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ENERGY SOLUTIONS FOR ALLPromoting Cooperation, Innovation and InvestmentThe Official Publication of the 20th World Petroleum CongressOfficial Host Sponsor

Total would liketo thank Qatarfor its generous hospitalityat the 20 th World Petroleum Congress.As a leading international oil and gas company, Total’s mission is to meetthe world’s energy needs. We first came to Qatar in 1936, and over thelast 75 years we have been proud to contribute to the development of thecountry’s natural resources and the advancement of its most valuableasset, its people. Backed by our strong culture of long-term cooperation,we are committed to being your partner of choice.www.total.com

ENERGY SOLUTIONS FOR ALLPromoting Cooperation, Innovation and InvestmentThe Official Publication of the 20th World Petroleum CongressMobile Version: Scan this code with your smartphone or visitwww.world-petroleum.org/app to download the 20th WPC mobile app,sponsored by Chevron. It’s the convenient way to plan your visit, scheduleyour time and engage with other attendees throughout the event.www.world-petroleum.orgProduced and published by56 Haymarket, London SW1Y 4RN, UK • Tel: +44 (20) 7389 9650 • Fax: +44 (20) 7389 9644 • Email: publisher@world-petroleum.netEditor David Buchan obeManaging Editors Dr Pierce Riemer, Ulrike Von Lonski (World Petroleum Council)Chairman and Founder Rupert Goodman, Chairman, Advisory Council Rt Hon Lord Hurd of Westwell ch cbe pcChief Operating Officer Eamonn Daly, Executive Publisher Alastair Harris, Production Manager and Design Jon Mark DeaneRegional Publisher Declan Hartnett, Consultant, Public Affairs Lord Cormack fsaNon-Executive Directors Timothy Bunting, Hon Alexander Hambro Vice President, European Affairs Cristina BruceMarketing Administrator Chris Cammack, PA – Chairman’s Office Hilary WinstanlyEditorial Consultant Jonathan Gregson, Secretariat Gil Pearson, Senior Staff Writer Nicholas LyneSpecial Advisor, China Lord Powell of Bayswater kcmg, Special Advisor, Russia Sir Andrew Wood gcmgSpecial Advisor, Latin America Jacques Arnold, Special Advisor, Global Issues Professor Victor Bulmer-Thomas cmg obeWorld Petroleum is composed of the opinion and ideas of leading business and political figures. All information in this publication is verified to the best of the author’s and publisher’s ability, but no responsibilitycan be accepted for loss arising from decisions based on this material. Where opinion is expressed, it is that of the authors. The views expressed and the data contained in this publication are not necessarily thoseheld or agreed by World Petroleum or the World Petroleum Council. All rights reserved. Reproduction in whole or in part without written permission is strictly prohibited. Colour transparencies or manuscriptssubmitted to the magazine are sent at owners’ risk; neither the company nor its agents accept any liability for loss or damage. Copyright 2011, FIRST/World Petroleum. All rights to World Petroleum are vested in FIRST.

Partnering to meetthe challengesof the future.BP’s analysis of the future energy landscapeindicates that demand for energy is set to increaseby up to 40 percent over the next 20 years.Meeting this rapid growth in demand is a hugechallenge that will require extensive resourcesand capabilities. The task of providing energysafely, reliably, affordably and sustainably willbe an exercise in collective problem-solving.This is why we value our relationships andregard it as a privilege to work in partnershipwith governments, NOCs and other internationalcompanies around the world.

BP and Partners at work in: Khazzan 5 in Central Oman; Tangguh plant in Papua, Indonesia; Greater Plutonio, offshore Angola; Southern Rumaila, Iraq.

ConocoPhillips is a Proud Platinum Sponsor ofThe 20th World Petroleum CongressDoha, Qatar • 2011Finding solutions to provide global access to reliable, affordable andsustainable energy through cooperation, innovation and investment.

CONTENTSforewordsPromoting Cooperation, Innovation and Investment 11By Dr Randy GossenPresident, World Petroleum CouncilWPC’s role in forging the past and crafting the future 13By Dr Pierce RiemerDirector General, World Petroleum CouncilA World Petroleum Congress in the Middle East at last! 15By His Excellency Dr Mohammed Bin Saleh Al-SadaMinister of Energy & Industry, Qatar and Chairman, Qatar PetroleumAllied interests of private and national oil companies 40By Christophe De MargerieChairman and CEO, TotalBuilding the service company of the future 44By David LesarChairman, President and CEO, HalliburtonOPEC: The importance of security of demand as well 48as supplyBy Abdalla Salem El-BadriSecretary General, OPECGECF: A new participant in the natural gas market 52By Leonid BokhanovskySecretary General, Gas Exporting Countries ForumThe view from the world’s biggest energy user 56By Professor Wang ZhenChina Univeristy of Petroleum at BeijingIndia’s emerging energy needs and supply options 60By Kirit S ParikhChairman, Integrated Research and Action for Development, New DelhiIndia: Maximising output, while facilitating imports 64By R P N SinghMinister of State for Petroleum and Natural Gas, IndiaCooperationPartnering to meet the challenges of the future 20By Bob DudleyGroup Chief Executive, BPSeeking oil market stability 26By His Excellency Ali Al-NaimiMinister of Petroleum and Mineral Resources, Saudi ArabiaIncreasing importance of Arab oil and gas producers 30By His Excellency Abbas Ali NaqiSecretary General, OAPECLessons from the last decade, strategies for the next two 34By Andrew GouldChairman, SchlumbergerNew producer-consumer dialogue: What to expect? 66By Noé van HulstSecretary General, International Energy ForumEurasian Pipelines: From Beijing to Berlin 70By John RobertsEnergy Security Editor, PlattsNabucco: A pioneering pipeline project 72By Reinhard MitschekManaging Director, Nabucco Gas Pipeline InternationalThe politics of pipeline permitting in North America 74By Sheila McNultyUS Energy Correspondent, Financial TimesTanker owners weather stormy economic conditions 76By Juliet WalshFreight Editor, Argus Media GroupEnergy Solutions For All 5

GE Oil & GasFueling thefuture togetherAfter more than 80 years of working in this great region, we are just asexcited as we were on day one. Our relationships within the Middle Easthave led to some of the world’s most innovative technologies and industrymilestones. Through investing in local partnerships we have maximisedprocess, skill and technology transfer across the region and togetherwe’ve made breakthroughs, headlines and friends. We look forwardto another 80 years of successful partnerships.geoilandgas.comGE imagination at work

CONTENTS ContinuedBuilding a truly sustainable energy system 78By Aron CramerPresident and CEO, BSRDemocracy and oil: A combustible mix 80By Keith MyersPartner at Richmond Energy Partners and Adviser to theRevenue Watch InstituteQatar’s mix of long-term contracts and flexible supply 83Interview with His Excellency Dr Mohammed Bin Saleh Al-SadaMinister of Energy & Industry, Qatar and Chairman, Qatar PetroleumSetting a new legal framework for Nigeria 86By Diezani Alison-MaduekeMinister of Petroleum Resources, NigeriaPromoting E&P in Peru’s mature and frontier basins 90Perupetro: A profilePost-Macondo reforms: The new regime in US waters 102By Michael R BromwichDirector, US Bureau of Ocean Energy Management, Regulationand EnforcementThe potential in Russia’s new energy frontiers 106By Professor Anatoly ZolotukhinGubkhin Russian State University of Oil and GasThe promise and the problems of developing the Arctic 110By Kieran CookeEditor, Arctic MonitorThe promise of Canada’s oil sands 112By Martin RomanowPresident and CEO, NexenThe power of integration to produce ingenuity at speed 116By John McDonaldVice President and Chief Technology Officer, Chevron CorporationResearching the future 119By Ashok BelaniChief Technology Officer, Schlumberger LimitedNatural gas ready to meet the world’s energy challenges 122By Dr Abdul Rahim HashimPresident, International Gas UnionJapan’s energy position post-Fukushima 126By Nobuo SekiFormer President of Chiyoda CorporationInnovationThe need to train the innovators of tomorrow 94By Rex W TillersonChairman and CEO, ExxonMobil CorporationPre-salt production development in Brazil 96By Guilherme EstrellaHead of Exploration and Production, PetrobrasBrazil’s deepwater: A financial as well as a technical challenge 100By Gareth ChetwyndSouth America Correspondent, Upstream NewspaperUnconventionals: The world has and needs tight oil 128By Greg HillPresident, Worldwide Exploration and Executive Vice-President, HessCan the US shale gas revolution be repeated elsewhere? 130By Peter HughesDirector, Head of Energy Practice, Ricardo Strategic ConsultingShale gas: Poland starts prospecting 132By Professor Stanislaw Rychlicki and Marek KarabulaAGH Univeristy of Science and Technology, Krakow and Vice-President,PGNiG respectivelyAiming to meet needs at home & sustain market share abroad 134Interview with Nordine CherouatiChairman and CEO, SonatrachEnergy Solutions For All 7

COLOMBIAThe ANH is the authority responsible for promotingthe optimal and sustainable development of thecountry’s hydrocarbons resources, through an integralmanagement approach that harmonises the interests ofsociety, the State, and the companies of the sector.Av. Calle 26 # 59-65 (of. 201)PBX (57+1) 593 1717 • Fax (57+1) 593 1718Bogotá, D.C. - Colombia| www.anh.gov.co | info@anh.gov.co |

CONTENTS ContinuedPearl GTL: Making liquids out of gas on a grand scale 138By Andrew BrownExecutive Vice-President, Shell QatarFloating Liquefaction (FLNG): How far will it go? 142By David LedesmaSenior Associate, Oxford Insitute for Energy StudiesCarbon capture and storage and the oil and gas sector 146By Brad PageChief Executive Officer, Global CCS InstituteThe challenge of sustainable biofuels 149By Anselm Eisentraut and Michael WaldronRenewable Energy Division and Oil Industry and Markets Division,respectively, International Energy AgencyFuture propulsion for personal mobility 152By Chris Borroni-Bird and Mary Beth StanekGeneral MotorsInvestmentGlobal upstream spending hits new highs 167By Iain BrownHead of Regional Upstream Research, Wood MackenzieMeeting rising demand and offsetting production decline 172Interview with Fatih BirolChief Economist, International Energy AgencyOil: Changing tides 174By Amrita SenOil Analyst, Barclays CapitalTrends in global gas pricing 178By Howard V RogersDirector, Natural Gas Research Programme, Oxford Institute for Energy StudiesEnergy project finance and bank capital constraints 182By Peter GawManaging Director, Global Head of Oil & Gas, Standard Chartered BankWPC New Member ProfileTrinidad and Tobago: First mover, still in the game 154By David RenwickCaribbean Energy Correspondent, World PetroleumPutting money aside: The Norwegian example 186By Wilhelm MohnMinistry of Finance, NorwayPetroleum fiscal terms: Old and new challenges 191By Philip DanielDeputy Division Chief, Fiscal Affairs Department, IMFEnergy Solutions For All 9

Promoting Cooperation,Innovation and InvestmentBy Dr Randy GossenPRESIDENT, World Petroleum COuncilIwould like to welcome each and every one of you to the20th World Petroleum Congress in Qatar. This Congresswill be a “First” in many ways: the first time for the WorldPetroleum Council to hold its triennial event in the MiddleEast, the first time to reach over 2,000 submissions for our Callfor Papers, and the first time we have a sold out exhibitionnearly a year before the event takes place. I am sure thereare many other “firsts” to share with you. They all point to thefact that this event has been exceptionally well targeted andorganised and that we have selected the right theme for theCongress to unify all that will be happening in Doha from 4-8December 2011.It is clear that there is not any single solution to ourenergy challenges but a union of the following: Investment,Innovation and Cooperation. We will be addressing thesechallenges throughout our extensive programme at theCongress, but we have also asked some of our key speakersand other industry leaders to share with us their thoughtson how we can provide energy solutions for all.One of the keys will be investment. Although economicgrowth and the liberalisation of markets all over the worldhave spurred significant demand for oil and gas over thelast decade, we are now going through more difficult timeswhich has significantly impacted the oil and gas sector.This has resulted in a major cutback in new investments inthe industry. The IEA estimates global demand for oil to rise to106 mb/d in 2030. 80 per cent of all energy comes from fossilfuels and that level is not expected to change very much by2030 or even 2050. Much of this increase in supply will haveto come from unconventional oil and gas which will requirehigher sustained prices. According to the IEA, 64 mb/d ofgross capacity needs to be installed between 2007 and 2030– six times the current capacity of Saudi Arabia – to meetdemand growth and offset decline. In the current economicsituation it is unlikely that these levels of investment will bemet, although those that are cash rich and have access tocredit will be able to take advantage of new opportunities.However one of our greatest assets are the people in ourindustry and investing in the next generation and engagingthem early and fully will provide us with the necessary tools tosucceed in meeting the future energy demands.The second driver is innovation. With conventionalreserves of oil and gas that are easy to access and inexpensiveto produce largely gone now, the industry is exploring inever more challenging new frontiers where large oil and gasdiscoveries are still being made. The development of suchnew discoveries will require deployment of cutting edgetechnologies delivered in an environmentally safe manner.Enhanced oil recovery is still one of the more promisingareas to increase reserves and production from existingfields. The development of new technologies is significantlyincreasing recovery factors and prolonging the life of matureoil and gas fields. Unconventional oil and gas resources arequickly becoming technically feasible and economicallyvery attractive.None of these can work without cooperation. Despite thecurrent economic situation, many of the largest oil and gascompanies are actually maintaining or raising their capitalinvestments to address the ongoing need to add reservesand grow production. This brings about new opportunitiesfor international oil companies (IOCs) to partner withnational oil company (NOCs) on a long-term, sustainablebasis. The economic crisis can therefore be a good timeto focus on forming and strengthening strategic alliances,particularly with NOCs.Cooperation between IOCs and NOCs is not without itschallenges: there are significant cultural, philosophical andsocial differences that can make working together awkwardat best and sometimes impossible. In addition, the possibilityof government changing the rules can pose a real riskand induce added uncertainty. Furthermore, governmentplaying the combined roles of policy maker, regulator,partner and investor is a complex mix requiring considerableskill, understanding and flexibility. Notwithstanding thesechallenges, the rewards of enhanced cooperation aresignificant for both parties. The World Petroleum Council(WPC) can facilitate the building of important bridges forthe two sides to find ways to work together.Strategic alliances enable businesses to gain competitiveadvantage through access to a partner’s resources, includingknowledge, markets, technologies, capital and people.Teaming up with others adds complementary resourcesand capabilities, enabling participants to grow and expandmore quickly and efficiently.Cooperation is not restricted to building relationshipsbetween companies, it also applies to enhancingrelationships with governments, non-governmentorganisations, academia, international institutions and thepublic. For critical issues such as climate change, no onesector of society can provide the answers on its own, butwill require cooperation among all sectors.I look forward to sharing with you the thoughts of ourindustry leaders on these issues here and at the 20th WorldPetroleum Congress.•Energy Solutions For All 11

WPC’s role in forging thepast and crafting the futureBy Dr pierce riemerDirector General, World Petroleum COuncilTo welcome delegates to the 1st World PetroleumCongress in 1933 its founder Mr Thomas Dewhurst,a geologist by profession, expressed the view that“Since World War I the developments which havetaken place in each and every branch of petroleumtechnology have been astounding, actually like arevolution. The stage has therefore been reached whenit is not merely desirable, but even imperative, thatrepresentatives from as many countries as possibleshould meet to discuss problems of this newer and betterworld of petroleum technology”. He was speaking torepresentatives of 28 nations in London and here we arenow in Qatar in 2011 with over 90 countries attending.Our forefathers in 1933 had a dream. Mr Dewhurst stated“Some day the World Petroleum Congress might becomea ‘League of Nations’ for Petroleum Technologists, andindirectly and subconsciously play a part in internationalgood feeling and fellowship.” Good feeling and fellowshipwas maintained by the WPC throughout the years and afterDoha we move to the next Congress in Moscow in 2014.The purpose of the WPC was “The management of theworld’s petroleum resources for the benefit of mankind”and that purpose hasn’t changed. Content and issueshave. In the beginning it mainly comprised oil and gastechnology and science. Today the much broader agendaincludes managerial, financial, environmental and socialissues. Mr Dewhurst and his colleagues would be surprisedto see these accomplishments today, but I am sure wouldalso be very happy to observe that what they started iscontinuing to go from strength to strength.Energy is the lifeblood of economic and socialdevelopment. The share of oil and gas is essential andrising. Oil and gas will not last forever, but it will be vitalfor global development in the many decades to come.Transitions will take place towards other forms of energyproduction and use but the oil and gas industry will alwaysbe an active leader and partner and the people who willshape the future will be at the 20th WPC in Doha.With the focus on the future and what is required froma technological point of view we often forget that we willneed more people on the ground to do the work. This isa real issue and the number of young people joining theindustry or even graduating in relevant areas has beensteadily decreasing in many countries. This growing skillsgap may impede the industry’s very ability to operate,especially in respect to major exploration and productionprojects. This challenge is particularly significant in thecontext of the world’s rapidly growing demands for energyand calls for greater adherence to responsible social andenvironmental practices.In response to this challenge the World PetroleumCouncil formed its youth policy. A Youth Committee wascreated that has grown in size each year since its formationin 2006. It brings a higher profile to the issue and formsan alliance with young people themselves in order tofind possible solutions to our challenges. We feel that itis important that young people are at the forefront ofresolving the issues, as they are the ones who will inheritthis industry and should be involved in crafting its future.The Youth Committee has prepared a unique programmeof activities for young people at the Congress includinga special round table with industry leaders to discuss theburning questions of today.The future of the WPC depends on its ability to stayneutral and non-political. It is imperative to be willingto intelligently and comprehensively discuss issues nomatter how controversial. The greatest impact will beachieved by working closely with other organisationsand professional bodies. Not only those who work in theindustry but everyone.•History of the Congress2011: 20th WPC Doha, Qatar2008: 19th WPC Madrid, Spain2005: 18th WPC Johannesburg, South Africa2002: 17th WPC Rio de Janeiro, Brazil2000: 16th WPC Calgary, Canada1997: 15th WPC Beijing, China1994: 14th WPC Stavanger, Norway1991: 13th WPC Buenos Aires, Argentina1987: 12th WPC Houston, United States1983: 11th WPC London, United Kingdom1979: 10th WPC Bucharest, Romania1975: 9th WPC Tokyo, Japan1971: 8th WPC Moscow, Russia1967: 7th WPC Mexico City, Mexico1963: 6th WPC Frankfurt, Germany1959: 5th WPC New York, United States1955: 4th WPC Rome, Italy1951: 3rd WPC The Hague, Netherlands1937: 2nd WPC Paris, France1933: 1st WPC London, United KingdomEnergy Solutions For All 13

A World Petroleum Congressin the Middle East at last!Foreword by His excellency Dr Mohammed Bin Saleh Al-Sada,Minister of Energy & Industry, Qatar and Chairman, Qatar PetroleumIhave great pleasure in welcoming you to the 20th WorldPetroleum Congress (WPC) which is being held under thepatronage of His Highness Sheikh Hamad Bin Khalifa AlThani, the Emir of the State of Qatar.We are honoured and delighted that the State of Qataris hosting the 20th WPC, as this is the first time since itsinception in 1933 that this event is being held in theMiddle East. This is a great testament to the importanceof Qatar as a key member within the GCC region and theglobal energy industry.The WPC is undoubtedly the biggest and mostprestigious event in the oil and gas industry calendar, andwe have ensured that the legacy of the Congress continuesfar beyond 2011and this Congress is set to be the biggestyet. We are delighted to welcome an expected 4,000delegates, 40 Ministers of Energy, 600 press and media, 550presenters, 500 exhibitors and more than 12,000 exhibitionvisitors to the Qatar National Convention Centre (QNCC),where iconic design and cutting edge facilities cometogether in the latest green technology venue in theMiddle East.I am sure the Congress will be a successful and memorableoccasion that will not only celebrate the achievements of thepetroleum industry, but also make a valuable contributionto the sharing of information and ideas within the energysector. The theme – “Energy Solutions for All: PromotingCooperation, Innovation and Investment” – providesan excellent opportunity for delegates to discuss thepetroleum industry’s role in delivering reliable, affordableand sustainable energy to the global market.A broad range of topics will be discussed at the Congress –such as the role of gas in the global energy mix, innovationsin the supply chain, complementary energy sources and,importantly, the industry’s commitment to sustainability.Given the high calibre of the speakers that will be presentat the Congress, I am sure that even the most experiencedindustry professional will come away from the Congresshaving learnt something new.I would like to thank all sponsors, official partners andparticipants for their support and commitment to the20th WPC. I am sure that the Congress will be an historiclandmark for all the participants and we can all celebratethe global achievement and impact that the energy sectorcontributes to our day to day activities.Finally, I hope you enjoy your stay in Doha, Qatar, and Iwish you a very successful event.•Energy Solutions For All 15

