energy & fuel users’ journal jul. – sep. 2014...

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Energy & Fuel Users’ Journal Jul. – Sep. 2014

Over the past decade, the US and Canadahave experienced a revolution in the productionof gas and oil. Production of shale gas in theUS has grown from 12 million m³ in 2002 to275 million m³ in 2012, and accounts for 40%of natural gas production.

The most important unconventional fossilfuels for the US are shale gas and tight oil,produced by horizontal drilling and hydraulicfracturing (‘fracking’).

Only the US and Canada produce naturalgas and oil from shale formations on acommercial scale. However, several othercountries have conducted exploratory test wells,and China is just starting commercialproduction. The North American experience cantherefore serve as an example for thedevelopment of unconventional energyresources in other regions.

The US and Canadian energy markets aretightly integrated. Canada is a net energyexporter, and provides about 9% of energyconsumed in the US, its principal customer.Energy trade between the two countries totallednearly US$100 billion in 2010.

Massive production of shale gas hasresulted in gas prices in the US being muchlower than in other world regions. High oil priceshave made the production of tight oileconomically viable. The increased domesticproduction of oil and gas has helped the USreduce its dependence on energy imports.Relatively lower energy prices in the US areregarded as a basis for prosperity andincreased industrial production. The increaseduse of gas for electricity production has helpedthe US reduce its CO2 emissions. On the otherhand, there are environmental concerns aboutwater pollution, land use and methane leaks.

PETROLEUMOil and Gas renaissance in North America –

USA, Canada and MexicoUnconventional oil from Canada’s tar sands

Canada is among the world’s five largestenergy producers.Besides tight oil (10% ofCanadian oil production), 56% of the country’soil production come from tar sands (or ‘oilsands’), a combination of clay, sand, water andbitumen, a heavy and extremely viscous oil. Incontrast to tight oil, which is a light oil, bitumencan also be refined into diesel fuel.

Producing bitumen from oil sands is a veryenergyintensive process which uses natural gasas a heatsource.The price difference betweencheap natural gas and expensive oil makes theprocess profitable, despite the high energyinputs.

Due to the energyintensive productionprocess, the greenhouse gas emissions of tarsands oil are 5-15% higher than thoseofconventional oil. While the import of tar sandsoil may enhance the EU’s energy security, itconflicts with its climate targets, embodied inthe EU Fuel Quality Directive which aims at a6% reduction of the carbon intensity of transportfuels by 2020. The EU has labelled tar sandsoil as carbon intensive, but Canada disagreeswith the calculations. As the EuropeanCommission does not plan to renew the FuelQuality Directive after 2020, the door may beopen to the import of tar sands oil.

Canadian oil production from tar sandsamounts to roughly 2 mbd, about the same levelas US tight oil production. Trans CanadaCorporation has proposed a pipeline (KeystoneXL) that could carry 0.83 mbd to US refineries.The project, which is opposed byenvironmentalistsbecause of its climate impact,has not yet been approved by the USadministration.

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Mexican oil and gas reforms

On August 11, 2014, Mexico’s presidentsigned into law legislation that will open its oiland natural gas markets to foreign directinvestment, effectively ending the 75-year-oldmonopoly of state-owned PetróleosMexicanos(Pemex). These laws, which follow previouslyadopted changes in Mexico’s constitution toeliminate provisions that prohibited directforeign investment in that nation’s oil and naturalgas sector, are likely to have major implicationsfor the future of Mexico’s oil production profile.As a result of the developments in Mexico overthe past year, EIA has revised its expectationsfor long-term growth in Mexico’s oil production.

Although there are many complexities tothe new reform and many details that still mustbe settled before the reforms can take effect,reform is expected to improve the long-termoutlook for growth in Mexico’s petroleum andother liquids production. Analysis in EIA’supcoming International Energy Outlook2014 (IEO2014) will include the potential effectson upstream oil exploration and production andthe potential for foreign participation.

The changes in EIA’s assessment ofMexico’s liquids production profile are profound.Last year ’s International EnergyOutlook projected that Mexico’s productionwould continue to decline from 3.0 millionbarrels per day (MMbbl/d) in 2010 to 1.8 MMbbl/d in 2025 and then struggle to remain in therange of 2.0 to 2.1 MMbbl/d through 2040. Theforthcoming Outlook, which assumes somesuccess in implementing the new reforms,projects that Mexico’s production could stabilizeat 2.9 MMbbl/d through 2020 and then rise to3.7 MMbbl/d by 2040—about 75% higher thanin last year’s outlook. Actual performance couldstill differ significantly from these projectionsbecause of the future success of reforms,resource and technology developments, andworld oil market prices.

Since 2008, the contract structure for anyprivate company partnering with Pemex was aperformance-based service contract, whichoffered financial incentives to private

contractors working in Mexico’s upstreamsector. Incentives were provided in some cases,such as when a project is completed ahead ofschedule, when Pemex benefits from the useof new technology provided by the contractor,or when the contractor is more successful thanoriginally expected. These contracts alsoinclude penalties for environmental negligenceor failure to meet contractual obligations.

Mexico’s legislation introduced three newcontract types that will provide more opportunityfor foreign investment in its energy sector:

Profit-sharing contracts allowcompanies to receive a percentage of theprofits resulting from oil and natural gasdevelopment. While companies enteringinto these contracts would not own theresources being developed, they would beallowed to include the revenue from theirpart of the estimated future profits.

Production-sharing contracts allowcompanies to own title to a percentage ofresource volumes as they are produced.

Licenses allow participating companies tobe paid in the form of oil and natural gasextracted from each project.

The production-sharing contracts andlicenses will effectively allow foreign companiesto account for reserves, which is a particularlyattractive incentive for investment in Mexico’senergy sector. Different contract types will likelybe applied according to the degree of riskassociated with specific projects. For instance,licenses will likely be used for projects that arevery capital intensive and high-risk, requiringadvanced technology, like oil shale or ultra-deepwater projects. Less risky onshore andshallow offshore projects would more likely useprofit-sharing arrangements.

Sources:

a. Unconventional gas and oil in North America by theEuropean Parliament - http://www.europarl.europa.eu/RegData/bibliotheque/br ief ing/2014/140815/LDM_BRI%282014%29140815_REV1_EN.pdf

b. US Energy Information Administration - http://www.eia.gov/todayinenergy/detail.cfm?id=17691

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Since the early 1970’s, OPEC has beenknown as a “pricing cartel,” and has beenconsistently portrayed as a more or lessunfriendly group of mean-looking non-Westerners seeking to impose their evil whimsupon the civilized Western world via the abilityto manipulate the price of crude oil. And whilethis caricature might make intuitive sense tothe lay-American who has had to contend withvarious price hikes at the pump over thedecades, the origins of OPEC tell a morenuanced, if not completely different, story.

Though the organization is typicallyassociated, for better or for worse, with the royalfamilies who rule the Gulf and the ArabianPeninsula, OPEC’s origins are to be found notin those parts of Western Asia and NorthernAfrica so commonly known as the “Middle East.”Rather, OPEC was born out of the initiative ofthe Venezuelan government of the late 1940’sand early 1950’s.

In 1947, the Venezuelan government,seeking to receive a more equitable share ofthe profits that foreign oil companies weremaking off of their reserves, demanded thatthese companies begin splitting those profits50-50. The government was well aware of theaudacity of its move, and was particularlyconcerned that international concerns mightretaliate by taking their business elsewhere.Thus, along with the new profit-sharing modelit sought to impose, delegations were sent tothe oil producing nations of the Middle East, atthe time Iran, Iraq, Kuwait, and the SaudiKingdom, where the wisdom of this move wasquickly embraced.

A BRIEF HISTORY OF OPEC

Institutionalizing the Rights of ExportingCountries

By 1960, oil companies had beenunilaterally cutting prices to deal with anostensible supply glut, thereby cutting in toVenezuelan profits. Venezuelan delegationswere again sent to the Gulf, this time with a farmore ambitious idea; a sort of global union toprotect the world’s oil producing countries andtheir interests. Shortly thereafter, OPEC wasborn, with 5 founding members – Iran, Iraq,Kuwait, Saudi Arabia and Venezuela. Thesecountries were later joined by Qatar (1961),Indonesia (1962), Libya (1962), the United ArabEmirates (1967), Algeria (1969), Nigeria (1971),Ecuador (1973), Gabon (1975) and Angola(2007).From December 1992 until October2007, Ecuador suspended its membership.Gabon terminated its membership in 1995.Indonesia suspended its membership effectiveJanuary 2009.Currently, the Organization hasa total of 12 Member Countries.

Among the changes that the organizationbrought to global energy markets, the mostsignificant among them were the establishmentof collective bargaining rights, as well asensuring the right to be directly involved in thedrilling and pumping that foreign companieswere doing on their soil. Also, the pricing systemimposed by OPEC was created as toautomatically adjust for inflation.

Oil & Politics - the Yom Kippur War of 1973and Subsequent Embargo

As onerous as these new rules may havebeen to oil companies, however, no single eventshaped US public opinion towards theorganization as did the 1973 war between Israel

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and the Arab states of Egypt, Syria, and to amuch lesser extent, the Kingdom of Jordan.

Though each of these countries had theirown respective interests in the conlict, OPEC’smember-states, comprised primarily of Arabcountries, closed ranks behind Egypt and Syria,and made the shocking decision to raise oilprices on their own, without first consulting thecompanies. The move was intended to punishWestern governments, whose support for thestate of Israel had only become moreunconditional in nature over the course of 3major Arab-Israeli conflicts beginning in 1948.

The Arab oil embargo of 1973 sent theprice of crude up nearly 400 percent at onepoint, profits that directly benefitted the OPECcountries much in the same way that oilcompanies had profited handsomely only acouple decades before from these sameunderdeveloped nations. Exorbitant prices atthe pump and unprecedented fuel shortagesthroughout the US, however, led to extremelynegative perceptions and portrayals of OPECand especially its Arab components in the USespecially, as citizens were chastened by thesudden demonstration of their near totaldependence on foreign energy resources.

The Quest for Energy Independence

Perhaps the most consequential long-termresult of the embargo was that it jump-startedthe quest for US “energy independence,” andgave this endeavor its patriotic subtext. TheOPEC embargo of 1973 is more or lessresponsible for the increased willingness of oilcompanies to take on more and more difficultprojects in far flung and dangerous places,particularly the waters off the coast of northernAlaska, as well as the UK’s North Sea.

Oil Glut of 1980

After 1980, oil prices began a six-yeardecline that culminated with a 46 percent price

drop in 1986. This was due to reduced demandand over-production that produced a glut onthe world market. Around this period, Iraq alsoincreased its oil production to help pay for theIran-Iraq War. Overall OPEC lost its unity andthus its net oil export revenues fell in the 1980s.

War & Price Slump

Iraqi President Saddam Hussein, leadingup to 1990-91 Gulf War, advocated that OPECpush world oil prices up, thereby helping Iraq,and other member states, service debts. Butthe division of OPEC countries occasioned bythe Iraq-Iran War and the Iraqi invasion ofKuwait marked a low point in the cohesion ofOPEC. Once supply disruption fears thataccompanied these conflicts dissipated, oilprices began to slide dramatically.

After oil prices slumped at around $15 abarrel in the late 1990s, concerted diplomacy,sometimes attributed to Venezuela’s presidentHugo Chávez, achieved a coordinated scalingback of oil production beginning in 1998. In2000, Chávez hosted the first summit of headsof state of OPEC in 25 years. The next year,however, the September 11, 2001 attacksagainst the United States, the following invasionof Afghanistan, and 2003 invasion of Iraq andsubsequent occupation prompted a surge in oilprices to levels far higher than those targetedby OPEC during the preceding period.

Sources :

a. A Brief History of OPEC Ahead of US “EnergyIndependence” - See more at: http://www.equities.com/editors-desk/stocks/energy/a-brief-history-of-opec-ahead-of-us-energy-independence#sthash.87cf7EX8.dpuf)

b. OPEC & its influence on Price of Oil by Ajith Basil- http://www.greatlakes.edu.in/gurgaon/sites/default/files/OPEC&its_Influence_on_the_Price_of_Oil_Ajit_Basil.pdf

c. www.opec.org

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The International Energy Agency wasformed in November 1974 in response to theoilcrisis of 1973-74. Originally comprising of 16members, the IEA now includes 27 memberstates, all of which are also members of theOrganization for Economic Cooperation andDevelopment(OEC)(some states, such asMexico, are members of the OECD but not ofthe IEA). The IEA’s members are drawn fromthe industrialized democracies of WesternEurope, North America and Asia-Pacific.Together, the members of the IEA constitutethe largest bloc of energy-consuming states,accounting for 60-70% of world

petroleum consumption. The IEA is closelyassociated with, but legally distinct from, theOECD; until fairly recently, the secretariats ofthe two organizations shared the same buildingin Paris. The IEA was created under theleadership of US Secretary of StateHenryKissinger, who saw the need for states torespond collectively and decisively tothreats inthe international energy environment, especiallyin light of the Arab oil embargo of 1973. Thethen-existing apparatus for addressing energyissues, namely the

committee structure of the OECD, wasperceived as too rigid and incapable of decisiveaction. Accordingly, the IEA is one of the veryfew international organizations that isempowered to make decisions that are legallybinding on its member states. Specifically, theIEA has binding requirements for a nationalstrategic oil reserve and the capacity to imposelegally binding allocation decisions in the eventof an international oil supply emergency.Moreover, these decisions can be made by

Brief History of International Energy Agency (IEA)

majority vote, rather than a universalconsensus, though in practice consensus is thenorm.

