Indian

basket have declined to below $60 per barrel

from $106 per barrel about six months ago.

Thus it will cost India around 35 – 40% less to

build strategic energy reserve at the present

price, says ASSOCHAM.

At present, India has three strategic crude

oil reserves – one in Andhra Pradesh and two

in Karnataka, and four more are proposed at

Bikaner in Rajasthan, Rajkot in Gujarat, Padur

in Karnataka, and Chandikholein in Odisha.

GOOD TIME TO BOLSTER INDIA’SSTRATEGIC CRUDE OIL RESERVE

The Indian government is planning tospend around Rs.5,000 – 6,000 crore onbuilding the additional capacities. But given theopportunity of lower crude prices, thegovernment must commit at least three to fourtimes more investments to augment suchcapacities for our future requirements, saysASSOCHAM. Refined mineral oils and theirproducts is also a major export item for India,accounting for around $65 billion of India’s totalexports of around $314.5 billion in FY2013-14.

Given the fact, that building of physicalinfrastructure takes long time, the studysuggests that the government could go in for alarger scales forward commercial storageagreements in countries from where we canship crude into our country. The refineries, bothin public and in private should be aggressivelyexploring such opportunities, saidASSOCHAM.

According to the World Bank, Indiaconsumed over 3.7 million barrels of oil per day,one million of which was domestically producedand the remaining 2.7 million barrels wasimported in 2013. The cost of India’s crude oilimports during the past three years hasaveraged $165 billion, and with crude oilaccounting for about a third of the import billand nearly two-thirds of the trade deficit, loweroil prices will help the government reduce itstrade deficit significantly.

According to the World Bank’sprojections, oil prices are likely to remain atlow levels through most of 2015 and riseabove $102 per barrel only in 2021.

(Source: The dollarbusiness)

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Finally, the diesel prices in India havebeen deregulated. The dismantling of theAdministered Pricing Mechanism(APM) andthe deregulation of prices introduced in 2002was supposed to be completed within a fewyears, but it took more than a decade fordiesel to get completely free fromgovernment intervention.

I had started my career in India’s largestpetroleum downstream company, Indian OilCorporation Limited (IOCL) in 2001, and rightafter the announcement of the dismantlingof APM by the Vajpayee government in 2002,I was transferred from the operations divisionof the company to the retail sales division. Iwas one among the several young entry levelofficers who were the market interface of theteam that was tasked with the responsibilityof overhauling the entire petroleum retailingsector(comprising of petrol pumps/fuelingstations or Retail Outlets as we used to callthem internally) and fight the onslaught of theprivate sector petroleum retai lers l ikeReliance, Essar and Shell.

Till then, the government decided whichOMC – Oil Marketing Company(IOCL, BharatPetroleum(BP), Hindustan Petroleum(HP) orIndo-Burma Petroleum(IBP) which was latermerged with IOCL) shall put up a Petrol Pumpin which a particular location, and thegovernment set the price for Petrol andDiesel. IOCL was(and is) not only the biggestpublic sector oil company, but also thegovernment’s f lagship downstream oilcompany, and as such, was entitled to thehighest market share. That meant that IOCL

DEREGULATION OF THEDIESEL PRICES IN INDIA

would be allotted the maximum petrol pumps,proportional to its targeted market share.That changed in the post-APM period. Notonly were the private companies like Reliancegiven the permission to open petrol pumps,the other government owned OMCs werealso given a free hand to set up petrol pumpsas they wished. The stage was now set forthe government controlled OMCs(BP, HP andIBP) and the private players(Reliance, Essar,Shell) to challenge the hegemony of IOCL,and grab market share from the leader.

The first post-APM year(2003-2004)moved along as predicted. The number ofpetrol pumps across the country increasedexponentially, with every company allottingpetrol pump dealerships at a breathtakingpace. It also led to lot of charges of corruptionin the allotment process, but that is anothertopic for another day. We, the officers in thefield and the foot soldiers of the company,were under tremendous pressure as Reliancestarted commissioning and operat ingmassive petrol pumps along the highways.Reliance offered hitherto unheard of serviceslike spotlessly clean Dhabhas/eateries, toiletsand overnight resting places for the truckdrivers, and fleet cards for the owners of thetruck fleet. Reliance is supposed to havebeen inspired the business model of the UScompany – Flying J. Reliance also deployedstate-of-the-art digital mult ipoint fueldispensers in an era when most of the petrolpumps of the public sector OMCs were stillusing analog dispensers which wereperceived to be tampered in most petrol

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pumps. While Essar was gradually expandingits retail network, and faced several fuelsupply constraints, Reliance penetrated themarket at a furious pace, and within a shortperiod of time, was able to gain considerablemarket share. Reliance also was able toseamlessly integrate the retail operationswith its Jamnagar refinery (one of the largestin the world) operations. (An interesting takeon the Reliance’s success can befound here). But the deregulation hit a wallin 2004.

The APM was dismantled at a timewhen the global crude oil prices wererelatively low, and the oil demand was slowlyrecovering after the global recession causedby the dot com burst and 9/11 attacks in2000-2001. By 2004, the global economystarted growing thereby increasing the oildemand, but the oi l supply remainedconstrained after the attack on Iraq in 2003.This caused the crude prices to increase,which started reflecting on the increased fuelprices at the petrol pump and the commonman started to protest the increase in prices.The new government(UPA 1) was dependenton the support of the communist partieswhich convinced(or forced, depending uponhow one looks at it) the government to capthe petrol and diesel prices sold by the publicsector OMCs which were compensated fortheir under-recoveries in the form of oil-bonds(more here), The private players werefree to fix prices, but there was no way theycould attract customers by selling the fuel atRs. 2 or 3 per litre more than what the publicsector OMCs were selling. Reliance, Essarand Shell started shutting down their petrolpumps, and with that, the first round ofderegulation of the petroleum retail ingended.(One positive result of permittingprivate players was that the amenities at the

petrol pump and the customer serviceimproved drastically, at least in the urbanareas)

The UPA government which came backto power in 2009 resumed the deregulationin a more gradual manner. The governmentfirst deregulated the petrol prices in 2010after gradually removing price controls(more here), and in January 2013, started toincrease the of diesel by around Rs. 0.50/month. The under-recoveries on dieselstarted to decrease, and was completelywiped out after the crude oil prices crashedby almost 25% from a peak of $115/barrel inJune 2014 to mid $80s at the t ime ofwriting(19 October 2014). It was then only amatter of t ime before the governmentannounced complete deregulation of thediesel price too.

With the crude prices per barrelpredicted to remain in the $80s throughout2014-15 as a result of Saudi Arabia’sintentions to gain market share, the newgovernment may not have to worry about anincrease in crude prices, and the political heatit will generate.

If the crude prices remains low aspredicted, we may have just witnessed thefinal chapter of the “automotive fuel pricedergulation”.

(Written by Madhavan Nampoothiri)

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NATURAL GASLNG, CNG, LPG AND HYDROGEN

There is always some confusionbetween the difference types of gaseousfuels. The following is a brief summaryhighlighting the main differences of thedifferent type of gaseous fuels.

Compressed Natural Gas or CNG isstored on the vehicle in high-pressure tanks- 20 to 25 MPa (200 to 250 bar, or 3,000 to3,600 psi). Natural gas consists mostly ofmethane and is drawn from gas wells or inconjunction with crude oil production. Asdelivered through the pipeline system, it alsocontains hydrocarbons such as ethane andpropane as well as other gases such asnitrogen, helium, carbon dioxide, sulphurcompounds, and water vapour. A sulphur-based odourant is normally added to CNG tofacilitate leak detection. Natural gas is lighterthan air and thus will normally dissipate inthe case of a leak, giving it a significant safetyadvantage over gasoline or LPG.

Liquefied Natural Gas or LNG isnatural gas stored as a super-cooled(cryogenic) liquid. The temperature requiredto condense natural gas depends on itsprecise composition, but it is typicallybetween -120 and -170°C (-184 and –274°F). The advantage of LNG is that itoffers an energy density comparable to petroland diesel fuels, extending range andreducing refuelling frequency.

The disadvantage, however, is the highcost of cryogenic storage on vehicles and themajor infrastructure requirement of LNGdispensing stations, production plants andtransportation facilities. LNG has begun to

find its place in heavy-duty applications inplaces like the US, Japan, the UK and somecountries in Europe. For many developingnations, this is currently not a practical option.

Liquefied Petroleum Gas or LPG(also called Autogas) consists mainly ofpropane, propylene, butane, and butylene invarious mixtures. It is produced as a by-product of natural gas processing andpetroleum refining. The components of LPGare gases at normal temperatures andpressures. One challenge with LPG is thatit can vary widely in composition, leading tovariable engine performance and coldstart ing performance. At normaltemperatures and pressures, LPG wil levaporate. Because of this, LPG is stored inpressurised steel bottles. Unlike natural gas,LPG is heavier than air, and thus will flowalong floors and tend to settle in low spots,such as basements. Such accumulationscan cause explosion hazards, and are thereason that LPG fuel led vehicles areprohibited from indoor parkades in manyjurisdictions.

Hydrogen or H2 gas is highlyflammable and will burn at concentrations aslow as 4% H2 in air. For automotiveapplications, hydrogen is generally used intwo forms: internal combustion or fuel cellconversion. In combustion, it is essentiallyburned as conventional gaseous fuels are,whereas a fuel cell uses the hydrogen togenerate electricity that in turn is used topower electric motors on the vehicle. Hydrogen gas must be produced and is

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therefore is an energy storage medium, notan energy source. The energy used toproduce it usually comes from a moreconventional source. Hydrogen holds thepromise of very low vehicle emissions andflexible energy storage; however, manybelieve the technical challenges required torealize these benefits may delay hydrogen’swidespread implementation for severaldecades.