1820th World PETROLEUM Congress

CooperationThe world petroleum industry is, in some ways, unusually cooperative. In no other industry docompanies, which compete in downstream retail markets, share risk and investment as they doin upstream oil and gas exploration. They need to. Their risks are big and their investments huge.Cooperation between governments of producing and consuming countries is equally importantto manage energy’s geo-politics and economic impact.For the producers, Ali Al-Naimi, the oil minister of Saudi Arabia, the world’s ‘swing producer’ of oil,Abdalla el-Badri, the secretary general of OPEC and Leonid Bokhanovsky of the GECF, acknowledgeconsumers’ desire for security of energy supply but stress producers must also have some securityof energy demand if they are to make the necessary investments. The importance of the MiddleEast in general, and Qatar in particular, is underlined by Abbas Ali Naqi, and Dr Mohammed BinSaleh Al-Sada. Producers can take reassurance about demand from China, which has become theworld’s ‘swing consumer’ of all forms of energy and which, as Professor Wang shows, finds it hard toactually restrain its rate of growth. Another driver of oil demand is India, as articles by the oil minister,R.P.N.Singh, and Dr Parikh show. Producers and consumers differ over causes of oil price volatility,but share an interest in removing it. One way is to make the oil trade more transparent by publishingmore information through the JODI oil data intiative, coordinated by the International EnergyForum. Noé van Hulst, IEF secretary general, delivers a gentle rebuke to countries lagging behindin providing better monthly oil data. It’s not surprising there are laggards. Nearly 100 countriesparticipate in the JODI oil initiative, which may be expanded into gas.Bob Dudley of BP points out that the once clear divide between international (IOCs) and national(NOCs) oil companies is beginning to blur in some cases with the emergence of some INOCs –national oil companies going international. Their ability to do so, and indeed the whole industry’scapacity to explore new frontiers and achieve new efficiencies, is in very large part due to theservice companies, whose evolution is charted by Dave Lesar of Halliburton and Andrew Gouldof Schlumberger. Nonetheless, as WPC president Randy Gossen says, IOC-NOC cooperation is “notwithout its challenges.” But it would be inefficient, argues Christophe de Margerie of Total, for NOCsto stick to their own reserves and IOCs to focus only on unconventional oil and gas. Joint venturesare the way to share experience and technology, and the best are those that develop a culture oftheir own out of a synergy between their parent companies. Nigeria’s oil minister, Diezani Alison-Madueke, stresses partnership with foreign companies.Cooperation must also extend to stakeholders in the wider community, addressing environmentaland climate concerns. Aron Cramer of BSR calls on energy companies to “join efforts to puncturethe view that short-term shareholder advantage is the sole way to define fiduciary responsibility”,while Keith Myers suggests that governments in energy-rich countries sharing more informationwith their own parliaments would make for more settled oil policy regimes.A cooperative approach can also be essential in the delivery of energy, not in the oil tanker tradewhose separate problems are described by Juliet Walsh, but as illustrated in the articles by ReinhardMitschek, John Roberts and Sheila McNulty on international pipelines. Fixed infrastructure can raisequestions of security of supply, and cause friction even between the best of neighbours. •Energy Solutions For All 19

CooperationPartnering to meet thechallenges of the futureBy Bob DudleyGroup Chief Executive, BPIt is fitting that this 20th World Petroleum Congressis being hosted in the Middle East. It recognises theregion’s importance for energy in the past and thepresent, but, more important – it signals just howsignificant the Middle East will be for the future.The Middle East has been central to the world’s energysupplies since the time of the first Congress in London in1933. That was a time when the foundations of the oil and gasindustry in this region were being established – with majordiscoveries in Iraq, Iran, Bahrain, Kuwait and Saudi Arabia.Indeed, in that same year, the forerunner of BP, the Anglo-Persian Oil Company, formed a joint venture called theKuwait Oil Company, which a few years later discoveredthe Burgan anticline structure – one of the largest oil fieldsin the Middle East.As we all know, such discoveries continued – and todaythe Middle East accounts for over half of the world’s oilreserves and almost half of its gas.However, this event is primarily a time to look ahead –and projections show that this region is likely to becomeeven more important for energy supply in the future.For example, our own analysis in BP suggests the region’sshare of oil production will grow from around 30 per centtoday to 37 per cent by 2030.What’s more, the Middle East is becoming very important interms of consumption as well as production. Energy demandBillion toe1816141210World energy demand 1990-2030 – emerging economiesaccount for over 90 per cent of the growth864201990Non-OECDOECD2000201020202030Billion toe181614121086420199020002010in this region is expected to increase by nearly 80 per cent by2030, twice the rate projected for the world as a whole.Meeting the rapidly increasing demand for energy –here and around the world – is a huge challenge that willrequire all of our capabilities as an industry. It is thereforeappropriate that the Congress theme is Energy Solutionsfor All – Promoting Cooperation, Innovation and Investment.Global Energy OutlookIn BP’s recent analysis of the future energy landscape –our Energy Outlook 2030 – we painted a picture of greatopportunity but unprecedented challenge. The headlinesindicate that in the most likely scenario, 40 per cent moreenergy will be required globally within the next 20 years,with over 90 per cent of this growth expected to comefrom emerging economies.In terms of sufficiency, the industry has to go to newfrontiers – in deeper water, in unconventional gas, in heavyoil, and in remote areas like the Arctic Circle in order tomeet the growing demand. This brings a new scale of risksfor our collective industry to manage.In terms of energy security, we see a growing disparitybetween producer and consumer countries. History tellsus that the pursuit of so-called ‘energy independence’ isoften impractical, whereas greater co-operation combinedwith energy diversity offer the greatest benefit.In terms of sustainability,2020*includes biofuels2030Renewables*HydroNuclearCoalGasOilwhether or not there is a majorinternational agreement ongreenhouse gas emissions,we must press on with actionsthat are good for all seasons –not only to address climatechange but also energysecurity. Among these areenergy efficiency, renewableenergy sources, technologicalinnovation, open marketsand an economy-wide pricefor carbon.These three sets ofchallenges – sufficiency,security and sustainability– are ones that are beyondany one company orgovernment’s capacity toresolve. All three challenges2020th World PETROLEUM Congress

Cooperationask big questions about trust: trust that industry can deliversufficient supplies; trust that governments will support themarket in delivering security; and trust that industry andgovernments can together find ways to limit greenhousegas emissions without damaging economies.Trust and co-operation are two sides of the same coin.And it is by finding new and deeper forms of co-operationbuilt on trust that we will meet these challenges.Let us look at two areas of co-operation which I thinkare fundamental to the way we need to operate goingforward – first, partnership in managing risk and, second,partnership between International Oil Companies (IOCs),National Oil Companies (NOCs) and governments.Managing RiskOne of the most fundamental areas for potential cooperationin our industry is safety and risk management.The Gulf of Mexico oil spill in which 11 colleagues lost theirlives was a tragic accident. We are grateful for the way inwhich many industry partners worked with us to solve theunprecedented challenges of sealing a well a mile belowsea level, containing oil and responding on the shore.Over one year later, we are still working hard to meetour commitments. On the ground, our focus has shiftedfrom response to recovery. Across BP, we are resetting thecompany as we make progress against the three prioritieswe laid out earlier this year. Theseare: putting safety and operationalrisk management at the heart of thecompany; rebuilding trust with thosearound us; and taking steps to delivervalue for our shareholders.Starting with safety, we havecreated a powerful new safetyand operational risk organisation(S&OR) which sets requirements andprovide deep technical expertise toour operating businesses. This teamof professionals, with experiencein high-hazard industries, fromnuclear power to chemicals as wellas energy, has the authority to stopoperations and drive correctiveactions. We have many examplesnow where line managers, workingwith S&OR, have decided to haltactivity to ensure safe operations.We have developed new and more rigorous standardswhich exceed industry norms. For example, we havedecided that a BP-contracted rig will not drill a deep waterreservoir from a dynamically positioned drill ship unless ithas two sets of blind shear rams. In the Gulf of Mexico,we are implementing a new set of voluntary deepwateroil and gas drilling standards which go beyond existingregulatory obligations and reflect our determination toapply the lessons learned from the incident.We are conscious that others are interested in what wehave experienced and learned and BP is working withothers in the industry to help improve safety, better preventaccidents, and enhance the industry’s response capabilities.Without in any way minimising our own responsibilities,we believe it is important to share what we have learnedin a spirit of partnership as the industry takes on thechallenges of working at new frontiers such as ever deeperwater and the Arctic Circle.We have briefed governments, regulators and partnersin 20 countries and held over 50 engagement events. Weare continuing to work productively with the US regulator,the Bureau of Ocean Energy Management, Regulation& Enforcement and many other regulatory bodiesworldwide. We have shared equipment and technologywithin the industry, for example with the Gulf of Mexico’sMarine Well Containment Company. →A process safety advisor at the Tangguh plant in Papua, Indonesia, discusses a permit towork with BP contactorsEnergy Solutions For All 21

Cooperation→ Our work also includes providing ‘top hat’ containmentsystems to the UK North Sea, managing the UK Oil SpillPrevention and Response Advisory Group (OSPRAG)project to construct the next-generation capping stack,and building a new BP global capping and containmentsystem that is ready to be transported by air freightanywhere in the world in the event of a crisis.Earning back trust takes time, but it is encouragingthat during 2011 we have seen new acreage awards inAustralia, Indonesia, Azerbaijan, the UK, the South ChinaSea and Trinidad, among others. A high-quality, materialposition in Brazil has been achieved with the completionof the acquisition of Devon Energy’s Brazilian assets, as wellas a groundbreaking deal in India with Reliance Industries.In Brazil, the regulator said BP had shown itself to be oneof the most prepared companies in terms of operationalsecurity in deep waters. It is now up to us to live up to thisthrough our actions.BP’s strategic prioritiesContinuing to embed safety and restoring trust are thefoundations for fulfilling our role of providing the energythat the world demands and rebuilding value for ourshareholders.A drilling team at the Southern Rumaila oilfield in IraqWe plan to grow value in a safe and sustainable way,investing in the factors that drive successful performanceover the long term – safety, capability, assets and of course,strong relationships.We are reshaping our portfolio, divesting non-strategicassets worth more to others, investing in a series of newmajor projects and focusing on distinctive strengthssuch as exploration – in which we are on track to doubleinvestment.We expect the momentum of our recovery to build into2012 and 2013 as new projects come on stream, particularlyin higher-margin areas; as we complete current turnaroundactivity; as uncertainties reduce; and as we resume drillingin the Gulf of Mexico, subject to the regulator’s permission.We also continue to reposition our downstream segment,investing in businesses which underpin long-term growthand improved returns, and divesting others for value.A common theme across all this activity is partnership.One of the primary skills of managing energy investmentis that of bringing together the right blend of partnersfor each project – to complement our capabilities andexperience and to share the risks as well as the rewards.This process is now leading BP into some innovativenew types of relationships – particularly with National OilCompanies and governments.The role and relationship ofIOCs, NOCs and governmentsNOCs originated as state organisations,established to serve national interests;while IOCs have always been privatecompanies, accountable to shareholders inmany countries.In very simple terms, the first chapterof the oil industry story was dominatedby IOCs, while the second, starting in the1970s was dominated by NOCs.Whereas once IOCs controlled 80 percent of the world’s oil and gas reserves, thefigure is now closer to 8 per cent.However I believe we are now enteringa third chapter that will be characterisedmuch more by partnership than rivalry.The once clear divide between IOCsand NOCs is starting to blur. NOCs arerapidly expanding beyond their nationalborders – the ‘INOC’ has emerged – and2220th World PETROLEUM Congress

Cooperationsome are gaining new shareholders. At the same time,IOCs have recognised the importance of serving nationalinterests where they operate.Today we are privileged to work with many NOCs andgovernments worldwide, combining our capabilitiesto discover and develop resources. Each project has itsown demands and therefore these partnerships all takedifferent forms.We believe it is important to share what wehave learned in a spirit of partnership as theindustry takes on the challenges of workingat new frontiersFor example, Iraq is a country where investment andcapability have been damaged by war. The task there is notonly to produce reserves but to foster national recovery. Interms of BP’s work, the commercial challenge is to increaseproduction from the supergiant Rumaila field from one tonearly three million barrels per day. But the wider goal is tocreate wealth, to provide over 9,000 jobs and to build thecapability of the workforce.To unlock these benefits we have formed a new kindof partnership, not only with an Iraqi NOC, but with aChinese NOC, PetroChina. We bring ourexperience in giant fields. PetroChinabrings access to drilling, manufacturingand engineering resource. And theIraqi South Oil Company brings a 5,000strong workforce, keen to develop itsskills. We added over 10 per cent toRumaila production last year and oneanalyst called it an example of “seamlessIOC/NOC co-operation.”We are working with governmentsand NOCs in many different ways indifferent countries – in Angola wherewe are building local capability, inAzerbaijan, where we are unlockingthe energy resources of the Caspian, inTrinidad where we have helped create anational fabrication sector.In Indonesia, we are working with thegovernment, BPMIGAS and Pertaminaat the Tangguh liquefied natural gas(LNG) plant in Papua which ships 7.6mtonnes of LNG each year to China, Korea,Mexico and Japan – helping to provide energy security andsupplying an alternative to coal.We have set ourselves the challenge of making thisoperation a real force for sustainable development. We’reemploying local villagers. We’re training local businesses.We’re handling security with great care. We’re supportingeducation and health programmes. And this carefulapproach has helped us create the foundations to expandour operations, with more LNG production and explorationnow being planned.ConclusionI strongly believe that the safe and sustainable approachis also the successful approach – and it nearly alwaysinvolves partnership.The future of energy will be an exercise in collectiveproblem-solving. The opportunities are of a new order.The challenges are of a new order. And the solutions needto be of a new order. We can find them, but only if weare prepared to work together – not only to discover newresources – but new levels of partnership.As the 2011 Congress explores ways to provide reliable,affordable and sustainable energy, I hope the issue of cooperationwill never be far from the centre of discussion. •Operators on the Greater Plutonio FPSO unit, offshore AngolaEnergy Solutions For All 23

CooperationSeeking oil market stabilityby His Excellency Ali Al-Naimi, Minister of Petroleumand Mineral Resources, Kingdom of Saudi ArabiaThe themes of the 20th World Petroleum Congress inQatar are cooperation, innovation and investment– three vital components for the energy industry asit looks to the future. The Kingdom of Saudi Arabiahas continued to cooperate, innovate and invest in 2011and will do so in 2012 and beyond. It is in all of our interests,and in the interests of consumers and producers aroundthe world, that we all strive to further strengthen our ties,make additional investments in capacity and infrastructure,and continually innovate in an effort to seek more efficientand cleaner energy consumption.And let me state for the record at the outset, whatevershort-term issues arise, whatever the day’s headlines orexpert predictions, one thing is certain: global economicgrowth will continue to rely on oil – and in that, consumerscan rely on Saudi Arabia.I would like to reflect on the three themes of thisconference, particularly regarding the future direction ofthe global economy and the challenges – as well as theopportunities – which lie ahead for the energy industry.It is predicted that the global population will increaseby another two billion people by 2030, predominantly indeveloping nations, with global energy demand growingby 40 per cent or more over the next two decades. This isa quite staggering proposition, presenting extraordinaryprospects for the industry.Estimates indicate that more than 200 million peoplewill join the middle class this year in Asia, the Middle East,Latin America and Africa. Such economic and populationgrowth, and rising living standards, will be accompaniedby a considerable expansion of cities. In fact, the number ofcities with one million people and above in the emergingeconomies is currently estimated at about 300 – and thisnumber is continually rising.This growth means rising demand for oil. It was only 20years ago that industrialised countries accounted for 70per cent of global oil demand. It is striking to note thatemerging and developing economies are on courseto surpass OECD industrialised countries in terms of oildemand – a first in the history of the oil industry.It is clear that Asia’s continued economic growth is thebig driver. Saudi Arabia and other Gulf producers havealready helped Asia’s development by supplying muchof the energy needed to fuel this prosperity – as Asia’seconomies have grown, so have our exports of petroleumto the region. This cooperation and investment is benefitingboth sides. Roughly two-thirds of the Kingdom’s crudeoil exports now go to Asia, and we are the largest singlesupplier to major markets like China, Japan, Korea andIndia. And given the scale of our reserves and productioncapacity, our continued investment in technology andtalent, as well as infrastructure, our clear and consistentenergy policies, and our collaborative relationships withproducers and consumers, we are determined to be Asia’spetroleum supplier of choice for many decades to come.Key to satisfying future global demand will be price.However, volatility in commodity markets continues,despite efforts from all parties to reduce fluctuations toa minimum. The economic crisis of 2008 proved we aremore interconnected than ever, and sharp commodityprice rises and falls in 2011 underline the fact. Yetregardless of attempts to increase cooperation andcoordination between producers and consumers, pricestability remains elusive.Over the past decade, we have witnessed dramatic shiftsin the global economy, and consequently in commoditymarkets, including oil. Shifts in commodity markets,in recent memory alone, give us a snapshot of oil priceunpredictability, with prices per barrel for WTI crude-oilswinging from the historic low in 1998 of US$11 to an alltimepeak of US$147 in 2008.But oil was not suddenly scarce during that decade, norduring 2011, so what was the problem? Of course thereare many factors – both real and imagined – which impacton the price of oil. But I continue to believe that it can beexplained, in part, by the fact that in recent years oil hasbecome well established as an attractive asset class for agrowing and diverse set of investors.This trend appears unlikely to abate any time soon. Infact, it will likely contribute to ongoing volatility as investormoney moves in and out of oil futures markets based ona variety of factors which may have very little to do withbasic oil market supply and demand fundamentals.This is a serious challenge for the industry – and forgovernments around the world. Oil producers andconsumers share a common interest in promoting stablemarkets and ensuring affordable and fair prices. Petroleumis a long-term, capital-intensive industry, with exploration,discovery and development taking long lead times of manyyears to bring new fields and increments to production.As such, adequate financial returns, stable prices, andtransparency and predictability of future demand arerequired. Wildly fluctuating prices are not conduciveto future investments to ensure that crude oil, refined2620th World PETROLEUM Congress

Cooperationproducts and natural gas supplies are delivered when andwhere they are needed.Like all businesses, the oil industry needs a reasonablelevel of certainty to undertake massive investments innew capacity. Efforts by the International Energy Forum,particularly its Joint Oil Data Initiative, certainly help takeproducer-consumer cooperation to a higher level.Such dialogue encourages the greater openness andunderstanding necessary to reduce volatility, becausetransparency is vital for both producers and consumers,so that they can collect, exchange and consider reliableand timely data.Ongoing innovations in dialogue and the study ofvolatility and transparency issues within the G20 frameworkhave also been constructive, allowing the internationalcommunity to improve its understanding of various factorsthat contribute to energy market instability.So as we head into 2012, where is the global economyheading and what role for oil producers? After a period ofturmoil and severe economic downturn, recovery may beunderway in large parts of the world, although it remainspatchy. Many developed countries have unacceptablelevels of unemployment and some nations are strugglingwith outsized national deficits and debts. Against thisbackdrop concerns remainabout global economic growth.Some have also expressedworries that rises in oil prices in2011 could signal a return to theconditions of 2008, when pricesapproached US$150 per barrel,and there are those who areanxious that a significant rise inoil prices could send the globaleconomy back into recession.While there is reason to bevigilant about price, the currentsituation is different from 2008.In the short term, I am confidentthat oil markets are relativelybalanced and that recentprice rises have less to do withsupply-demand fundamentalsthan with other factors, suchas gyrations in the value of thedollar and in traders seeking totest new price levels.There is definitely adequate spare capacity in the system.Inventories in all key markets are ample, and there issignificant spare capacity in Saudi Arabia.It is clear that markets and higher oil prices are beingdriven by doubts and uncertainties. These include thefuture of non-OPEC conventional supplies, whether OPECwill make investments to significantly expand productioncapacity, and whether non-conventional sources, such asoil sands, can meet growing demand without passing ontheir higher costs to the consumer.These questions are not new, and there will always besome who discount the role of technological progress inmaking vast new reserves economical to produce in thefuture. We have heard talk about peak oil for decades, butpeak demand may well arrive before we ever reach a peakin supplies. After all, the world turned away from whale oillong before the end of whales.There has always been a level of doubt about theindustry’s ability to meet growing global requirements forenergy – and there always will be. But time and time again,the petroleum industry has risen to the challenge, and itwill continue to do so in the future. Again, dialogue andcooperation between consuming nations and producerswill be vital. →Saudi fiscal balance as a percentage of GDPSource: Ministry of Finance, Haver, Barclays CapitalEnergy Solutions For All 27

Cooperation→ Of course, meeting future energy needs will requirecontributions from across the spectrum of sources –including renewables, nuclear, natural gas, coal, and ofcourse, oil. Such great demand will mean that the moreestablished energy sources will be called to the fore, giventheir known quantities including supply, infrastructure andend-use technologies.But the gap between the readiness of fossil fuels andthat of renewables, which still must overcome hurdles onthe way to making an appreciable contribution, makes acompelling argument for the place of oil in the energy mix.The world does not have the luxury of discarding anyparticular energy source, marginalising or penalising itscompetitiveness through policy, public opinion, regulatorymeasures, or distribution of subsidies and incentives tounfair advantage. The effect of such an approach wouldbe damaging to global economic development and toefforts to raise living standards for the billions of peoplestill living in poverty.A level playing field that encourages the investment neededfor all viable energy sources to fully contribute is vital for asecure energy future. Likewise, that level playing field shouldseek to minimise governmentintervention policies as these tendto manipulate demand and createuncertainties through artificialmeans rather than market signals.The traditional fossil fuelenergy sources, especially oil, willcontinue to serve as the “baseload”for meeting growing worldenergy demand for decades tocome. Just as energy outlooksconcur on a 40 per cent jump inenergy demand over the next 20years, they also indicate that morethan 80 per cent of that demandwill be met by fossil fuels – of whichoil will deliver the lion’s share. Thiswill be true at least through midcentury,and perhaps even longer,thanks to human creativity.One fact remains clear, and Imake no apologies for repeatingmyself. Saudi petroleum policy,implemented under thedirections and direct supervisionof the Custodian of the Two Holy Mosques King ‘Abd Allahibn ‘Abd al-‘Aziz, remains constant. It stresses moderation,cooperation and stability.Moderation means the Kingdom’s ongoing effortsto promote peace, justice, international cooperation,regional and international stability, and human prosperity,as well as employment of all resources to achieve suchobjectives. Cooperation means working with companiesand countries, both with OPEC and non-OPEC producers,and with consuming countries. This cooperation is crucialto guaranteeing oil’s positive contribution to globaleconomic growth and prosperity. And stability meanscreating the conditions for additional investments incapacity and infrastructure, which will also lead to furtheradvances and innovations as the world’s demand forenergy grows.Whatever the future holds, it is clear that sustainedcooperation, unceasing innovation and continualinvestment will be essential. If we can seek to dampenprice fluctuations – by increased dialogue andtransparency – the better for the industry, producers and,ultimately, consumers. •A supertanker berths at the Ras Tanura Sea Island Terminal, the main Saudi loading port2820th World PETROLEUM Congress