The IEA has two principal functions. Thefirst and most important is to maintain andimprove systems for coping with oil supplydisruptions. OECD members responded to the1973 oil embargo with competitive behaviorssuch as stockpiling of oil reserves, thusexacerbating the economic costs to all.Consequently, the IEA was organized tominimize the impact of supply disruptions andto manage the response to them. Since itsinception, the IEA has required its membercountries to maintain a petroleum reserveequivalent to its consumption of net oil importsover a certain period of time. The reserverequirement was initially set at 60 days ofimports and was then increased in the1970s to70 and finally to 90 days, which has remainedunchanged for more than 30 years. In theinstance of an international disruption to oilsupply, the IEA is empowered to distribute oilallocations to its member countries. Theorganization also requires major oil companiesto share information, including proprietaryandclassified data, which is necessary to takeaction in the case of an emergency. The secondkey function of the IEA is to act as a body forthe development of policy, information sharingand technology transfer. During long periodsof oil-market stability, this second function isthe principal activity of the IEA.

Historically, the advanced industrialdemocracies also have used two otherorganizationsto address energy issues. The firstwas the OECD, which at the time of the 1973-

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74 oilcrisis was the only major institutionavailable for consumer response. However, duetothe restrictive nature of its own structure andrules, it was found to be inadequate foraddressing the oil crisis, which gave rise todevelopment of the IEA. The secondorganization was G-7(now G8 and G20). Nowone of the most important internationalbodiesfor economic cooperation in general,itis not well-known that the G7 was createdinlarge part to address the economic issuesarising from oil and energy supply. Originallyformed as the Group of Six, the heads of statemet for a high-level summit in Rambouillet,France in 1975. These initial meetings were farsimpler affairs than they are now, with eachcountry allowed to bring just four individuals tothe meeting, including the head of state. Thesummit focused on a very narrow agenda offour principal items, two of which focused onenergy and related economic problems. Whilethe G7 subsequently became a moresophisticated organization, its focus after the1970s largelymoved away from the issues ofoil and energy (at least until the rise in oil pricesin 2005-2008). Thus by virtue of its focus onenergy issues, its institutional strength and theeconomic importance of its members, the IEAremains the single most important institutionfor energy-importing countries.

Although there are other institutions thataddress the coordination of energy policy,only the IEA has the responsibi l i ty ofcoordinating the release of the memberstates’ strategic petroleum reserves. This hasbeen done on two occasions.The firstoccurred one day before the 1991 US-Iraqwar to quell fears of insufficient oil suppliesin the market; the second was in responseto the 2005 hurricanes in the Gulf of Mexicothat destroyed oil productio ,distribution andrefining facilities in the US states of Louisiana

and Mississippi. The collective IEA actions,in both instances, ensured the continuity ofoi l supply and prevented oi l marketdisruptions.

The IEA’s emergency response systemhas evolved over time, partly in recognitionof its limitations. The 1974 InternationalEnergy Program (IEP) established three corecommitments for each member state: i) tomaintain national oil reserves, now set at 90days’ worth of net oil imports; ii) to have readya program of demand restraint measuresequal to 7% and 10% of national oi lconsumption;and iii) to participate in an oilallocation system if necessary in a severeemergency. The same agreementestablished a working definition of a supplydisruption as being equal to a 7% volumetricloss of normal oil supplies for IEA membercountries as a whole. However, in 1995, theIEA’s Governing Board adopted a decisionthat gives the IEA more flexibility in identifyingand responding to crises, even pre-crisissituations. This decision gave rise to theCoordinated Emergency ResponseMeasures(CERM), through which the IEA canuse its most rapid response to mitigate sub-and pre-oil crisis situations: the joint releaseof emergency oil stocks into the market. Inaddition to joint releases from national oilreserves, the IEA has a portfolio of secondaryresponse measures, including demandrestraint programs, fuel-switching and surge-production in IEA member countries such asNorway, Canada and the UK, but there aresignificant limitations to these options. TheIEA’s focus is to complement the marketwherever possible, using the allocationsystem as a last resort.

(Source: The International Energy Agency -Challenges for the 21st Century by Global Public

Policy Institute - http://www.gppi.net/fileadmin/gppi/GPPiPP6_IEA_final.pdf )

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The Organization of PetroleumExporting Countries (OPEC) and Russiahave dominated the oil and gas exportenvironment for over half a century. Today,new suppl iers are chal lenging theirsupremacy, and in the process, altering thegeopolitical landscape. With hydrocarbondemand centers shifting to Asia-Pacific, thecompetition for control over supply is beingreplaced by competition for customers. Thiscould benefit importing nations by increasingdiversity of supply and potentially reducingthe risk of disruptions.

OPEC’s waning influence

Exports by OPEC accounted for 28% oftotal crude oil consumption in 2012, aboutthe same as in the prior decade. While OPECwill continue to be a major force in the globaloil markets, increasing production in the USand elsewhere will likely curb its power toinfluence crude oil prices by controllingmarginal production.

The most significant factor in this power-shift is the impact of the US unconventionalboom, with the nation poised to become anet natural gas exporter by the end of thisdecade and with its reliance on foreign oilimports declining. According to the EIA, UScrude oil output grew by 1.6 MMbbl/d to 10.4MMbbl/d between 2010 and 2013. This ledto a drop in imports from OPEC countries,mostly Nigeria and Algeria, by 1.2 MMbbl/d.Increasing production from tight oil reservesmay even allow the US to overtake SaudiArabia as the world’s largest liquid producerin 2014.With US oil output expected toincrease by at least another 1.5 MMbbl/d by

Energy Supply – New sources,New Geopolitics; the waning influence of OPEC

2017, the volume of crude oil purchased fromOPEC countries is likely to fall further.

Higher US production volumes couldalso decrease imports from the country’sother major suppliers, Venezuela, Canadaand Mexico, just as the latter two countriesare expected to increase their own domesticproduction. According to EIA forecasts,Canadian crude oil output is expected to growby 1.0 MMbbl/d by 2020.49 Meanwhile, theMexican government is hopeful that steps toliberalize its oil and gas industry will lead toa production increase of 1.5 MMbbl/d by2025.

If US appetite for their exports plateausor wanes, these nations will need to look foralternative markets. Brazil and Kazakhstanalso have the potential to expand globalsupplies. Production in these nations isexpected to grow by 3.9 MMbbl/d and 1.7MMbbl/d respectively by 2030.

The rising tide of global oil supplies,however, won’t raise all ships. In the past,OPEC has responded to oversupplyconditions, and depressed prices, by loweringthe overall export ceiling for its members.This time, internal discord could limit OPEC’sability to provide a unified response. In 2013,its output hovered above the agreed ceilingof 30 MMbbl/d despite the crisis in Libya,technical issues in Iraq, and sanctions on Iran– conditions that severely limited exportsfrom these countries. This is becausemembers with spare capacity, mainly SaudiArabia, the United Arab Emirates and Kuwait,made up for the loss of output. This was

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against the intentions of countries with limitedspare capacity such as Iran, which was keenon lowering overall output to ensure highprices. Dissention among OPEC membersmay become even more acrimonious in thefuture. OPEC will soon need to make adecision about which members will cut theiroutput when production in Libya, Iran and Iraqrecovers. Cutting export levels in countriesaffected by the Arab Spring may be anespecially contentious issue since thesefragile governments are being pressured tofund education, health and social securityprograms with oil revenues.

OPEC faces a medium-term dilemma.Expectations of supply exceeding demandcould potentially lead to lower global oilprices, creating budgetary difficulties forexporting countries and posing challenges tothe industry, especially for projects in high-cost environments. However, OPEC’s typicalresponse of lowering the production ceilingmay equally create deleterious effects, suchas generating less revenue for somemembers, further lowering OPEC’spercentage of global crude oi l , andsubsequently reducing the Organization’sinfluence on the global markets.

Fight for customers in Europe

Russia, the other leading global oil andgas exporter, could also see its dominancechallenged in its main gas market, Europe.Driven largely by environmental regulations,European demand for natural gas is expectedto grow by 17% by 2035, according to theBP Energy Outlook.52 However, this does notnecessarily translate into more demand forRussian imports.

Russia may face significant competitionin the European gas market. Norwayovertook Russia as Europe’s main supplier

in 2012 due to its more competitive, hub-based spot prices.Supplies from MiddleEastern countries could also pose a futurethreat to Russia’s supply dominance inEurope. In 2012, Algeria, Iran, Libya, Egyptand Nigeria combined sold 75 billion cubicmetres (bcm) of natural gas via pipelines andas LNG, compared to Russian supply of 130bcm.In addition, Qatar, which was set to bea major supplier to the US a few years ago,sold close to 30 bcm of LNG in Europe in2012. Of note, more than half of this volumewas shipped to countries in Western Europewhere Russia also sel ls gas throughpipelines. The volume of Qatari LNG offeredto Europe could also increase as a numberof LNG projects come online in the secondhalf of the decade, increasing competition inthe Asia Pacific market and making moreshipments available for Europe.

At the same time, several Europeancountries are keen to loosen Russia’s gripon their energy supplies. Both Finland andEstonia are planning to build LNG re-gasification plants to reduce Russian imports.Poland is prepared to pay significantly morefor Qatari LNG for the same reason.

Coal displaced by the US shale gasboom could also lessen Europe’s appetite forRussian gas. The long-term outlook forRussian supplies in the European marketcould also be affected by the crisis in Ukraine,with some calling on the US government tospeed up the approval process for LNGexport applications as a mitigating measure– although this would only impact Europeover the longer-term.

To offset slower demand growth andincreased competition in Europe, Russia hasturned to Asia Pacific, and China in particular,targeting new markets there through piped

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gas and LNG. Russia, however, will not bealone in its quest.

Fight for market share in Asia Pacific

Asia Pacific is a hot bed of demandgrowth. Between 2012 and 2035, 72% of theworld’s demand growth for liquids is expectedto come from Asia Pacific. This growth willbe mainly driven by gains in thetransportation sector. Meanwhile, risingelectricity consumption and the movementaway from coal and nuclear power generationby some Asian nations is expected toenhance further the region’s robust energydemand profile.

Countries in Asia Pacific are currentlyOPEC’s main customers, purchasing 57% ofits crude oil exports in 2012.And the regionis poised to become even more important toOPEC since US demand is declining. BeyondOPEC, other exporting nations are alsolooking to Asia Pacific to absorb additionalcrude oil supplies from the Americas, Russiaand Central Asia.

In terms of natural gas, Asia Pacific, ledby Japan, is the largest importer of the fuel.While demand growth in Japan is expectedto slow, China, South Korea and Malaysia areexpected to use more natural gas in thecoming years. Exports from Malaysia andIndonesia are expected to decline due todeplet ion and increasing domesticconsumption.

However, the current Middle Easternsuppliers to the region – Qatar, Oman, theUnited Arab Emirates and additionally Nigeria– will face competition not only from new LNGexport facilities opening in Australia and EastAfrica, but potentially from the US in thesecond half of the decade. Russian LNGprojects in planning and construction will also

aim to capture some of this market.If plannedexport facilities are successfully completed,the Asia Pacific LNG market will becomeincreasingly crowded and highly competitive.

However, demand dynamics in theregion are less than straightforward sincethey are mainly driven by China, the world’slargest net importer of crude oil and otherliquids. OPEC supplies met the majority ofChina’s needs in 2013, but the country hasbeen seeking greater supply security throughdiversification. Accordingly, in recent years,i t has been investing in domesticinfrastructure projects in a number of its ownpetroleum producing provinces. In the future,if it needs to, China could increasingly lookbeyond OPEC and Russia for its oil supplies.

The same applies to natural gas. Chinais increasingly focused on diversifying theirportfolio and is choosing to obtain its suppliesfrom a variety of sources, such as importingpiped gas from East Siberia and CentralAsian countries, as the recently announced$400 billion gas purchase deal with Russia’sGazprom demonstrates. For example, a newbranch of the main Central Asia-China GasPipeline is expected to be operational by2016. This branch will transport gas from thelarge Turkmenistan Galkynysh gas field toChina, increasing the volume of shipmentsto 65 bcm by 2020.

In addition, the speed and magnitude ofChina’s own shale development efforts willalso affect its future appetite for natural gasimports.

As Asia Pacific’s market power increasesso does its strategic importance. Thisportends a greater focus on protectingpotential choke points for oil and gas traderoutes, such as the Strait of Malacca betweenMalaysia and Singapore, as wel l as

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heightened tensions in the South China Seawhere territorial claims are often made andsubsequently disputed. The Sea is not onlyimportant for strategic reasons but also forits potentially large, and yet-to-be-exploited,oil and gas resources.