Hydrogen can be obtained throughvarious thermochemical methods utilizingmethane (natural gas), coal, l iquif iedpetroleum gas, or biomass (biomassgasification), from electrolysis of water, or bya process called thermolysis. Each of thesemethods poses its own challenges.

(Source : Alternate Fuel System Inc.)

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While Natural Gas is also a fossil fuel,

and emits Co2, it is still considered as a much

better option than other solid fossil fuels like

coal, and liquid fossil fuels like petroleum

products. Here is a look at some of the impact

of Natural gas on the environment.

Air Emissions

At the power plant, the burning of

natural gas produces nitrogen oxides and

carbon dioxide, but in lower quantities than

burning coal or oil. Methane, a primary

component of natural gas and a greenhouse

gas, can also be emitted into the air when

natural gas is not burned completely.

Similarly, methane can be emitted as the

result of leaks and losses during

transportation. Emissions of sulfur dioxide

and mercury compounds from burning

natural gas are negligible.

The average emissions rates in the

United States from natural gas-f ired

generation are: 1135 lbs/MWh of carbon

dioxide, 0.1 lbs/MWh of sulfur dioxide, and

1.7 lbs/MWh of nitrogen oxides.Compared to

the average air emissions from coal-fired

generation, natural gas produces half as

much carbon dioxide, less than a third as

much nitrogen oxides, and one percent as

much sulfur oxides at the power plant.2 In

addition, the process of extraction, treatment,

and transport of the natural gas to the power

plant generates additional emissions.

NATURAL GAS ANDENVIRONMENTAL IMPACT

Water Resource Use

The burning of natural gas incombustion turbines requires very little water.However, natural gas-f ired boi ler andcombined cycle systems do require water forcooling purposes. When power plantsremove water from a lake or river, fish andother aquatic life can be killed, affectinganimals and people who depend on theseaquatic resources.

Water Discharges

Combustion turbines do not produceany water discharges. However, pollutantsand heat build up in the water used in naturalgas boilers and combined cycle systems.When these pollutants and heat reach certainlevels, the water is often discharged intolakes or rivers. This discharge usuallyrequires a permit and is monitored.

Solid Waste Generation

The use of natural gas to createelectricity does not produce substantialamounts of solid waste.

Land Resource Use

The extraction of natural gas and theconstruction of natural gas power plants candestroy natural habitat for animals and plants.Possible land resource impacts includeerosion, loss of soi l productivi ty, andlandslides.

(Source : US Environmental Protection Agency)

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Nearly 80% of the world’s total provennatural gas reserves are located in tencountries. Russia tops the list, holding abouta quarter of world’s total gas reserves,followed by Iran and Qatar in the Middle East.Hydrocarbons-technology.com profiles thetop 10 countries with the world’s biggestproven gas reserves.

Russia

Russia holds the largest amount ofnatural gas reserves in the world. The countrywas estimated to possess about 1,688 trillioncubic feet (Tcf) of proven gas reserves as ofJanuary 2013, accounting for about onefourth of the world’s total proven gasreserves.

More than half of Russia’s gas reservesare located in Siberia. Three of the majorSiberian fields, namely Yamburg, Urengoyand Medvezh’ye, account for approximately45% of the country’s gas reserves. Themajority of the country’s gas reserves underdevelopment and production are located inthe Nadym-Pur-Taz (NPT) region of upperWestern Siberia.

Russia produced 20.916Tcf of naturalgas in 2012. The state-run oil and gascompany Gazprom dominates upstream gasproduction in the country.

The company accounts for about 80%of Russia’s total natural gas output andcontrols more than 65% of proven gasreserves in the country. Other companiesinvolved in gas production in Russia includeNovatek, PSA operators, Lukoil and Rosneft.

NATURAL GAS – COUNTRIES WITH THEWORLD’S BIGGEST NATURAL GAS RESERVES

Iran

Iran holds the world’s second biggestnatural gas reserves. Its proved natural gasreserves as of December 2012 stood at1,187Tcf. Most of these reserves remainundeveloped due to international sanctionsand delays in field development.

More than 60% of Iran’s natural gasreserves are located offshore. Non-associated fields account for around 80% ofthe country’s proven gas reserves. SouthPars is the largest gas field comprising 27%of Iran’s total proved natural gas reserves and35% of the country’s natural gas output.North Pars, Kish and Kangan are the othermajor natural gas fields in Iran.

Gross natural gas production of thecountry in 2012 stood at 8.1Tcf. NationalIranian Oil Company (NIOC), through itssubsidiaries including National Iranian SouthOil Company (NISOC) and Pars Oil & GasCompany (POGC), manages thedevelopment and production of natural gasresources in the country. The National IranianGas Company (NIGC), another subsidiary ofNIOC, is responsible for natural gasinfrastructure, transportation and distribution.

Qatar

Qatar holds the third largest natural gasreserves in the world. Its proven natural gasreserves as of December 2012 wereestimated at 885.3Tcf. It accounts for around13% of the world’s total natural gas reserves.Qatar is also the single largest LNG supplierin the world.

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A vast majority of the country’s naturalgas reserves are located in the giant offshoreNorth Field, which covers an area almostequivalent to Qatar itself. North Field is theworld’s largest non-associated gas field. It isthe main source of Qatar ’s natural gasproduction. The Barzan gas project, the latestNorth Field project under construction, isexpected to produce an additional 600 billioncubic feet of gas per year upon its completionin 2015.

The gross natural gas production of thecountry in 2012 stood at 5.7Tcf. The state-owned Qatar Petroleum (QP) is the dominantplayer in the country’s natural gas sector.

The natural gas resources aredeveloped by integrated mega projects inassociation with foreign players, includingExxonMobil, Shell and Total. QP holds majorshare in these projects. Qatargas and RasGas are the major LNG companies operatingin Qatar.

Turkmenistan

The Central Asian countryTurkmenistan holds the world’s fourth largestnatural gas reserves. The country’s provennatural gas reserves as of December 2012stood at 353.1Tcf. Turkmenistan, however,faces challenges in developing its gasreserves because of far-off end-use marketsand a lack of sufficient pipeline infrastructureand foreign investment.

Most of Turkmenistan’s proven gasreserves are located in the Amu Darya basinin the south-east and in the Murgab SouthCaspian basins in the western part of thecountry. The Dauletabad field in the AmuDarya basin, with estimated gas reserves of60Tcf, is one of the largest and oldest gasfields in Turkmenistan. The South Yolotan

area in the eastern region of Turkmenistanalso contains significant gas reserves.

Turkmenistan produced 2.274Tcf ofnatural gas in 2012. Turkmengaz, one of thefive state-run companies for exploration,development, production and distribution ofhydrocarbon resources in the country, isresponsible for gas production. Russia is thekey export market for Turkmenistan naturalgas. CNPC of China is the only foreigncompany directly operating in Turkmenistanwith its involvement in Bagtyiarlyk projectnear the Amu Darya River.

United States of America

The United States ranks as the fifthlargest, holding 334.07 Tcf of proven naturalgas as of January 2013. The nation’s provengas reserves have steadily increased since1999 with the expansion of exploration anddevelopment activities in its shale formations.

The Barnett play located in Texas andMontana, Haynesville play in the Texas-Louisiana Salt Basin, Marcellus Shale playin the Appalachian Basin, Fayetteville play,Woodford play in Oklahoma and Texas andthe Eagle Ford play, in the Western GulfBasin of South Texas, are the major shaleplays contributing to the country’s natural gasexpansions. Barnett is the largest shale gasreserve in the nation. Other natural gasreserves in the country include the AntrimShale in Michigan, Caney Shale inOklahoma, Conesauga Shale in Alabama,Granite Wash Play in Texas and Oklahomaand the onshore and offshore Gulf of Mexicobasin.

The US is currently the world’s largestproducer and consumer of natural gas. Itproduced 24.06Tcf of natural gas andconsumed 25.5Tcf of natural gas in 2012. The

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country had more than 210 natural gaspipeline systems as of 2012. The interstateand intrastate transmission pipelines exceed305,000 miles (490,850km) in length.

Saudi Arabia

Saudi Arabia holds the sixth largestnatural gas reserves in the world. I tsestimated proven natural gas reserves as ofDecember 2012 stood at 290Tcf, includingits share of gas reserves in the Saudi-KuwaitNeutral Zone.

Associated gas at the giant oil fields,such as the Ghawar onshore field and theoffshore fields Safaniya and Zuluf, accountfor about 57% of the country’s proven gasreserves. The Ghawar field alone accountsfor more than 30% of Saudi Arabia’s provengas reserves. Karan gas field, which cameonline in 2011, is the first offshore non-associated gas field to be developed in SaudiArabia. Other major non-associated gasfields under development are the Arabiyahand Hasbah gas fields.

Gross natural gas production in SaudiArabia in 2012 stood at 3.927Tcf. The countrydoes not import or export natural gas. Itsentire gas output is consumed domestically.The state-owned Saudi Aramco isresponsible for gas production in the country.The company has partnered with foreigncompanies such as Lukoil, Sinopec, Eni andRespol for exploring non-associated onshoregas resources especially in Rub al-Khali, theworld’s largest sand desert.