Many Viewpoints One Vision*Mark of Schlumberger. © 2011 Schlumberger. 11-OF-0129Scientific curiosity and technical innovation have been part of the Schlumberger culture for morethan 80 years. Today, these characteristics lie at the foundation of our vision of helping customersimprove performance and reduce technical risk in oil and gas exploration and production, waterresource development, and carbon dioxide storage.With more than 140 nationalities represented among our 110,000 strong workforce, our technologydevelopment is backed by a vital cultural diversity to bring the many viewpoints that come fromevery person, every region, and every talent. Just as importantly, this force is connected to apowerful knowledge network of 27,000 people from 26 scientific and engineering disciplinescollaborating in more than 175 communities of practice.www.slb.comGlobal Expertise | Innovative Technology | Measurable Impact

CooperationIncreasing importance ofArab oil and gas producersBy His Excellency Abbas Ali Naqisecretary general, OAPECThe Organisation of Arab Petroleum ExportingCountries (OAPEC) is a regional intergovernmentalorganisation located in the stateof Kuwait, concerned with the development ofthe petroleum industry through fostering cooperationamong its members. It contributes to the effective use ofthe resources of member countries through sponsoringjoint ventures. Among these joint ventures, which wereset up in the 1970s, are the Arab Maritime PetroleumTransport Company, the Arab Shipbuilding and Repair YardCompany, the Arab Petroleum Services Company, and theArab Petroleum Investments Corporation, whose mainactivity is oil project finance.Kuwait, Libya and Saudi Arabia undertook theestablishment of OAPEC on January 9, 1968. The foundingmembers wanted the organisation to be restricted to Arabcountries in which oil revenues constitute a “significantsource of its national income”. However, it was decided onDecember 9, 1971, to relax membership conditions to beopen to any Arab country for whom petroleum forms animportant source of national income”, rather than just amain source of national income .The founding countries (Saudi Arabia, Kuwait, and Libya)were later joined by Algeria (1970), Bahrain (1970), UnitedArab emirates (1970), Qatar (1970), Syria (1972), EgyptNorth Sea - 0.7%China - 1.7%North America - 3.0%Rest of the world - 5.5%CIS - 8.3%Total non-Arab OPEC - 24%Proven reserves of crude oil according toInternational groups,2010 (%)(1973), Iraq (1973) and Tunisia (1982). Tunisia’s membershipis in suspension.Therefore OAPEC has 10 active members spread acrosstwo continents, Asia and Africa. As of 2010, OAPECmember countries with a combined population of 218million people, representing 62 per cent of the Arabpopulation. OAPEC total GDP amounted to US$1,635billion, accounting for 81 per cent of total Arab GrossDomestic Product measured in current prices.OAPEC member countries occupy a significant positionin the international oil and natural gas markets. They arelocated in a region where economic, political, and securityfactors are interlinked in a manner unparalleled in otherregions of the world. Their significance – present andfuture – can be illustrated by the main parameters of theirreserves, production, consumption and exports of oil andnatural gas.World total oil proven reserves have undergone a sharprise in the last decade, increasing from 1,104.9 billionbarrels in 2000 to 1,188.7 billion barrels in 2010. .OAPEC member countries account for about 35 per centof the increase in world proven reserves. OAPEC provedreserves increased from 640.2 billion barrels (57.9 per centof world total) in 2000 to 670.1 billion barrels (56.4 per centof world total) in 2010. Five OAPEC members (Saudi Arabia,Iraq, Kuwait,OAPEC - 56.4%World total: 1188.7 Billion barrelsUnited ArabEmirates, andLibya) holdabout 53per cent ofworld provenreserves. Thisputs OAPECat the topversus otherinternationalgroupings orregions, asshown left.As for naturalgas, worldproven reservesincreased from154.3 trillioncubic metres(tcm) in 2000 to3020th World PETROLEUM Congress

Cooperation188.3 tcm in 2010. Natural gas reservesare more dispersed than those ofoil, with the Commonwealth ofIndependent States (CIS) accountingfor 32.6 per cent of world total, andOAPEC coming next with a share of28.3 per cent rising from 25.2 per centof world total in 2000, as shown right.At the end of 2010, OAPEC naturalgas reserves reached 53.3 tcm, andthey are concentrated in Qatar whichholds 47.6 per cent of the OAPEC totaland 13.5 per cent of the world total.In terms of crude oil (excludingcondensates and NGLs), worldproduction also witnessed a sharprise between 2000 and 2010. Worldproduction increased from 67.1 millionb/d in 2000 to 72.1 million b/d in 2010.By the end of 2010, OAPEC crude oilproduction reached 19.7 million b/d,even though its share receded to 27.3per cent of world total compared to28.9 per cent in 2000, as shown below.The bulk of OAPEC crude oilproduction is concentrated in SaudiArabia which holds 22.3 per cent ofworld proven reserves. Saudi Arabiaproduced 8.1 million b/d or 11.3per cent of global output in 2010,followed by the United Arab Emiratesand Kuwait with 2.3 million b/d or 3.6per cent each of world total.Key spare capacity holderOAPEC members play a central rolein balancing the world market, not only because of thesize of their production, but also because of their spareproduction capacity. Saudi Arabia, the leading worldexporter, with total capacity of around 12.5 million b/d,holds the bulk of the world spare capacity – defined asoil that can be brought onstream within 30 days andsustained for 90 days.It is worth noting that OAPEC oil production share of theworld total (27.3 per cent) is much less than its share fromworld proven reserves (56.4 per cent). The opposite is truefor other regions such as the North Sea, North America, and30252015105035302520151050CISOAPECNatural gas reserves by region, 2010 (%)OAPECTotal non-Arab OPECRest of the WorldNorth AmericaTotal: 188.3 tcmNorth SeaCrude oil production by region, 2010 (%)Total non-Arab OPECCISRest of the WorldWorld Total: 7.21 Million b/dNorth AmericaCIS where their share in total production is higher than theirshare in world total reserves.This fact strengthens OAPECcapacity to meet the expected increase in world oil demand,and indicates the organisation’s member countries will playa more dominant role in the world oil market.Among the world top 18 producing countries, each ofwhose output exceeded 1.5 million b/d in 2010, there wereseven OAPEC countries, headed by Saudi Arabia followedby the UAE, Kuwait, Iraq, Algeria, Libya and Qatar.Turning to marketed natural gas, world total production in2010 was estimated at 3,193.3 billion cubic meters (bcm) →ChinaChinaNorth SeaEnergy Solutions For All 31

Cooperation→ compared to 2,504.6 bcm in 2000. OAPEC productionof natural gas witnessed a similar increase from 255.4 bcmor 10.2 per cent of world total in 2000 to around 443 bcmor 13.9 per cent of world total in 2010. The bulk of OAPECgas production in 2010 was concentrated in Qatar, whichproduced 26.3 per cent of OAPEC total (3.6 per cent of worldtotal), followed by Saudi Arabia (18.9 per cent), Algeria (18.2per cent) , Egypt (13.8 per cent), and UAE (11.5 per cent).Growing ConsumptionGenerally, OAPEC countries witnessed a steady increase inconsumption of both oil and natural gas. Oil consumptionincreased from 3.2 million barrels of oil equivalent per day(4.2 per cent of world total) in 2000 to 4.9 mboe/d (5.6per cent of world total) in 2010, representing an annualgrowth rate of 4.3 per cent, while production was close to20 million b/d. The difference between OAPEC membercountries production and consumption of oil illustratestheir significance to supplying energy-deficit countries.Domestic consumption of natural gas increased from 2.7million boe/d (6.3 per cent of world total) in 2000 to 4.7million boe/d (8.6 per cent of world total) in 2010, with anaverage annual growth rate of 5.5 per cent. Consumptionvaried from one country to another due to the differencesin availability of oil and gas resources, energy-intensivelocal industries and standard of living in each country. SaudiCrude oil reserves and production by region, 2010 (%)100%90%80%70%60%50%40%30%20%10%0%ReservesNorth SeaChinaNorth AmericaRest of the worldCISTotal non-Arabe OPECOAPECArabia consumed 25 per cent of OAPEC total, followed bythe UAE (23.7 per cent) and Egypt (12.7 per cent). OAPECcountries’ relatively greater surplus of production over localconsumption – compared to other regions in the world –magnifies the importance of their role in the internationalgas market.The net trade balance between regions is a goodindicator of the importance of countries in the oil market.The Middle East is the largest exporting region in the worldwith net oil exports of 16.9 million b/d in 2009. Exports ofoil and oil products from OAPEC countries played vital rolein the last decade, irrespective of the fact that their 2009level was the same as that for the year 2000, as shown inthe graph on the next page.During 2009, OAPEC crude oil exports were estimated at14.2 million b/d, and oil products exports estimated at 2.6million b/d . Total OAPEC oil exports represented 29.1 percent of the world total, followed by exports from WesternEurope (14 per cent), Eastern Europe and FSU (13.2 percent) and Asia- Pacific (11.7 per cent).The net position of OAPEC members in 2009, shows thatOAPEC hold the largest surplus of oil and oil products inthe world reaching 16.8 million b/d compared to deficitsof 16.3 million b/d in Asia-Pacific, 9.7 million b/d in WesternEurope and 8.2 million b/d in North America.Of the world’s 15 largest oil exporters – each exportingmore than 1.0 million b/d) – therewere seven OAPEC countries in 2009,headed by Saudi Arabia with an exportlevel of more than 7 million b/d.OAPEC members played andcontinue to play a vital role in theworld oil trade. Their share in totalimports of crude oil and oil productsexceeded 27 per cent in 2009. In factOAPEC countries supplied 18.8 percent of North America total oil imports,14.6 per cent of Western Europe and44.2 per cent of Asia- Pacific duringthat year.As regards gas, OAPEC exports morethan doubled in the last decade, risingfrom 83.5 bcm in 2000 to 164.3 bcm in2009, and accounting for 18.1 per centof world total in 2009.Approximately 60.3 per cent ofOAPEC natural gas exports were inProduction3220th World PETROLEUM Congress

Cooperationthe form of Liquefied Natural Gas(LNG), while the rest were pipelinegas from Algeria , Egypt, Libya. Qataris OAPEC’s largest exporter of gas(41.5 per cent of OAPEC) , followedby Algeria (32.1 per cent) and Egypt(11.2 per cent).The net trading position of naturalgas during 2000 – 2009, indicatesthe significance of OAPEC surplus,at a time when western Europe, Asia– Pacific, and North America wereincurring increasing deficits as shownin the graph below.In 2009, OAPEC surplus exceeded135 bcm, versus deficits of 209 bcmin Western Europe, 87.9 bcm in Asia -Pacific and 4.1 bcm in North America.20151050-5-10-15-20OAPECOil balance of international regions,2000 and 2009, (million b/d)Eastern Europe & FSULatin AmericaNorth AmericaWestern Europe20002009Asia and PacificConclusionOAPEC member countries occupya significant position in theinternational oil and natural gasmarkets, as they held more than 56per cent of world oil reserves, andmore than 28 per cent of natural gasreserves. On the other hand, OAPECaccounted for approximately 27.3per cent of world oil productionand 13.9 per cent of world naturalgas production highlighting thesignificance of OAPEC members inmeeting rising world demand.The net position (oil balance) in2009 shows that OAPEC contributedaround 17 million b/d towardcovering the increasing oil deficits inother regions such as North America,Western Europe, and Asia-Pacific. Infact, one third of world total oil imports in 2009 came fromOAPEC member countries, supplying one fifth of NorthAmerican imports, 14.6 per cent of Western Europe, and44.2 per cent of Asia – Pacific during that year.OAPEC member countries are likely to continue toplay a major role in meeting future world demand for oiland natural gas, contributing effectively towards marketstability. OAPEC major producing member countries1401006020-20-60-100-140-180-220The trade balance of natural gas, 2000 and 2009(billion cubic metres/year)OAPECEastern Europe & FSULatin AmericaNorth AmericaWestern Europe20002009Asia and Pacific(Saudi Arabia, Iraq, Kuwait, and the United Arab Emirates),accounting for around 53 per cent of the world provenreserves, will be the world’s main oil suppliers in themedium to long term. But for this to be realised, theproducers will need to add production capacity requiringlarge investment outlays. This will take place only if theyare confident that anticipated demand for their oil willmaterialise and they have access to sufficient funds. •Energy Solutions For All 33

CooperationLessons from the last decade,strategies for the next twoBy Andrew GouldChairman, SchlumbergerDespite the crises of the last decade, the worldconsumed energy in 2010 at a level that was notexpected to be reached before 2015. This didnot come from demand in the OECD countries,but from that of the developing countries. In spite of this,energy poverty remains a major issue with nearly 1.6 billionpeople around the world without access to electricity.I would like to examine the subject in terms of the majorevents and trends of the 2000s that have had, or will have,a lasting effect on the exploration and production industry.I will try to relate these to the strategies that I think willbe necessary for the next two decades. These choiceswill naturally be personal, and not necessarily those ofSchlumberger where I have spent the last 35 years.Oil and gas supplies have always been subject topolitical and geopolitical interference. Fear of disruptionhas governed political action almost since the birth of theindustry and the quest for energy security has motivatedevery form of such action.The last decade was marked by a fundamental shift inthe security of supply which had been the preserve of theOECD nations for the last hundred years. We discovered thatChina, and to a lesser extent India, had assumed the mantleof demand driver with the world waking up to China’senergy needs through the spectacular increase in demandof 2004. In terms of oil alone, China’s apparent consumptionmore than doubled in ten years. This was the first, andundoubtedly the most important, shift of the past decade.The second shift was undoubtedly the emergenceof Russia as the single largest producer of oil and gas.Following the collapse of the Soviet Union, Russianproduction collapsed to as low as 6.1 million barrels a day(mb/d). In the six years following 1999, it rose by more than50 per cent and became the major reason why oil pricesdid not rise much faster, much earlier.When supply and demand balances started to tighten inthe early 2000s, the industry faced its first supply challengein 25 years. The cushion of excess supply created followingthe oil shocks of the 1970s began to shrink. The decline ofthe three key pillars of the 1970s, Alaska, Mexico and theNorth Sea, was evident. The age of the production basewas becoming obvious and exploration and productioncapital expenditure duly exploded leading to a period offrantic growth in activity that in turn had major effects onthe exploration and production industry’s structure.The first of these was the re-emergence of resourcenationalism. This was not new – countries have expelledforeign interests in the past after all. Nor was resourcenationalism limited to foreign interests, as the capture ofgreater shares of petroleum rent takes many forms; veryoften in the form of taxation. However, whatever the formthe consequences are the same – creating uncertaintiesabout the stability of the investment climate and restrictingcapital flow, both of which slow the supply response.In the 2000s, resource nationalism was rife. Russiachanged investment rules to capture a greater share ofthe rent. Venezuela closed again, and the Middle East didnot open significantly. Mexico did not open at all. Iran andSudan remained largely off limits through sanctions. Andafter a spate of extraordinary discoveries Brazil started toclose again – not to investment but to the notion of foreignoperators in the pre salt domain. Consequently, perhaps75 per cent of the world’s known conventional oil reservesare today closed to international private capital while 60per cent of production originates from international andindependent oil companies.Wide range of national companiesLargely as a result, national companies form a vast range– both in structure and ability. Some are major offshoreoperators; others have mastered complex projectmanagement. Several are sophisticated technology users,and are often more ambitious than their internationalcolleagues. They are determined to learn, and can competewith the best. They manage their resource as part of thenational wealth. Others are emerging with increasinglylarge international portfolios as they respond to theircountries’ energy demands.The role of the service industry in providing technologyand process to the national oil companies has been muchdebated. From time to time it has been believed that byproviding these services to the national oil companies theservice industry has slowed international capital accessto closed domains. In fact, the role of the service industryhas not changed; their big opportunity came after thenationalizations of the 1970s and their role has graduallyexpanded through more sophisticated offerings during aperiod when international oil companies reduced researchand development expenditure while encouraging serviceindustry competition.Another aspect of access that should not be ignored isthe ability of pressure groups to restrict access to someof the most promising remaining reserves. The exampleof the United States is obvious where even prior to the3420th World PETROLEUM Congress

CooperationDeepwater Horizon accident the ability of various lobbiesto convince politicians to restrict access was legendary.These restrictions have led international operators andindependents to opportunities offshore and in harsherand more remote environments. Furthermore, newlydiscovered conventional oil accumulations have becomesmaller while sources of conventional production areincreasingly complemented by unconventional oils. Inaddition, heavy or unconventional oil projects includingshale oil and various conversions from coal or gas aremassive undertakings of long duration that require hugeamounts of capital.As a result, if there is one common characteristic in the oilexploration and development projects to be executed inthe next 20 years, it is that they will become more complex,more difficult to execute, and more expensive.If the 2000s were a decade of tremendous change for oilit was equally true, if not more so, for gas. Conventional oil iscompletely fungible, where constraints in the distribution ofeither crude or products have become minor. From well headto consumer a full competitive chain with many alternativesexists. The same is not true of gas where movement tomarket by pipe or LNG is still an incomplete chain.During the last decade, the entire gas infrastructureand its sources of supply came into focus. Consumptionincreased rapidly, as did supply. The huge LNG andpipeline infrastructure projects begun in the 2000s havethe potential to fundamentally change traditional wisdomand completely allay fears of rupture in gas supply inWestern Europe. The rapid development of gas resourcesin Australasia considered stranded only ten years ago haschanged the availability of long-term supply for China,Korea and Japan. And in the US, the development ofshale gas has changed the dynamics of domestic supply.Of these factors, the huge expansion in LNG and thedevelopment of shale gas in the US truly marked thedecade and although markets are currently oversuppliedfollowing the dramatic drop in demand in 2009, this effectwill be eliminated in a few years time.The US shale revolution required technology, marketforces and entrepreneurship. Today’s combination ofhorizontal wells and hydraulic fracturing has madecertain shales economic, but technology will have tomove much further to systematically extract full valuefrom every shale as current extraction methods are bothwasteful and expensive.Shale gas enthusiasm has been sufficient to lead tomajor revisions in US reserves. In the rest of the world,where knowledge of shales is vastly inferior to that of theUS, countries and companies are actively searching →Schlumberger helped drill a backup third shaft for the successful rescue of the 33 miners trapped in Chile’s San José mineEnergy Solutions For All 35

Cooperation→ to understand the potential of their own shale gasresources. But much remains to be done before we canbe assured that the world’s shales are as prospective asthose of the United States. Environmental, water and landconsiderations, among others, must be resolved.No review of the last decade would be complete withoutmention of the tragedy that occurred in April 2010 in the USGulf of Mexico. Eleven men lost their lives on the DeepwaterHorizon, the accident led to the largest oil spill in US history,and the incident received one of the largest media exposuresever seen. This one event will have major effects on the waythe industry operates in the foreseeable future.Having now outlined the major changes of the pastdecade, I would like to turn to some of the objectives Ibelieve the industry will need to examine.The first and most important will be to re-establish theconfidence of the regulator and the public in the industry’scapacity to find and produce deepwater oil and gasresources safely. In the last ten years, more than half of allnew resources discovered worldwide have lain offshore.Partly as a result, offshore production is expected to supplyapproximately one third of the world’s needs late in thenext decade. And with deepwater production increasingsteadily, its contribution will correspond to approximately10 per cent of global supply by then.Regulation will therefore become stricter, standardsupgraded and oversight increased. Safety andSophisticated field processing equipment ensures quality controlmanagement systems will be constantly tested andimproved. Comprehensive spill response plans will berequired. Technology will become increasingly critical fordeepwater success and those who possess it will derivecompetitive advantage. Automation and instrumentationwill have to be adapted to create a control environmentsimilar to the aerospace or nuclear industries. Above all,the industry will require increasing numbers of competentand well-trained people to execute improved processes.As a result, the overall time to new deepwater productionwill increase, costs will escalate and those who do notadapt will lose.The second objective for the industry will be theneed to dramatically improve its project managementskills. Projects have become larger and more costly ascomplexity has grown. There are now over 200 projectsworldwide that have budgets in excess of US$1 billion. It isextraordinary that national and independent oil companiesnow represent over 80 per cent of total industry capitalexpenditure. It is also extraordinary that 40 oil and gascompanies have annual capex budgets in excess of US$4billion – up from only 10 in 2001.Size and complexity are consequently enhancing therole of project management as a core industry skill. Inthe past, this has been found in just a few companies –the super-majors in particular. But with more companiesexecuting larger projects, often in remote or complexenvironments, the need to trainseasoned project managers isbecoming acute. Such a skill is notrapidly acquired as it mixes technicaland organisational capability withstrong leadership ability. It involvesconstant evaluation of options andtheir potential implications and is, toa large extent, a transferable skill withmany other industries.The third objective that will beimportant in the next two decadesconcerns the true viability of shalegas. There is no doubt that theresource is large. However, so manyunknowns remain that it is extremelydifficult today to estimate its ultimatepotential. We have insufficient data,and we do not have the reservoirmodelling capability to lend credibility3620th World PETROLEUM Congress