Our view

New sources of supply will shake up theglobal hydrocarbon markets in the nextdecade. Increased US domestic output, aswell as production growth in Canada, Mexico,Brazil and Kazakhstan, will re-shape globaloil and gas markets and the geopoliticallandscape.

The dominance of traditional producers,mainly OPEC countries and Russia, will bechallenged, and they wil l be forced tocompete more aggressively to maintain theirmarket share and influence.

From the demand side, the Asia Pacificoil and gas markets have accounted for themajority of demand growth over the past

decade and the upward trajectory is expectedto continue. This makes the region, and thenations within it, strategically important. Theirability to absorb new supplies is likely to havea major impact on global geopolitics andinternational trade.

Future developments in the Asia Pacificoil and gas markets will be driven by whatthe main customer, China, does next to meetits growing energy needs and to enhance itsenergy security. While Chinese oil and gasdemand is forecast to increase significantlyover the next decade, the nation may opt toincreasingly tap emerging sources outsidethe purview of its traditional suppliers, suchas oil and gas from Central Asian countries;i ts own domestic shale production;or alternative energy sources, such asrenewables, nuclear and hydro, to diversifythe energy mix.

(Source : “Oil and Gas Reality Check 2014”by Deloitte)

The European Investment Bank is providing a long-term loan of EUR 200 millionto the Indian Renewable Energy Development Agency (IREDA) to help finance projectsin the renewable energy and energy efficiency sector in the country. EIB Vice-PresidentMagdalena Álvarez Arza and Shri Debashish Majumdar, Chairman and ManagingDirector of IREDA, signed the loan agreement in Delhi today.

EIB Vice-President Magdalena Álvarez stressed that “the Framework Loan willmake long-term loans available to support renewable energy and energy efficiencyprojects in India, a priority for the Bank’s lending activity” and highlighted “the excellentcooperation with IREDA in this operation.”

Ambassador of the European Union to India, Dr João Cravinho, stated: “Thisagreement significantly strengthens an important dimension of our relationship withIndia, and it opens up new perspectives for cooperation between the EU and India ina sector that is of great interest for both. The private sector is the global engine ofgrowth and the primary source of new investments and the EU is committed toencouraging such investments in India.”

(Source: Scandoil.com)

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World Downstream Scenario 2013 – Petroleum Refineries(This article appeared in the “Oil & Gas Journal” dated 2nd December 2013)

Global crude oil refining capacity in 2013fell from the high it had attained in 2012 (OGJ,Dec. 3, 2012, p. 32) so that capacity growthsince 2010 appears to be flattening, accordingto the latest OGJ Refinery Survey.

Only the Middle East reported an increasein capacity, but of less than 2%, for a regionthat reports slightly less than 7.4 million b/d.African capacity crept higher as well.

Western Europe, which with more than13.5 million b/cd ranks third in total capacitybehind Asia and North America, led the generaldecline in capacity, dropping more than 3% from2012. Even Asia, which had seen robust growthto nearly 25.3 million b/cd, experiencedessentially no growth in 2013.

The world’s three largest regions for crudeoil refining—Asia, North America, and WesternEurope—comprise more than 68% of globalrefining capacity.

For 2013, OGJ’s survey data show totalglobal capacity at slightly more than 88 millionb/cd with a drop in both number of plants—by10—and capacity—by more than 900,000 b/cd—mostly in Western Europe and Asia.

The 2012 figures represented a peak inglobal refining capacity of more than 88.9 millionb/cd. For 2010, capacity had fallen by 175,000b/d from 88.23 million b/cd; the number ofrefineries by seven. For 2009, global capacitystood at 87.2 million b/cd for 661 refineries.

Fig. 1 shows trends in operating refineriesand worldwide capacity.

Largest refining companies

Table 1 lists the top 25 refining companiesthat own most worldwide capacity. Table 2 listscompanies whose plants total more than200,000 b/cd of capacity in Asia, the US, andWestern Europe. Capacities from Tables 1 and2 include partial interests in refineries that thecompanies do not wholly own.

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Major changes in Table 1 positions sinceJan. 1, 2013, are few: Saudi Aramco replacedValero by opening its Jubail operation;Marathon Petroleum replaced Pemex with itspurchase of BP PLC’s Texas City, Tex., refinery.Other changes in capacity that appear in Tables

1 and 2 result from adjustments in declaredcapacity.

Table 2 shows refineries by region with200,000 b/d capacity or greater. Table 3 liststhe world’s largest refineries with a minimum

Table 1- HOW THE WORLD’S LARGEST REFINERS RANK

Rank CrudeJan. 1,2014 Jan. 1,2013

Companycapacity, b/cd1

1 1 ExxonMobil Corp. 5,589.0002 2 Royal Dutch Shell PLC 4,109.2393 3 Sinopec 3,971.0004 4 BPPLC 2,858.9645 10 Saudi Aramco 2,851.5006 5 Vatero Energy Corp. 2,776.5007 6 Petroleos de Venezuela SA 2,678.0008 7 China National Petroleum Corp. 2,675.0009 8 Chevron Corp.2 2,539.60010 9 Phillips 66 2,514.20011 11 Total SA 2,304.32612 12 Petroteo Brasileiro SA 1,997.00013 17 Marathon Petroleum Co. LP 1,714.00014 13 Petroleos Mexicanos 1,703.00015 14 National Iranian Oil Co. 1,451.00016 15 JX Nippon Oil & Energy Corp. 1,423.20017 16 Rosneft 1,293.00018 18 OAO Lukoil 1,217.00019 19 SK Innovation 1,115.00020 20 Repsol YPF SA 1,105.50021 21 Kuwait National Petroleum Co. 1,085.00022 22 Pertamina 993.00023 23 Agip Petroli SPA 904.00024 24 Flint Hills Resources 714.40025 25 Sunoco Inc. 505.000

1Includes partial interests in refineries not wholly owned by the company.2Includes holdings in Caltex Oil and GS Caltex.

Table 2 - COMPANIES WITH 200,000+ B/CD REFINING CAPACITY

Rank Company No. of Cruderefineries capacity, b/cd1

Asia2

1 Sinopec 27 3,971,0002 China National Petroleum Corp. 25 2,675.0003 Exxon Mobil Corp. 10 1,956.5004 JX Nippon Oil & Energy Corp. 7 1,423.2005 Indian Oil Co. Ltd. 11 1,314.566

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6 Royal Dutch Shell PLC 12 1,255.8757 Reliance Petroleum Ltd. 2 1,240.0008 SK Innovation 2 1,115.0009 Pertamina 8 1,011.82510 GS Caltex Corp. 1 3775.00011 Chinese Petroleum Corp. 3 770.00012 S-Oil Corp. 1 4669.00013 Tonen/General Sekiyu Seisei KK 4 5628,25014 Idemitsu Kosan Co. Ltd. 4 608.00015 Chevron Corp. 6 583.15816 Cosmo Oil Co. Ltd. 4 565.25017 Formosa Petrochemical Co. 1 540.00018 Hindustan Petroleum Corp. Ltd. 3 478.00019 Hyundai Oil Refinery Co. 2 399.50020 BPPLC 4 351.785

Middle East1 Saudi Aramco 8 2.512.0002 National Iranian Oil Co. 8 1.167.0003 Kuwait National Petroleum Co. 3 936,0004 Takreer 2 500.0005 Oil Refineries Administration 6 485.5006 Bahrain Petroleum Co. 1 253.6507 National Oil Distribution Co. 1 200.000

US1 Valero Energy Corp. 12 2.096.5002 Phillips 66 12 2.060.2003 ExxonMobil Corp. 7 2.043.5004 Marathon Oil Corp. 8 1.714,0005 Chevron Corp. 5 955.0006 Royal Dutch Shell PLC 8 6901.0007 Petroleos de Venezuela SA 4 7849.4008 BPPLC 5 795.9009 Motiva Enterprises LLC8 3 772.00010 Flint Hills Resources (Koch Industries) 3 714.40011 Tesoro Corp. 6 564.30012 Sunoco Inc. 2 505.00013 Saudi Aramco 3 9410.00014 Encana Corp. 2 276.00015 LyondellBasell 1 268.00016 Alon USA 3 241.00017 Husky Energy Inc. 2 237.500

Western Europe10

1 Total SA 14 2.025.5522 Royal Dutch Shell PLC 9 1.718.0003 ExxonMobil Corp. 9 1.567.0004 AgipPetroli SPA 10 876,1175 BP PLC 8 844.3756 Repsol YPF SA 5 709.2007 Turkish Petroleum Refineries Corp. 4 613.2758 Compania Espanola de Petroles SA (CEPSA) 3 427.0009 Petrolneos Refining Ltd. 2 402,80010 OMVAG 3 396.46011 ERG Group 4 396.214

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12 Phillips 66 3 350.12513 Preem Raffinaderi AB 2 316.00014 Hellenic Petroleum SA 3 313.00015 Neste Oil 6 11311.07516 Statoil AS 3 304.21017 Galp Energia SA 2 304.17218 Saras SPA 1 300.00019 Petroleos de Venezuela SA 8 294.55020 Valero Energy Corp. 1 210.000

1 Includes partial interest m refineries not wholly owned by the company. 2Asia includes Australia, Bangladesh,Brunei, China (and Taiwan), India, Indonesia, Japan, Malaysia, Myanmar, New Zealand, North Korea, Pakistan,Papua New Guinea, the Philippines, Singapore, South Korea, Sri Lanka and Thailand. 3Includes Caltex’s50% stake. 4Includes Saudi Aramco’s 35% stake. 5Includes ExxonMobil Corp.’s 50% stake. 6Includes Shell’sstake in Motiva and its 50% stake in the Deer Park, Tex., refinery. 7Consists of PDVSA’s ownership of Citgoand its 50% stake in the ExxonMobil’s Chalmette. La., refinery. 850/50 joint venture between Shell andSaudi Aramco. 9Consists of 50% stake in Motiva. 10Western Europe includes Austria, Belgium, Denmark,Finland, France, Germany, Greece, Ireland, Italy, the Netherlands, Norway, Portugal, Spain, Sweden,Switzerland, Turkey and the UK. 11Includes 50% stake in AB Nynas refineries.

Table 3 - WORLD’S LARGEST REFINERIES

Company LocationCrude

capacity, b/cd

1. Paraguana Refining Center Cardon/Judibana, Falcon, Venezuela 940,000

2. SK Innovation Ulsan, South Korea 840,000

3. GS Caltex Corp. Yeosu. South Korea 775,000

4. S-Oil Corp. Onsan. South Korea 669,000

5. Reliance Petroleum Ltd. Jamnagar, India 660,000

6. ExxonMobil Refining & Supply Co. Jurong/Pulau Ayer Chawan, Singapore 592,500

7. Reliance Industries Ltd. Jamnagar, India 580,000

8. ExxonMobil Refining & Supply Co. Baytown, Tex. 560,500

9. Saudi Arabian Oil Co. (Saudi Aramco) Ras Tanura, Saudi Arabia 550,000

10. Formosa Petrochemical Co. Maihao, Taiwan 540,000

11. Marathon Petroleum Co. LLC Garyville, La. 522,000

12. ExxonMobil Refining & Supply Co. Baton Rouge, La. 502,500

13. Kuwait National Petroleum Co. Mina AI-Ahmadi, Kuwait 466,000

14. Shell Eastern Petroleum (Pte.) Ltd. Pulau Bukom, Singapore 462,000

15. Marathon Petroleum Co. LLC Galveston Bay, Tex. 451,250

16. Citgo Petroleum Corp. Lake Charles, La. 440,000

17. Shell Nederland Raffinaderij BV Pernis, Netherlands 404,000

18. Sinopec Zhenhai, China 403,000

19. Saudi Arabian Oil Co. (Saudi Aramco) Rabigh, Saudi Arabia 400,000

20. Saudi Aramco-Mobil Yanbu, Saudi Arabia 400,000

21. Saudi Aramco Total Refinery &Petrochemicals Co. (Satorp) Jubail 400,000

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capacity of 400,000 b/cd. OGJ data reflect theclosing and conversion to a terminal of the350,000 b/d refinery by Hovensa LLC, a jointventure of Hess Corp. and Petroleo deVenezuela SA, at St. Croix, Virgin Islands (OGJOnline, Jan. 29, 2013).

Table 4 lists regional process capabilitiesas of Jan. 1, 2014.

Asia-Pacific trims

Refining capacity declined in Asia-Pacificduring 2013 alongside a slowdown in economicgrowth early in the year. But refiners continuedwith plans for additional expansions aimed atprocessing more diversified crude slates.

Reductions in regional refining capacitylargely resulted from ongoing closures in Japan.In October, the US Energy InformationAdministration (EIA) issued its country reviewfor Japan. It said the Japanese government’smove to promote operational efficiency inrefining may lead to further closures.

In 2010, Japan’s Ministry of Economy,Trade, and Industry (METI) enacted anordinance to raise refiners’ mandatory cracking-to-crude distillation capacity ratio to 13% orhigher from 10% by March 2014 (OGJ, Dec. 3,2012, p. 32). EIA expects refinery closures inJapan already announced, along with the METIrule, to lower refining capacity by nearly 1 millionb/d more between April 2010 and April 2014,

reducing Japan’s total capacity to about 3.9million b/d.