United Arab Emirates

The United Arab Emirates (UAE) hasthe seventh biggest gas reserves in theworld. The country’s proven natural gasreserves as of December 2012 wereestimated at 215.1Tcf. Despite the vast gas

reserves the country imports natural gas,primarily from Qatar. The UAE imported 616billion cubic feet of gas in 2011. Around 30%of UAE’s gas output is re-injected into oilfields. The power sector of the country toouses natural gas as a major feedstock.

About 94% of the country’s provennatural gas reserves are located in AbuDhabi. Sharjah and Dubai account for fourpercent and 1.5% of UAE’s total gas reservesrespectively. The development andprocessing of the UAE’s gas reserves areeconomically challenging as most of thecountry’s natural gas has relatively highsulphur content.

The UAE’s gross natural gas productionin 2012 stood at 3Tcf. Individual emiratesmanage gas production in their respectiveterritories. ADNOC, through its subsidiariesADCO and ADMA-OPCO, carr ies outexploration and production of gas resourcesin Abu Dhabi. The Abu Dhabi Gas Industries(GASCO), a joint venture between ADNOC,Shell, Total and Partex, is responsible forprocessing onshore natural gas in thecountry. Abu Dhabi Gas Liquefact ion(ADGAS) manages the production and exportof liquefied natural gas (LNG) and liquefiedpetroleum gas (LPG).

Venezuela

Venezuela, the world’s biggest oilreserves holding country, possesses theeighth largest gas reserve. The provennatural gas reserves of the country wereestimated at 195Tcf as of December 2012.Associated gas accounts for nearly 90% ofVenezuela’s natural gas reserves. Thecountry plans to increase its natural gasproduction up to 14 billion cubic feet per dayby 2015.

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The existing onshore fields such asAnaco, Barrancas and Yucal Place are beingdeveloped for increased gas production.PlataformaDeltana, Marsical Sucre andBlanquilla-Tortuga areas off the north-eastcoast of Venezuela, and the gas blocks inthe Gulf of Venezuela in the north-westernpart of the country are being developed withinvolvement of foreign companies includingTotal, Statoil, Chevron and Gazprom.

The country produced 1.137Tcf ofnatural gas in 2012. A large share of thecountry’s gas output is re-injected into theoil fields for better crude oil extraction.Venezuela currently imports gas fromColombia and the US in order to meet itsgrowing industrial demand.

Nigeria

Nigeria holds the ninth largest gasreserves in the world. The largest oi lproducing African country was estimated tocontain 182Tcf of proven natural gas reservesas of December 2012. Most of natural gasreserves of the country are located in theNiger Delta. Nigeria produced 1.525Tcf ofnatural gas in 2012.

Amenam-Kpono, Bonga and Akpo arethe major oil and gas fields located in NigerDelta. Gbaran-Ubie, one of the latestintegrated oil and gas projects in the country,achieved peak production of one billion cubicfeet per day in 2011. Much of the country’snatural gas is flared since most of the oilfields lack the infrastructure to produce andmarket associated natural gas.

Shell is the leading gas producer in thecountry. I t ’s Soku gas-gathering andcondensate plant provides nearly half of thefeed gas to the only LNG facility of Nigeria.

Total, Eni and Chevron are among the othermajor foreign companies involved in Nigeriangas production. The Nigerian Gas Company(NGC), a subsidiary of Nigerian NationalPetroleum Corporat ion (NNPC), isresponsible for the marketing, transmissionand distribution of gas. Most of Nigeria’smarketed natural gas is exported as LNG.

Algeria

Algeria’s gas reserves rank as the tenthbiggest in the world. It is also the largest gasproducing country in Africa. The provennatural gas reserves of the country wereestimated at 159.1Tcf as of December 2012.Algeria’s gas production has, however,declined in the recent years with the depletionof some of its mature gas fields.

More than half of Algeria’s provennatural gas reserves are contained in thecountry’s largest gas field, HassiR’Mel.Associated and non-associated fields in thesouth and south-east regions of the countrycomprise the remaining gas reserves of thecountry. RhourdeNouss, Alrar and Hamra areamong the other largest mature gas fields inthe country.

The country produced 2.875Tcf ofnatural gas in 2012. Sonatrach is the leadinggas producing company in the country. Othercompanies involved in gas production inAlgeria include Eni, BP, Repsol, GDF Suezand the BG Group. A host of new gas projectsincluding GassiTouil, In SalahExpansion,Reggane Nord, Timimoun and Touat areunder development in the country.MenzelLedj imet East (MLE), whichcommenced production in 2013, is the latestgas project to be developed in the country.

(Source - http://www.hydrocarbons-technology.com/

features/feature-the-worlds-biggest-natural-gas-reserves)

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When natural gas is cooled to minus260 degrees Fahrenheit at a liquefactionfacility, the fuel condenses to roughly 1/600thof its original volume, facilitating overseastransport in specially designed ships. ARegasification terminals heat the liquefiednatural gas (LNG) to restore the deliveredvolumes to a gaseous state before pipelinestransmit the product to end-users.

This network of LNG carriers andimport and export terminals effectivelyreleases natural gas from the geographicalconstraints of the pipeline network, enablingproducers to deliver their output to overseasend-markets.

LNG accounted for about 32 percentof the global trade in natural gas in 2012,compared to 26 percent in 2005. At the sametime, LNG represents only 9.8 percent ofglobal gas consumption, making it a nichemarket.

Surveying the Supply Side

The build-out of LNG import and exportcapacity has accelerated over the past

WORLD LNG MARKETS

decade, with global shipments increasing atan average annual rate of about 13 percentbetween 2001 and 2011.

However, global LNG volumes havestagnated over the past two years, reflectinga lull in the completion of new liquefactioncapacity.

Of the two export terminals slated tocome onstream last year, only the long-delayed Angola LNG project commencedoperations; in Algeria, the start-up ofSonatrach’sSkikda liquefaction train slid from2013 to the end of January 2014.

Angola LNG, the US$10 billion facilityoperated by Chevron Corp. sent out its firstcargo in June, and then five more over thenext six months. But a deadly accidentinvolving a pipe-laying rig left the terminaloperating at 20 percent of its capacity in thefall. Management indicated that the operationwould ramp up to its nameplate capacity bythe end of 2014.

These limited capacity additions andhigher utilization rates at certainfacilities were offset by supplydisruptions in Nigeria and waningproduction in Egypt, where anunstable pol i t ical si tuat ion,reservoir issues and domesticdemand curtailed exports by 44percent.

At the end of 2013, 17exporting countries boasted of 86liquefaction trains, with a totalcapacity of 286 million metric tonsper annum (mmtpa).

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Source: BG Group, Global LNG Market Overview 2013-14

And the pipel ine of new projectsremains robust, with 15 new export projects(102.6 mmtpa, or 35 percent of existingcapacity) under construction at the start of2014.

Australia accounts for about 60 percentof this forthcoming liquefaction capacity, atrend that reflects the resource-rich nation’sproximity to China and other key demandcenters in Asia.

Oil and gas companies have alsoreached final investment decisions on threeprojects, with a combined 28 mmtpa ofproduction, bringing the total capacity ofconfirmed additions to 130.6 mmtpa.

Beyond these established projects,operators have announced 22 potentialliquefaction facilities that are in some phaseof front-end engineering and design((FEED)), the stage where the contractorconducts studies to address any technicalissues and estimate construction costs.

With a total liquefaction capacity of186.5 mmtpa, these FEED-stage projectswould eclipse widely-cited estimates that callfor the industry to construct another 135

mmtpa to 150 mmtpa through 2020 to meetanticipated demand growth.

Given the complexity and capitalintensity of building a liquefaction facility,announced projects that fail to secure long-term contracts - a prerequisite for financing- likely will fall by the wayside. This hurdlehelps to prevent overbuilding.

Meanwhile, the emergence of the USas a viable LNG exporter has raisedquestions about the feasibility of someproposed projects, and put pressure oninternational operators to lock up longer-termcontracts.

Many prospective US liquefactionschemes involve the addition of exportcapacity to existing import-only facilities,reducing construction costs relative toprojects in Australia and offshore East Africa.

And whereas the majority of existingLNG export facilities exploit a specific basin,US liquefaction sites would draw theirvolumes from a wide range of producers andbasins, reducing explorat ion anddevelopment risks.

15


Reliable supply and the prospect ofpricing indexed to Henry Hub natural gas -as opposed to Brent crude - holds significantappeal to countries that rely heavily on LNGto meet their energy needs.

After a prudent period of study, theObama administration in May 2013 ended themoratorium on approving LNG exports tocountries with which the US doesn’t have afree-trade agreement - a crucial componentfor most proposed terminals to move forward.

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The 37 LNG export applications that theDept. of Energy has approved or is in theprocess of reviewing include a contemplated38.56 billion cubic feet per day of capacity -equivalent to almost 55 percent of US naturalgas production and 90 percent of global LNGexports in 2013.

The US Dept. of Energy ostensibly willplay a role in picking the winners bydetermining which projects ultimately securepermits for exports to nations with which theUS lacks a free-trade agreement.

Thus far, the regulator has approved atotal of 10.9 billion cubic feet per day (83.5mmtpa) of export capacity for unrestrictedshipments, a volume that would propel theUS into the ranks of the top three LNGproducers.

The agency wil l consider eachapplication on an individual basis and weigh

the cumulat ive effect of previousauthorizations when granting approvals.Accordingly, the projects at the top of thereview list stand the best chance of gainingapproval.