Cooperationto reserve or recovery numbers. Our traditional geologicaland petrophysical models do not apply. We cannot use theusual evaluation methods to identify productive zones.The production mechanism itself is not understood andthe decline patterns even less.Today’s method of extraction puts the wellbore incommunication with as much of the rock as possible toget gas to flow through created fracture networks. To dothis, long horizontal sections are completed with stagedsets of perforations that are then massively hydraulicallyfractured. The process uses huge amounts of horsepower,sand, proppant and above all, fresh water. Such a bruteforce approach has resulted in huge variability in individualwell production.If we are going to exploit the full potential of shale gas,we need a technology package that allows optimisationof completion design as a function of reservoir quality. Intime, the industry will find ways to map reservoir quality,tying shale responses directly to wireline or logging-whiledrillingmeasurements. This will help optimise well design,completion design and fracturing treatment. Only then willwe then drill the best wells, and fracture the best intervals.Shale gas undoubtedly has a major contribution to maketo future energy supply, but technology will have to evolveconsiderably for it to realize its full potential.As a fourth objective, the industry must face the fact thatit will be desperately short of experienced human resourcesif it is to maintain the rhythm of exploration and productionnecessary to sustain oil and gas supplies. The 16 years oflow oil prices after 1986 meant that little recruiting wasdone, and many earth science and petroleum engineeringfaculties were closed. In the 2000s, the industry recognizedthe problem and recruiting and training began to pick up.All operators alike – international, national andindependent – are relying on technology to a largeextent to increase the productivity of their petrotechnicalprofessionals. Only the majors are counting on processes ofstandardisation and codification to a large extent to be ableto staff projects with more junior people. The independentand national operators appear to be relying more onoutsourcing to better utilise their staff. It would seem to methat increased project size and complexity require that betterprocess be essential to proper manpower utilisation withoutsourcing not being an adequate solution on its own. Afailure to implement process will also make it more difficultto comply with the regulator as competency assurance willbecome an essential tool for certain key positions.If the industry is to meet the challenges it faces, itwill need much greater training to create the technicalpopulation it will require. Technology and process will help,but they cannot remove the need for a highly technicaland competent workforce.Finally, no discussion of oil and gas for the nexttwo decades would be complete without mention ofgreenhouse gas emissions. Energy-related carbon dioxide(CO 2) emissions have increased by over 40 per centover the past two decades with forecasting agenciesprojecting similar relative increases over the next 20 years.The sustainability of such a rise has been questioned bymany leading climate experts. A reduction to the levelsrecommended at recent G20 summits would require aportfolio of carbon abatement options, among whichenergy efficiency would clearly have the largest impactand lowest abatement cost.Analyses by the International Energy Agency and otherorganisations have, however, shown that carbon captureand storage (CCS) has the potential of providing nearly 20per cent of the reductions required by 2050. But in orderto achieve this ambitious target, CCS needs five mainingredients – financial mechanisms, legal and regulatoryframeworks, technological innovation and cost reduction,international collaboration, and public acceptance.The Cancun climate change conference made someprogress on financial mechanisms through the adoptionof CCS as a clean development mechanism but there is stilla long road ahead for carbon abatement prices to reachlevels that would make CCS fully commercial. Enhancedoil recovery using CO 2could help speed-up the learningcurve to some extent, as well as providing an economicincentive and developing part of the surface infrastructure.Storage applications from the main emitters such as powerplants would need CO 2prices far above the level currentlyforeseen in emission trading markets. The focus over thenext few years should probably therefore be on buildingexperience through pilot projects to serve as publicconfidence builders as well as technological test beds.I believe that the issues I have raised, post-Macondooperations, project management, shale gas technology,human resources and energy emissions will all be importantissues for the two decades to come. I also believe after threeand a half decades in this business that the resourcefulnessand enthusiasm of the people who work in the oil and gasindustry will be equal to overcoming the challenges. Thisis a very different industry from the one I joined in 1975.•Energy Solutions For All 37

Unlockingthe Arctic’s potentialEduard Khudainatov,President of RosneftRosneft is extremely proud to bea platinum sponsor of the WorldPetroleum Congress held in Doha,Qatar this year. It is a great honorfor our company given the weightand importance of this event in thedevelopment of the global energyindustry particularly as Moscow is thehost city of the next World PetroleumCongress scheduled for 2014.Over the years, the World Petroleum Congress has built a reputation as oneof the most authoritative international energy forums. We recognize that theCongress represents an enormous opportunity not only for Rosneft to networkwith our international partners but also for the company to take an activerole in shaping the global energy agenda while discussing the main trends andchallenges that key global energy players face today.Оne of the main challenges facing the energy industry is increased demand forenergy resources and the gradual depletion of traditional deposits with easy-torecoverreserves. With renewables not yet integrated fully into the energy mix, weneed to develop new oil and gas provinces to avoid facing global energy shortagesin the near future. It is our firm conviction that, shelf deposits, including the Arcticshelf, offer the greatest opportunities.In terms of hydrocarbon reserves, Russia’s shelf fields are amongst the mostpromising areas in the world. Total recoverable resources on the Arctic shelf areestimated to reach nearly 700 billion barrels of oil equivalent – over 20 percentof the global total. Rosneft owns 17 licenses for different blocks on Russia’s shelffields. They are grouped into three key zones: Western Arctic (the Barents andKara Seas), the Sea of Okhotsk and the Sakhalin shelf аs well as the Southernseas (Black, Azov and Caspian Seas).Significantly, Rosneft is taking firm steps to develop its shelf fields. In August2011 Rosneft signed a Strategic Cooperation Agreement with ExxonMobilfocusing on joint exploration and the development of three shelf blocks in theKara Sea and one in the Black Sea. With a combined estimated resourcepotential totaling 110 billion barrels of oil equivalent, the Kara and Black Seablocks are among the most promising on the Russian shelf. The developmentof shelf deposits therefore aims to balance supply and demand on the worldenergy market, avoid energy shortages and ensure global energy security in thenear future.

The scale of projects in the Arctic is unprecedentedand both Rosneft and ExxonMobil are fully aware of thetechnical and environmental challenges they will facein the course of implementing these complex projects.The Arctic presents Rosneft and ExxonMobil with anumber of challenging technical tasks dictated bythe difficult ice situation. Indeed, the sea is ice-boundfor 300 days of the year and extremely low wintertemperatures plunge to -46 O С and beyond in theArctic. Whilst the challenges are well-documented, webelieve that ExxonMobil and Rosneft have the relevantexpertise to overcome these challenges. This expertisecomes from the Hibernia project, in which ExxonMobilis a partner, and which shares key similarities with theKara Sea shelf and Sakhalin 1 projects. In addition,as part of the strategic partnership, Rosneft andExxonMobil will create an Arctic Research and DesignCenter for Offshore Developments (ARC), whichwill focus on creating, consolidating and adaptingtechnologies to support joint projects in the Arctic. Weanticipate that Arctic cooperation will stimulate thedevelopment of new technologies across the industry.The center will strongly focus on environmentalmonitoring and the development of environmentallyfriendlytechnologies. Environmental monitoringwill benefit from the two companies’ environmentalprotection experience, including environmental andgeo-environmental monitoring and obtaining licenses tocarry out environmental protection activities.Importantly, we believe that the Arctic projects will bea stimulus to economic growth for the energy sector,spurring development of all related industries. Weanticipate that the development of the energy sector inthe Arctic will have a major effect as projects to developdeposits will set challenging and far-reaching tasks forother industries. Oil production in the Kara Sea will spurdemand for oilrigs and there will be increased demandfor tankers to ship both oil and LNG. On top of that,there will be a need for new infrastructure creating newjobs and opportunities.The development of projects in the Arctic andelsewhere in Russia will therefore not only ensure thebalance of supply and demand is maintained in theglobal energy market but will also stimulate economicgrowth for the whole industry. Arctic resources willbe of benefit to future generations, but we stronglybelieve that only companies with relevant technologies,expertise and environmental protection experienceshould have access to developing projects in the region.About RosneftRosneft is a Russian oil industry leader and one of thelargest public oil and gas companies in the world. Rosneft’smain operations are exploring for and extractingoil and gas and manufacturing and selling oil productsand petrochemicals. The company is a strategic Russianenterprise. OJSC Rosneftegaz is the main shareholderin the company (holding 75.16% of shares) andis 100% owned by the Russian state. Approximately15% of the company’s shares are in free float.Rosneft’s exploration and production activities spreadacross all of Russia’s main oil and gas provinces: WesternSiberia, Southern and Central Russia, Timan Pechora,Eastern Siberia, the Far East and the Arctic Seashelf. The company also has projects in Kazakhstan,Algeria, Venezuela, Abkhazia and the UAE. Rosneft hasseven large refineries spread across Russia from theBlack Sea coast to the Far East, while the company’ssales network covers 41 Russian regions. Rosneft hasa 50% interest in Ruhr Oel GmbH, which owns stakes in4 refineries in Germany.According to an independent DeGolyer & MacNaughtonaudit, Rosneft’s proven PRMS reserves were 2.5 billiontons of oil and almost 800 billion cubic meters of gasat the end of 2010. As such, Rosneft’s internationalstandard proven reserve replacement ratio in 2010was 106%. Total proven hydrocarbon reserves amountto 22.8bn barrels and proven liquid hydrocarbon reserveshave placed Rosneft at the top of global rankingtables among publicly traded companies. As at the endof 2010, Rosneft’s hydrocarbon reserves will last for25 years, with oil reserves lasting for 21 years and gasreserves enough for 67 years.

CooperationAllied interests of privateand national oil companiesBy Christophe de MargerieChairman and CEO, TOTALIn a globalised and inter-connected world, whereknowledge, competence and technological innovationare continuously shared, international oil companies mustask themselves what their future role will be and howthey can best cooperate with their national counterparts.Although often turbulent and sometimes tense, it is acooperation that has ultimately proven to be long lastingand mutually beneficial. It has made it possible to forgepartnerships, ensure a transfer of knowhow and highlightthe benefits of aligned interests.As we steer in uncertain waters, marked by structuralchanges and challenges, it has become difficult to makea clear-cut distinction between IOCs and NOCs. Ourcommon external conditions range from an unstableeconomic environment, fluctuating and geographicallyuneven demand patterns, tightening climate changeparameters, geopolitical turbulence and an overhaul of along established financial system.Against this backdrop of uncertainty, consumption levelscontinue to rise and our common task is to ensure thatdemand is being met. The reliable supply of energy sourcesto consuming markets thus increasingly supersedes thedistinction of whether the producing company is privateor national.Furthermore, as the energy mix continues to evolve andhost countries pave the way for the future by increasinglytaking into account issues such as climate change-relatedconcerns or the final use of their resources, IOCs and NOCsmust seize the opportunity to take their cooperation to thenext level. Their ability to adapt to the new environment,produce new forms of energies and view each other asequal partners will shape the oil industry for some timeto come.A common goalAs uneven demand patterns, exposure to volatile oilmarkets and tightening environmental regulationsincreasingly affect the oil sector, NOCs and IOCs aregradually shedding their distinction and must be seen asproducers. Security of demand and security of supply areconcerns that affect them both.Our industry cannot live in isolation and the environmentin which it operates is undergoing fundamentaladjustments. Over the past 18 months, structural changeshave marked our times: they included, only to name afew, the growing role of the state in key market-basedeconomies, where the debt crisis had devastating effectson the eurozone, the worst oil spill in US history which ledto a fundamental rethink, strict adoption and sometimesreadjustment of Health Safety Environment protocolsacross the oil industry and the catastrophic consequencesof a natural disaster which badly hit Japan and highlightedamongst other things the inherent contradiction of cleanand risk-free energy sources.The necessity of industries like ours to restore trust andconfidence with the public has emerged even further as akey issue while consumers continue to centre their objectivearound secure, accessible and reliable energy sources.On the political level, new and unprecedented forms ofgovernance are gradually emerging in the Middle East andNorth Africa – the outcome of which is still unknown.External risks expose NOCs and IOCs alike as they weathercommon challenges while they strive to achieve commonobjectives, that is to say provide oil and gas supplies in areliable and secure manner.What is certain, is that today’s conditions in which bothhave to navigate are more unpredictable and rapidlyevolving, than they were 20 years ago.Bridging the gapAs NOCs continue to differ in their competence, size, marketshare and know how, they face similar constraints but indifferent ways: while some NOCs produce less than they needfor their domestic market, such as the Chinese NOCs, othersproduce more (i.e. Saudi Aramco). A number of distinctivedifferences between NOCs and IOCs spring to mind:• Host countries remain the largest reserve holderscontrolling about 75 per cent of the world proved reservesand more than 55 per cent of the world production. Oilproduction policy determines the production of thesereserves, the timing of production, as well as the legal andtax regime applicable to oil and gas developments. Theirnational companies remain inevitably defined by policyorientations as set by the energy ministries; they build andimplement a long-term national reservoir managementand development strategy; they contribute to the turningof the country’s natural wealth into long-term socioeconomicdevelopment.• IOCs are tied to their international markets, consumingstates and demand centres. As demand continues to climb,it has to be met in a timely manner. Indeed, one of themain and most stimulating tasks of IOCs is to sustainablyalign the respective requirements of both host countriesand their customers abroad, or, in other words, to act as4020th World PETROLEUM Congress

Cooperationfacilitators between producing countries and consumers.• IOCs have a diversified and worldwide experience, whichcreates excellent conditions to innovate. As a result, IOCscan offer wide-spread technological expertise as well as anintegrated approach for the most challenging resources(very deep offshore, extra-heavy oils, tight and sour gasetc). In the Pazflor project, offshore Angola, for instance,Total implements in partnership with Sonangol a newsubsea gas/liquid separation concept, a world technologyfirst, which is the result of our extensive R&D efforts.Converging interestsAs owners of the largest part of world reserves, NOCs oftencall upon their international partners to jointly developtechnically most complex areas where the deployment ofinnovative technology is paramount. The production anddevelopment of oil and gas resources remain evidentlya key objective of any oil company; a world where IOCsand NOCs would grow separately, one where NOCs wouldmanage their own resources and where IOCs wouldbe focused on the development of non conventionalhydrocarbons in other areas, is not a vision one shouldwish for. Such a split would not be efficient as it implies nocooperation, no cross-fertilisation of their experiences andno risk mitigation.Alignment of interests for parties remains, however, anunconditional element of a successful partnership. WhenIOCs are being offered suitable contractual terms payingfor the risk taken and giving sufficient incentives to bringthe best of their expertise, the joint venture acquires alife of its own, with its own culture, a product of the hostcountry, the NOC and the IOC. One of the best examplesof this being the giant Jubail Refinery being built by Satorp,a company where Aramco and Total employees have aunique goal: joint success.But producing states might ask themselves ‘what is it infor me?’ Indeed, what can an IOC effectively bring?Research and Development: R&D and the consequenttechnological innovation continue to be shared betweenIOC, the host country’s NOC and the contractor. But it isup to the oil companies, both IOCs and NOCs, throughtheir extensive knowledge of the resources’ challenges,to define the required technology and R&D programmesthat are needed. In this spirit, Total spends US$1bnannually on R&D. Technological breakthrough, resultingfrom well focused R&D, can bring beneficial responses inour constant struggle to control cost, such as for instancethe modularisation of LNG plants, or the concept of iceresistant floating processing platforms designed for theextreme sea and weather environment of Arctic regions.As partners in increasingly complex projects, NOCs andIOCs have a common interest in delivering successfulproduction units.Exposure and knowledge: expertise brought in fromother projects can add substantial value. The capacityto reach markets can add further commercial value. Theexample of QatarGas springs to mind: Total’s capacityto access markets through its regasification terminalsand customer portfolio allowed Qatar to sell LNG topreviously inaccessible markets. In another vein, IOCs haveaccumulated experience in managing large and complexdevelopments and are used to handling huge, multibilliondollar projects. This is clearly demonstrated whenlooking at the growing share of deep-offshore, heavyoil, ultra-deep gas reservoirs, and LNG projects in theirportfolio, such as the Yemen LNG project and the Akpodevelopment, offshore Nigeria, both operated by Total.IOCs are also managing large, integrated projects, beyondjust exploration and production: such projects involve themidstream section (power plants and desalination) and thedownstream section (refining and petrochemicals) of theircorporate activities. In some cases, they also implement, asoperators or key partners, trans-national projects, such asthe Qatar-UAE Dolphin project.Risk mitigation: As NOCs are increasinglyinternationalising their activities, IOCs, whose core businessis located by definition in international markets, can helpmitigate risks. But successful joint investments inevitablyrequire joint objectives. They need to be aligned, technologyneeds to be shared, training needs to be provided and accessto new countries can be offered. Working in associationwith NOCs outside their country of origin, especially soas NOCs expand worldwide, has taken the oil sector intoa new phase. We often forget that most IOCs were oncestate-held. Examples range from the partnership betweenTotal and Qatar Petroleum International in the Taoudeniexploration permits in Mauritania to our JV with CNPC andPetronas in Iraq; from our partnership with Kufpec in Yemenand Sudan to our affiliation with Sinopec in Canada andYemen or even the very ambitious LNG project we have inAustralia with Petronas.Preparing the future: IOCs are committed to preparingthe energy future as new, increasingly complex andmore diversified energy sources are necessary to meet →Energy Solutions For All 41

Cooperation→ growing energy demand, and to limit CO 2emissionsassociated with energy consumption. Considerable R&Dand technology related work are needed before thesenew energies become competitive. It makes sense for anoil and gas company to get more involved in alternativeenergies as we have to stay in step with the long-termenergy transition that our industry, and the world, arefacing. It is in NOCs’ best interest to cooperate with IOCsin the challenging domain of new energies, and manyproducing countries, concerned by the diversification oftheir energy mix, are presently developing projects in thefield of renewable energies. In the UAE for instance, TotalProduction and gas processing platform in the North Sea off the Netherlandsis building a 100 MW solar power plant in association withMasdar and the Spanish company Abengoa. Innovativeinvestment, if performed today, will pave the way forsecuring energy needs in the next decade, including inoil-exporting countries.Building sustainable relationshipsUpstream projects are long in duration and wide in scope:IOCs and their host country learn in time to understandtheir respective cultures and exchange know-how in asustainable manner. Total has been working with manycountries for 50 to 75 years, thus giving us an intimateunderstanding of a country’s cultureand expectations; they are ingredientsfor building mutually beneficial relationsbased upon common trust and respect.Two essential and organic trends resultfrom a successful joint venture betweenan NOC and its international partner: one,which starts with a human experiencewhereby the project staff create their ownculture, one of the project. Their driveto make their mission a successful onesupersedes quickly their affiliation to theNOC or the IOC. They become affiliatedto the JV, the project. This meeting ofthe cultures, perceptions and know-howinevitably gives the project a successfuldynamic.The second element refers to thebenefits of a JV in a given host country: jobcreation, training, transfer of technology,business opportunities for local suppliers,social and environmental impact. In manycountries our presence is not limited to theupstream but it extends to other domains:refining, petrochemicals, research centres,renewables. And for us, there is no betterexample of a wide-ranging and successfulpartnership than Qatar where this WorldPetroleum Conference is being held.In short, IOCs must build the hostcountry’s development expectations intotheir wider thinking and contribute to localsocio-economic development: where itoperates, it should behave as a local playerand be entirely recognised as such. •4220th World PETROLEUM Congress

Demner, Merlicek & BergmannOliviaia, Lukas and Alexander withtheheirforward-lookiking“Dopoppepelentntdedecker” they buililt themselveses.Where do the children get their energy from?It’s sure to be from OMV as well, because right now they’re meeting tomorrow’s energy needs.More at www.omv.atMoving more. Moving the future.