OGJ’s survey data show Japanese refiningcapacity at 4.4 million b/d, down from nearly4.8 million b/d in 2012, with three refineryclosures on the year.

But Chinese refining capacity held steadyfrom 2012. In its October Short-Term Energyand Winter Fuels Outlook, EIA estimated thatliquid fuels consumption in China will increaseby 420,000 b/d in 2013 and a further 430,000b/d in 2014, compared with average growth ofabout 510,000 b/d/year 2003-12.

Noting that China’s steady growth in oildemand has made it the world’s largest net oilimporter, exceeding the US in September 2013,EIA forecast this trend to continue through2014.

But much of China’s fresh capacity overthe past year came late in 2012, with mostadded during fourth quarter, according to theInternational Energy Agency’s Medium-Term OilMarket Report 2013 released in May.

By early November 2012, state-ownedChina Petroleum & Chemical Corp (Sinopec)had completed a 200,000-b/d crude distillationunit (CDU) to boost sour crude processing atits Maoming refinery in the southeast GuandongProvince. After the unit’s December 2012commissioning, the refinery was processing

Table - REGIONAL LOOK AT WORLDWIDE REFINING OPERATIONS

Africa 45 3,218,085 509,504 210,380 458,426 61,754 833,626 1,841Asia 162 25,275,612 4,662,741 3,040,668 2,168,831 1,242,200 9,881,233 20,450Eastern Europe 89 10,602,308 3,946,235 868,470 1,466,344 394,058 4,298,848 12,950Middle East 43 7,393,365 1,863,275 357,550 630,797 566,891 2,044,063 3,300North America 147 21,591,067 9,499,402 6,531,656 4,145,594 1,964,608 16,640,894 139,793South America 65 6,359,987 2,680,560 1,311,007 401,638 132,400 1,689,562 20,140Western Europe 94 13,588,454 5,399,998 2,069,316 2,006,337 1,250,364 9,581,361 12,614

Total 645 88,028,878 28,561,715 14,389,047 11,277,966 5,612,276 44,969,587 211,088

RegionCrude

destillationb/cd

No. ofrefineries

Vacuumdestillation

b/cd

Catalyticcracking

b/cd

Catalyticreforming

b/cd

Catalytichydrocracking

b/cd

Catalytichydrotreating

b/cd

Coke,million

tonnes/day

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around 350,000 b/d by Jan. 20, according toSinopec.

The addition of the CDU at Maoming willboost refinery output to more than 400,000 b/d, Sinopec said.

But as 2013 began, China’s refiningindustry faced sluggish global economicrecovery, slowdown of the country’s economicgrowth, and weak demand in oil andpetrochemical markets.

In May, Reuters reported thatPetroChina—the publicly listed arm of state-owned China National Petroleum Corp.(CNPC)—delayed plans for doubling capacityat its 100,000-b/d Huabei refinery in HebeiProvince, initially slated to be operating at200,000 b/d by yearend 2012. The companynow expects to complete the expansion by late2014, with commissioning in early 2015.

In September, China’s Ministry ofEnvironmental Protection shelved all proposalsfor upcoming refining projects by Sinopec andCNPC, the country’s two largest state-ownedrefiners. The sanction came as a result of bothcompanies’ failure to meet targeted emissionslevels.

The government freeze on refiners’activities included stalling PetroChina’s jointventure with Royal Dutch Shell PLC and QatarPetroleum for a 400,000-b/d refinery andpetrochemical complex in Taizhou, in easternZhejiang Province (OGJ, Dec. 5, 2011, p. 30).

Also in September, PetroChina delayedcommissioning its 200,000-b/d Pengzhourefinery in China’s southwestern province ofSichuan following an investigation intoaccusations of corruption against formercompany officials. Pengzhou is to be Sichuan’sfirst major refinery and will process crude fromnorthwest China and Kazakhstan.

Despite the economic downturn during thefirst three quarters of 2013, recovery later inthe year encouraged refiners to move forwardwith plans for adding capacity.

Ongoing commitment to investment indownstream operations came amid increasedprofits stemming from reforms to petroleumproducts pricing instituted in March by China’sNational Development and ReformCommission (NDRC).

In late March, NDRC revamped its systemof setting domestic oil product prices moreclosely to reflect the international pricing ofimported crudes from which the products aremade, increasing refiners’ profitability.

In late June, PetroChina released anenvironmental impact assessment for theKunming refinery in southwest YunnanProvince. The refinery is to have a 200,000-b/d processing capacity and open in 2014.

In October, CNPC signed an agreementwith Rosneft for the commissioning scheduleand oil supply for the 260,000-b/d refinery inthe eastern port city of Tianjin, first announcedin 2010 (OGJ Online, Sept. 2, 2010).

Under the detailed work schedule signedbetween CNCP and Rosneft, a joint finalinvestment decision on implementation of theTianjin refinery is to be made in 2017, with therefinery to be commissioned before yearend2020.

Rosneft will be the major oil supplier forthe refinery, which will be granted the rights forcrude import, oil products export, and productsales by the Chinese government.

Sinochem also plans to commission a240,000-b/d refinery at Quanzhou in southernFujian Province by yearend.

China National Offshore Oil Co. (CNOOC),China’s third-largest state refiner, continues to

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advance plans to add 200,000 b/d of capacityat its 240,000-b/d refinery in Huizhou,Guangdong Province, by 2014.

But, as GlobalData of London reported,ongoing corruption probes into state-ownedcompanies as well as the Chinesegovernment’s indeterminate freezes onupcoming projects due to environmentalrestrictions could slow development of otherrefinery projects planned for 2016-25.

India also remains committed to expandingits refining capability to meet rising demand.

In March in India, Hindustan PetroleumCorp. Ltd. and the state government ofRajasthan signed a memorandum ofunderstanding (MOU) for a refinery andpetrochemical complex at Barmer. The project,for which no capacity was announced, wouldbe developed by state-owned HPCL, RajasthanState Refinery Ltd., and other equity partners(OGJ Online, Mar. 14, 2013).

India’s Ministry of Petroleum and NaturalGas (IMPNG) estimates the Barmer project willcost $6.85 billion and take 4 years to construct.The complex would use crudes produced locallyand from abroad, making it Rajasthan’s firstrefinery and India’s first petrochemical plantdesigned to process indigenous crude oil,IMPNG said.

In May, the Wall Street Journal reportedthat Hindustan Petroleum Corp. Ltd. revived itsplan to build a refinery and petrochemicalcomplex at Visakhapatnam in the southernstate of Andhra Pradesh. The refinery will beable to process 300,000 b/d.

Bharat Petroleum Corp. Ltd., Mumbai,continued to let contracts in 2013 for servicesrelated to an expansion and upgrade of its Kochirefinery at Ambalmugal in the state of Kerala.The project will expand crude capacity to 15.5

million tonnes/year (tpy; about 300,000 b/d)from 9.5 million tpy. It will include a CDU, fluidcatalytic cracking (FCC) unit, and delayedcoker.

In July, Bharat awarded Essar Projects Ltd.a contract in a consortium with GR Engineeringof Mumbai for the engineering, procurement,and construction of the reactor regeneratorpackage of a 2.2-million-tpy FCC at the Kochirefinery. The FCC project is to be completed in24 months.

In August, Chennai Petroleum Corp. Ltd.—a partly owned subsidiary of Indian Oil Corp.Ltd.—let a turnkey contract to Engineers IndiaLtd. for the addition of a delayed coker at its10.5-million-tpy Manali refinery in Tamil Nadu,India (OGJ Online, Aug. 14, 2013). Accordingto press reports, the coker will have capacity of2.2 million tpy. It’s part of a project enabling therefinery to upgrade resid and increase distillateyield by about 7%. The Manali project includesthe revamp of the refinery’s existinghydrocracker.

More immediately, completion of a300,000-b/d, full-conversion refinery by IndianOil at Paradip on India’s northeastern coast wasexpected in November, according to IMPNG(OGJ Online, Mar. 13, 2013). In addition tocrude and vacuum distillation units, the refinerywill have a hydrocracker and delayed coker.

But plans for the start of commercialoperations at Nagarjuna Oil Corp. Ltd.’s120,000-b/d Cuddalore refinery in Tamil Nadu,India, during this year’s first half remain delayedfollowing extensive damage from cycloneThane in 2011. Downstream units of therefinery, slated for start-up during first-half 2014,will include an FCC unit and delayed coker(OGJ, Dec. 3, 2012, p. 32).

While China and India prepared foradditional capacity, smaller countries in Asia-

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Pacific also planned for expanding theirdownstream sectors.

In January, Cambodian Petrochemical Co.Ltd., through a contractor, let a licensing andengineering services contract to KBR for ahydrocracker at a 5-million-tpy refinery plannedin Cambodia (OGJ Online, Jan. 18, 2013).Tianjin Petrochemical Engineering Design Co.Ltd. is engineering, procurement, andconstruction contractor for the 1.2-million-tpyunit, which will use VebaCombi Crackingtechnology.

KBR said China Perfect MachineryIndustry Corp. Ltd., Shanghai, will build therefinery in the Kampong Som PetrochemicalIndustrial Zone, with start-up slated for 2015.The refinery will be Cambodia’s first sincedestruction in 1972 of a 10,000-b/d refinery builtin 1969.

In April, state-owned Pakistan State Oilsigned an MOU with the government of thenorthwest province Khyber Pakhtunkhwa tobuild a 40,000-b/d refinery on 400 acres inKohat district of K-P (OGJ Online, Apr. 12,2013). The plant will process crude from nearbyindigenous sources for production of productsconforming to Euro IV standards. The projectis to be commissioned by 2016-17, withconstruction to begin by yearend.

In July, Nghi Son Refinery & PetrochemicalLLC let a project management and consultancyservices contract to a Foster Wheelersubsidiary for its 200,000-b/d refinery andpetrochemical complex in ThanhHoa Province,Vietnam (OGJ Online, July 30, 2013). Therefinery, currently under construction, willprocess Kuwaiti heavy crude and include an80,000-b/d FCC unit as well as a 700,000-tpyaromatics complex.

Once completed, the Nghi Son refinery—which is set for start-up in 2017—will fulfill about

two thirds of Vietnam’s total refined petroleumliquids needs, according to local media.

But Vietnam’s rising demand for oilproducts also prompted the Vietnamesegovernment to approve a license for Thailand’sstate-owned PTT Public Co. Ltd. to build a $27billion refinery and petrochemical complex inBinhDinh Province. Local media reported theproject, for which details remain vague, is tobe commissioned by 2020.

Elsewhere, Indonesia’s state-owned PTPertamina and UOP LLC agreed in October todevelop a feasibility study for modernization offive of Pertamina’s Indonesian refineries (OGJOnline, Oct. 7, 2013).

The refineries to be covered in themodernization master plan are at Balikpapan,East Kalimantan; Cilacap, Central Java; Dumai,Riau; Plaju, South Sumatra; and Balongan,West Java. The refineries have capacitiestotaling slightly more than 1 million b/d,according to Pertamina. The company said thework to be studied includes upgrades to enablethe refineries to process heavier, lower-qualitycrude oil.

But in Australia, refining capacitycontracted in 2013, with still further contractionspossible next year.

After shuttering its 79,000-b/d Clyderefinery at Sydney last year, Shell Australia inApril said it is looking for a buyer for its onlyother Australian refinery. Sale of the 120,000-b/d Geelong refinery is part of the company’sglobal strategy to concentrate investments onlarge-scale sites, such as its PulauBukomrefinery in Singapore (OGJ Online, Apr. 4,2013).

Shell said if it cannot negotiate a sale ofthe Geelong plant by 2014, it would considerconverting the refinery into an import terminal,

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as it did with the Clyde refinery (OGJ Online,June 7, 2012).

Middle East expansions, growth

In Kuwait late in 2012, Kuwait NationalPetroleum Co. awarded a $500 million projectmanagement contract to UK-based AMEC tobuild a 615,000-b/d refinery. The award targetscompletion in 2018.

In the United Arab Emirates, the $10 billionexpansion of Takreer’s (Abu Dhabi Oil RefiningCo.)Ruwais refinery, some 385 miles west ofAbu Dhabi City, will add 417,000 b/d of crudecapacity, taking the plant to more than 800,000b/d capacity. The company expects start-up infirst-half 2014.

In September, Dubai signed agreementswith China Sonangol to build the secondrefinery in the country; Emirates National OilCo. operates the 120,000-b/d Jebel Ali refinery.China Sonangol is owned by Sonangol (30%)and New Bright International (70%), a privateHong Kong company.

In Iraq in October, the country’s primeminister signed a $6 billion contract with Swisscompany Satarem to build and operate a150,000-b/d refinery in the southern borderprovince of Maysan.

In April, Qatar Petroleum signed a jointventure agreement with Total and Japan’sIdemitsu, Cosmo Oil, Marubeni, and Mitsui toexpand its 146,000-b/d Laffan Refinery (LR1)condensate splitter at RasLaffan (OGJ Online,Aug. 19, 2011; Apr. 22, 2013).