Nevertheless, the markets ultimatelywill dictate which projects go ahead andwhich fall by the wayside.

Building natural gas liquefaction andexport facilities requires a significant capitalinvestment, especial ly greenfielddevelopments; the financial markets shouldfavor projects that have secured long-termcapacity reservation agreements fromcustomers.

The table below highlights the five USLNG export projects that have secured long-term supply agreements with potentialcustomers.

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Fortunately, the need for long-termcontracts to secure project financing shouldhelp to prevent the market from slipping intoan oversupply - barring a major shift indemand, akin to what happened when theUS shale gas revolution came into its own.

Surveying the Demand Side

On the demand side, 12 regasificationfacilities cameonstream last year, includingfive floating units - a less capital-intensivesolut ion that continues to gain favor,especial ly with countr ies that place apremium on flexibility.

These additions bring the number ofreceiving terminals to 104 and the totalcapacity to 721 mmtpa. The facilities arespread across 29 different nations.

Israel, Singapore and Malaysiareceived their first LNG volumes last year.Meanwhile, the current project slate suggeststhat Jordan, Egypt, Lithuania, Poland andUkraine could join the ranks of importers in2014.

Other countries that have announcedplans to develop LNG receiving facilitiesinclude Croatia, Finland, Ireland, Sweden,Bahrain, the Philippines, Sri Lanka, Vietnam,Colombia and Uruguay. If these proposalscome to fruition, the number of importingnations could reach 50 by the end of 2016.

Although the number of potential end-markets for LNG exporters continues toincrease, the Asia-Pacific region continuesto dominate the global market, accountingfor 75.1 percent of LNG volumes in 2013.

Japan and South Korea traditionallyhave accounted for the bulk ofglobal LNG demand. Not onlydoes a paucity of domestic energyresources force Japan and SouthKorea to rely on imports, butformidable geographic obstacles -the Pacif ic Ocean and NorthKorea, respectively - also preventthese nations from accessing thecontinental pipeline system.

This trend still holds: In 2013,Japan received about 88 millionmetric tons of LNG (37 percent ofthe global market), while SouthKorea’s imports increased by 9.8percent year-over-year to about 40million metric tons (17 percent).

However, China remains the primarygrowth driver on the demand side. TheMainland’s appetite for LNG cargos hasincreased dramatically in recent years,thanks to ongoing urbanization, r isinghousehold incomes and concerns about airquality.

To understand the outlook for the globalLNG market, we must consider the evolvingdynamics in these key markets and theirimplications for overall demand.

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China: Gassing Up

Over the past five years, MainlandChina’s consumption of natural gas hasgrown at an average annual rate of 22percent, reaching 16.4 billion cubic feet perday in 2013.

This trend should accelerate over thenext half-decade. The National Developmentand Reform Commission’s 12th five-year

plan calls for annual gas consumption to hit22.2 Bcf per day by the end of 2015. To meetthis goal, Chinese demand would need toexpand by 17.5 percent in each of the nexttwo years.

And PetroChina est imates thatd o m e s t i cconsumption ofnatural gas wi l lexpand to 38 Bcf perday by 2020, implyingan average annualincrease of 19percent over the nextseven years.

M a s s i v einvestments inpipeline, generationand l iquefact ioncapacity will abet thisupsurge in theMainland’s gas

consumption. Based on planned projects,China’s network of gas pipelines will grow tomore than 90,000 kilometers from about

19


50,000 kilometers in 2012. Meanwhile, thecountry also continues to build out powerplants to burn thermal fuel supplied by thesepipelines.

Although China’s upstream operatorshave expanded production of natural gassignificantly over the past decade, domesticsupply has failed to keep pace with the rapidincrease in consumption.

Despite the government’s commitmentto developing the Mainland’s shale gasresources and growing domestic output,policymakers also expect imported naturalgas to play an important role in meeting risingdemand.

Not only is natural gas subject to alower value-added tax than crude oil, but theMinistry of Finance also instituted a tax rebate(relative to a benchmark) on losses from gasimports via pipeline and LNG terminals.

China’s LNG imports have quadrupledover the past five years and climbed to about18 mmtpa in 2013 - an increase of 27 percent.

China’s growing demand for natural gashinges on two factors: rising domestic

demand for supplies, and the expansion ofLNG import terminals.

At present, the country boasts 10operational regasification units, with a totalcapacity of 32.2 mmtpa, which implies autilization rate of about 56 percent last year.

The Mainland’s LNG import terminalsdon’t operate at nameplate capacitythroughout the year; imports usually increasein the fall, when customers prepare for peakdemand during the winter heating seasonand turn to the spot market for cargoes.

China’s three national oil companieshave six additional projects (17.1 mmtpa)under construction, suggesting that domesticconsumption will continue to grow in comingyears. And this list of potential projectsexcludes potential expansions to existingfacilities.

Although crit ics question whetherpotential pipeline imports from Russia andCentral Asia and domestic shale gasproduction could curb China’s appetite forLNG, the equity interests that the country’sstate-owned oil companies have taken in

Australian and East Africanexport concerns imply anongoing reliance on imports.

Assuming that natural gaswil l grow to 9 percent ofChina’s energy consumption,global gas giant BG Group’s base scenario - which factorsin additional pipeline suppliesand domestic production -projects that the nation’s LNGdemand wil l expand to 65mmtpa by 2025. This outlookimplies average annual growthof 23.7 percent.

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Japan

Japan accounts for 37 percent of theglobal LNG market, and remains the world’sleading importer by a wide margin.

Over the past decade, the country hasprovided a source of steady demand growth,posting larger jumps in imports whenever aslug of new l iquefact ion capacitycomesonstream.

However, the sudden surge in thenation’s LNG imports in 2011 had nothing todo with the addit ion of l iquefaction orregasification capacity.

In spring 2011, the magnitude-9.0earthquake and resultant tsunami thatdevastated Japan’s Tohuku region andcrippled the Fukushima Daiichi nuclear powerplant prompted authorities to temporarily

21


shutter the bulk of the nation’s nuclearreactors.

Two of Japan’s nuclear power plantsresumed operation, but all of the nation’s 48reactors have remained offline since the No.

3 and No. 4 reactors at Kensai ElectricPower’s Oi plant closed for maintenance inSeptember 2013.

To offset the loss of about 30 percentof Japan’s baseload power, the country’s 10

22


largest electric utilities have stepped up theirconsumption of coal, heavy fuel oil and LNG.

With Japan’s LNG imports surgingunexpectedly in 2011 and growing further in2012, the so-called Fukushima effect hasintensified competition for volumes in the spot

market and elevated prices to levels thatincentivize producers and traders to redirectvolumes from Europe to Asia.

This inflection point is clear when youcompare the recent price histories of naturalgas at the Henry Hub in the US, the UK

23


National Balancing Point and the averageprice that Japan pays for its liquefied naturalgas.

For example, LNG imports to Europein 2013 declined for the second consecutiveyear, tumbling by 28.5 percent and sinkingto their lowest level since 2005. The pricecompetitiveness of coal-fired power plantsand the Continent’s ongoing economicmalaise ensured that Europe once againserved as the source of swing volumes tomeet Asia’s robust demand.

If we compare Japan’s LNG imports tothe volumes covered by existing contracts ina given year, we can approximate the extentof the nation’s activity in the spot market fornatural gas. (This rough calculation assumesthat Japanese importers received all theiragreed-upon LNG shipments, and doesn’taccount for any potential supply disruptionsor shortfalls).

Japan’s LNG imports fell short ofcontracted volumes in 2009 and 2010,reflecting reduced demand during the globaleconomic downturn. However, the gapbetween the nation’s contracted LNGvolumes and total imports widened to 17.39million metric tons in 2012 - almost 3 times2008 levels and 11.3 percent of the Asia-Pacific market.

The question looming over the LNGmarket: When will Japan’s shuttered nuclearreactors come onstream, and how many willbe in operation?

Only nuclear power plants deemed safeafter a rigorous inspection by the NuclearRegulatory Authority will be allowed to restart.

The government has also indicated thatnuclear power plants must bedecommissioned after 40 years of operation,

and has instituted a ban on the constructionof new nuclear reactors and the expansionof existing facilities.

On April 11, 2014, Japan’s cabinetapproved an energy policy reversing theprevious government’s plans to shutternuclear power plants gradually.

However, the document didn’t set atarget for nuclear power’s contribution to thenation’s energy mix, and questions remainabout exactly how many of the nation’s 48reactors will return to service.

Based on questionnaires andinterviews with industry experts andcomments from Japan’s 10 plantoperators, Reuters earlier this year estimatedthat Japan would restart about 14 of itsreactors, and pegged another 17 as likelyclosed forever. The jury is out on theremaining 17 units.

Although the timing and magnitude ofreactor restarts remains uncertain, thesedecisions and long-term policies regardingthe country’s energy mix will hold significantramifications for international LNG prices inthe next few years and global demand in thelong term.

Japan’s utilities have already reducedtheir consumption of crude oil and heavy fueloil - the most expensive feedstock forelectricity generation - by ramping up theircoal consumption.

Although short on details, Japan’s planto restart some of its nuclear reactors servesas a reminder that too many industryobservers conveniently take the prevailingabnormal supply-demand picture for grantedin their assessment of international LNGmarkets.