CooperationBuilding the servicecompany of the futureBy David LEsarchairman, president and CEO, HalliburtonWe have cause for great optimism andenthusiasm about the future of ourindustry. Innovation and experience aremaking complex reservoirs – such as shaledeep water – economically viable and boosting reserveestimates to levels that would have seemed fantastic afew years ago, while also helping increase production frommature reservoirs. In the next decade we will see enormousopportunities in exploration and production – if we evolveto meet the challenge.Service companies in particular are changing. I want tosketch the changes and investments we are making thatwill enable us to provide a higher level of service and realisethe opportunities that are coming into view. I also want todiscuss the key themes that will persist in all phases ofour business cycle; these are the areas where we will bemaking investments year in and year out.Two themes are likely to intensify and dominate the nextdecade because they are the foundation of the higherlevel of service and value creation that complex reservoirsdemand. These themes are the holistic approach toreservoir development, and the acceleration of innovationand organisational learning.Holistic solutions for complex reservoirsWhether it’s tight gas in the Middle East, pre-salt playsoffshore Brazil, or shale oil in the Bakken, the geologicaland technical complexity of these enormous newbasins – combined with their capital intensity and longdevelopment times – make a holistic approach the onlyeconomically viable option.Deliverability throughout the life cycle of the reservoirrequires operators and service companies workingtogether to take time and cost out of each step – fromprospect generation to production. And each step needsto be integrated with the others to become a holisticsolution that includes all the elements – from reservoirdescription to drilling, well completion and productionmanagement. Helping operators achieve that holisticsolution is the way service companies are adding themost value.This is demanding changes in the way service companiesoperate. In technology, we create the cross-functionalworkflows needed for holistic development. And we arechanging organisational structures, training, and workprocesses to help us speed up our learning and help usmobilise the right expertise at the right moment for theparticular reservoir development need. We take a holisticapproach to creating holistic reservoir solutions.Integrated workflows create efficiencyat the wellsiteThe definition of cost-effective service delivery is evolving.In complex reservoirs, it is not enough to deliver a discreteservice at the lowest cost. The service must be optimisedfor the well, and it must also contribute to optimizingthe whole. At the wellsite, this means using services thatincorporate real-time data capture and respond to realtimedecision making, and services that integrate intoholistic development planning. Cost-effective services arenow ones that minimise costs for the whole project andprovide information and knowledge that can be used tohelp optimise the plan. And these are also the servicesthat can feed organisational learning, create databases andexpertise that help optimise the next project in that basin,and provide insights useful for developments in otherbasins and other continents.Integrated workflows in a collaborative environment,which combine discrete services, are the next level invalue creation in complex reservoirs. Such workflows inreservoir evaluation, real-time stimulation and completiondesign, and an optimised drilling process, are producingdramatic results in North American shale basins, and theyare equally applicable to complex reservoirs worldwide.In the future, we expect that similar advances developedfor India or Brazil or Russia will also set new standards ofproductivity.For example, we are linking specialised reservoirevaluation and modeling technologies to select the correctrock to stimulate. By fracturing only the most productiverock, we have increased production up to 30 per centin one reservoir, compared to offset wells. In anotherproject, by fully integrating drilling services, drill bits anddrilling fluids, the operator saw a 55 per cent reductionin drilling days over the course of drilling 50 wellbores –a great illustration of the power of rapid learning. On thesame project, by combining logging, stimulation andcompletions, the operator was able to almost double thenumber of producing zones completed in a month.The trend is toward treating larger pieces of the project asa whole, because that is where we can create the greatestvalue. In one North American basin, we partnered withthe operator to optimise full field development startingwith the first well. By integrating 3D seismic, microseismic4420th World PETROLEUM Congress

Cooperationfracture modeling, geological interpretation andcompletion data, and by modeling to optimise both thewell construction parameters and completion strategies,we estimate the operator will see a 20 per cent increase inultimate recoveries and a 10 per cent unit cost reductionover the life of the field.Reducing environmental impactOur work is increasingly being judged not only by theenergy produced, but also size of the operation’s footprintand the ultimate impact on the area. These concerns andthis scrutiny will most likely continue to increase.Our response is to create and introduce technologieswith these goals in mind and plan developments thatwill maximise safety and reliability and minimise footprintfor the long term. These are substantial investments, butthey are necessary for our long-term success. We do notconsider these efforts optional extras; we regard them aspart of our core competency.For example, in North America, hydraulic fracturing hasbecome a much-discussed question as shale developmentmoves into heavily populated areas. We anticipated this,and have introduced a suite of fracturing technologies thatset new standards for minimizing impact. These includea fracture fluid system comprised of materials sourcedentirely from the food industry, a service that uses ultravioletlight instead of chemical biocides to control bacteria influid systems, and a system that uses electrocoagulationto treat flowback and produced water to make it reusable.These technologies are in service now, helping to reduceour footprint and overall impact.People are the coreDelivering these solutions also requires another set ofchanges, the second theme I mentioned at the outset:we are changing to speed up organisational learning andknowledge management.Creating integrated workflows is dictating a change ofemphasis within the organisation, because it requires anorganisation that cultivates and values collaboration acrossbusiness units and across disciplines. This is a substantialcultural change that is taking place in stages. Onesuccessful collaboration begets the next, and gradually thenumber of integrated workflows grows, and the scope ofthe integration broadens to become more holistic.The ability to mobilise the right expertise anywhere inthe world to solve the particular development challengeis a more visible source of value. We think of it as bringingthe full intellectual capital of the company to bear on thesituation – knowledge management in its highest form.Our Consulting and Project Management product serviceline is explicitly built along these lines. It exists outside ourdivisional structure and pulls experts from all disciplines forspecific challenges.North America’s shale basins provide an illustration ofhow the knowledge management approach can work.We invest in reservoir understanding, and in developingholistic solutions based on that understanding. We havea ‘tech team’ assigned to each basin – a multi-disciplinedteam of individuals who are the experts in that basin. Theyhave the knowledge and experience to develop and applythe total solution that draws upon all the capabilities ofthe company. They are the ultimate integrators and thearchitects of the holistic solution.Part of their mission is sharing their knowledge andinsights with the rest of the organisation. They link upwith tech teams from other basins. They make theirdata and results available, and they consult with otherteams where they can contribute. This will be especiallyimportant outside North America, where 75 per cent ofthe shale reserves are located. Sharing the tech teams’knowledge with our staff in other regions where shaledevelopment is just getting started will be crucial toaccelerating value creation.To help speed this process, we bring experts from otherregions and embed them with our North American techteams for a year or more to acquire first-hand experiencein reservoir knowledge, scenario testing, developmentplanning, and engineering for every phase of the project.This will shorten the learning curve for emerging complexplays. The process will also work in the opposite direction,as insights and techniques developed for offshore Brazil orIndonesia are transferred to North America. The systematicsharing of cutting-edge expertise will be a permanent partof our life.These trends also influence the way we recruit anddevelop employees. We search the world for topengineering and business talent, work with universities onevery continent to help shape curricula and promote theopportunities in our industry. And we provide employeeswith a breadth of assignments to help them become moreflexible and more able to contribute to holistic solutions.Greater integration across disciplines also demands a newlevel of reliability and predictability in service delivery, →Energy Solutions For All 45

Cooperation→ which in turn requires a new generation of competenciesand skills. In response, we are broadening our training andformal competency system to provide both a predictableinventory of skills for the organisation, and a clear path toadvancement for employees.At the same time, we are standardising work methodsaround the world to provide both greater uniformity in theservices we deliver, and more flexibility and responsivenessto new needs. Standardised work processes will help speedup innovation and learning. Innovations in practice can becaptured faster and spread across the organisation. Peoplecan more easily transfer to new geographies. We can rollout new technologies more rapidly. In short, these practiceswill help speed organisational learning and contribute todeveloping and applying holistic reservoir solutions.Flexibility and rapid responseThere are other long-term changes that contribute toflexibility and rapid learning. To help us develop tailoredsolutions, we have created regional technology centresin India and Singapore. Currently there are some 250technologists working in these two centres. And we arebuilding centers in Saudi Arabia and Brazil that will have asimilar mission – technology, applications and experiencefor specific customers and challenges. And the knowledgecreated in these basins will be a valuable asset to be sharedthroughout the organisation.We are also distributing our manufacturing capacityand supply chain around the world and bringing themcloser to customers and basins; this helps the organisationrespond more quickly to local needs. Combined withan efficient global logistics operation, we can bettermanage materials and equipment so they are where theyare needed most.Finally, faster organisational learning and faster, moreuniform spread of best practices will help with regulatorycompliance. We expect the regulatory environment tobecome more uniform and more detailed across the globe.To succeed in that environment, service company practiceswill also need to become more consistent and uniform.And by doing this, service companies will also be able tocontribute to effective regulation. For example, we arecollaborating with authorities to develop new standards foroffshore work in the Gulf of Mexico. And consistent, uniformregulation will help us create the technologies and practicesthat reduce our footprint and environmental impact. Afterall, the fundamental challenges are the same worldwide.The world needs big ideas, big energy projects andbig results now more than ever. To get them, we willneed the horsepower and work ethic service companieshave provided for generations. And we will also needsmart, high-performing service companies that can helpoperators develop optimised solutions for their complexreservoirs and speed up the process of innovation andorganisational learning. If we build organisations withthose needs in mind, we will once again overcome allthe pessimistic forecasts and deliver the energy ourcivilisation needs. •Photo courtesy of GazpromEnergy Solutions For All 47

CooperationOPEC: The importance of securityof demand as well as supplyBy His Excellency Abdalla Salem El-BadriSecretary General, OPECIn a world that is ever more inter-linked, with internationaltrade, greater personal mobility and mass communicationbringing us all closer together, it has become increasinglyimportant to appreciate the scope and intricacies of theglobal energy system. It is a system that helps support thefabric of our everyday lives. Thus, it is essential to learn fromthe past, understand the present, and comprehend thepossible energy futures the world may face. It is a path ofperpetually evolving analysis, as the energy system facesboth local- and global-impacting events.This has been strongly evident over the past few yearswith the world economy undergoing a recession thatturned out to be the deepest in more than six decades. Noone was immune from the downturn, but the degrees towhich industries, countries and regions were affected havediffered. This has been apparent in the economic recovery.Emerging economies, with China and India to the fore,have returned to strong growth rates, and the challengenow comes from overheating and rising inflation. This isin contrast to many OECD countries that are juggling theneed for additional monetary and fiscal policies to supportfragile growth and the necessity for fiscal consolidation. Inthe US, growth has slowed this year, and in the eurozone,despite efforts to avoid the contagion risks from the Greeksovereign debt crisis, serious concerns have emergedabout a worsening situation in other countries.In addition, this year has also seen a number of otherunforeseen events, such as the multiple disasters thathit Japan – earthquake, tsunami and nuclear accident –and the unrest that has been witnessed in a number ofcountries in North Africa and the Middle East.The knock-on impacts of these developments to oiland energy markets have been varied. For example, theinitial impact of the global recession was a demand dropoff in both 2008 and 2009, although demand has grownappreciably in the period since. A number of energyinvestments were initially put on hold, although many ofthese are now being implemented; and of course, jobswere lost. In terms of Japan, the disaster led to a suddendecline in the country’s oil use. However, this was broadlyoffset by the need to substitute some of its shut-in nuclearcapacity – whose future is now being questioned, as it iselsewhere – with oil- and gas-based generation. Moreover,reconstruction efforts are expected to lead to higherenergy use. And in North Africa and the Middle East, therehas been interruption in supplies from Libya, as well asFigure 1: Relationship between WTI prices and net long positions of money managers120110100908070605040’000 Contracts3002502001501005001 September 20091 November 20091 January 20101 March 20101 May 20101 July 20101 September 20101 November 20101 January 20111 March 20111 May 20111 July 2011WTI (LHS)Managed money net long positions (RHS)4820th World PETROLEUM Congress

Cooperationmarket fears that disruptions might spread.These developments underscore some of the multiplechallenges facing the market, but it should be noted thatoil markets have rapidly adjusted to these events. Over theperiod highlighted here, there has been no shortage of oilanywhere in the world. It is essential that all stakeholderslook to maintain oil market stability in the months andyears ahead.That is not to say that the market has been free fromvolatility. This is clearly underscored in the price swingswitnessed over the past few years. In mid-2008, crudeprices reached a peak of US$147/b, with crude pricesearlier that year fluctuating by as much US$16/b on asingle day. The magnitude of the price volatility was notat all consistent with market fundamentals. Then, drivenby the global economic downturn, they plummeted tothe low US$30s in December of the same year. In 2009,prices rose steadily, to end at close to US$80/b at the endof the year, and it remained around this level throughout2010. However, the early part of the year saw a surge in oilprices to above US$120/b, although prices in the secondand third quarters saw some movement in the oppositedirection on the back of bearish economic concerns.As in 2008, the volatility in thefirst half of this year has in partbeen driven by speculation. Thiscan be observed in speculatoractivity on the Nymex, whichsurged to record highs in the first 400part of the year. For example, bymid-March, the volume of open350interest contracts for Nymex WTI300was 18 times higher than thevolume of daily traded physical250crude. Such an increase was theresult of concerns of a further200deterioration in supply. Thebuild-up of large speculative150positions on the crude futuresmarkets was a key factor behind 100the increased crude oil pricevolatility. Figure 1 highlights the 50relationship between WTI pricesand the speculative activity of 0the net long positions of moneymanagers. A curb in speculativeactivities is needed.1960 —It should also be noted that the price rises in the first halfof this year were even more pronounced at the consumerend, where the effect of consuming country taxation isgreatly felt. While OPEC has played its role by ensuringthe market remains well supplied in crude, it is of coursehelpful if consuming countries that have a high level oftaxation on oil products consider revising down theselevels, at least when prices reach certain levels, to alleviatethe impact on consumers.The last few years have been an unpredictable timeand the industry continues to face many hurdles andchallenges. Yet, there is still good reason to look aheadwith optimism.As economies expand, the global population grows andliving conditions improve, energy demand will continueto increase. By 2035, world energy demand is expectedto be more than 50 per cent higher than it was in 2010.With this expansion in mind, it is clear there is room fora variety of energies, but it is important to appreciatewhat each can actually offer. Which energies will form thecore of our future? And which energies will play a morecomplementary role?Renewable energy, mainly wind, solar, small hydro and →Figure 2: World supply of primary energy by fuel type1965 —1970 —1975 —1980 —1985 —1990 —1995 —2000 —2005 —2010 —2010 —2020 —2025 —2030 —GasOilCoalNuclear/hydro/biomass/other renewables2035 —Energy Solutions For All 49

Cooperation→ geothermal, is expected to grow fast, as a result ofmassive government support and incentives. Globally,however, its share in the energy mix will remain modest,given its low initial base. Hydropower should also expand,but given the limited scope for further expansion in manydeveloped countries, it is expected that much of this willbe in developing countries.Biofuels are also expected to play a greater role, supportedby direct and indirect government subsidies, but not atlevels once assumed. For first-generation biofuels, muchconcern has recently been expressed over the competitionbetween food and fuel. There have also been reportson their possible negative impact on biodiversity, theirpotential to make scarce water resources, even scarcer,and, in most cases, their relatively high greenhouse gasemissions, when land use change effects are fully takeninto account. Second generation biofuels can overcomesome of these concerns, but they are still far from beingavailable for commercial use.Nuclear power had witnessed something of a revival inrecent years, with a number of countries looking to buildnuclear plants. Events earlier this year at the Fukushimanuclear complex in Japan, however, have led to manyquestions being asked about nuclear power, particularlyin terms of safety, waste and decommissioning.353025201510501971Figure 3: Energy use per capita (mboed)1990OECD2010Developing countriesIt means that fossil fuels will maintain their prominentrole, continuing to supply over 80 per cent of the world’senergy needs by 2035 (Figure 2). Even with a numberof energy policies that to a considerable extent seek toreduce oil use, it is clear from OPEC’s World Oil Outlook(WOO) 2011 that oil’s leading role in the energy mix willcontinue for most of the period to 2035. Towards the endof this timeframe, however, it will be surpassed by coal,with oil’s overall share falling to around 28 per cent in 2035.Fossil fuels also have challenges, such as theirenvironmental footprint, in particular in terms of CO 2emissions. It should be recalled, however, that the petroleumindustry has a long history of successfully reducing itsenvironmental footprint, for example, in drilling, gasflaring and plant emissions. And the automotive industry,as well as the refining industry, has a good track record incontinuously reducing the pollutant emissions of vehicles.It is essential that we continually look to advance theenvironmental credentials of oil, both in production anduse; improve operational efficiencies and recovery rates,and push for the development and use of cleaner fossil fueltechnologies, such as carbon capture and storage.Looking ahead, developing countries are set to accountfor most of the long-term oil demand increase, withconsumption rising 26 million barrels a day (mb/d) overthe period 2010-to-2035to reach almost 62mb/d.Around 80 per cent of the netgrowth in oil demand in thisperiod is in developing Asianeconomies. Transportation isthe main source of this growth,and developing countries’percentage of passenger carsglobally will increase fromaround 23 per cent to 49 percent in 2035.In fact, the hub for oil demandhas been progressively shiftingtowards Asia in recent years.For example, since 2005, OECDoil demand has contractedby around 3.7 mb/d, whiledeveloping Asia actually sawan increase of almost 4.8 mb/dover the same period.Nonetheless, energy poverty20355020th World PETROLEUM Congress

Cooperationwill remain. Energy use per capita in developing countrieshas always been well below that of the OECD and thisremains the case in the future: in 2035 the OECD will beusing on average three and a half times as much energyper capita as developing countries (Figure 3).From an oil perspective, the world also has plenty ofresources to meet the expected increase in demand. Theend of oil has been talked about since the very beginningof the oil age, more than 100 years ago. However, it hasnever come to pass, and since the early 1980s, ultimatelyrecoverable reserves of conventional oil worldwide havedoubled and the figure continues to rise. Technology hasresulted in new discoveries, increased recovery rates andimproved efficiency. Today, we are also seeing the vastpotential for the expansion of non-conventional sourcesof oil.While suppliers continue to face significant challenges,such as the impact of the global financial and economiccrisis, market volatility and the role of speculation, and anoften unclear demand picture as a result of a number ofconsuming country policies, investments to turn resourcesinto capacity are being made. In the medium-term to2015, OPEC Member Countries are expected to investan estimated US$310 billion in upstream projects. OPECremains committed to future investment plans to boostits capacity.It is important to stress,however, that the pace of futureenergy demand growth, andin turn investments, is affectedby many uncertainties. Thisincludes the possibilities ofvaried economic growth paths,consuming countries’ energyand environmental policies,technology and consumer choices.For example, OPEC’s WOO2011 shows that demand forOPEC crude by 2025 could beas low as 31 mb/d or as high as38 mb/d. These scenarios pointto an uncertainty range in thebillions of dollars. Such fearsconstitute a great challenge forall stakeholders.If there is no confidence inthere being additional demandfor oil, there is no incentive to invest. Why waste preciousfinancial resources on unneeded capacity? On the otherhand, if investments are not made in a timely and adequatemanner, then future consumer needs might not be met.The supply and demand balance is essential to the overallhealth of the industry. Oversupply or a supply shortfallis detrimental to both producers and consumers. It isimportant to appreciate and better understand the twosides of energy security: security of supply and securityof demand.The oil market has been — and will continue to be — anever-changing arena. This is because oil is so vital to theworld economy, it is present in everyone’s daily lives andits market is truly global. This underscores the importanceof dialogue and cooperation, on both a bilateral andmultilateral basis, to meet both the challenges andopportunities facing the industry. While differences ofopinion will obviously occur, it is important to try and reachan underlying consensus on, at least, the major issues thatconcern all parties — such as pricing, stability, security ofdemand and supply, investment, environmental issues andsustainable development. This will hopefully ensure thatthe world oil market continues to operate efficiently andeffectively in the future, for the enhancement of everyoneacross the globe.•Energy Solutions For All 51

CooperationGECF: A new participantin the natural gas marketBy Leonid BokhanovskySecretary General, Gas Exporting Countries ForumToday’s globalised world, interconnected morethan ever by technology, politics, economics,social and environmental issues, requiresplatforms for dialogue and fora for convergingthe interests of countries that want to make rational useof their resources. International organisations representsuch platforms and therefore developed and developingcountries, producers, exporters, importers and consumersof natural resources must continually appreciate theactions of international organisations.Within this context the Gas Exporting Countries Forum(GECF) plays a significant role as an organisation thatcontributes to maintain energy security worldwide andstability in natural gas markets, considering that the globalfinancial crisis and the ensuing economic slowdowntogether with volatile energy prices have created indeed aunique set of challenges for the gas industry.The Gas Exporting Countries Forum is anintergovernmental organisation established as a Forumduring the 1st Ministerial Meeting held in Tehran, Iran, inMay 19-20, 2001, by the governments of Algeria, Brunei,Indonesia, Iran, Malaysia, Oman, Qatar and Russia, withTurkmenistan and Norway as Observers. The meetingpromoted by Iran aimed to bring together the main gasexporters with the purpose of increasing the level ofcoordination and strengthening collaboration, exchanginginformation about their corresponding industries andtechnical know-how and debating on common concernsand goals on crucial issues of gas market development andfuture planning. The GECF seeks also to build a mechanismfor a more meaningful dialogue between gas producersand gas consumers for the sake of stability and security ofsupply in global natural gas markets.Since the first meeting of energy ministers, it startedan active process that involved a series of meetings ofthe different governing bodies of the Forum; as a result,the Agreement on the Functioning of the Gas ExportingCountries Forum and the Statute of the GECF weresigned by the representatives of the governments of 11Member Countries during the 8th Ministerial Meetingheld in Moscow on December 23, 2008, thus transformingthe GECF into a fully-fledged international organisation.However, in the name of the organisation the word “Forum”was kept to reflect its open and democratic nature.The next step of the organisational developmentinvolved the submission of five ratifications as per theAgreement, which entered into force on October 1, 2009.Afterwards, the Headquarters Agreement was signed withthe State of Qatar in December 2010 and the first SecretaryGeneral of the Forum was appointed by the 9th MinisterialMeeting and his tenure started in February 2010.The structure of the Gas Exporting Countries Forum aslaid down in its Statute is as follows:• The Ministerial Meeting: this is the supreme governingbody of the Forum. It holds meetings at least once a yearand adopts Decisions in the form of Resolutions. In 2011the Minister of Petroleum of Egypt is holding the rotatingPresidency of the Ministerial Meeting, while the AlternatePresident is the Minister of Energy and Energy Affairs ofTrinidad and Tobago.The Ministerial Meeting formulates the general policy ofthe Forum and determines the appropriate ways and meansof its implementation; appoints the Secretary General, as wellas the Chairman and Alternate Chairman of the ExecutiveBoard; decides upon applications for membership of GECFand approves the budget of the Forum.Besides the first one in Tehran in 2001, MinisterialMeetings have been held in Algiers, Algeria (February2002); Doha, Qatar (February 2003); Cairo, Egypt (March2004); Port of Spain, Trinidad and Tobago (April, 2005);Doha (April 2007); Moscow, Russia (December 2008); Doha(June and December 2009); Oran, Algeria (April 2010) andDoha (December 2010). The 12th Ministerial Meeting washeld in Cairo, Egypt on June 2, 2011.• The Executive Board: this directs the management ofthe affairs of the Forum and the implementation of thedecisions of the Ministers; approves the work programmeof the Secretariat and draws up its budget, among otherfunctions. The Chairman of the Executive Board for 2011is the representative of Trinidad and Tobago, while theAlternate Chairmanship is held by Egypt.• The Secretariat: this organises and administers the workof the Forum and carries out its executive functions inaccordance with the provisions of the Statute under thedirection of the governing bodies. It consists of SecretaryGeneral – the authorised representative of GECF – and staff.Today, the GECF is a gathering of the world’s leadinggas producers. The Member Countries of the Forumare: Algeria, Bolivia, Egypt, Equatorial Guinea, Iran, Libya,Nigeria, Qatar, Russia, Trinidad and Tobago and Venezuela.Kazakhstan, the Netherlands and Norway have the status ofObserver Members. With the current number of Membersthe GECF is a strong player in the world gas market andamong international energy organisations. Its potential5220th World PETROLEUM Congress