The expansion (LR2), to be operated byQatargas Operating Co. Ltd., will processuntreated condensate from supergiant Northgas field, producing as much as 60,000 b/d ofnaphtha, 53,000 b/d of jet fuel, 24,000 b/d ofgas oil, and 9,000 b/d of LPG. Construction ofthe $1.5 billion facility is to be complete in

second-half 2016.

A diesel hydrotreater to be commissionedsecond-quarter 2014 will be able to process alllight gas oil from LR1 and LR2, yielding ultralow-sulfur diesel.

Ownership under the joint ventureagreement is QP, 84%; Total, 10%; Idemitsuand Cosmo, 2% each; and Marubeni and Mitsui,1% each.

In October, Qatargas awarded Qatar KentzWLL, a unit of Kentz Corp. Ltd., a manpowerservices contract for LR2 (OGJ Online, Oct. 9,2013).

In September, Malaysia’s news agencycited Iranian sources that Sinopec and a SouthKorean firm had completed arrangements fora $1.5 million revamp of Iran’s Esfahan refinery.The project is to boost the refinery’s gasolineand diesel production.

Also in September in Saudi Arabia, SaudiAramco Total Refinery & Petrochemicals Co.(Satorp) began shipping refined products fromits 400,000 b/d full-conversion refinery at Jubail(OGJ Online, Apr. 25, 2013; Sept. 26, 2013).

Construction on Jubail started in April2010, and all units are slated to be operatingby yearend. The $14 billion refinery will processArab heavy crude from nearby Safaniya andManifa fields and yield petrochemicals as wellas high-quality fuels. It will be Saudi Arabia’sfirst producer of petroleum coke andparaxylene.

Satrop is a joint venture of Saudi Aramco(62.5%) and Total SA (37.5%).

North American growth, ownership

In Canada in September, officials gatheredfor groundbreaking for the first major newrefinery in North America in nearly 30 years.The $5.7 billion (Can.) 150,000-b/d refinery

20


north of Edmonton in Sturgeon County willprocess bitumen and produce diesel, diluentnaphtha, low-sulfur vacuum gas oil and lightends—butane, propane, and ethane.

The North West Redwater Partnership isa 50-50 joint venture of North West UpgradingInc. and Canadian Natural Resources Ltd. (OGJOnline, Nov. 13, 2012). The first 50,000-b/dphase is to be operating by late 2016.

In the US in late 2012, Koch Industries’unit Flint Hills Resources, Wichita, Kan., soughtapproval from the Minnesota Pollution ControlAgency to amend its air-quality permit to allowa $400 million upgrade to the company’s PineBend refinery at Rosemount, Minn., about 20miles south of St. Paul.

Improvements would allow the refinery tohandle crude oil feed closer to its 320,000-b/dprocessing capacity and to reduce emissionsof nitrogen oxide and sulfur dioxide.

The upgrade, a company spokespersontold OGJ, will start up in early 2014. It will bethe largest at the refinery since it completed a$350 million project in 2006 to produce low-sulfur diesel.

Construction began earlier this year onNorth Dakota’s second refinery.

The 20,000-b/d Dakota Prairie plant willsit on 318 acres west of Dickinson, StarkCounty, in southwestern North Dakota. It willproduce diesel and kerosine to meet truckingand commercial demand rising in response tooil production boom in the Bakken area in thenorthwestern part of the state.

The refinery will be operated by DakotaPrairie Refining LLC and is being built by MDUResources Group Inc., Bismarck, through itsunit WBI Energy Inc., and by Calumet SpecialtyProducts Partners LP, Indianapolis. Westconis general contractor with Ventech Engineering

providing primary equipment and technology,according to area media reports.

North Dakota’s only operating refinery, the58,000-b/d Tesoro Mandan refinery nearBismarck, also produces diesel fuel, jet fuel,heavy fuel oils, and LPG.

In May, North Dakota’s Three AffiliatedTribes broke ground for the $450 million,20,000-b/d Thunder Butte refinery about 2.5miles west of Makoti and about 30 milessouthwest of Minot. Products of the refinery willbe diesel, propane, and naphtha.

Three Affiliated Tribes include the Mandan,Kidatsa, and Arikara tribes, which jointly governthe MHA Nation, according to its web site.

Another refinery, the 20,000-b/d Trentondiesel refinery to be owned by Dakota OilProcessing, received an air-quality permit fromthe North Dakota Department of Health in early2012, according to EIA. No further progresstoward construction has been announced.

With a cost estimated at $200 million, itwill have an atmospheric distillation column,hydrotreater, naphtha stabilizer, and associatedprocess equipment. According to Dakota OilProcessing’s web site, the primary product fromthe refinery will be light gas oil.

Other products will be naphtha, which maybe used to produce petrochemicals or mixedas diluent into heavy crude oil; kerosine, whichthe refinery plans to blend into the distillate poolto maximize distillate yield; atmospheric gas oil;and heavy fuel oil, which can be sold in thebunker fuel market, according to EIA.

Bakken crude isn’t the only productionprompting upgrading to Lower 48 refineries.

In September, Husky Energy Co. soughtapproval from Ohio for a $300 million upgradeto its Lima refinery specifically to processheavier crudes from Alberta.

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Husky has initiated design work on a crudeoil flexibility project that would allow the Limarefinery to process as much as 40,000 b/d ofheavy crude, according to a Huskyspokesperson.

“The project would not expand therefinery’s capacity,” but would give Huskygreater flexibility to switch between lighter andheavier blends. It would give the refiner “theability to process a small amount of bitumen,but would primarily give us the capability toprocess heavy oil,” the Husky spokespersonsaid.

Earlier this year, the joint venture BP-Husky Refining LLC announced it hadcommissioned a 42,000-b/d naphtha reformerat the joint venture’s 160,000-b/d Toledorefinery at Oregon, Ohio.

The $400 million project replaced two oldercatalytic reformers and a hydrogen plant alsoto provide the flexibility to handle heavier crude(OGJ Online, Mar. 12, 2013).

In July, BP PLC started up a 250,000-b/dcrude unit at its Whiting, Ind., refinery, a stepthat returned the refinery to its 413,000-b/dnameplate processing capacity. It also allowedfor remaining upgrades of new coking andhydrotreating units (OGJ Online, Feb. 1, 2011;July 1, 2013).

A BP spokesperson told OGJ the projectremains on schedule with the final new unit—the 102,000-b/d coker—coming online beforeyearend.

When all units are online, the reconfiguredrefinery will have the flexibility to increase heavy,sour crude processing to about 80% of itsoverall crude run.

Construction of the Whiting refineryupgrade is more than 95% complete, said thecompany, which has commissioned a 105,000-

b/d gas oil hydrotreater and other associatedunits.

In late 2012, Calumet Specialty Productssaid it will double production at its Great Falls,Mont., refinery over 2013-14 with an expansionto its 20,000-b/d crude unit.

Calumet planned to invest $275 million withimprovements expected to be completed bymid-2015.

In late 2012, Calumet agreed to pay $100million for the 14,500-b/d refinery at San Antoniofrom NuStar Refining LLC and NuStar LogisticsLP, both units of NuStar Energy LP, SanAntonio.

The refinery produces ultralow-sulfurdiesel, jet fuel, specialty solvents, reformates,naphtha, and vacuum gas oil. At the site is about200,000 bbl of storage capacity along withabout 200,000 bbl of crude oil storage capacityat a crude oil terminal in Elmendorf, Tex. Crudeoil feedstocks are from South Texas, primarilythe Eagle Ford shale.

In February, Marathon Petroleum Corp.closed on the purchase of BP’s 451,000-b/cdTexas City, Tex., refinery, renaming it theGalveston Bay refinery.

The transaction also includes a 1,040-Mwcogeneration plant, four light product terminalslocated in the US Southeast, retail marketingcontract assignments for about 1,200 brandedsites representing about 61,000 b/d of gasolinesales, three operating intrastate NGL pipelinesoriginating at the refinery, and a 50,000-b/dallocation of BP’s Colonial Pipeline Co. shipperhistory.

Base purchase price is about $598 million,plus inventories valued at about $1.1 billion.

Also in February, Hess Corp. completedthe closing of its 70,000-b/d Port Reading, NJ,

22


refinery, as it had announced it would in January(OGJ Online, Jan. 29, 2013).

The adjacent 6-million-bbl storage terminalwas put on the market and, in October, Hessannounced agreement with Buckeye PartnersLP to sell its US East Coast and St. Luciaterminal network for $850 million in cash.

The terminal network along the East Coasthas a total of 28 million bbl of storage capacityat 19 terminals, 12 of which have deepwateraccess. Also included was Hess’s St. Lucia oilstorage terminal in the Caribbean with 10 millionbbl of capacity.

In June, Tesoro Corp. closed on itspurchase of BP PLC’s 266,000-b/d Carsonrefinery near Los Angeles for a little more than$1 billion for refining and marketing assets and$1.35 billion for inventory and other workingcapital (OGJ Online, June 3, 2013; May 17,2013).

Media reports in late 2012 saidPetroleoBrasileiro SA (Petrobras) was to sellits 100,000-b/d refinery in Pasadena, Tex.,operated by Pasadena Refining Systems Inc.Proceeds from such a sale were to helpunderwrite more drilling off Brazil.

Petrobras paid almost $1.2 billion in totalwhen it bought first a 50% ownership from AstraOil Co. Inc., a subsidiary of Transcor, in 2006,then the remaining 50% later.

In March, however, regional mediareported Petrobras had taken the refinery offthe market in favor of selling its Argentine unit.Repeated calls by OGJ to Pasadena Refining’sPasadena, Tex., offices and messages toPetrobras’s main offices in Rio de Janeiro werenot returned or answered.

In September, Hawaii Pacific Energy LLC,a subsidiary of Houston-based Par PetroleumCorp., completed the $75 million purchase of

Tesoro Hawaii LLC from Tesoro Corp. (OGJOnline, June 19, 2013; Sept. 27, 2013).

Included were the 94,000-b/d Kapoleirefinery; storage capacity for 2.4 million bbl ofoil and 2.5 million bbl of refined products; andrelated logistics assets, including five productterminals, 27 miles of pipelines, and a single-point mooring terminal.

The Kapolei refinery produces gasoline,jet fuel, high-sulfur diesel, and high and low-sulfur fuel oil. It also is a major supplier ofultralow-sulfur diesel to the Hawaiian Islands.

Major process units include crudedistillation, vacuum distillation, hydrocracking,naphtha hydrotreating, reforming, andvisbreaking. The refinery is in the CampbellIndustrial Park in Kapolei, 20 miles west ofHonolulu

European woes

In its analysis for 2013 through thirdquarter, the UK research and consulting firmGlobalData noted that global refinerythroughputs suffered rapid decline throughoutthis year’s third quarter, with Europe and Asia-Pacific faring the worst. Dismal refining marginsand maintenance programs were hurtingprofitability.

Europe has been suffering more than anyother region in the world from reductions inrefining margins. This results from its over-capacity and sliding demand amid a lingeringeconomic recession, which had “destroyedcompanies’ hopes of profitability,” GlobalDatasaid.

Furthermore, maintenance during thisyear’s third quarter removed about 1.2 millionb/d of the region’s atmospheric distillation unitcapacity, with many plant turnarounds expectedto extend into fourth quarter.

23


Imports of gasoline, gas oil-diesel, jetkerosene, and all other hydrocarbon products,however, were readily available from the US,Middle East, India, and Russia. Thus, the reportsaw “little urgency” to bring these plants backon stream even after the planned work.

Several of Europe’s refineries are up forsale, and those that remain unsold are underthreat of being transformed into terminals bytheir owners, thereby taking this capacity offthe market forever, said GlobalData.

Heavy maintenance in North Americathreatened to take offline 1 million b/d ofatmospheric distillation capacity, as refinerschanged over to heating oil production fromgasoline production in preparation for winterheating demand.

A further 500,000 b/d of crude capacity,said the analysis, was under maintenance inAsia-Pacific in third quarter, with some of thiswork planned to continue into the fourth quarter.

In 2012, TotalErg—a joint venture of Total(49%) and Italian refiner Erg (51%)—closed its86,000-b/d Rome refinery at the end of thirdquarter, converting it to a storage terminal.

Another Italian refinery, the 52,000 b/dMantua refinery operated by Hungary’s MOL,will cease operations at yearend 2013 and beconverted into a product storage terminal.

In April this year, a French court’s decisionrejecting two offers for France’s PetroplusHoldings AG’s Petit-Couronne refineryeffectively doomed the plant, for which OGJdata shows a nameplate capacity of 154,000b/d; press accounts of the court’s decision gavecapacity as 161,800 b/d. Operations thereceased in 2012.

In June, Phillips 66 said it would sellIreland’s only refinery, the 71,000-b/d Whitegateplant at Cork.

A Phillips 66 spokesperson told OGJ thecompany had retained Deutsche Bank tomarket its business in Ireland, which includesthe refinery and associated wholesalemarketing business and a crude oil and refinedproducts storage terminal in Bantry Bay.