(Source: www.nasdaq.com)

24


On 18 October 2014, the Governmentof India approved the revision of domesticgas price. The new price is a volumeweighted average of Henry Hub, NBP, Albertahub and Russia gas price. Under the newprice scheme, domestic gas price will be$5.61/MMBtu from 1 November 2014 to 31March 2015. This represents an increase of50% from US$3.8/MMBtu (Gross CalorificValue) and will be revised every six months.In this executive brief, Enerdata analyses thedomestic gas market situation in India andprovides i ts opinion on the possibleimplications of the gas price increase.

The increase in gas price has come asa huge relief to the upstream players likeONGC and Oil India. Government estimatesthat 80% of the additional revenue will go togovernment owned companies. Natural gaswas losing its market share in India due toexpensive LNG imports and lack of domesticsupply. The discovery of Krishna Godavari

IMPLICATIONS OF THE GAS PRICEINCREASE IN INDIA

field (KG-D6) by Reliance in 2002 hadincreased the hope of transforming thenatural gas industry in India. However,production started falling after reaching apeak of 57 mmscm/d in 2010. The expectedpeak production was 80 mmscm/d.

The announced price reforms are notapplicable to the KG-D6 field. Relianceclaims that technical problems led to a fall inproduction from KG-D6. The arbitrationrelated to the aspect of shortfall in productionis still unsettled. Reliance will be paid $4.2/MMbtu until the legal outcome of the legalproceedings. At its peak production in 2010,KG-D6 accounted for 40% of total domesticgas production in 2010.

Figure 1 shows the dependency ofIndia’s natural gas market on LNG imports.Import dependency, which is measured bythe ratio of imported volumes and totalconsumption, increased from 1% in 2003 to

Source: Enerdata, Global Energy and CO2 Data

Figure 1: Import dependency of Natural Gas and LNG import price in India

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26% in 2007. It decreased in 2008 due tolower gas consumption as a result of theeconomic recession. Natural gas productionsoared in 2009 and 2010 due to contributionfrom KG-D6 basin and led to a fall in importdependency. However, since 2011, the importdependency is rising constantly due to lowerthan expected production from the KG-D6basin. At the same time, the average priceof LNG imports in India increased fromaround $4/MMBtu in 2010 to $8.5/MMBtu in2013 undermining the competitiveness ofnatural gas against other fuels like coal.

Problems in domestic productioncoupled with increase in prices have weigheddown on the gas consumption in India, whichdecreased by 30% from 2010 to 2013whereas the coal consumption has increasedby 10% in the same period (Figure 2). Theshare of natural gas in the total primaryenergy consumption decreased from 7% in2010 to 5% in 2013.

Natural Gas R/P ratio fell from 33.5%to 22% from 2008 to 2010 due to increasedproduction but then rose again to 42% in2013 without any major discoveries. Therevision in gas price policy will certainly givea boost to exploration and productionactivities. Fuel price reforms are expected tobring in more investments in the gas sector.

However, the gas price policy still doesnot consider the domestic supply anddemand fundamentals in India. The earliergas price revision proposed in 2013 alsomade similar compromises on economicreasoning. Linking domestic gas prices toother markets in U.S, Mexico, Canada,European Union, FSU and Russia as shownin equation 1 is very unlikely be a long-termsolution. Deregulated gas prices shouldreflect the domestic supply and demandsituation.

Equation 1: Proposed domestic gasprice in India to be effective from 1November 2014

Source: Enerdata, Global Energy and CO2 Data

Figure 2: Share of different fossil fuels in total primary energy consumption in India

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Pgas =VHH*PHH + VAC*PAC+VNBP*PNBP+VR*PR

VHH+VAC+VNBP+VR

Where :

Pgas, PHH, PAC, PNBP and PR is theproposed price of domestic gas, annualaverage of daily Henry Hub, annualaverage of daily NBP, annual average ofmonthly Alberta hub and Russia.

VHH, VAC, VNBP and VR is the volume ofgas consumed in USA & Mexico,Canada, EU & FSU excluding Russiaand Russia.

The data used will be trailing fourquarter with one quarter lag.

Source: Press Information Bureau, Government of India

Furthermore, the price elasticity of gasdemand is high in India which makes itdifficult to raise end user gas prices withoutfacing political and social pressures. Facedwith gas shortages, government made powerand fertilizer as the priority sectors for theallocation of gas produced. Power plantsconsumed around 28% of the total gas in2013 whereas the fertilizer sector consumedaround 31% of the total gas in India. Of thetotal gas volumes consumed in power andfertilizer, imported LNG accounted for around19% share in 2013.

The total installed gas based powercapacity in India is 23.8 GW with 15.9 GWplanned and 10.6 GW under construction atthe end of 2013. Gas-fired power generationdecreased by 12.5% from 2012 to 2013. Fuelprice accounts for the majority share of thelevelized cost of electricity generation(LCOE). We estimate that a 50% increase ingas price can have a 24-26% increase in theLCOE which can defer the investmentdecisions in gas power plants if appropriateincentives are not in place. If passed to end

users, an increase of 25% in LCOE of gaspower plants results in increase of aroundUS$1.4c/kWh. Comparing this to 2012electricity prices, this represents a significantincrease: the average electricity prices wereUS$9.7c/KWh for industry and US$4.5c/KWhfor households. Hence, it will be difficult forgovernment to allow an immediate cost passthrough to electricity end users.

Natural gas accounts for 65%-70% of thefertilizer total cost of production in India. Oneton (t) of fertilizer production can consumearound 900 cubic meters (cm) of natural gas.An increase of US$2/MMbtu in gas prices willincrease the cost of production by aroundUS$64/t of fertilizer. Urea based fertilizer inIndia are sold at a maximum retail price (MRP)of US$90/t1 and government subsidizes thedifference between MRP and actual cost ofproduction.

Under the new price regime, there is noclear guideline on the end-user pricemechanism. One potential outcome would bethat the government will not pass all the priceincrease to the end-users immediately andEnerdata estimates that potential additionalannual subsidies will be around US$2bn whichis around 0.013% of India’s GDP in 2013. Thesubsidies will be used to maintain the powerand fertilizer industries competitive and then inthe long term the additional costs will be passedto the end-users. In summary, Enerdata expectsthat the indigenous gas price increase willattract additional investors in the energyupstream sector and at the same time theIndian government should be able to absorbthe additional end-users costs by providingtemporary subsidizes.

Notes:

1 Department of Fertilizers, Ministry ofChemicals and Fertilizers, Govt. of India. http://fert.nic.in/page/fertilizer-policy

(Souce :Enerdata)

27


Policy Progress of JNNSM

After growing at a disappointing rate ofless than 1 GW per year during the last twoyears, India’s solar sector is staring at thepossibility of growing exponentially, or morespecifically, reach 100 GW installed capacityin the next five years (till 2019). The newgovernment, led by Prime Minister NarendraModi, is drafting the plan to achieve the 100GW capacity. As a first step, the Ministry forNew and Renewable Energy (MNRE) hasalready released the draft guidelines forachieving a capacity of 20 GW through SolarParks in various states across the country.

Background

The Jawaharlal Nehru National SolarMission (JNNSM), launched in 2010, had seta target of 22 GW of Solar capacity (20 GWof grid-connected systems and 2 GW of off-grid systems) by 2022. The targets were setat a time when the capital cost of solarsystems were quite high (around Rs. 18Crores/MW). The cost of solar systems hassince then gone down by more than 50%,and today, it costs around Rs. 7 to 8 Crores/MW.

The implementation of the JNNSM wasdivided into 3 phases, (1,000 MW in Phase1 up to 2012-2013, 9,000 MW in Phase 2during 2013-2017 and 10,000 MW in Phase3 during 2017-2022).

Status of Phase 1 of the JNNSM

The Phase 1 of the Mission wasimplemented in 2 batches. In the first batch,150 MW of PV (30 projects of 5 MW capacityeach) and 470 MW (7 projects of varying

RENEWABLE ENERGY UPDATEScapacities) of Solar Thermal (CSP) projectswere selected through a tariff based reversebidding process. The tariff range for theselected solar PV projects was Rs. 10.95/kWh-Rs.12.76/kWh. For the CSP projects,the range was Rs. 10.49/kWh-Rs. 12.24/kWh. The average tariffs were Rs. 12.12/kWh for PV and Rs. 11.48/kWh for CSPprojects.

Apart from this, 98.5 MW (78 projects)were allotted under the Rooftop PV and SmallSolar Power Generation Programme(RPSSGP) and another 84 MW (PV-54 MWand CSP-30 MW) were selected undermigration scheme.

In the second batch, 350 MW of solarPV projects were selected based on thereverse bidding process, and the tariff rangewas Rs. 7.49/kWh-Rs.9.44/kWh, with theaverage tariff being Rs. 8.77/kWh.

During the Phase 1 of the JNNSM,there was a Domestic Content Requirement(DCR) for Crystalline Silicon Modules, whichmandated the use of Indian made modulesfor the Batch 1 SPV projects, and both cellsand modules for the Batch 2 projects. Allprojects using Thin Film technology basedPV modules were exempted from the DCR.

According to the MNRE, a total capacityof 568 MW has been commissioned so farunder Phase-1, excluding the projects underRPSSGP.

Status of Phase 2 of the JNNSM

The Phase 2 of the JNNSM spans aperiod of 5 years (2013-17), and the originaltarget for this Phase was 9,000 MW. This

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phase is also being implemented in batches,and the allocation of 750 MW of projectsunder Batch 1 of this Phase was completedin March 2014. The projects will be supportedthrough a Viability Gap Funding (VGF)mechanism, with the funds coming from theNational Clean Energy Fund (NCEF). Underthe VGF mechanism, power would bepurchased from developers at a fixed tariffof Rs.5.45/ unit (Rs.4.95/unit in case benefitof Accelerated Depreciation is availed) andVGF will be paid to the developers as pertheir bids, up to a maximum of Rs.2.5 crore/MW).