Cooperationrests on the enormous natural gas reserves of the MemberCountries, which all together accumulate 70 per cent ofthe world proved natural gas reserves. The Forum highlyvalues the potential of its Member Countries and ObserverMembers and at the same time is looking forward tofurther increases in membership and welcomes newmembers that share the common interests and objectivesof the Forum’s Statute.The GECF takes into account the importanceof long-term contracts and fair pricingfor natural gas at levels reflecting marketfundamentals and parity with oil pricesThe main objective of the GECF is to support thesovereign rights of Member Countries over their naturalgas resources and their abilities to independently plan andmanage the sustainable, efficient and environmentallyconscious development, use and conservation of naturalgas resources for the benefit of their peoples. According tothe Statute, these objectives will be promoted through theexchange of experience, views and information on suchtopics as:• Worldwide gas exploration and production trends;• Present and anticipated supply-demand balance for gas;• Worldwide gas exploration, production andtransportation technologies;• The structure and development of gas markets (regionaland global);• Transport of gas: pipelines and LNG carriers;• Interrelationship of gas with oil products, coal, and otherenergy sources ;• Technologies and approaches for sustainableenvironmental management, taking into accountenvironmental constraints, national regulations andmultilateral agreements on environment and their impacton volume and sustainability of gas consumption;• Techniques and approaches for maximising thecontribution of natural gas resources, at all stages of thevalue chain, to the promotion of sustainable economiesand human resources development in member countries.Based on these objectives, the main tasks of the GECFare related, on the one hand, to the development andimplementation of necessary steps to guarantee thatMember Countries derive the most value from their gasresources, since natural gas is a non-renewable sourceof energy. In this regard, GECF takes into account theimportance of long-term contracts and fair pricing fornatural gas at levels reflecting market fundamentalsand parity with oil prices for ensuring the energysecurity of producers and consumers. This condition isa prerequisite for the development of gas reserves andthe success of important infrastructure projects relatedto gas. However, even though the GECF Ministerssupport oil-gas price parity, this does not imply that theForum has plans to regulate the volume of gas exportsor to determine prices.It is clear that without well thought-out investmentsand infrastructure development in the gas industry it willnot be possible to talk about sustainable growth in theworld’s major economies, as global gas consumption willonly increase over the next decade. The GECF considersnecessary to establish a more predictable and reliableglobal gas industry and member countries can contributeto the progress of a coherent framework for strong,sustainable and balanced economic growth. Moreover,the Forum finds that the present gas market dynamicspushes its main participants to closer cooperation.On the other hand, the GECF promotes the developmentof dialogue between natural gas exporters and importers.It is ready to study and discuss problems concerning theinterests of all Member Countries (including pipelinesgas and LNG exporters), as well as problems relatingto the security of supplies. The Ministers of the Forumhave stated positions on issues such as the stimulationof cross investments and technological exchangesbetween gas consumers and producers based on growinginterdependence between them, but without unjustifiedbarriers, especially those related to carbon taxation. TheGECF also considers that meeting local demand for naturalgas in the producing countries is a priority.The GECF is progressively becoming a reference inthe gas market and in the next years it will play a morerelevant role as a factor of stability and cooperationamong Member Countries and consumer countries, in ascenario where the natural gas will grow in importancein the global energy mix, considering its advantages asa clean, abundant and safe fuel of choice capable ofcontributing greatly to global energy security. These andother issues are part of the discussions to be held at thefirst ever summit of heads of state and governments ofthe GECF countries in Doha in November 2011, in themost important event of the GECF this year: the 1st GasSummit of the GECF in Qatar. •Energy Solutions For All 53

CooperationThe view from the world’sbiggest energy userBy Professor Wang ZhenChina University of Petroleum at BeijingChina has become the world’s second largesteconomy, but its biggest energy consumer. China’sgross national product only surpassed that of Japanlast year and was only 41 per cent of the US. ButChina’s energy intensity – the ratio of energy input toeconomic output – is 3 times that of the US and 5 timesthat of Japan. Accordingly, there is a very high potentialcapacity to improve energy efficiency in the future. Howfar China succeeds in increasing the efficiency with whichit uses energy will have an enormous influence on worldenergy markets.The economic and energy boom duringthe past five yearsDuring the 11th Five Year Plan (2006-2010), China’seconomy developed at an extraordinary pace, as did itsenergy industry. The 11th Five Year Plan for China’s EnergyDevelopment had limited growth in China’s primaryenergy consumption to 2.7 Gigatons of coal equivalent(Gtce) a year by the end of the plan period. This would haveamounted to roughly 4 per cent annual growth. However,by 2010 the actual energy consumption figure hadreached 3.25Gtce, reflecting an annual growth rate of 7.66per cent, or 6.7 per cent after a revision of the 2005 basedata. So, from 1949, it took China 41 years to reach 1Gtce/year’s consumption, another 14 years to reach 2Gtce/yearby 2004, but only five years after that for China’s energyappetite to exceed 3Gtce/year.Moreover, coal dominated China’s primary energyconsumption mix. The 11th Five Year Plan was to reducecoal’s share in total energy consumption to 66.1 per cent.However, in the past five years, the share of coal has stayedsteady above 70 per cent, with coal consumption reaching3.2Gt, or 0.65Gt higher than indicated in the Plan.The unusually fast growth of energy consumptiondramatically accelerated energy production in the 2006-2010 period. The actual annual growth rate of productionwas 7.75 per cent (after adjusting for the base data, still ashigh as 6.72 per cent), far higher than the planned 3.54per cent yearly increase. By the end of 2010, total energyproduction peaked at 2.99Gtce, a 45.22 per cent increaseover the year 2005 and 22.04 per cent higher than theplan. The unplanned production growth in crude oil,natural gas and nuclear power was not as significant asthat of coal and hydropower. Given the relatively smallvolume of hydropower capacity, the excess in totalenergy production came mostly from coal, while theexcess in coal production was in turn driven by excessgrowth in domestic power consumption.But the most eye-catching growth rates were in naturalgas and hydropower. For the reason that the proportionof natural gas in China’s energy structure had always beenlower than the world average level, the growth of naturalgas production was seen as a major element in the 11thFive Year Plan strategy to improve the country’s energystructure. Natural gas production increased at recordrates and at record volumes during the 11th Five YearPlan. The annual growth rate reached 14.45 per cent, andproduction nearly doubled over the five years. As the lastphase of Yangtze Three Gorges Hydropower Project wascompleted and put into operation, China’s hydropowercapacity grew at an annual growth rate of 10.77 per cent.Explaining the excessWhy did actual energy consumption and production soover-shoot the planned targets? One reason was statistical– the national bureau of statistics had underestimated thelevel of energy consumption and production for the 11thFive Year plan’s base year of 2005. But there were two morefundamental reasons.First, the whole Chinese economy grew faster than theplan. The 11th Five Year Plan for National Economic andSocial Development clearly laid down that China’s targetannual GDP growth rate would be 7.5 per cent. However,the actual annual average growth rate turned out to be 11.2per cent, or 3.7 percentage points higher than expected.As the plan for energy consumption and productionwere made on the basis of National Economic and SocialDevelopment Plan, the greatly under-estimated level ofeconomic growth had the effect of pulling up the growthrate of energy consumption. In fact, each percentagepoint of extra expansion in the general economy led to adisproportionately larger increase in energy consumption.Second, less energy efficiency was achieved throughindustrial restructuring than was hoped. Aside fromtechnological and management factors, China’s economicdevelopment status and industry structure account forChina’s low energy efficiency compared with developedcountries. Statistics show that a one percent increase inthe share of the tertiary sector, or services, in the wholeeconomy will reduce total energy consumption by around0.1Gtce. From 2005 to 2010, the share of the tertiary sectorin the economy went up by 2 per cent, at the expenseof agriculture (but not of mining) which reduced the5620th World PETROLEUM Congress

Cooperationrelative size of the primary sector. The energy intensityof manufacturing and services is higher than that ofagriculture. So the aim of reducing energy consumptionthrough industry restructuring did not work out.In addition to China being in the high energyconsumption phase of urbanisation, the financial crisisalso hindered China’s steps toward industry restructuring.In order to offset the impact of the global financialcrisis on China’s economy, the Chinese governmenttook countermeasures such as the Major Ten Industries’Rejuvenation Plan to stimulate economic growth as wellas to create employment opportunities. However, thosemeasures in fact encouraged the revival of high energyconsumingindustries, making it harder to conserve energyand reduce emissions.The outlook for the next five yearsIn the 12th Five Year Plan (2011-2015) for National Economicand Social Development, there are three constraintindicators which are closely related to energy consumption.These are that non-fossil energy consumption should riseto 11.4 per cent of total primary energy consumption; thatenergy consumption per unit of GDP should fall by 16 percent; and that carbon dioxide emission per unit of GDPshould decrease by 17 per cent. Among the three, nonfossilenergy consumption indicator is the most important.Assuming that the 16 per cent decrease in energyintensity from 2010 to 2015, the economy will still be ableto grow at the expected growth rate of 7 per cent, providedthe annual growth rate of primary energy consumptionwill be 3.95 per cent. This would allow China’s total primaryenergy consumption to grow to at least 3.945Gtce by 2015,from 3.25Gtce in 2010.Assuming that non-fossilenergy consumption perGDP will increase to 11.4per cent of total primaryenergy consumption, theproportion of natural gasin energy consumptionstructure will have torise so as to realise thegoal of reducing energyconsumption and carbondioxide emission per GDP.China’s natural gasproduction is on the risingPlanned Energy Consumption in 2015Total energyconsumption - Gtcetrack. Assuming that future growth rate of productionequals the average annual growth rate in the 11th FiveYear Plan period, China’s natural gas production will be190Bcm. Add 70bcm of net imports, and China’s naturalgas demand should reach 260bcm (0.31565Gtce) by 2015,accounting for 8 per cent in the 3.945gtce of total primaryenergy consumption. In the next five years, demand forcrude oil will rise steadily, rising to 0.51 Gt or 10.2 millionbarrels a day, accounting for 18.4 per cent in the total.Domestic oil production is impossible to increasemuch. So demand growth will mostly have to rely on theinternational market. By 2015 China will probably dependon imports for nearly 60 per cent of oil, but at the sametime it is filling up its Strategic Petroleum Reserve whichshould contain 270m barrels by the end of 2012. The MiddleEast and Africa will remain China’s dominant sources ofimported oil. But, with the Russia-China crude pipeline incommercial operation since 2010, the second phase of theKazakh-Chinese crude pipeline finished, and several ‘loansfor-oil’deals signed with South American suppliers in thelast couple of years, Beijing is diversifying its sources ofsupply. The rapid pace of upstream investment by China’sthree oil majors will also consolidate these companies’trading power.The huge residual of this equation is the demand for coal,whose consumption is virtually guaranteed to increaseto 3.44Gt by 2015. But the share of coal in total energyconsumption will have to shrink a little if non-fossil energyis to increase its share to 11.4 per cent in total energyconsumption. Among low carbon sources, hydropowerwill continue to dominate, with nuclear power second anda fast-growing contribution from wind. →2010 Actual 2015 Estimated 2015 Proportion (%)3.25 3.945 100Coal - Gt 3.20 3.44 62.2Crude oil - Gt 0.43 0.51 18.4Natural gas - Bcm 104.80 260 8Non-fossil energy - Gtce 0.21 0.45 11.4Energy Solutions For All 57

We’re ChangingMindsetsWeatherford’s Tactical Technology and flexibility can changethe way you think about your service needs.© 2011 Weatherford. All rights reserved. Incorporates proprietary and patented Weatherford technology.Inventive new approaches to reduce your costs and increase wellproductivity. Flexibility and open-mindedness. Get-it-done mentality.That’s what you’re looking for and that’s Weatherford. And that’s why we havea rapidly expanding worldwide presence.DrillingEvaluationOur Tactical Technology and services span the life cycle of a well:Drilling services make well construction safer, reduce nonproductive timeand enhance reservoir deliverability. Evaluation services combine moreconveyance options with industry-qualified measurements. Completionservices offer systems engineered for all environments from conventionalto the most challenging. Production services maximize reservoir recoverywith artificial lift, well optimization and remote monitoring and controltechnologies. Intervention services remediate problems to extend wellproduction life.Discover for yourself how our Tactical Technology and service flexibilitycan change your mindset.SMThe change will do you goodCompletionProductionInterventionweatherford.com

Changing Mindsets withTactical Technology and a get-it-done mentality.Weatherford Tactical Technologycuts costs and delivers results tohelp you reach strategic goals.Future uncertaintiesMany uncertainties surround forecasts about China andenergy. The biggest uncertainty, given what happenedduring the 11th Five Year plan period, is the country’soverall growth rate. My analysis, and the government’s, isbased on the assumption of 7 per cent average growth inthe coming five years. But if the growth rate were to average10 per cent, the total primary energy consumption wouldrise to 4.3Gtce, even if efforts to reduce energy intensitywere to do well.In the next five years natural gas will play an importantpart in energy consumption optimisation. But a crucialfactor here is pricing reform. If the natural gas price is stillrelatively low, motivation to develop unconventional gaswould be reduced. Thus, any delay in the price reformmay directly influence the realisation of the goal ofnatural gas taking 8 per cent in the total primary energyconsumption structure.Development of the gas market and the expansionof wind power are both related to energy infrastructure.Future growth of China’s natural gas consumption isclosely tied to the construction of three major cross-bordergas pipelines – the Central Asia-China gas pipeline comingfrom Kazakhstan and connected to the domestic West-East gas pipeline, the China-Myanmar gas pipeline andthe Russia-China gas pipeline – as well as the constructionof LNG import facilities. Improvements in the domesticgas network and strategic gas storage are also vital tomeet the rapid growth of demand. In 2010, China’s windpower capacity was an astonishing 33 times bigger than in2005, rising from 1.26m kw to 41.82m kw over that period.This amounts to a quarter of world wind power capacity.However, to maintain this rate of growth requires constantimprovement in grid connection.The Fukushima nuclear accidents in Japan may affectChina’s medium and long term plan for nuclear powerdevelopment, especially if new safety measures raise thecost of nuclear construction and operation, affecting thecompetitiveness of nuclear power. But the influence onthe 12th Five Year Plan period will be relatively limited,because of the long lead time in building nuclear powerplants. Plants now under construction will be completedand put into use in the 12th Five Year Plan period. Even iffuture projects are postponed, the impact will only showin the more distant future.•Advancements in drilling includeour Revolution ® rotary-steerablesystem that makes extremeconditions routine. And, you canspeed up operations using ourdrilling-with-casing (DwC ) systemto simultaneously drill and caseyour well.Exclusive evaluation technologyincludes Compact logging toolsand Assure conveyance optionsto ensure quality data in deviatedand rugose wellbores.Completion innovations includeexpandable sand screens andtubulars, intelligent well systemsand more—all to increase wellproductivity and reduce costs.Production capabilities featureindustry-leading artificial-lift andwell optimization products andservices, including the LOWIS life-of-well information system.Intervention technologies includeour OneTrip StarBurst Level 4multilateral that saves two daysof rig time and risk exposure.To discover how WeatherfordTactical Technology andservice flexibility can change theway you think about your serviceneeds, visit weatherford.com.SMThe change will do you goodweatherford.com© 2011 Weatherford . All rights reserved.Incorporates proprietary and patented Weatherford technology.20th World PETROLEUM Congress

CooperationIndia’s emerging energyneeds and supply optionsBy Kirit S Parikh, Chairman, Integrated Research andAction for Development (IRADe), New DelhiIndia, like China, is Figure 1: Energy intensity and TPCES in India since 1994expected to be one ofthe main drivers of worldenergy consumption asIndia’s economy continues togrow at a rapid rate. Indeedits energy needs could beeven more dynamic thanthose of China. In additionto a quasi-Chinese rateof economic expansion,it is also undergoingrapid population growth.Moreover, it is chasing theever-moving target of tryingto link all its people to theelectricity grid. Of the 1.5bn people who according to theInternational Energy Agency lack access to electricity in theworld, nearly 400m live in India. However, India’s RGGVY(Rajiv Gandhi Grameen Vidyutikaran Yojna- Rajiv GandhiVillage Electrification Scheme) has the objective to electrifyall villages and connect free of cost all estimated around25 million households below the poverty line by March,2012. If successful, this massive effort of electrificationwould have consequences for world energy producersvying to supply this modern form of energy to the Indianeconomy, as well as being of enormous benefit to thecurrently power-less poor of India.Since 1994, the energy intensity – the ratio of energyinput to economic output – of India’s economy has beendeclining, as in most countries of the world. In figure 1 we0.0208 kgoe/rupee by 2009. This also shows the growthin total primary commercial energy supply (TPCES); thereason for defining it as ‘commercial’ is to exclude theconsiderable use in the Indian countryside of firewoodand animal dung which do not enter the regular economy.Commercial energy grew from around 210 Mtoe in 1994 toaround 474 Mtoe in 2009. The twin drivers of this growth inenergy use have been economic expansion and populationgrowth. In the period of 1994 to 2009 India’s GDP grewat an average growth rate of 7 per cent, whereas in thelatter part of this period (2003-2009) the rate of economicexpansion accelerated to an average of 8.3 per cent.Table 2: projected electricity requirement until 2030Yearsee that it has fallen from 0.0259 kgoe/rupee in 1994 toTable 1: TPCES until 2030YearPopulation(billions)GDP (Rs billions) at1993-94 pricesTPCES* (Mtoe)GDP growth rate8% 9% 8% 9%2009 1.169 23098 23098 474 4742010 1.176 24946 25177 502 5062015 1.254 36654 38738 657 6842020 1.326 53856 59603 860 9252025 1.389 79132 91706 1114 12362030 1.44 116271 141101 1445 1654Source: http://www.censusindia.net/, and RBI (2010), Table 2* based on falling elasticities of 0.75 for 2004 to 2010,0.70 for 2010 to 2020 and 0.67 for 2020 to 2030.Total energyrequirementat GDpgrowht rateEnergyrequirementat GDP growthrate (BKWh)Projectedpeak demandGW at GDPgrowht rateInstalledcapacity (GW)required atGDP growthrate8% 9% 8% 9% 8% 9% 8% 9%2009 906 906 834 834 125 125 188 1882010 974 982 897 904 138 140 202 2042015 1348 1414 1241 1302 197 206 280 2932020 1866 2036 1718 1874 280 306 387 4222025 2519 2850 2319 2623 378 428 522 5912030 3403 3993 3133 3675 511 599 706 828Source: Ministry of Finance (2011) & Planning Commission ofIndia (2006)• based on falling elasticites of 0.95 from 2004 to 2010,0.85 from 2010 to 2020 and 0.78 from 2020 to 2030.• Electricity generation and peak demand is the totalof utilities and non-utilities above 1MW size.6020th World PETROLEUM Congress