“Several parties have expressed interest.We are currently evaluating the bids,” he said.A decision on whether to go ahead with a salewill be made by yearend.

Why anyone would want a small,outmoded refinery in such a market as Irelandis the subject of both industry and generaldebate.

But the biggest news from WesternEuropean refining has come from Scotlandwhere in October Ineos Group Holdings SAannounced it was shutting the 210,000-b/dGrangemouth refinery and petrochemical plantbefore a strike that could interrupt nearly halfof UK crude production.

Ineos cited many of the same woes thathave dragged down other European refiners,mainly slimmer margins due to more expensivefeedstocks.

The Grangemouth refinery receives feedfrom BP’s Kinneil terminal, part of the Fortiessystem, and from the Finnart Ocean terminalabout 62 miles to the west (OGJ Online, Oct.23, 2013).

Petroineos, a joint venture of Ineos GroupHoldings SA and PetroChina International(London) Co. Ltd., operates the refinery andpetrochemical plant.

By the end of October, the strike had beensettled under an agreement that will keep therefinery open for 3 years.

Ineos and Petrochina pledged to build anLNG regasification terminal at the refinery to

24


accept shipments of US natural gas. Thiselement alleviates the refinery’s dependenceon more expensive North Sea-produced naturalgas and residual fuel oil for plant power.

In Eastern Europe in May, Russian oilproducer Gazprom Neft announced plans toinvest about $1.5 billion to upgrade its Moscowrefinery over 2013-15.

Plans are to upgrade the plant to producebetter grades of products, increase the oilconversion rate, enhance energy efficiency, andreduce the plant’s effect on the environment.

Gazprom will commission a light-naphthaisomerization unit and a catalytic crackinggasoline hydrotreater this year and completethe second stage of a diesel fuel hydrotreater.

The program will also build a combinedrefining unit with a capacity of about 118,000b/d and introduce advanced technologies.

Africa edges up

Some fresh capacity came online in Africain 2013, but details emerged across the yearfor additional capacity expansions.

In late December 2012, Angola’s state-owned Sonangol began construction on itsSonaref refinery in Lobito, in BenguelaProvince. The refinery, estimated to cost $8billion, will process Angolan crude oil to produceunleaded gasoline, diesel, jet fuel, kerosene,LPG, and small amounts of sulfur, local mediareported. The refinery is to start up in late 2015or early 2016 and will eventually reach acapacity of 200,000 b/d, the company said.

In April, Sinopec said it reached acooperation framework agreement withPetroleum Oil & Gas Corp. of South Africa(PetroSA) that enabled the companies toadvance the 400,000-b/d Mthombo refineryproject in Port Elizabeth’s Coega Industrial

Development Zone. PetroSA originallyscheduled a final investment decision for theMthombo refinery for 2010 (OGJ Online, Dec.8, 2008).

In May, Reuters reported that Algeria’sstate-owned Sonatrach increased output at thecountry’s largest refinery at Skikda following aseries of delays during maintenance to upgradetwo CDUs. Work on the 300,000-b/d refinerybegan in July 2012, leaving operations at half-capacity during the upgrading.

In late August, Sonatrach, through acontractor, awarded a contract to OCIConstruction Group for both greenfield andbrownfield work at the company’s 60,000-b/dAlgiers refinery in SidiArcine near the port ofAlgiers. Under the contract, OCI will executesome of the civil works, paving works,underground piping, and related brownfieldconstruction work as part of the rehabilitationand adaptation of the refinery.

In October, Uganda’s Ministry of Energyand Mineral Development (MEMD) released arequest for qualifications (RFQ) to identify alead investor-operator for a 60,000-b/d refineryand related downstream infrastructure.

The refinery would be Uganda’s first andwould serve a growing demand for refinedpetroleum products, which is estimated to reach232,000 b/d by 2020, MEMD said. The RFQfollows a feasibility study on a refinery inUganda that MEMD commissioned in 2010(OGJ Online, Feb. 2, 2010).

(http://www.ogj.com/articles/print/volume-111/issue-12/special-report-worldwide-report/western-

europe-leads-global-refining-contraction.html)

25


Despite decades of extraction and use, theestimated size of the U.S. natural gas resourcehas steadily risen since the 1990s, largelybuoyed by the increased feasibility of extractinggas from unconventional deposits.

Unconventional natural gas, whichincludes shale gas, tight gas, coal bed methane,and methane hydrates, has been more difficultand costly to exploit than conventional deposits,until recently.

Such sources could help close the growinggap between domestic production andconsumption in the United States, but theypresent greater environmental challenges intheir production.

The Energy Information Administrationcurrently estimates the U.S. unconventional gasresource base to be 2,203 trillion cubic feet. Ofthat, 167 trillion cubic feet are consideredproven reserves—recoverable under currenteconomic and operational conditions.

Shale Gas

Unlike conventional gas, which resides inhighly porous and permeable reservoirs and

can be easily tapped by standard vertical wells,shale gas remains trapped in its original sourcerock, the organic-rich shale that formed fromthe sedimentary deposition of mud, silt, clay,and organic matter on the floors of shallowseas.

Today, shale gas is the fastest growingnatural gas resource in the United States andworldwide as a result of several recentdevelopments. Advances in horizontal drillingtechnology allow a single well to pass throughlarger volumes of a shale gas reservoir and thusproduce more gas.

The development of hydraulic fracturingtechnology (also known as hydrofracturing,hydrofracking, or simply fracking) has alsoimproved access to shale gas deposits. Thisprocess requires injecting large volumes ofwater mixed with sand and fluid chemicals intothe well at high pressure to fracture the rock,increasing permeability and production rates.In addition to these technological advances,high natural gas prices between 2001 and 2008have provided further incentive to develop theshale gas resource. However, the resulting

increase in shale gas combined withthe recent economic recession hasresulted in a dramatic decline in gasprices since 2008.

To extract shale gas, aproduction well is drilled verticallyuntil it reaches the shale formation,at which point the wellbore turns tofollow the shale horizontally. Steeltubing, called “casing,” is insertedinto the well to keep it open andprotect the integrity of the wellbore. Cement is then pumped into the well

Shale Gas, CBM and other unconventional gas

26


and forced up the outside of the steel casing toseal the well and try to prevent natural gas,fracking fluids, chemicals, and produced waterfrom leaking into groundwater supplies.

After drilling and well casing is completed,small explosive charges are detonated in thehorizontal portion of the well to create holes inthe casing at intervals where hydraulicfracturing is to occur. Ina hydraulic fracturingoperation, thefracturing fluid ispumped in at a carefullycontrolled pressure tofracture the rock out toseveral hundred feetfrom the well. Sandmixed with thefracturing fluid acts toprop these cracks openwhen the fluids aresubsequently pumpedout. After fracturing,gas will flow into the

well bore and up to thesurface, where it is collected.

As of 2011, slightly morethan 39 percent of U.S.natural gas reserves, or 132trillion cubic feet, were inshale deposits, mostly inTexas, Louisiana, Arkansas,and Pennsylvania. Thesedeposits are locatedthroughout the United States,typically where conventionalgas resources also occur.Recently, the Marcellus Shalein Pennsylvania and WestVirginia, the Barnett Shale in

Texas, the Hanesville shale in Louisiana andTexas, and the Fayetteville shale in Arkansashave all seen a significant growth in natural gasproduction.

Tight Gas Sandstone

Tight gas refers to natural gas that hasmigrated into a reservoir rock with high porositybut low permeability.

27


floor of the deep ocean. Although they look likeice, methane hydrates will burn if lit.

Methane hydrates are the most abundantunconventional natural gas source and also themost difficult to extract. While there is muchuncertainty about the total size of the methanehydrate resource, it is conservatively estimatedto be 4,000 times the amount of natural gasconsumed in the United States in 2010.However, the technical challenges ofeconomically retrieving the resource aresignificant, and only a small fraction of the totalresource is found in high enough concentrationsto be feasibly captured.

There is also a significant risk that risingtemperatures from global warming coulddestabilize methane hydrate deposits, releasingthe methane — a potent greenhouse gas —into the atmosphere, and further exacerbatingthe problem.

Biogenic Gas

Certain types of bacteria, known asmethanogens, can produce methane, the chiefcomponent of natural gas, in the process of

These types of reservoirs are not usuallyassociated with oil and commonly requirehorizontal drilling and hydraulic fracturing toincrease well output to cost-effective levels.

Coalbed Methane

Natural gas is often collocated withpetroleum, but it can also be found trappedwithin coal deposits.

Methane has traditionally posed a hazardto underground coal miners, as the highlyflammable gas is released during miningactivities. Otherwise inaccessible coal seamscan also be tapped to collect this gas, knownas coalbed methane, by employing similar well-drilling and hydraulic fracturing techniques asare used in shale gas extraction. As of 2010,slightly more than 6 percent of U.S. natural gasreserves, or 17.5 trillion cubic feet, were incoalbed methane deposits, mostly in Colorado,New Mexico, and Wyoming.

Coalbed methane deposits have alsoattracted interest for their potential for carbonsequestration. Injecting carbon dioxide (CO2)into hard-to-mine coal seams would cause theCO2 to displace the methane locked within thecoal, enhancing therecovery of the naturalgas resource whilestoring the CO2 where itwould not contribute toglobal warming.

Methane Hydrates

Methane hydrates,which consist ofmethane moleculestrapped in a cage ofwater molecules, occuras crystalline solids insediments in arcticregions and below the

28


breaking down organic matter in an oxygen-free environment.

This type of gas is call “biogenic” todifferentiate it from the “thermogenic” or fossilgas produced from organic material buried inthe Earth’s crust at high temperatures andpressures. The properties of biogenic methaneare identical to those of thermogenic methane.

Livestock manure, food waste, andsewage are all potential sources of biogenicgas, or biogas, which is usually considered aform of renewable energy.

One study has estimated that the U.S.technical potential from livestock manure alonecould supply 1 percent of the country’s energyneeds and lead to a 4 percent reduction in U.S.greenhouse gas emissions . Already, dozensof U.S. farmers, particularly in the Midwest,have invested in anaerobic digesters andgenerators to produce electricity and heat (and

extra farm revenue) from livestock wastes.Small-scale biogas production is a well-established technology in parts of thedeveloping world, particularly Asia, wherefarmers collect animal manure in vats andcapture the methane given off while it decays.

Landfills offer another under-utilizedsource of biogas. When municipal waste isburied in a landfill, bacteria break down theorganic material contained in garbage such asnewspapers, cardboard, and food waste,producing gases such as carbon dioxide andmethane. Rather than allowing these gases togo into the atmosphere, where they contributeto global warming, landfill gas facilities cancapture them, separate the methane, andcombust it to generate electricity, heat, or both.

(Source :http://www.ucsusa.org/ - http://www.ucsusa.org/clean_energy/our-energy-choices/

coal-and-other-fossil-fuels/shale-gas-unconventional-sources-natural-gas.html)

“Bureau of Energy Efficiency(BEE) plans to replace the present system of biennial

changes in rating standards with one that lasts longer to reduce the rate of

obsolescence for an energy-efficient model.

The agency also plans to include televisions and geysers from this year under

mandatory energy ratings, which now includes only frost-free refrigerators, air-

conditioners and tube lights.

“The present system of upgrading energy rating norms every two years was

prevalent till the latest change effective this calendar year as per what we had decided

six years ago and hence will now be evaluated,” said BEE director general Ajay Mathur.

“Now that Indian energy rating norms are at par with global standards and consumers

value energy-efficient products, we can continue with the rating standards for a longer

period such as four years,” he said.

(Source: Economic Times)

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India was the fourth-largest consumer ofoil and petroleum products after the UnitedStates, China, and Japan in 2013, and it wasalso the fourth-largest net importer of crude oiland petroleum products. The gap betweenIndia’s oil demand and supply is widening, asdemand reached nearly 3.7 million barrels perday (bbl/d) in 2013 compared to less than 1million bbl/d of total liquids production. EIAprojects India’s demand will more than doubleto 8.2 million bbl/d by 2040, while domesticproduction will remain relatively flat, hoveringaround 1 million bbl/d. The high degree ofdependence on imported crude oil has ledIndian energy companies to diversify theirsupply sources. To this end, Indian national oilcompanies (NOCs) have purchased equitystakes in overseas oil and gas fields in SouthAmerica, Africa, Southeast Asia, and theCaspian Sea region to acquire reserves andproduction capability. However, the majority of

Oil and Natural Gas scenario in IndiaPetroleum and other liquids

imports continue to come from the Middle East,where Indian companies have little directaccess to investment.

Exploration and Production

According to the Oil & Gas Journal (OGJ),India held nearly 5.7 billion barrels of provedoil reserves at the beginning of 2014. About44% of reserves are onshore resources, while56% are offshore. Most reserves are found inthe western part of India, particularly theWestern offshore area near Gujarat andRajasthan. The Assam-Arakan basin in thenortheastern part of the country is also animportant oil-producing region and containsmore than 23% of the country’s reserves and12% of the production.

Historically, ONGC dominated theupstream oil sector and relied on productionfrom Mumbai High basin and its associated

30


fields in the western offshore area. India’s total

petroleum and other liquids production increase

has been very gradual during the past two

decades, growing at less than 2% total and

peaking at 996,000 bbl/d in 2011. Production

has declined slightly to 982,000 bbl/d in 2013.