In this batch, 50% of the total availablecapacity of 750 MW was reserved for projectsusing Indian made modules and theremaining 375 MW projects did not have theDCR. Power Purchase Agreements (PPAs)with the successful bidders were signed inMarch 2014, and the projects have 13 monthsfrom the date of signing of the PPA tocommission the projects.

Batch 2 of Phase 2

MNRE has proposed to add 15 GW ofSolar PV Capacity during the Phase 2 of theMission in 3 tranches till 2019. The plannedallocation under the 3 tranches is 3 GWduring 2014-2017, 5 GW during 2015-2018and 7 GW during 2016-2019. Many of theseprojects will be allocated in solar parks invarious states highlighted at the beginningof the article.

The way forward

As mentioned earlier, the governmentis proposing to drastically increase the solarinstallation targets to 100 GW by 2019. Thistarget is very ambitious considering the factthat today, the total solar installed capacityin the country is just 2,765 MW (as ofSeptember, 30 - 2014). In order to achievethe ambitious goal, it is hoped that thegovernment will work together with thestakeholders in overcoming all technical,manufacturing capacity, infrastructural, policyand financial challenges.

(Source: Intersolar.in)

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One of the first major solar relatedpol icy announcements from the newgovernment headed by Mr. Narendra Modihas been on Solar parks. Earl ier inSeptember 2014, the Ministry of New andRenewable Energy (MNRE) released a draftscheme for development of Solar Parks andUltra Mega Solar Power projects across thecountry. Mr. Narendra Modi, under whomGujarat became the first state to implementa state level solar policy starting in 2009-10,was also instrumental in successful lydeveloping Asia’s first multi-developer solarpark at Charanka in Gujarat.

The idea of setting up large scale solarpower plants in the wastelands of variousparts of the country was first put in motion inNovember 2013 by the previous government.The MNRE had then announced that it wasplanning 5 Ultra Mega Solar Projects (UMSP)to be set up mostly in the wastelands ofRajasthan, Gujarat and Ladakh region ofJammu & Kashmir. The projects were toproposed in Sambhar, Rajasthan (4 GW),Bhadla Solar Park, Rajasthan (3 GW),Kharaghoda, Gujarat (Solar/Wind EnergyPark with 4 GW solar power capacity and 700MW of wind power systems) and Ladakhregion (two plants of capacity 2 GW and 5GW). One of the parks – Bhadla Solar Park– in Rajasthan was already underdevelopment, and the work for plant inSambhar was also initiated. The Jammu andKashmir government also had also signed anMemorandum of Understanding (MOU) withthe MNRE in March 2014 for implementationof solar projects of the capacity of 7,500 MW(more here).

SOLAR PARKS – THE FUTURE?

Prime Minister Mr. Modi’s governmenthas decided to expand the scope of Solar Parksand Ultra Mega Solar projects and the draftscheme released by the MNRE proposessetting up 25 solar parks, each with a capacityof 500 to 1,000 MW. If the scheme isimplemented properly, 20 GW of solar capacitywill be added in the next five years from thesesolar parks alone. The learnings from thesuccess of “Charanka Solar Park” in Gujaratwill be valuable in executing these projectswithout much hassles.

Charanka Solar Park, Gujarat

Spread over close to 5,500 acres ofunused land in the District of Patan in Gujarat,“Charanka Solar Park” was developed byGujarat Power Corporation Ltd (GPCL) underthe state government’s solar policy. Theestimated capacity of the plant is 590 MW, andaccording to GPCL, a total of 224 MW has sofar been commissioned by 20 developers. Mostof the projects were commissioned during thefirst half of 2012. The park also has the capacityto generate 100 MW of Wind Power and twowindmills of 2.1 MW have already beencommissioned in the park, and is considered agood model for solar-wind hybrid Park (Source:www.gpclindia.com )

The major advantage of such centralizedparks is the common infrastructure. The“Charanka Solar Park” has commoninfrastructure like

1. Roads

2. Water pipelines, common water storagefacilities and waste water treatmentfacilities

30


3. Evacuation infrastructure

4. Telecom network

5. Fencing and compound walls

6. Security

The land for Charanka Solar Park wasacquired, developed (completion of landlevelling and grading) and the commoninfrastructure created by the governmentagencies at a cost of Rs. 4,500 Crores.

(Source: GPCL).

Replicating the “Charanka” Model

The proposed programme of MNREhighlights the success of Charanka SolarPark and “Bhadla” solar park in Rajasthan,and aims to emulate the success of theseparks. Some of the advantages cited byMNRE for setting up large scale solar parksare

1. “Individual projects of smaller capacityincur signif icant expenses in sitedevelopment, drawing separatetransmission l ines to nearestsubstation, procuring water and increation of other necessaryinfrastructure.”

2. “I t takes a long t ime for projectdevelopers to acquire land, get changeof land use and various permissions,etc. which delays the project.”

“The solar park is a concentrated zoneof development of solar power generationprojects, by providing to developers an areathat is well characterized, properly infra-structured and where the risk of the projectscan be minimized as well as the facilitationof the permitting process.”

There are several stakeholders who areagainst the concept of centralized solar

power generation, and advocate in-situ powergeneration and consumption in the form ofdistributed generation (rooftop solar PV, off-grid PV or solar microgrids) The oppositiontowards such massive concentrated solarpower generation are on two counts – one isa philosophical argument that solar isavailable everywhere, and by its very nature,harnessing of solar power should bedecentralized. But a second and biggerargument against central ized solargeneration relates to the high Transmission& Distribution (T&D) that are inherent to utilityscale solar projects, especially when they arelocated in remote locations far away from thedemand centres. However, in a country likeIndia where power deficit is so high, bothmassive solar parks, and small rooftop PVsystems can easily co-exist if the rightincentives are provided.

Conclusion

Given the huge power deficit faced byIndia, and the recent challenges to coalsupply as a result of legal issues, it is veryimportant for the government to scale up thesolar sector in India. The massive expansionof capacity addition targets proposed by theMNRE can be achieved only by such mega-projects. The success of the scheme,however, will to a large extend depend onthe intentions and the efforts of the stategovernments.

(Source: Intersolar.in)

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After Tamil Nadu and Maharashtra, newerstates like Rajasthan, Madhya Pradesh andAndhra Pradesh are coming up as favorabledestinations for wind power, driven by attractivepolicies and high tariffs.

According to data from the Indian WindTurbine Manufacturers Association, in the firsthalf of financial year 2014-15, capacity additionsin states like Rajasthan have gone up to 108megawatt (MW) from 35 MW last year, whileMadhya Pradesh saw 94 MW of capacity in2014 from no capacity being added during thesame period in 2013, while a traditionally strongstate Maharashtra saw a sharp fall in newwindmill additions due to policy uncertainties.

“Rajasthan and Madhya Pradesh will bethe new top states next year. Tariffs are goodand policies are easy in the states and a lot ofcompanies are going there,” Sunil Jain,president of Wind Independent PowerProducers Association (WIPPA) and CEO ofHero Future Energies, said. Rajasthan andMadhya Pradesh offer tariffs of Rs 5.64 andRs 5.92, a higher than Andhra Pradesh offeringRs 4.71, Tamil Nadu’s Rs 3.51 and Rs.4.20 inKarnataka.

Andhra Pradesh and Karnataka have alsoseen an increase in capacity additions in thelast six months. While these are primarilybecause of orders booked last year, things arelooking up in the states. “Andhra Pradesh isdoing a lot for renewable energy, planning 500MW each of wind and solar power by next year,so we expect positive revisions of tariffs, andthere will be a lot of capacity coming in there”an official from a wind turbine manufacturing

NEW STATES ON INDIA’S WINDPOWER MAP

company said. Karnataka too is doing well, withseveral companies looking to put up windmillsfor tax saving under the accelerateddepreciation scheme where companies get towrite off 80% of the project costs asdepreciation in the first year to save taxes.Going forward too, improvements in technologywill allow wind turbines to operate well even inareas where wind flow is not very high,companies say.

“It is good that many new states areemerging as destinations for wind farms andwind energy is spreading from beingconcentrated in just Tamil Nadu andMaharashtra, but it is equally important that thenew states prepare in advance to manage thetransmission requirements, and handle gridintegration of these resources,” VineethVijayaraghavan, an industry expert said.

The traditional wind power strongholds -Tamil Nadu and Maharashtra - are losing flavor.New installations in Maharashtra fell sharplyfrom 426 MW between April and September2013 to 88 MW this year.

“Companies found it very difficult last yearas there were uncertainties on signing powerpurchase agreements (PPAs) with the stateutility, transmission issues and problems withland acquisitions. So, not many companies willtake the risk again,” Jain of WIPPA said.In TamilNadu, while installation numbers show anincrease in capacity additions in Tamil Nadu,they are projects planned earlier being executednow, and no new orders have been booked inthe state in the last six months due to low tariffsand issues of transmission.