CooperationTable 1 shows how population, economy and energyuse are likely to rise in absolute numbers over the next 20years to 2030 and how these trends translate into India’sfuture electricity needs is illustrated in table 2.What would be the impact on electricity requirements ifall households were connected to electricity?To estimate this, first of all we need to establish abaseline by projecting from the last household energyconsumption survey of 1999-2000 what household energyuse would be in 2030. This takes account of the fact thatas households’ income rises so does their overall energyconsumption, but it assumes that within their overallenergy consumption, their pattern of fuel use (as betweenelectricity, firewood, dung etc) would remain unchanged.Table 3 shows the result.It should be noted that the requirement of electricity,kerosene and gas for household consumption areincluded in the projection given in Table 3. The impactof the RGGVY scheme, which targets provisionof electricity to all by March 2012, will alterthe demand for electricity. To account for thisimpact, household demands are projected from2010 onwards using the energy use pattern ofonly those households, which had electricity inthe 1999-2000 household consumption survey.These projections are given in Table 4.The differences between the two tables giveus the impact of electrification of households ontheir energy consumption. This is summarisedin table 5. The differences are substantial onlyin 2015, as even without the acceleration inrural electrification planned under RGGVY, mostof the households will have been electrifiedby 2020. It is worth noting that for the year2015 electrification does not reduce keroseneconsumption significantly. This is rational. As longas kerosene is available, especially subsidisedkerosene, what is saved from lighting is used asfuel and the consumption of dung goes down.This substitution is more convenient and thedung saved has greater value as fertiliser.Electricity demand grows by 5 mtoe whichis around 16 bkwhr in 2030, for which we haveprojected a requirement of 3100 to 3600 bkwhr.Even after adding T&D losses and auxiliaryconsumption, additional demand for householdscomes to be around 0.5 per cent of the totalprojected electricity requirement.Electrification of all the villages would not only increasehousehold demand but also increase consumption forproductive industrial activities.Since many rural households use dirty bio-fuels such aswood and dung, they suffer from indoor air pollution withsignificant adverse impact on health particularly of womenand children. It is estimated in 2001 that 25m adults hadsymptoms of respiratory diseases with 17m having serioussymptoms.Also 30bn person hours are spent in gathering bio-fuelsoften by girls who are kept out of school. Due to theseexternalities on health and education, India’s integratedenergy policy plans to provide entitlements of liquidpetroleum gas (LPG) to all households appropriatelysubsidized for the poor households. The additionalrequirement of subsidized LPG in 2015, if the programme isfully implemented by then, is estimated to be around 15 →Table 3: Projected energy consumption byhouseholds in India 2030 (Mtoe)Year Fire wood Electricity Dung Kerosene LPG8% 9% 8% 9% 8% 9% 8% 9% 8% 9%2005 87 87 16 17 36 36 12 12 14 142010 93 93 25 27 40 40 14 14 22 242015 98 98 36 39 42 41 15 15 31 342020 101 102 48 52 42 41 15 15 40 422025 104 105 59 63 41 40 15 15 47 482030 106 106 68 70 41 40 15 15 51 52Table 4: Impact of electrification on household energy demand (Mtoe)Year Fire wood Electricity Dung Kerosene LPG8% 9% 8% 9% 8% 9% 8% 9% 8% 9%2010 88 88 28 30 32 32 13 13 23 252015 92 92 40 44 32 31 14 14 32 352020 96 97 52 57 32 31 14 14 41 432025 99 100 64 68 30 29 14 14 47 492030 102 102 73 75 29 29 14 14 52 52Table 5: Changes in energy consumption byhouseholds in 2030 with electrification (Mtoe)Fire wood Electricity Dung Kerosene LPG8% 9% 8% 9% 8% 9% 8% 9% 8% 9%Difference -4 -4 5 5 -11 -11 -1 -1 0.3 0.2Energy Solutions For All 61

CooperationSource: BP (2011)→ mtoe which would reduce over time as incomesincrease and fewer households qualify for subsidy. Thus,the implications of energy access to all are really modestand benefits significant.Supply OptionsIndia’s options for energy supply are limited. It has verysmall reserves of crude oil and currently nearly 80 percent of consumption of petroleum products is based onimports. While some more reserves of natural gas havebeen located in the Krishna-Godavari basin, these deep seareserves pose formidable challenges to exploit. Domesticgas is not expected to constitute more than 20 percentof India’s primary energy supply. The most importantresource is coal. India will continue to depend on it for thenext few decades. Even for coal, the presently estimatedextractable reserves would be exhausted in 40 to 45 yearsif coal consumption keeps growing at the current rate ofgrowth of 5 per cent per year.Among the renewables hydro-power is important.However, assuming full development of India’s potential,it can generate no more than 450 bkwhr of electricity.Compared to the projected requirement for 2030 of 3400to 4000 bkwhr, this is less than 15 per cent. Wind powerpotential is much smaller and with the current technologythe estimated potential of 45 GW can generate about 90bkwhr which will be less than 3 per cent of the neededgeneration in 2030.Other renewables such as ethanol, bio-diesel and woodFigure 2: Structure of Commercial Energy SupplyTable 6: Percentage of energy use met by domestic production1980-81 1990-91 2000-01 2011-12*Coal 99.7 97.8 96.1 93.02Lignite 100 100 100 100Oil 32.6 42.8 30.3 27.59Natural gas 100 100 100 69.30Hydro 100 99.93 99.96 95.94Source: Planning Commission, 2008* Projected; Note: Excludes nuclear and wind power; does nottake into account increases in domestic gas production from 2009plantation have limited scope as India is short of land andthese would compete with food production. Cellulosicethanol, when the technology is developed can make asubstantial contribution if ethanol can be produced fromagricultural wastes such as wheat straw or rice straw.The sources that have sizable potential are solar energyand nuclear power. India’s strategy is to use its limiteduranium reserves to run first generation plants thatalso produce plutonium along with power, using theplutonium in fast breeders reactor that produce moreplutonium than what is put in, and then using in the thirdstage its abundant resource of thorium can provide 4 to 5million MW of power for more than 100 years. The catchhere, however, is the time required to realise this. By 2030one can expect no more than 100 GW of nuclear capacity.Solar is abundant and the land requirement does nothave to compete with agricultural land. The problem is itshigh cost. Today solar powercosts 5 times as much as coalpower in India. Yet there is lotof hope that solar power canbe made cost-competitivewith coal power by 2020.India’s long-term hope forenergy security rests criticallyon realising that goal. Energyefficiency is a major resourceand should be pursuedwith the highest priority.Nonetheless there are limitsto what it can deliver. Ourprojections based on fallingelasticities do embody gainsfrom energy efficiency to alarge extent.•6220th World PETROLEUM Congress

CooperationIndia: Maximising output,while facilitating importsBy R P N Singhminister of state for petroleum and natural gas, IndiaAs the world’s fourth largest oil importer, and asa major refining hub, India’s role in the world’senergy markets is growing. With an economy of1.2 billion people growing annually at 8 per cent ormore, India’s energy needs are growing, and to secure theseneeds the country is taking a multi-pronged approach.We have taken several steps to increase domesticproduction of oil and gas. The New Exploration LicensingPolicy (NELP) launched in the year 1997-8 has seeninvestments of US$14.2bn and has resulted in 87 oiland gas discoveries, with three blocks in production.NELP offers all the necessary ingredients of a favourableinvestment climate: macro-economic and fiscal stability,transparency and the rule of law, contract stability, minimalpolicy-induced uncertainties, and ensures a stable legaland regulatory framework. We have just completed the9th round of NELP covering a sedimentary area of about88,000 sq km, which saw participation by 37 companiesincluding eight foreign ones.The Mangala fields in Rajasthan have shattered the misperceptionthat India was devoid of hydrocarbon potential.These fields, which commenced production in August2009, are the biggest discovery since “Bombay High” in the1970s, and at peak production will contribute about 25 percent of the country’s domestic oil production. Similarly,the KGD-6 gas field, which commenced production in2009, has led to a 75 per cent increase in India’s domesticproduction of natural gas. BP’s recent decision to buy a 30per cent stake in the KGD-6 gas field for US$7.2 bn, one ofthe largest foreign direct investments in India, is a concreteexample of the tremendous opportunities.In petroleum refining, India has witnessed a silentrevolution and has emerged as a major export hub in therecent years. During 2010-11, India exported 56m tonnesof petroleum products valued at about US$40 bn, makingpetroleum products our largest foreign exchange earnerin the merchandise category. With three new greenfieldrefineries coming up at Bina, Bathinda and Paradip inthe year ahead, India will have an even larger exportablesurplus of petroleum products. We look forward to forgingclose trade ties with countries looking for refined products.Presently, natural gas accounts for around 10 per cent ofIndia’s primary energy basket as against the world average of24 per cent. As natural gas is a more versatile fuel besides beingenvironmentally benign, the Government has embarked on apath of increasing the use of this fuel in the country’s energybasket. The Government has initiated gas pricing policyreforms, to incentivise production of natural gas. Alongside,to cater to the huge demand for LNG, the country is investingheavily in the creation of LNG re-gasification facilities. Withnew RLNG terminals coming up at Dahej, Kochi and Dabhol,the country’s current import capacity of 12.5m tonnes a yearis set to increase to 20m tonnes a year by 2012-13.We are keen to diversify our source of LNG supplies andare looking to LNG exporters across the globe for tyingup our growing requirement of LNG imports. Recently,we have signed a long-term contract with an Australiancompany for supply of LNG over the next 20 years. Weare interested in not only buying additional quantities ofLNG, but also seek to have equity participation in existingand upcoming LNG liquefaction projects globally. We arealso keen to explore farm-in opportunities in producingoil and gas blocks whenever they may be available. Totransport natural gas to different parts of the country,we have launched an ambitious pipeline developmentprogramme. GAIL (India) alone is expanding its existingpipelines by 5,000 kms in the four years ahead. Privateoperators are adding another 5,000 kms.We are seriously pursuing the development of shalegas. We have undertaken the mapping of India’s shale gasresources and are working to put in place a regulatoryregime for licence rounds by December 2013. We arealso harnessing coal bed methane: so far, we have heldfour licence rounds, and commercial production hascommenced at Raniganj in West Bengal. As India has oneof the world’s largest coal reserves, we want to work withinternational companies having the requisite experienceand expertise in coal seam gas.While we have significant achievements under our beltin the petroleum sector, there are huge challenges beforeus: our dependence on crude oil imports has grown to theextent of around 75 per cent of our requirement. Naturally,being the fourth largest oil importer in the world, we aredeeply impacted by a rise in the international oil prices. As anemerging economy, India can ill-afford growing budgetarydeficits or high inflation; and high international oil prices canlead to both. Hence, as a leading player in the InternationalEnergy Forum, we have been vocal about our demand forgreater transparency and stability in the price formation of oil.India firmly believes that enhanced energy security for theworld can only come through inter-dependence among theproducer, consumer and transit countries. We need greaterinvestments in the upstream sector if more oil and gas areto be brought to the international markets.•6420th World PETROLEUM Congress

CooperationNew producer-consumerdialogue: What to expect?By Noé van Hulstsecretary general, International Energy ForumIn an historic meeting in Riyadh on 22 February2011 ministers and representatives from 86 energyproducing, energy consuming and transit countriessigned a fresh charter for the International Energy Forum.Since then, Azerbaijan has joined as the 87th member.The IEF Charter marks a new era of international energycooperation, signalling a reinforced political commitmentto an informal, open and continuing producer-consumerdialogue in the global framework of the IEF. It creates a solidfoundation for a productive dialogue that fosters greatermutual understanding between energy producing andenergy consuming countries on key energy policy issues,seeks to narrow differences in views and helps build trustin policy intentions. With all the major energy producersand consumers in this enhanced dialogue framework, thisfact alone sends a powerful signal to the energy worldand energy markets that difficult issues can and will betackled in a global context, whenever necessary. It isunderstandable that the signing of the IEF Charter hasraised expectations. So what can realistically be expected?Recent events rock energy marketsSince the IEF Charter was signed, we have witnessedsignificant political events in some Middle East and NorthAfrican countries, as well as in Japan that have increasedenergy market volatility and uncertainty. Energy marketvolatility has been, and will continue to be addressed inthe cooperation programme with the International EnergyAgency and the Organisation of Petroleum ExportingCountries that underpins the IEF Charter. The first pillarof this joint programme is the shared analysis of energymarket trends and energy outlooks. The IEA, IEF and OPECheld their first Symposium on Energy Outlooks in Riyadh inJanuary 2011, with the objective to improve the clarity andunderstanding of the various short-, medium- and longtermoutlooks, particularly those of IEA and OPEC. It turnedout that there was more consensus between IEA and OPECon the oil market outlook than is often acknowledged inthe press. However, it was recommended to move “towardsharmonising definitions, where possible and appropriate,and disclosing more data, in a more timely manner, toenhance comparability between the outlooks.”Obviously, as noted before, things have changedsignificantly since early 2011. Analysts have identified ahost of factors that may have contributed to the increasein prices and in volatility, ranging from increased financialmarket activity to unanticipated strong demand in Asiaand quality demand/supply mismatches following the lossof Libyan sweet, light oil, as well as overstated geopoliticalconcerns. Some producing countries attempted to bringback more stability by increasing production and a groupof consuming countries released some of their emergencystocks. However, despite these efforts, oil prices are morevolatile and currently at more elevated levels than in 2010.Meanwhile, it is worth pointing out that thefundamentals of oil demand and supply for 2011/2012 stilllook relatively comfortable. Both IEA and OPEC still projectoil demand in 2011/2012 to grow in step with oil supply,with OPEC’s remaining spare capacity at adequate levels(around 4 mb/d). In addition, there is ample spare capacitydownstream and commercial inventories remain high.Furthermore, we see, for now, no major changeenvisaged in the medium term supply/demand balancefor 2015/2016. Significant oil investment projects areunder way in both OPEC and non-OPEC countries and oildemand does not seem to grow significantly faster thanprojected supply. Producing and consuming countriesare both committed to step up efforts to improve energyefficiency, as this will help dampen demand growth andthus improve the demand/supply balance. Similarly,producing and consuming countries are fully aware ofthe importance of facilitating adequate investment, bothupstream and downstream, in a timely manner. IEA, IEFand OPEC are working closely together in moving towardsgreater harmonisation of definitions and disclosing moredata, in a more timely manner, to enhance the comparabilityof the outlooks. They will provide more transparency ontheir respective publications on the outlook for 2012.Physical and paper oil market linkageThe second pillar of the IEA/IEF/OPEC cooperationprogramme is the linkages between physical and financialenergy markets. A first joint workshop was held in November2010 in London, back to back with a Regulators Forum. Thisevent showed a continuing divergence of views on theimplications of the emergence of oil as an asset class for thephysical oil market. However, there was a consensus on theneed for greater data transparency in both the physical oilmarket (in particular on oil inventories) and the financial oilmarket (in particular the OTC market), the need for stronginternational coordination of regulation and the need tocontinue the horizontal dialogue between physical andfinancial oil markets (including the regulators). Again,we have seen changes since the end of 2010 in this area.6620th World PETROLEUM Congress

CooperationIf anything, the interaction between the physical andfinancial oil markets seems to have intensified in 2011,with paper oil market trading reaching new record levels.At the same time financial regulators (CFTC, FSA, EU andothers) around the world are designing important newrules for paper oil markets which may have a significantimpact. This underscores the need for further improvingdata transparency in both the physical and financial oilmarkets, international coordination of regulation andcontinued physical-financial market dialogue. IEA/IEF/OPEC cooperation on physical and financial markets’linkages and energy markets regulation will be takenforward in a new joint workshop and Regulators Forum inNovember 2011.Improving data transparencyThere is an urgent need to significantly improve theperformance of countries in providing timely, completeand reliable data to the Joint Organisations Data Initiative(JODI) on oil, as well as on natural gas. Despite repeatedassurances of their commitments to this issue, theactual performance of the nearly 100 JODI-participatingcountries on delivering better monthly oil data has lagged.JODI is coordinated by the IEF and its partner organisationsinclude APEC, IEA, EU, OLADE, OPEC and UNSD. The JODIorganisations will have to step up the pressure on thosecountries failing to deliver adequate market transparency.Better physical market data transparency is key to anyeffort to mitigate energy market volatility. The extension ofJODI to cover monthly natural gas data is well under way,including cooperation with the Gas Exporting CountriesForum (GECF), and will hopefully result in the first launchof JODI-gas to the market before the end of 2011.The extension of JODI to annual oil data on upstream anddownstream capacities and expansion plans will start withoil and is currently under way, with first results expectedat the earliest in 2012. This extension is very important toimprove the visibility of the medium-term demand/supplybalance in the oil market.The G20 group of countries has requested the IEF, incooperation with IEA and OPEC, to advise on what needsto be done to improve the reliability, timeliness andquality of JODI-oil. In April 2011 the IEF submitted its finalreport to the G20 Finance Ministers (available on www.ief.org). It addresses actions for both JODI organisationsand for governments of participating countries. JODIpartner organisations will need to continue their effortsin training statisticians in charge of JODI data compilationand submission in participating countries/economies;develop new tools and practices to regularly check JODIdata and streamline data submission; enhance interactionwith data users (in particular market analysts) and upgradeJODI platforms such as the JODI website (www.jodidata.org). It is equally important that participating countries/economies ensure that administrations and organisationsin charge of data collection are better equipped andstaffed, to implement appropriate regulations to ensureindustry is fully engaged in the process of data submissionand to address confidentiality issues and reduce if noteliminate them. IEF countries, starting with the G20, shouldset themselves a concrete target of complete, timely andreliable oil data submission by the end of 2011.The G20 has also requested the IEF, IEA, OPEC and IOSCOto produce a joint report on how the oil spot market pricesare assessed by oil price reporting agencies and how thisaffects the transparency and functioning of oil markets.This report will be submitted to G20 Finance Ministers byOctober 2011. In addition, the G20 asked the IMF and IEF,in cooperation with IEA, OPEC and GECF to develop byOctober 2011 concrete recommendations to extend theG20’s work on oil price volatility to gas and coal. It is tooearly to elaborate on the content of this work in progress.However, it is interesting to note that the IEF, as the neutralfacilitator of the energy dialogue and the most globalinternational energy body, is becoming more involved inthe G20 energy work.Facilitating NOC-IOC cooperationA final focus on a couple of key topics that the IEF isalso currently working on. NOC-IOC cooperation hasbeen identified as of crucial importance to improve theglobal energy investment climate and meet the hugeinvestment challenge of nearly US$33 trillion up to 2035.The IEF has organised two NOC-IOC Fora (2009, 2011)which have underlined the need for innovative longtermpartnerships based on mutual trust and respect.In an increasingly demanding environment, NOCs andIOCs need to explore new models of cooperation that gobeyond simple resource development, and integrate hostcountry’s expectations, such as economic development,technology transfer, infrastructure development andsupport of the local economy. Building on the findings ofthe last NOC-IOC Forum in April 2011, we will work withthe IEF’s Industry Advisory Committee to formulate a set →Energy Solutions For All 67

Cooperation→ of general principles or best practices defining successfulcooperative schemes between NOCs and IOCs. Theseguidelines will be presented to the 13th IEF Ministerialand 5th IEBF meetings in Kuwait in 2012 for discussion andendorsement.Energy efficiency is the fastest, cheapest and cleanestway to meet the world’s energy demand and enhanceenergy security for both energy producing and consumingcountries alike. IEF acts as a platform to engage developingcountries in the effort to harvest the huge potential forimproving energy efficiency in order to curb the demandgrowth. In many emerging economies this demand growthpushes up oil and gas imports as well as emissions. In mostoil and gas producing countries domestic demand growthis increasingly crowding out the potential for growth ofoil and gas exports to world markets. In all developingcountries, the issue of sound energy pricing and thetackling of inefficient, wasteful energy subsidies in a sociallyresponsible manner needs urgent attention. On the basisof the findings of an IEF Symposium held in Jakarta (June2011), the IEF Secretariat will report to Ministers at the 13thIEF in Kuwait in 2012 on concrete recommendations onhow to improve energy efficiency in both producing andconsuming countries.Energy poverty remains one of the world’s most urgentproblems. The fact that more than one billion people lackaccess to electricity and modern cooking fuels inhibitseconomic and social development and the achievementof the Millenium Development Goals, particularly inSub-Saharan Africa and South-East Asia. With roughlyone-quarter of the IEF membership from developingcountries, energy poverty will stay high on the agendaof the IEF, and will be discussed at the 13th IEF in Kuwaitin 2012, on the basis of results from an IEF symposium inVienna in November 2011.With the new mandate provided by the IEF Charter,the IEF Secretariat will work hard to deepen and enhanceits role as a neutral facilitator of the global energydialogue. Working together with all relevant internationalorganisations, including the big sisters IEA and OPEC, aswell as with industry (both NOCs and IOCs), we will doeverything we can to deliver concrete results to the G20on their requests and, first and foremost, to the 13th IEFMinisterial Meeting in Kuwait in March 2012. •IEF investment events: recent timeline11th IEF Rome - 20 April 2008HR Symposium - 13 April 2009Uncertainties Report - 1 January 2010Extraordinary IEF Ministerial Meeting - 22 Feb 20114th Asian Ministerial - 18 April 20112nd Asian Ministerial - 2 May 200711th IEF Rome 1st NOC-IOC Forum 30 March 20093rd Asian Ministerial 200912th IEF Cancun - 29 March 20102nd NOC-IOC Forum - 7-8 April 201113th IEF Kuwait - 13-14 March 2012Energy Solutions For All 69