The Mumbai High, Gujarat, and Assam-Arakan

basins contain mature fields experiencing

production declines, although several

redevelopment projects, enhanced oil recovery

efforts, and marginal field development projects

in these basins are underway to lift production

by 2030.

Indian and foreign companies are investing

in more frontier developments and marginal

fields to help offset production declines from

mature basins. In recent years, major

discoveries in the Barmer basin in Rajasthan

and the offshore Krishna-Godavari basin by

smaller companies such as Gujarat State

Petroleum Corporation and Andhra Pradesh

Gas Infrastructure Corporation hold some

potential to diversify the country’s production.

India’s relatively small land-based resource

endowment means companies require more

upstream technical expertise to tap into offshore

reserves, especially in technically challenging

deepwater reserves. Foreign companies

historically took the lead in exploring new

offshore opportunities. For example, Cairn India

brought online the largest field, Mangala, of the

RJ-ON-90/1 block in Barmer basin in 2009, with

a production capacity of 130,000 bbl/d. The

Rajasthan fields, including Mangala, produced

179,000 bbl/d in 2013, according to FACTS

Global Energy (FGE), and Cairn India reports

production from the fields could peak at 300,000

bbl/d. Despite Cairn’s successful drilling in

Rajasthan, foreign investment in India has

waned in recent years, both because of

increased competition from domestic Indian

companies and India’s complex exploration and

production laws.

The government has encouraged

companies to acquire overseas upstream

assets as a way to shield the domestic energy

sector from global price volatility. Indian

companies hold large stakes in Sudan’s GNOP

block, Russia’s Sakhalin-1 project,

and Venezuela’s San Cristobal and Carabobo

blocks. Amerada Hess Corporation sold key oil

fields in Azerbaijan to ONGC in 2012. Also,

ONGC, OIL, and RIL have taken stakes in gas

plays in Mozambique, shale gas assets in the

United States and Canada, and oil and gas

assets in Myanmar, and the companies are

actively pursuing other overseas upstream

deals. In 2011, several government agencies

agreed to establish a sovereign wealth fund that

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could also aid in financing overseas energyacquisitions.

Downstream and Refining

India’s government started encouragingenergy companies to invest in refineries at theend of the 1990s, and the investment helpedthe country become a net exporter of petroleumproducts in 2001. In particular, the governmenteliminated customs duties on crude imports,lowering the cost of fuel supply for refiners.These reforms made domestic production ofpetroleum products more economic for Indiancompanies. In its 11th Five Year Plan (2007-2012), India’s government set the goal ofmaking India a global exporting hub of refinedproducts.

However, India still imports kerosene andliquefied petroleum gas (LPG) products fordomestic use, and some export-orientedrefineries began reorienting production fordomestic use in 2009 to help ease shortagesof motor gasoline, gasoil, kerosene, and LPG.These products make up 73% of India’spetroleum product consumption, according toFGE. In particular, many rural areas of Indiause LPG and kerosene along with traditionalbiomass as cooking fuels (see Biomass andWaste below). The government is encouraginga shift from kerosene used in cooking fuel inrural areas to LPG, a cleaner and less-expensive fuel. Liquid fuels have competed withnatural gas in the past few years as the powerand fertilizer industries are using natural gasas a substitute for some naphtha and fuel oilsupply. Diesel remains the most-consumed oilproduct, accounting for 42% of petroleumproduct consumption in 2013.

The refining industry is an important part

of India’s economy, and the private sector owns

about 38% of total capacity. At the end of 2013,

India had 4.35 million bbl/d of refining capacity,

making it the second-largest refiner in Asia after

China, according to FGE. The two largest

refineries by crude capacity, located in the

Jamnagar complex in Gujarat, are world-class

export facilities and are owned by Reliance

Industries. The Jamnagar refineries account for

29% of India’s current capacity. These refineries

are close to crude oil-producing regions in the

Middle East, which allows them to take

advantage of lower transportation costs.

India projects an increase of the country’s

refining capacity to 6.3 million bbl/d by 2017

based on its current five-year plan to meet rising

domestic demand and export markets, although

this projection hinges on all proposed projects

becoming operational. Some refinery projects

have faced delays in the past few years, and

there is now greater competition within Asia

from countries such as China that has built large

refineries able to process more complex crude

oil types. Two refineries, Paradip in Odisha and

Cuddalore in the southern state of Tamil Nadu,

are scheduled to be operational by 2015, adding

420,000 bbl/d of capacity. Also, refiners have

plans to upgrade several existing refineries to

produce higher-quality auto fuels to comply with

more stringent specifications for vehicle fuel

standards. India plans to adopt the equivalent

of Euro IV fuel efficiency standards on a

nationwide basis by 2015 and Euro V

standards on passenger cars by 2016.

Refineries have proposed several expansions

to existing facilities and a few new refineries by

2020, although the timeline of these projects

depends on economic recovery and fuel sales

in both domestic and export markets.

32


Crude refining Refinery location Name of company capacity (1,000

barrels/day)

Public Sector

Barauni, Bihar Indian Oil Corp. Ltd. 120

Bongaigaon, Assam Indian Oil Corp. Ltd. 47

Digboi, Assam Indian Oil Corp. Ltd. 13

Guwahati, Assam Indian Oil Corp. Ltd. 20

Haldia, West Bengal Indian Oil Corp. Ltd. 151

Koyali, Gujarat Indian Oil Corp. Ltd. 275

Mathura, Uttar Pradesh Indian Oil Corp. Ltd. 160

Panipat, Haryana Indian Oil Corp. Ltd. 301

Mahul, Mumbai Hindustan Petroleum Corp. Ltd.(HPCL) 131

Visakhapatnam, Andhra Pradesh Hindustan Petroleum Corp. Ltd.(HPCL) 166

Mahul, Mumbai Bharat Petroleum Corp. Ltd. 241

Kochi, Kerala Bharat Petroleum Corp. Ltd. 191

Manali, Chennai Chennai Petroleum Corp. Ltd. 211

Nagapattinam, Tamil Nadu Chennai Petroleum Corp. Ltd. 20

Numaligarh, Assam Numaligarh Refinery Ltd. 60

Mangalore, Karnataka Mangalore Refinery & Petrochemicals Ltd. 302

Tatipaka, Andhra Pradesh Oil & Natural Gas Corp. Ltd. (ONGC) 1

Joint-Venture

Bina, Madhya Pradesh Bharat-Oman Refinery Ltd. 120

Bathinda, Punjab HPCL-Mittal Energy Ltd. 180

Private Sector

Jamnagar Reliance Industries Ltd. 660

SEZ, Jamnagar Reliance Industries Ltd. 580

Vadinar, Gujarat Essar Oil Ltd. 405

Total 4,351

Note: SEZ = Special Economic ZoneSources: U.S. Energy Information Administration, IndiaMinistry of Petroleum & Natural Gas, Oil & Gas Journal, FGE.

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OIL AND NATURAL GAS SCENARIOIN INDIA - NATURAL GAS

Natural gas mainly serves as a substitutefor coal for electricity generation and as analternative for LPG and other petroleumproducts in the fertilizer and other sectors. Thecountry was self-sufficient in natural gas until2004, when it began to import liquefied naturalgas (LNG) from Qatar. Because it has not beenable to create sufficient natural gasinfrastructure on a national level or produceadequate domestic natural gas to meetdomestic demand, India increasingly relies onimported LNG. India was the world’s fourth-largest LNG importer in 2013, followingJapan, South Korea, and China, and consumedalmost 6% of the global market, according todata from IHS Energy. Indian companies holdboth long-term supply contracts and moreexpensive spot LNG contracts.

Natural gas consumption has grown at anannual rate of 8% from 2000 and 2012,although supply disruptions starting in 2011resulted in declining consumption. Natural gasconsumption in India was tied closely todomestic production until imports becameavailable in 2004. In 2012, India consumed 2.1

trillion cubic feet (Tcf) of natural gas. LNGimports accounted for about 29% of 2012demand, and LNG is expected to account foran increasing portion of demand at least in thenext several years as Indian energy firmsattempt to reverse the country’s recentdomestic production declines. Increasing LNGimports will depend on the pace of expansionin regasification terminal capacity and pipelineinfrastructure connecting gas to markets thatcurrently lack access. The country’s pricingsystem is undergoing revision to unlockregulated prices that are well below the importprice levels. Raising gas prices would provideoil and gas firms with economic incentives forupstream development, especially in deepwaterplays and technically challenging fields, andwould allow LNG importers to compete moreeffectively for gas consumers in a higher-pricedenvironment.

The majority of natural gas demand in2012 came from the power sector (33%), thefertilizer industry (28%), and the replacementof LPG for cooking oil and other uses in theresidential sector (15%), according to India’s

34


MOPNG. The government has labeled theseas priority sectors for domestic programs, whichensures that they receive larger shares of anynew gas supply before other consumers. Thefertilizer sector, which is highly price-sensitive,has been able to maintain low fuel costs byusing natural gas. The recent unexpectednatural gas production declines since 2011 haveforced electric generators to seek fuelalternatives, primarily coal. The government ispromoting the use of natural gas in theresidential sector as an alternative to LPG as acooking fuel.

Exploration and Production of Natural Gas

According to the Oil & Gas Journal, Indiahad 47 Tcf of proved natural gas reserves atthe beginning of 2014. About 34% of totalreserves are located onshore, while 66% areoffshore, according to India’s Ministry of Oil andGas. In 2002, energy companies made anumber of large gas discoveries in the Krishna-Godavari (KG) basin off of India’s eastern coast,pushing up both the reserve base andproduction. However, production from some ofthe more mature fields have declined in recentyears, and RIL cut the recoverable reserves ofits two major gas fields in the major D6 block(D1 and D3) in the KG basin from 10.3 Tcfestimated in December 2006 to 3.1 Tcf in 2012because of unexpected declines and reservoirperformance problems.

Total gas production in India amounted toaround 1.5 Tcf in 2012. The two biggest state-owned companies, ONGC and Oil India Ltd.(OIL), dominate India’s upstream gas sector.ONGC operates the Mumbai High Field, whichprovides a large amount of India’s natural gassupply. ONGC remains India’s largest naturalgas producer, accounting for 62% of thedomestic production in 2012 as reported in thecompany’s annual report. However, the

government has encouraged private andforeign companies to enter the upstream sectorin recent years. RIL is becoming a majorupstream force because of natural gasdiscoveries in the Krishna-Godavari basin. RILhas a strategic partnership with BP, which hasa 30% stake in 21 of RIL’s production-sharingcontracts. Other major international oilcompanies do not have significant investmentsin India’s natural gas upstream sector. India’sMOPNG estimates that gas productioncontinued to decline during 2013.

The KG-D6 field came online in early 2009,ramping up production to hit a peak of morethan 2.4 billion cubic feet per day (Bcf/d) or 876Bcf per year (Bcf/y), in 2010. However, the fieldhas experienced production shortfalls in recentyears, and output dropped to 0.4 Bcf/d (146Bcf/y) at the end of 2013. RIL and BP plan totie in production from satellite fields and invest$5-10 billion to restore the production of theD6 block to more than 2.1 Bcf/d (767 Bcf/y) by2020.

ONGC and Gujarat State PetroleumCorporation Limited (GSPCL) are alsodeveloping several offshore areas in Krishna-Godavari basin. Another promising producingarea is the Cambay basin in western India,where independent company Oilex has donesome preliminary work assessing the potentialfor tight natural gas.

Liquefied Natural Gas

Liquefied natural gas (LNG) has becomean important part of India’s energy portfoliosince the country began importing it from Qatarin 2004. In 2013, India was the world’s fourth-largest LNG importer, importing 638 Bcf, or 6%,of global trade, according to data from IHSEnergy. Petronet, a joint venture between GAIL,ONGC, IOC, and several foreign firms, is themajor importer of LNG supplies to India.

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Petronet owns two existing LNG terminals,Dahej (480 Bcf/y) and Kochi (120 Bcf/y). Shell(74% share) and Total (26% share) jointly ownthe Hazira terminal (240 Bcf/y), which operatesas a merchant facility, importing only short-termand spot cargoes at present. India’s totalregasification capacity now stands at 936 Bcf,and terminal owners have proposed capacityexpansions at all existing terminals. Expansionunder construction at Dahej will increase theterminal’s capacity to 720 Bcf by 2016.

Unexpected production declines in India’sKG-D6 gas field mean the country must relyon higher LNG imports. Average imported LNGprices have increased to three times the priceof domestically produced natural gas becausethey are not subject to the government settingprices through the Administered PriceMechanism (see Sector Organization). Indianproducers such as RIL have asked thegovernment to raise the wellhead price for gas(the wholesale price at the point of production)as a way of justifying investment into deepwaterprojects. If the proposed gas pricing reform isimplemented, there will be greater investmentincentives for domestic gas development thatcould increase competition for LNG imports.