(Source : Times of India, November 2014)

32


ENERGY & FUEL USERS’ ASSOCIATION OF INDIAOFFICE-BEARERS’ ADDRESSES - 2014 - 2015

1. Mr.S.Ramalingam, CMD, CPCL (Retd.), National President 96770 11766Anand Apartments, 262/11 Poonamallee High Road,Kilpauk, CHENNAI-600 010.Email: [email protected] / [email protected]

2. Mr. K.Sadasiva Chetty, Vice President-HQ 98410 46289G-4, Ground Floor, Kala Flats,New No.15, Old No.18/19, Kamatchipuram 2nd Street,West mambalam, CHENNAI - 600 033.Email : [email protected] / [email protected]

3. Mr.R.Sundar, Director of Boilers, Vice President – 94430 01763North Wing, PWD Office Compound,1st Floor, Southern RegionChepauk, CHENNAI-600 005. Email:[email protected]

4. Mr. Ramnath S. Mani, Chairman Vice-President – 98400 62118Emergys Software Pvt. Ltd. Eastern RegionAuras Corporate Centre, 4th Floor,98-A Dr Radhakrishnan Salai, Mylapore,CHENNAI-600 004. Email: [email protected]

5. Capt. Dinesh .T.S.R, Director, Secretary 98842 03213Praddin Energy Pvt. Ltd., No.4, N.S.K. Street,Eswaran Nagar, Pammal, CHENNAI-600 075.Email: [email protected]

6. Mr. S.Sakthivel, Deputy Director of Boilers, Treasurer 94431 49993A5/1, BHEL Quarters, Kailasapuram, TRICHY-620 014.Email: [email protected] / [email protected]

7. Mr. Pradeep Chand KRD Joint Secretary 94455 76307Senior Manager (Shift Operations),Chennai Petroleum Corporation Ltd.Manali, CHENNAI - 600 068.Email: [email protected] / [email protected]

8. Mr. S.Jeyaram, CEO, Joint Secretary 97910 20132Six Elements Environmental ConsultingSuite No.49, 3rd Floor, Real Regency Complex,Old No.102, New No.234, Bharathi Road, Royapettah,CHENNAI-600 014. Email: [email protected]

9. Mr. Madhavan Nampoothiri, Founder & Director Chairman - 98848 29214RESolve Energy Consultants, New No.7, New Renewable EnergyMalleeswarar Koil Street,. Mylapore, Chennai-600 004.Email: [email protected]

10. Mr. R.Raju Pandi Chairman-Power 93827 40069Flat No.9, 3rd Floor, Hemamanor, Generation Sector23 Branson Garden Street, Kelly’s, CHENNAI-600 010.Email: [email protected]

11. Mr.S.Baskara Sethupathy, Assistant Professor, Chairman – 94456 33381Vellammal Engineering College, Vellammal Nagar, Academic interfaceAmbattur, Redhills Road, Chennai-600 066.Fax: 91-44-26591771, Email:[email protected]

33


12. Dr. A.Rajakumar, 3/25 A-II Mahalakshmi Flats, Editor/Member 99412 51640Abdul Razaak Street, Saidapet, CHENNAI-600 015.Email: [email protected]

13. Mr. K.R.Govindan, New No.22 Janakiram Street, Task Group Member 94443 82649West Mambalam, CHENNAI-600 033.Email: [email protected]

14. Mr. B.Sreerama Sreenivasu, Coordinator - Pune 099701 94339Flat No.603, Block D-2,Mahalaxmi Vihar, Vishrantwadi, Pune-411 015,MAHARASHTRA, Email: [email protected]

15. Mr.G.L. Srinivasan, Member / 94449 07738New No.6/2, Old No.17/2, Immediate Past PresidentRaghu Veda Apartments, Jagdeeswaran Street,T.Nagar, CHENNAI-600 017. Email:[email protected]

16. Mr.Govindasamy Thangaraj, Member / 98402 6197881, South West Boag Road, T.Nagar, CHENNAI-600 017. Past PresidentEmail: [email protected]

17. Mr.T. Ambalavanan, Member 98407 39858No.24, Block MIG 13, 3rd Loop Street,Kottur Gardens, Kotturpuram, CHENNAI-600 085.Email: [email protected]

18. Mr. T. Doraivel, No.5 First Street, Member 94441 85424East Abhiramapuram, CHENNAI-600 004.Email: [email protected]

19. Dr. K.S. Dhathathreyan Member 94442 91041T-1, Ragam Apartments, New No.2, First Avenue,Sastry Nagar, Adyar, CHENNAI-600 020.Email: [email protected] / [email protected]

20. Dr. Mrs. Hyacinth j . Kennady, HOD & Professor, Member 94448 98258Dept of Mech Engg, Hindustan University, P B No.1,Rajiv Gandhi Salai, Kelambakkam, CHENNAI-603103Email: [email protected]

21. Mr. Krishna Pillai, Managing DirectorCape Institute of Technology, 4-D, 4th Floor, Member 94431 26329Century Plaza, No.560-562, Anna Salai, Teynampet,CHENNAI-600 018. Email: [email protected]

22. Mr.C.E.Karunakaran, Member 93810 41615Flot No.2A, Madeleine CourtNew No.26, Old No.72 Spur Tank Road, Chetput,CHENNAI-600 031. Email: [email protected]

23. Mr. V.Kanniappan, President, Aban Offshore Ltd., Member 99403 40009Janpriya Crest, 113, Pantheon Road, Egmore,CHENNAI-600 008. Email: [email protected]

24. Dr. B.V.S.Lakshmi, Member 098481 99200G-2, 5-10-197/2, Hill Fort Road, Adarsh NagarHYDERABAD-500 004. Email: sreeramvasu@vsnl,net

34


25. Mr. S.Pandarinathan, G M (Dev), C P C L (Retd), Member 94443 90012#7, Nathamuni 2nd Cross Street, Naduvankarai, Anna Nagar,CHENNAI-600 040. Email: [email protected]

26. Mr. Pashupathy Gopalan, Managing Director Member 99406 70562Sunedison Energy India Pvt Ltd, Menon Etemity,10th Floor, New No.165, Old No.110 St Mary's Road,Alwarpet, CHENNAI-600 028. Email:[email protected]

27. Dr. A.Peer Fathima, Professor, School of Electrical Member 94440 22777Engineering (SELECT), VIT, ChennaiVandalur-Kelambakkam Road, CHENNAI-600 127..Email: [email protected] / [email protected]

28. Mr. S.R.Pradhish Kumaar, Director, Member 99401 50530Praddin Energy Pvt. Ltd., 0 I -A, Bakthani Building,First Street, Cenotaph Road, CHENNAI 600 018.Email: [email protected]

29. Mr. C. Rajesh Srinivasan, Project Manager, Member 92837 01460Cape Energy Pvt. Ltd., 4-D, 4th Floor, Century Plaza,No.560-562, Anna Salai, Teynampet, CHENNAI-600 018Email: [email protected]

30. Mr. R. Ravikumar, Director Technical ES MemberElectronics (India) Pvt. Ltd., 098441 36209Plot No.82, Kiadb Industrial Area, Bommasandra-Jigani Link Road, Jigani Hobli, Anekaltaluk,BANGALORE-560 105. Email:[email protected]

31. Capt. M.Singaraja, Ratnabala Designs & Consultants Member 94441 27704New No.90, Rama Naicken St., Nungambakkam,CHENNAI-600 034. Email: [email protected]

32. Mr. V.Siva Kumar, General Manager - Safety Member 098847 23766Health and Environment Indian Oil Corporation Ltd. 94440 62884Indian Oil Bhavan, 139, Nungambakkam High Road,CHENNAI-600 034.Email: [email protected] / [email protected]

33. Dr.A. Venkatraman, A19, Anna Nagar Main Road, Member 99427 62255ANNA NAGAR, TENNUR, TRICHY-620 017. 89399 92755Email: [email protected] / [email protected]

34. Mr. Vineeth Vijayaraghavan Member & AdvisorFounder-Editor, Panchabuta-Cleantech & RenewableEnergy in India, No.30 Sapthagiri Colony 1st Street,Jafferkhanpet, CHENNAI-600 083, Email:[email protected]

35. Mr. Vishwanathan (Vish) Iyer Member & Adviser 73030 94212Deputy General Manager - Solar BusinessWest & South India Sterling and Wilson Ltd.Associates of Shapoorji, Pallonji & Co. Ltd.Universal Majestic Building, 10th Floor, P.L.Lokhande MargChembur (W), MUMBAI-400 043.Email:[email protected]

35


ENERGY & FUEL USERS’ ASSOCIATION OF INDIACHENNAI - 600 034.

APPLICATION FOR ADMISSION

From

................................................................................

................................................................................

................................................................................

To

The Honerary SecretaryEnergy & Fuel User’s Association of India4, B-1, J.P. Tower, 7/2 Nungambakkam High Road,Chennai - 600 034.

Dear Sir,

I/We requested that I/We may be admitted as a (Please tick in appropriate box)

Life Member Member Individual Member Student

Our organisation falls under the following category (please tick whichever is applicable)

Manufacturer/Energy and Fuel Consumer/Academic Institution / Consultancy Services /Individual.

Our annual turn over in Rs......................... (Rupees............................................ only)

I/We send herewith a D.D. / Cheque for Rs.......................... being subscription for theyear together with the Entrance Fee of Rs.100/-

I/We agree to abide by all the rules and regulations of the Association as per itsconstitution, in force on the date on which our membership is accepted and any changes andamendments / alterations that may be made in the constitution by-laws thereafter.