Indian companies have invested inincreasing the country’s LNG regasificationcapacity in recent years to meet rising demand.In early 2013, GAIL, NTPC, and several othersmaller players restarted the Dabhol project,originally proposed by now-defunct Enron,which includes a regasification terminal to fuelthree gas-fired power stations. Dabhol LNGalso ships natural gas to southern India throughthe new pipeline to Bengaluru. GAIL is installinga breakwater facility to double Dabhol’s capacityby 2017. Petronet’s LNG terminal at Kochi wascommissioned in late 2013. However, theterminal is experiencing low utilization becauseof delays in the approval and construction of aproposed pipeline to Mangalore and other parts

of southern India, according to PFC Energy.The eastern side of India lacks pipelineinfrastructure and gas supply following declinesin the KG basin; thus companies are quicklyplanning terminals to come online in the nextfew years. IOC proposed the Ennore project inTamil Nadu in southeastern India. Otherproposed projects are located along India’seastern coast include three floating terminalprojects at Kakinada and one at Gangavaram.Several proposed regasification projects alongthe western coast include GSPC’s Mundraterminal in Gujarat, expected to be built by2016.

Qatar’s RasGas is India’s sole long-termsupplier of natural gas, with two contracts for atotal of 360 Bcf. In 2013, Qatar was the sourceof 84% of India’s total LNG imports, accordingto IHS Energy. India has been an activeimporter of spot cargoes following interruptionsin the KG-D6 field production after 2010 andbegan receiving LNG cargoes from a varietyof exporting countries. Nigeria, Egypt,and Yemen have become India’s largest short-term LNG suppliers.

Indian LNG importers actively soughtsupply from various new LNG sources andsigned several short- and long-term purchaseagreements in the past few years. India signedagreements to receive supply from Australia’sGorgon LNG terminal and several U.S.terminals (Sabine Pass, Cove Point, and MainPass) and from the portfolio of various globalLNG suppliers such as BG, GDF Suez, GasNatural Fenosa, and Gazprom. As Indiancompanies become more active in pursuingoverseas upstream oil and gas plays, OIL hasinvested in gas projects in Canada (PacificNorthwest LNG) and an offshore gas projectinMozambique (jointly with ONGC) to secureLNG imports for India.(Source : US Energy Information Administration – EIA)

36


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 - 89397 24520RESolve Energy Consultants, New No.7, New Renewable EnergyMalleeswarar Koil Street,. Mylapore, Chennai-600 004.Email: [email protected]

10. Mr. R.Raju Pandi Chairman-Power 94449 22954Flat No.9, 3rd Floor, Hemamanor, Generation Sector23 Branson Garden Street, Kelly’s, CHENNAI-600 010.Email: [email protected]

11. Mr.S.Baskara Sethupathy, Professor & Head Chairman – 94456 33381Department of Civil Engineering Academic interfaceS.A. Engineering College, Chennai - 600 077.Email:[email protected]

37


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.S. Arul, Arul Design MEP Consultant Member 98408 70075New No42/1, Old No.44/1, Ponni Amman Koil StreetBesant Avenue Road, Adyar, CHENNAI-600 020.Email: [email protected]

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

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

20. 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]

21. Dr. Mrs. Hyacinth J. Kennady Member 94448 98258Assistant Engineer / Mechanical, O & ETNEB (TANGEDCO)North Chennai Thermal Power Station,CHENNAI 600 120.Email: [email protected]

22. 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]

23. 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]

38


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

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

26. 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]

27. 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]

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

29. 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]

30. 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]

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

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

33. 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]

34. Dr.R. Venkatraman Member 99427 62255Door No.7, 3rd Cross, 5th Main Road, 94434 92404Srinivasa Nagar South, TRICHY - 620 017.Email: [email protected] / [email protected]

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

36. 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]

39


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

40


Categories and Subscription Rates

Categories Annual Annual Life

Turn-over Subscription Member

Rs. Rs. Rs.

Large Industries Over 100 lakhs 1,000/- 10,000/-

Medium Industries 60 to 100 lakhs 600/- 6,000/-

Small Industries/

Academic Institution 30 to 60 lakhs 400/- 4,000/-

Individual 200/- 2,000/-

Students 100/-

All these categories have a one-time payment of Rs.100/- as Entrance fee at the time of

becoming member.

For all your correspondence, please contact

Energy & Fuel Users’ Association of India4, B-1, J.P. Tower, 7/2, Nungambakkam High Road,

Chennai - 600 034.Phone : 28278604 / 28205553

e-mail : [email protected] / [email protected]

41


ENFUSEENFUSEENFUSEENFUSEENFUSEVolume - LXIV Book - 2

July - September 2014

EDITORIAL BOARD

Associate 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 I sit down to write this editorial, the energy market is witnessing aperhaps historic collapse in oil prices triggered by Saudi Arabia’s decision tooffer discounts to its crude, and its decision not to cut crude oil production.The prices have dropped by more than 25% from the peak this year($112/barrel in mid-June 2014 to $84/barrel on October 15, 2014). The pricereduction is a boon for oil importing countries, especially India, which importsmore than 80% of its crude requirements. It is estimated that the oil subsidybill in India will be cut by about 60% during the financial year as a result ofthe price drop.

The slowing economic growth in OECD countries and China, and theresultant drop in demand for crude oil are cited as the reasons for the pricedrop, but an oversupply of oil is also a reason. The North American oilrenaissance in the form of shale oil and gas has led the USA to become lessdependent on import of oil in the Middle east, thereby diminishingthe powerof the Organization of Petroleum Exporting Countries(OPEC), of which SaudiArabia is the largest producer of oil and also the one with the largest reserves.

Experts are speculating that the move of Saudi Arabia to reduce oilprices and to hold the crude prices to around $80/barrel for about 2 years isaimed at slowing down the shale oil revolution in the USA, and also make ituncompetitive for the Usshale oil producers to compete in the global oilmarkets. Since the Islamic State in Iraq and Syria (ISIS)’s primary source ofrevenue for funding its war is oil, reduced oil prices will hurt their capability toexpand fast, and becomes less threatening to Saudi Arabia. The lower pricesalso hurt Saudi’s rivals Iran and Iraq. Russia, which depends on oil revenuesto run the country, will also be badly hit by the lower prices, and it will havean implication on the Ukraine crisis.

The fast moving action in the crude oil markets reiterate the hugeinfluence of oil on the economies of the world, and also the geopolitics. It isthus very apt(more by default than design) that this edition of the ENFUSEjournal focusses on all the issues mentioned above. We start with a look atthe North American renaissance and follow it with brief histories of theorganizations OPEC and IEA which represent the oil producers and oilconsumers respectively. We then look at the waning influence of OPEC as aresult of the oil renaissance in North America, followed by a look at thepetroleum downstream sector.

In the next section, we focus on Natural Gas, which is fast becomingthe preferred fuel choice across the world due to its characteristics. Wewrap up the journal with a comprehensive look at the scenario of Oil andNatural Gas in India.

We hope that this edition will turn out to be a ready reference for theglobal oil and gas markets. Please let us know your comments and feedback.

Happy reading during the happy festive season!!

MADHAVAN NAMPOOTHIRI

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42


FROM THE PRESIDENT’S DESK

Readers may recall that the PowerMinistry, Govt. of India has proposed toestablish a National Smart Grid Mission(NSGM) by 2014 fol lowing the recentlylaunched National Mission for Electric Mobilityby the Ministry of Heavy Industries. Thisinitiative aims at transforming the Indian powersector into a secure, adaptive, sustainable anddigitally enabled ecosystem providing reliableand quality energy for all with the activeparticipation of stake holders.

Consistent with the message from thePresident’s desk in the earlier issue of ourquarterly journal that the Executivecommittee for the year 2014 -15 will workout ways and means to take the messageof the National Smart Grid Mission to theinvolved segments. Planning is underwayto hold a workshop on SMART CITIES inthe month of Feb 2015. The Indiangovernment plans to develop 100 smart citiesand in this regard an allocation of Rs 7,060crore was proposed in the Union Budget.

While presenting the Budget for 2014-15,Finance Minister Arun Jaitley had said thePrime Minister has a vision of developing 100smart cities as satellite towns of larger citiesand by modernizing the existing mid-sizedcities.

With the Oil and Gas conservation fortnightslated in our country from Jan16th to 31st Jan2015, highlighting on the importance ofconserving the Liquid Gold , our editorial Boardthought that it will be appropriate to bring outthis quarter ly issue ful ly dedicated toinformation on oil and Gas world over.

Oil and Gas politics vary violently fromcontinent to continent. In the INDIANSUBCONTINENT, oil and gas supply positionscontinues to be critical, with a large scaledependency on Imports. Surprisingly thereappears to be Oil and Gas renaissance inNorth America – USA, Canada and Mexico andinteresting articles are appearing on thesubject in this issue. Also the readers canfind interesting overview on The InternationalEnergy Agency formed in November 1974in response to the oil crisis of 1973-74

On the solar energy power generation frontlast quarter witnessed conflicting signals in themarket place. The potential investors continueto be silent spectators, eagerly awaiting for theBREAK !

The Executive Committee deliberated overthe current scenario in Tamil Nadu, AndhraPradesh & Karnataka on the Solar PowerGeneration Activities. The President requestedMr. R Raju Pandi, Former Member, Tamil NaduRegulatory Commission to prepare for aseminar in the first week of January 2015 onthe subject “An Update on Solar PowerGeneration Opportunities in India”. He will besupported by Mr. Madhavan Nampoothiri, Mr.Rajesh & Capt. Dinesh TSR.

Again there is a interesting news flashingfrom the Supreme Court observing “Coal isking and paramount Lord of industry… andremains the dominant fuel for powergeneration.”

Coal plays crucial role in India’s industrialand economic fortunes. This was recentlyemphasised by Supreme Court during thejudgment on captive coal mines in the Country.Industrial Leadership and greatness has beenbuilt upon coal. In India, coal is the mostimportant indigenous energy resource andremains the dominant fuel for powergeneration.

With the festive season round the corner,our warm greetings to the members and theirfamilies.

S. RAMALINGAM

II

43


ENFUSE NEWS

Student Chapter Inauguration on 11th

September 2014 at VIT College

ENFUSE –VIT Student chapterinauguration was held on 11/09/14 at VITUniversity, Chennai campus. Welcomeaddress was delivered by Dr. A. PeerFathima, Professor, School of ElectricalEngineering, VIT, Chennai campus and thefaculty co-ordinator of the student chapter.The chapter activities for the year 2014-15was flagged off by Mr. S. Ramalingam,President- ENFUSE. He was introduced bythe PG student president Mr. Arka Das. ThePresident- ENFUSE delivered a speciallecture on “National Mission For EnhancedEnergy Efficiency” for the benefit of VITstudents and faculty members. 78 studentsof VIT,Chennai were registered for themembership and took part in the discussionsession on energy related issues with thePresident-ENFUSE. The program wasconcluded with the vote of thanks proposedby the student President Mr. Sumit Agarwal.

Student Chapter Inauguration on 12th

September 2014 at Saveetha EngineeringCollege

In a colourful function the Students’Chapter of ENFUSE was inaugurated byPresident, Enfuse on 12th Sep 2014 atSaveetha Engineering College. ThePresident during the inaugural addressportrayed the Energy Scenario in the country

III

and emphasised the need for adoptingEnergy Eff iciency and ConservationMeasures. In this connection the role of thestudents community in spreading themessage with the masses as well as theemerging opportunities were discussed indetail. The event was coordinated by Dr. SMohanamurugan, HOD, Automobile ablysupported by HOD of CSE and HOD Energy& Environment.

Mr.Vineel Satyakanth, student of II yearAutomobile Engineering gave the speakerintroduction.

The vote of thanks was given byMr.SujayJairaman and Mr. MC: RakeshKumar of II year Automobile engineeringstudents.

MCCI Chamber Day on 29th September2014 :

Mr. S Ramalingam, President & CaptDinesh T S R, Secretary attended to theChamber Day function of Madras Chamberof Commerce & Industry (MCCI) at HotelHyatt Regency, on 29th September 2014.The Chief Guest Dr. Arvind Mayaram IAS,Secretary, Ministry of Finance,

Department of Economic Affairs,Government of India addressed the gatheringportraying the Economic Policies of theGovernment of India.

44


CONTENTSPage No.

1. PETROLEUM - OIL AND GAS RENAISSANCE IN NORTH AMERICA – USA,CANADA AND MEXICO 1

2. A BRIEF HISTORY OF OPEC 3

3. BRIEF HISTORY OF INTERNATIONAL ENERGY AGENCY (IEA) 5

4. ENERGY SUPPLY – NEW SOURCES, NEW GEOPOLITICS; THE WANINGINFLUENCE OF OPEC 7

5. WORLD DOWNSTREAM SCENARIO 2013 – PETROLEUM REFINERIES 11

6. SHALE GAS, CBM AND OTHER UNCONVENTIONAL GAS 25

7. OIL AND NATURAL GAS SCENARIO IN INDIA PETROLEUM AND OTHER LIQUIDS 29

8. OIL AND NATURAL GAS SCENARIO IN INDIA - NATURAL GAS 33

IV

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

energy & fuel users’ journal jul. – sep. 2014...

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