Yours faithfully,

Signature

Name in Capital Letters

Designation

36


THE NATIONAL PRESIDENT&

THE MEMBERS OF THE EXECUTIVE COMMITTEE

WWWWWish the membersish the membersish the membersish the membersish the membersofofofofof

ENERGY & FUEL USERS’ ASSOCIATION OF INDIA

AAAAAProsperousProsperousProsperousProsperousProsperous

&&&&&Happy 2015Happy 2015Happy 2015Happy 2015Happy 2015Season’s Greetings

&Best Wishes

S. RamalingamS. RamalingamS. RamalingamS. RamalingamS. RamalingamNational President

37


ENFUSEENFUSEENFUSEENFUSEENFUSEVolume - LXIII Book - 4

October - December 2014

EDITORIAL BOARD

Associate Editor :

Dr. A. Rajakumar

Guest Editor :

Madhavan Nampoothiri

Advisors :

Dr. R. Natarajan

Mr. G. Thangaraj(Past President)

Dr. Sulaiman A. Alyahya

Members Ex-Officio:

Mr. S. Ramalingam, President

Capt. Dinesh .T.S.R, Secretary

Mr. S. Sakthivel, Treasurer

Mr. K.R.D.Pradeep Chand, Joint Secretary

Mr. S. Jeyaram, Joint Secretary

Members :

Mr. S. Baskara SethupathyChairman Academic Interface

Mr. R. Sundar, Vice President, Southern Region

Mr. G.L. Srinivasan, Imm. Past President

Mr. P. Mukundan, Chairman - Rural Energy

Publisher :

Mr. S. RamalingamHonorary PresidentEnergy & Fuel Users’ Association of India

Editorial-cum-Admn. Office :

No. 4, B-1, J.P. Tower7/2, Nungambakkam High Road,Chennai - 600 034. INDIAPhone : (091 - 044) 2827 8604e-mail : [email protected]

[email protected]

Printer :

EDITORIAL

As we enter the New Year 2015, the global energymarkets have been seeing massive changes in the form ofthe continued drop of crude oil prices and its impact onalmost every major global economy. The crude oil price dropis hurting most of the oil producers, and the oil importersare reaping the benefits. In other words, if the oil pricescontinue to be low, there will be a significant wealth transferfrom oil producers to oil importers.

In this issue of the journal, we examine some of thereasons for the oil price drop and its impact on India. It isexpected that the fall in prices will add trillions of dollars tothe Indian economy. Apart from that, the lower prices willmake it possible for the government to go ahead with theStrategic Crude Oil Reserve. Diesel prices have also beenfinally deregulated(though the benefit is not reaching thecustomers due to the increase in excise duties), and thesubsidies on LPG and Kerosene could be streamlined. Thebottom line is that as one of the major importers of oil, Indiastands to benefit immensely from the crude price drop.

We also continue our updates on fossils fuels – thistime Natural Gas. The different types of gaseous fuels, theenvironmental impact of Natural Gas, reserves and LNGmarkets are examined in detail. The impact of the naturalgas pricing in India is also looked at.

After a gap of a couple of editions, renewable energy isback in the journal. There are some updates on both solarand wind. As the government’s focus increasing shiftstowards renewables and ambitious targets being set, thefuture editions of ENFUSE journal will see more coverageof renewables.

Please feel free to share your suggestions and feedbackon the topics covered and the content in general.

On behalf of ENFUSE journal, I extend warm New YearGreetings and wishing all our readers a prosperous andsuccessful 2015!!

MADHAVAN NAMPOOTHIRI

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38


FROM THE PRESIDENT’S DESK

We are coming to very near the close of the year 2014and getting ourselves geared up to welcome the New year2015. I wish to convey on behalf of ENFUSE , Best Wishes tothe energy fraternity in the country for positive Energy Trendsto emerge in the decades to come in general, and moreparticularly in 2015..

Mr.William M. Colton, an executive at ExxonMobil, hasobserved at a recent presentation “People and progress driveenergy demand”. And if we ponder over this simple statement,we will understand how profound it is. Progress and populationare directly tied to energy. This is visible all throughout history.Without the development of coal to generate steam and steel,the Industrial Revolution never would’ve taken place. Thepeople of the world wouldn’t have seen progress on severalimportant fronts like poverty, health care, transportation, andfresh food and water. But since the development of this energyand the boom times of the 1800s and 1900s, we have seeneven more amazing advancements. Back then, the world’spopulation was at about 1 billion. Today, it’s exploding over 7billion. According to the Brookings Institute, the worldpopulation will be nearly 10 billion by 2030. What’s even moreshocking is that, according to the research firm, about half ofthose people will be in the middle class. Keeping count, thatmeans 5 billion middle-class consumers by 2030 — anincrease of 3 billion in just 20 years. So it almost goes withoutsaying that energy demand will skyrocket past its current levels.

With such tremendous population growth on the way,and trends of urbanisation it’s inevitable that demand for alltypes of energy will increase out of necessity-Everything fromalternative energy like solar, wind, and geothermal to traditionalforms like coal and natural gas besides, uranium, thorium,and hydrogen making technological strides as well. With somany people ready to compete for resources and a better life,one could safely bet that pretty much all forms of energy willbe in short supply.

According to Exxon’s energy outlook for 2015, therewill be a 35% increase in global demand for energy by 2040because of population and the human desire for progress.

‘An Exxon research report predicts that the primarydemand growth is going to be directed at two sources In a.Bottom of Form Oil and Natural Gas. Oil will continue to

occupy the centre stage through 2040 and perhaps beyondwith Demand growth of about 30%.And it will be followedclosely by natural gas, which will ultimately overtake coal aspreferred fuel for power generation. with demand levelincreasing by 65% by 2040.Although most of this informationcomes from Exxon, the biggest energy producer in terms ofnatural gas and oil, we can still rely on it as an indicator oflong-term trends. Hence in the Global Energy front, oil andgas is projected to occupy the centre stage atleast for the nextthree decades

With another twist of events, we are witnessing currentlyLow international crude prices, prices having fallen by almost40% from their peak levels in six months’ time. The currentinternational crude prices of around $60 per barrel presentsan excellent opportunity to build strategic crude oil reservesfor India, says the ASSOCHAM study and this is the best timeto build and expand the strategic crude oil reserves in Indiawhich imports nearly 70% of its oil requirement. This can bedone by enhancing the investment in physical infrastructurebesides signing the forward contracts with the expor tingcountries, it says. The study adds, “It is once in several decadeopportunity for India to scale up its strategic oil reserves tomuch higher level than even three months’ consumption, whichitself is long way to go for us at this point of time.”In fact,India’s crude oil import bill in November 2014 when comparedto May 2014 shows that India has saved around $3 billion permonth as the prices of fuel in the Indian basket have declinedto below $60 per barrel from $106 per barrel about six monthsago. Thus it will cost India around 35 – 40% less to buildstrategic energy reserve at the present price, saysASSOCHAM.

Keeping in mind these importance trends, Enfuse isbringing out the current issue a complete update of thePetroleum Scene in the country , with relevant articles on thesubject.

In the much hyped Solar front, after very disappointingyear 2014 ,prospects are finally appearing to be opening up in2015.

India’s federal cabinet have since approved a plan toset up 25 solar power parks in the country that wouldcollectively add 20,000 megawatts of electricity generationcapacity in the next five years. The parks, which will be acluster of projects, would have a collective generationcapacity of 500 MW or more. It can also house ultra-megasolar projects, or solar power plants with independentgeneration capacity of over 500 MW. The government-backed projects will see financial support to the tune of40.50 billion rupees. The federal cabinet also cleared a planto set up solar power projects of 300 MW or more on areasunder defence establishment.

Once again With Seasons’ Greetings and best wishesto the readers 1n 201I,

I conclude.S. RAMALINGAM

II

39


CONTENTSPage No.

1. WHY THE OIL PRICE IS FALLING 1

2. FALLING CRUDE OIL PRICES WILL PUMP USD 1.4 TRILLION IN TO INDIAN ECONOMY 2

3. GOOD TIME TO BOLSTER INDIA’S STRATEGIC CRUDE OIL RESERVE 3

4. DEREGULATION OF THE DIESEL PRICES IN INDIA 4

5. LNG, CNG, LPG AND HYDROGEN 6

6. NATURAL GAS AND ENVIRONMENTAL IMPACT 8

7. NATURAL GAS – COUNTRIES WITH THE WORLD’S BIGGEST NATURAL GAS RESERVES 9

8. WORLD LNG MARKETS 13

9. IMPLICATIONS OF THE GAS PRICE INCREASE IN INDIA 24

10. RENEWABLE ENERGY UPDATES 27

11. SOLAR PARKS – THE FUTURE? 29

12. NEW STATES ON INDIA’S WIND POWER MAP 31

AN APPEALAs you are aware our advertisement tariff had been kept at very low levels for a long

time. However due to run away cost in all activities, the production cost of the journalalso has increased tremendously. This has necessitated a reworking of the advertisementtariffs us given hereunder. This Tariff comes into force with effect from 1.4.2011.

All members are requested to cooperate:

BACK WRAPPER - Rs.10,000/- per insertFRONT INNER PAGE - Rs. 5,000/- per insertBACK INNER PAGE - Rs. 5,000/- per insertFULL PAGE (ART PAPER) - Rs. 2,500/- per insertFULL PAGE - Rs. 2,000/- per insertHALF PAGE - Rs. 1,000/- per insert

For Details Please contact:

Hon. Secretary, ENFUSE4, B-1, J.P.Towers, 7/2 Nungambakkam High Road,

Chennai - 600 034. Phone: 044-2827 8604

VII

energy & fuel users’ journal oct. – dec. 2014...

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