CooperationEurasian Pipelines:From Beijing to BerlinBy John RobertsEnergy Security Editor, PlattsTurkmenistan’s gas flows east to China, north toRussia and south to Iran. In the past Turkmen gas hasreached as far west as Germany and, there are seriousplans for it to do so again. From one field alone, SouthYoloten, it has the capacity to supply large volumes of gasfrom Beijing to Berlin, from Amritsar to Zagreb.But there is a whole series of paradoxes concerning thedevelopment of the vast span of pipelines that stretch fromone end of Eurasia to the other. One is that Russia, the world’sbiggest gas producer and the holder of the world’s largestgas reserves, is now focusing at least as much on developingnew ‘bypass’ pipelines – lines that essentially replace existingpipeline systems across transit countries that Russia nowprefers to avoid – as on development of actual fields toensure that new lines carry new gas to market.Another is that Iran, holder of the world’s second largestgas reserves, remains a net importer, its export ambitionsthwarted as much by its own internal consumption as byinternational sanctions. A third is that Turkmenistan, ownerof the world’s largest onshore gasfield, considers that it is forothers to develop the pipelines that might carry its output tointernational markets. Turkmen gas, says Ashgabat, shouldsimply be sold at Turkmenistan’s borders.The net result is that companies or consortia seekingto develop pipelines in Eurasia have to be incrediblydetermined to overcome a welter of political andcommercial obstacles. And of these, the China NationalPetroleum Corporation (CNPC) is clearly the mostdetermined. In 2012 gas from Turkmenistan is scheduledto reach Hong Kong. To get there, it will have to passthrough a complex set of interlocking systems, notablythe Trans Asia Gas Pipeline (TAGP) from Turkmenistan toWestern China, the newly revamped and enlarged West-East pipeline in China; then its spur to the south-east ofthe country; and finally the 29.3 km sub-sea line from themainland to the Special Administrative Region of HongKong, currently under construction.All these have been or are being developed by CNPC.Indeed, ever since it began building the West-East systema decade ago, CNPC has been at the heart of some of thebiggest pipeline projects in the world. In July 2007 it signedan agreement to build the 2,200-km TAGP from Turkmenistanthrough Uzbekistan and Kazakhstan to Urumchi in Xinjiang.In December 2009, less than 30 months later, the firstTurkmen gas entered China. By 2015, the TAGP’s twin 20bcm/y (billion cubic metres a year) lines are expected tobe carrying close to 40 bcm/y of gas from Turkmenistan,Kazakhstan and Uzbekistan to China. In addition, plans arein hand for a third 20 bcm/y string.But Turkmenistan is not CNPC’s only focus, and CNPCis not alone in focussing on Turkmenistan. CNPC is alsodeveloping the twin oil and gas pipelines intended to linkthe Burmese port of Kyaukphyu (Sittwe) in the Bay of Bengalwith Kunming in China’s Yunnan province at a cost of aroundUS$2.5bn. These lines have the advantage that as well asenabling China to tap into Burma’s own gas resources,notably the offshore Shwe field, it can also by extension useBurmese ports to bring oil from the Middle East and Africato south-west China without passing through the Malaccaor Sunda straits. Pipeline construction officially beganin October 2009. The 771-km, 12 mt/y (240,000 b/d) oilpipeline will terminate at Kunming, Yunnan’s capital, whilethe 12 bcm/y, 2,800-km gasline will extend much furtherinto the heart of China, to Guangxi.The Chinese projects may yet be matched by theemergence of a new pipeline system intended to carrygas from the Caspian to Europe. At the time of writingthere was no indication as to which of the contendersseeking to secure Azerbaijani gas for their various pipelineprojects would actually win the approval of the developersof Azerbaijan’s giant Shakh Deniz gas field and of theAzerbaijani government itself.But the very fact that a connection is to be made to Europereopens the question of whether Turkmenistan will find away to plug its gas resources into such a system. Ashgabathas always viewed the opening of the TAGP as one stage ina process of developing what it terms a multi-vector policyfor its gas exports. It needs such a policy because of SouthYoloten, a field which is now thought to contain at least sixtrillion cubic metres (tcm) and – quite probably – aroundthree times that amount. At the time of writing, fresh auditfigures for the field were still awaited. But at 18 tcm, onlythe 34.6 tcm reserves in the giant offshore North Field/South Pars resource shared by Qatar and Iran in the Gulfwould be bigger, while South Yoloten would come close toaccounting for one-tenth of the world’s total gas reserves.So it is no wonder that the Turkmens are also keen todevelop a variety of new export pipelines. Their immediatepriority is development of the 1,760-km, 33 bcm/yTurkmenistan-Afghanistan-Pakistan-India (TAPI) pipeline,a project being jointly developed by the four countriesconcerned. The Asian Development Bank is providingsignificant technical backing but actual implementationhas to await an improvement in security conditions in7020th World PETROLEUM Congress

CooperationAfghanistan. Security issues are also likely to impact on bothIranian proposals for a major new gas pipeline to cross Iraqand Syria and on Iraqi plans for both oil and gas pipelinesto reach new export terminals on the Mediterranean andto link up with the existing Arab Gas Pipeline that carriesEgyptian gas to Jordan and Syria.What happens to Iranian and Iraqi gas has an impacton plans for Caspian gas exports to Europe – and thus onproposals for major pipeline projects to Europe. The biggestof these projects, Nabucco, was originally predicated on theconcept that it would carry gas from both Azerbaijan andIran through Turkey and the Balkans to the Central Europeangas hub at Baumgarten in Austria, although in recent yearsIran was replaced by Iraq as a prospective supply source.Azerbaijan’s choice concerning export routes for its gaswas not known at the time of writing, but what was clearwas that whatever choice Baku made to carry gas from thegiant second stage of the Shakh Deniz Gas field to market, itsimplementation would raise the question that if Azerbaijancould export large volumes of gas to Europe without passingthrough Russia, then why could Turkmenistan not follow suit?Possible Trans-Caspian pipelineFor Turkmenistan to achieve this goal requires constructionof a trans-Caspian pipeline, and that is exactly the goalthat Turkmenistan and the European Commission hopeto achieve negotiations planned for the autumn of 2011.The reason the Turkmens require the development ofa large scale – say 30 bcm/y – Trans-Caspian Gas Pipelineis because the country is still suffering from the loss ofmost of its exports to Russia in the wake of what can onlybe described as the engineered explosion of 9 April 2009on the main line carrying Turkmen gas to Russia. Russiantechnicians, wanting to reduce the flow of Turkmengas exports to Russia, gave their Turkmen counterpartsinsufficient time to close down input, resulting in a buildupof gas that caused an entirely predictable explosion.The long term consequence was that when Turkmenexports were eventually resumed nine months later, itwas at a rate of around 10-11 bcm/y, in contrast to annualrates of around 30-40 bcm anticipated by Ashgabat.So Turkmenistan, whose gas in Soviet days fuelled thefirst giant pipelines to western Europe, now faces a realprospect that it could wind up selling less gas to Russiathan it does to China or even Iran – and thus needing atrans-Caspian line to reach European markets if it cannotreach agreement with Moscow on access to the Russianpipeline system for access to markets beyond Russia.As for Russia itself, it is pressing ahead with both its NordStream and South Stream projects. The first string of NordStream, a 1,200-km pipeline through the Baltic from Russiato Germany, is already operational although not carryinganything like its 27.5 bcm capacity. But it does fulfill a majorfunction for Russia in providing it with direct access to the EUwithout having to transit other countries, an important issuein the wake of major disputes with Ukraine in 2006 and 2009.In 2011 Gazprom has been busy setting up a formalcorporate structure for South Stream which has still tosignify specific routes, costs or projected volumes for asystem intended to link Russia with Southeastern Europeand Italy. In 2009 the CEO of Eni, the Italian partner in SouthStream, put the cost of the project at €25bn and said it wasintended to carry 63 bcm. Since then, Marcel Kramer, SouthStream’s CEO, has been more cautious concerning potentialcosts, whilst noting that only one-third of the line’s capacitywould likely come from new fields.Although Eurasian pipelines are often seen in terms of bigprojects for lines extending for thousands of kilometres, a keyelement is the massive development of a host of distributionlines at either end of the Eurasian landmass. These are theinternal systems that serve the giant Chinese and EuropeanUnion markets, epitomised by the link to Hong Kong and themultiplicity of small-scale interconnectors and regional linesin central and southern Europe intended both to bring gasto wholly new markets and to ensure that, in a crisis, no EUmember state is solely reliant on just one single supply system.There is one last peculiarity of Eurasian pipeline proposalsthat is worth considering. Pipelines are usually consideredthe alternative to plans for maritime transportation in theform of liquefied natural gas (LNG). Eurasian producersmay be changing this paradigm using pipelines to carrygas from fields located in one country to LNG facilities inanother. Azerbaijan is considering doing this with an LNGfacility on Georgia’s coast, and a shuttle fleet of LNG tankersin the Black Sea to carry the gas to Europe. Turkey hasproposed the construction of LNG facilities at Ceyhan, withfeedstock coming from both Azerbaijan and Russia – andpossibly even Iran. For the time being, pipelines remain thepreferred choice for evacuating gas from the landlockedstates of Central Asia. But it is just possible that at somefuture date they may also come to serve LNG terminals thatwould enable Caspian gas to access an even wider range ofmarkets than is possible through current and prospectiveEurasian pipelines alone.•Energy Solutions For All 71

CooperationNabucco: A pioneeringpipeline projectBy Reinhard MitschekManaging Director, Nabucco Gas Pipeline InternationalNabucco is Europe’s flagship project in what hasbecome known as the southern corridor linkingdemand in European markets to the abundantand almost untapped supply of gas in the Caspianregion and the Middle East beyond.As the new gas bridge from Asia to Europe, Nabucco is thefirst pipeline project that will connect European and Turkishmarkets and the South East European national grids. Nabuccowill run from the eastern border of Turkey via Bulgaria,Romania and Hungary to the Central European Gas Hub nearVienna in Austria and have off-take points in every country.Once completed, the 3.900 km pipeline will have a capacity of31 bcm. Six shareholders make up the Nabucco consortium:Germany’s RWE, Austria’s OMV, Hungary’s MOL, Romania’sTransgaz, Bulgarian Energy Holding and Turkey’s Botas. Eachof them holds equal stakes on the project company.Increasing demand for natural gasThe issue of supply security is one of the biggest challengesthat Europe will have to cope with in the energy sectorin the coming years. Further diversification of natural gassupplies and the creation of new transit routes are thereforeof the utmost relevance. Consequently, it is crucial that newinfrastructure will be established to meet the future growingdemand in Europe for natural gas, and thus contribute to astable and secure future of European energy.Europe will need additional gas, for in the light of dwindlingindigenous gas resources it will have to import more andmore of it. According to estimates from the InternationalEnergy Agency, demand for natural gas in Europe will risefrom the current level of 555 bcm (in 2008) to 653 bcm in2030. According to the IEA the reasons lie in the increasingabundance of affordable natural gas, coupled with risingdemand for the fuel from China and the fall-out from theFukushima nuclear disaster in Japan. The latter has calledinto question the future role of nuclear power and promptedre-evaluation of related policies in many countries, forinstance, Germany which has decided to accelerate its exitfrom nuclear power. Acquiring new sources and suppliersof gas is therefore the right thing to do. In turn, Azerbaijan,Turkmenistan, Iraq and Egypt are developing new gas fieldsand raising production. These are the world’s richest naturalgas regions. They have huge reserves, which taken togetherare significantly higher than those of all the other regionsof the world.Nabucco is therefore the answer to the energy securitychallenge outlined above, and consequently will open upa new transport route to Europe. It is also the most viabletransport route from the Caspian basin, both logisticallyand economically, making it more attractive than otheralternatives being discussed. Nabucco will enable Europeand Turkey to diversify their energy sources and contributeconsiderably to gas supply for the next decades.Nabucco legal framework finalisedThe Intergovernmental Agreement (IGA) was signedin Ankara on 13th July 2009 and ratified by all nationalparliaments by March 2010. It marks an important milestonein the development of Nabucco, as it is a treaty betweenthe governments of the Nabucco transit countries – Austria,Hungary, Romania, Bulgaria, and Turkey - which harmonisesthe legal framework and grants stable and equal transportconditions for all partners and customers. It is also the firsttreaty ever concluded between Turkey and EU MemberStates for an energy project.The signing of the Project Support Agreements (PSAs)- a bilateral agreement between NABUCCO Gas PipelineInternational GmbH and the responsible ministries of thefive transit countries - took place in Kayseri, Turkey, on 8 June2011.The PSAs set out the practical aspects and uniformstandards for the construction and long-term operation ofthe pipeline in each country. The main elements of the PSAsare the affirmation of an advantageous regulatory transitregime under EU and Turkish energy law; the protection ofthe Nabucco Pipeline from potential discriminatory changesin the law; and support for legislative and administrativeactions for the further implementation of the project. ThePSAs also mark a commitment by each government tosupport the project. Together with the IGA, the PSAs are anecessary prerequisite for the successful financing of theproject. They create the stable, long-term regulatory regime,which is required by the group of international lenders tosecure the financing of one of the largest multi-national gastransmission projects worldwide.Route selectionThe route selection was a complex process in whichmany different factors have been taken into account;areas with high population density, protected areas andareas with valuable cultural heritage have been avoidedas far as possible.. In addition existing energy supplycorridors will be fully utilized to minimise the impact onthe environment. Extensive surveys were conducted toselect the route, such as subsoil investigations as well as7220th World PETROLEUM Congress

Cooperationgeological, archaeological, ecological,social and climatic assessments. Acomprehensive Environmental andSocial Impact Assessment under strictEuropean standards is currently workin progress by international experts toassure long term cooperation betweenour pipeline project and the peopleliving along the route.Project financingIn September 2010 a mandate letterwas signed by the European Bank forReconstruction and Development(EBRD), the European Investment Bank(EIB), the International Finance Corporation arm of theWorld Bank Group, and the shareholders of Nabucco andNABUCCO Gas Pipeline International GmbH. The signing ofthe mandate letter marks the start of the appraisal processof the Nabucco project, a required step towards a potentialfinancing package of up to €4 billion. The current investmentfigure of €7.9 billion for the Nabucco construction is basedon the technical feasibility study. We are currently reviewingour calculations of the capital expenditure estimate in orderto better reflect the intermediate results of the Front EndEngineering Design and a number of recent developmentsin the market and adjustments to the technical andcommercial parameters. The results of this review will beavailable in the upcoming months. The investment will beraised from shareholders, international financial institutions,export credit insurance companies and the commercialbanking market in accordance with internationallyrecognized social and environmental standards. 30 percent of the investment will be funded by the shareholderconsortium and 70 per cent by lenders.Project status and next stepsAs soon as gas commitments will be negotiated betweenthe suppliers and the Nabucco shareholders Nabuccowill start with the open season process and the finalinvestment decision will be taken by the shareholders.Before construction will start, detailed planning as well asthe Environmental and Social Impact Assessments (ESIA)must be finalised. The ESIA process is currently ongoing andthe long lead items such as line pipes, bends and valves willbe ordered in a transparent tender process after the finalinvestment decision will have been taken. Nabucco alreadyThe Nabucco pipeline projectcarried out a pre-tender process where potential suppliersfrom around the world participated and the best companieswere identified. This assures that the actual tender will becarried out most efficiently.Pipeline projects such as Nabucco, which open new sourcesfor gas traders and customers, are of crucial importance interms of more diversification and greater market liquidity.Nabucco offers the opportunity to negotiate long-termtransport contracts with a pre-arranged tariff structure. Thatis an important incentive for investors. ‘Open Season’ is thename of the process for reserving capacity. It consists oftwo phases. In the first phase, shareholders will be given theopportunity to reserve a total of 50 per cent of the transportcapacity. In the second phase, it will be possible for thirdparty market participants to reserve capacity on the sameterms. This means that 16 bcm of transport capacity everyyear will be offered to third parties.In sum, Nabucco provides Europe with a uniqueopportunity to obtain gas directly from Central Asia,rather than via alternative routes. We must now utilise thismammoth opportunity. The shareholders will be negotiatinggas supply contracts with potential gas supply countriesin the coming months and thus a further foundation for adecision on construction by the shareholders is laid. Startof construction is planned for 2013. First gas will flow fromthe eastern border of Turkey to the Central European Gashub in Austria in 2017. The southern corridor between theCaspian region, the Middle East, Turkey and Europe willthen be a symbol for a new and viable partnership. Or asEuropean Commission president Jose Manuel Barroso put itso succinctly: “Gas pipes may be made of steel, but Nabuccocan cement the links between our peoples.”•Energy Solutions For All 73

CooperationThe politics of pipelinepermitting in North AmericaBy Sheila McNultyUS energy correspondent, Financial TimesPresident Barack Obama came to office in 2009promising to do his part to stop global warming.Two years later, not only has Congress failed to passany comprehensive carbon-reducing energy policy,but Mr Obama even failed to put solar panels on the roofof the White House by summer 2010 as he had promised.For their part, environmentalists have been focusing theiranger on a project they fear will actually increase carbonemissions. The project – the Keystone XL pipeline fromAlberta’s oil sands across the US to Texas refineries on theGulf Coast – would be the third such pipeline importingwhat environmentalists always refer to as tar sands.According to the IHS CERA consultancy, on a life-cyclebasis fuels produced solely from oil sands result in 5 to 15per cent more greenhouse gas emissions than the averagecrude oil refined in the US. But it also points out that theCanadian oil sands are poised to become the largest singlesource of foreign oil to the US market and building thepipeline will mean new jobs. The proposed US$7 billionKeystone XL pipeline is among the biggest “shovel ready’’projects in the US. At a time of weak economic growth andhigh unemployment, the question is whether the ObamaAdministration will put what environmentalists dismiss asthe short-term gain in jobs before emissions, particularlywhen, they say, clean energy jobs are a more secure andlong-term path for economic recovery.The US Department of State must make a decisionwhich route to take by year’s end. The last time Secretaryof State Hillary Clinton was put in this position – less thana year after President Obama had taken over, in August2009 – she approved the Alberta Clipper pipeline to carryoil-sands fuel from Canada into the US, saying, “approval ofthe permit sends a positive economic signal, in a difficulteconomic period, about the future reliability and availabilityof a portion of the United States’ energy imports.’’ The StateDepartment noted the project would provide constructionjobs for US workers. But this time around environmentalistsinsist the US already has two pipelines (the first wasapproved by the Bush Administration) bringing in oilsands fuel and does not need another. “We’re alreadytaking as much oil as Canada can give us,’’ said Susan Casey-Lefkowitz, international programme director at the NaturalResources Defense Council, the environmentalist group.Pipeline critics point to a series of spills from the firstKeystone pipeline in its first year of service, which ledUS authorities to suspend its operation temporarily insummer 2010. TransCanada, which operates the pipeline,gained approval to restart the Keystone pipeline withina few days and responded to concerns by noting the lastincident, at a pumping station in Kansas, had involvedless than 10 barrels of oil. “Almost all the oil releases overthe past 12 months on Keystone have been minor –averaging just five to 10 gallons of oil,” according to RussGirling, TransCanada’s president and chief executive. Butthat the first Keystone has suffered 12 spills in its first yearremains a worry for Ms Casey-Lefkowitz, who fears theyare the result of the highly corrosive nature of bitumenin the oil sands. This is of particular concern, she says,because the Keystone XL is to cross the Ogallala Aquifer,a freshwater source for eight states. “This is one issuewhere the president has total control – he has to grant ordeny the necessary permits,” according to Bill McKibben,an environmental activist. “Congress can’t get in the way.It’s where Obama can get his environmental mojo back.But we need him to lead.”The problem for critics is that the US has set a precedentby approving two previous pipelines to funnel oil sandsinto the US. Jim Vines, partner at King & Spalding in theEnergy Environmental Practice, says it would be tough forthe State Department to reject the Keystone XL on thegrounds that it is any different. “Given high gasoline pricescombined with high unemployment,’’ he said, “the publicwill demand convincing evidence in the public record thatthe Keystone XL is ecologically unsound before they buythe anti-oil sands environmental rhetoric.’’Yet a growing number of officials have spoken outagainst the 2,673km oil pipeline, including the mayors of25 towns and cities, who wrote a letter on March 24 to MrsClinton, expressing concerns about additional tar sands oilimports: “We are concerned that expansion of high carbonprojects, such as the proposed Keystone XL tar sandspipeline will undermine the good work being done in localcommunities across the country to fight climate changeand reduce our dependence on oil. “The oil industrybelieves, despite the outcry, the pipeline will get built.Jim Mulva, chief executive of ConocoPhillips, said, “It’s veryimportant to energy security. Any delay in infrastructuredevelopment has an impact on the flexiblity of supply.’’Given the rise in oil prices, spurring the InternationalEnergy Agency to release strategic petroleum reservesthis year, there is no doubt energy security has grown inimportance for the Obama Administration.However, that it is a high priority has not translatedinto permitting unfettered drilling in the Gulf of Mexico,7420th World PETROLEUM Congress

Cooperationwhich regulators have scaled back significantly since theMacondo disaster. And it has not meant promoting theuse of natural gas with subsidies and incentives despitethe rapid growth in supply brought on by technologicaladvances. Indeed, the US has so much natural gas in thelower 48 states that it is moving to export it. And plans tobring gas down from Alaska through a massive US$35bnpipeline are at real risk. However, in terms of natural gas, oneof the two competing plans, by BPand ConocoPhillips, was cancelledin May after the oversupply of gasfrom shale pushed down prices solow there was insufficient demandfor Alaska gas from gas shippers.The other project, involvingTransCanada, the Canadianpipeline company, andExxonMobil, is moving ahead.Rex Tillerson, ExxonMobil’s chiefexecutive, has said the companystill is interested in building apipeline to bring gas out of Alaskadown to the lower 48 states. “Thegas has basically been developed,’’Mr Tillerson said. Oil companieshave been pushing it back downinto the ground to aid in enhancedoil recovery and could just as easilyput into a pipeline and send it outof the state. “It would be a supplythat would be available for yearsand years,’’ he said. The big hurdlein accessing that supply in thelower 48 states remains Alaska’sfiscal regime, which is uncertain,in addition to the regulatory andtechnical challenges involved inbuilding the pipeline itself. But ifthat can be overcome, Mr Tillersonhas said he believes “the gas canbe competitive.’’Whether the pipeline to get thatgas down from Alaska to the lower48 states will ever be built remainsto be seen. Ms Casey-Lefkowitznotes tar sands development usesnatural gas for fuel: “There are validconcerns that expansion of the tar sands will mean Alaskanatural gas feeding into Alberta and being used there asfuel. That means using a relatively clean fuel to make a dirtyfuel and less natural gas coming to the US.’’ But the meritsof that is an argument for another day. For this year, thefocus of both environmentalists and the energy industryis on the Keystone XL – a pipeline whose fate rests solelywith the priorities of the Obama Administration. •The proposed Keystone XL projectEnergy Solutions For All 75

CooperationTanker owners weatherstormy economic conditionsBy Juliet WalshFreight editor, Argus Media GroupThat 2011 has been a tough year for shipowners iswell documented, with earnings across all sectorscoming under varying degrees of pressure. Theflow of new ships into the market has continued tooutpace demand, and the inevitable result is lower spotfreight rates, as competition for business increases. Add tothe mix net increases in bunker costs over the year to date,and owners’ margins in some sectors have been reduced tozero, and have even at times slipped into negative territory.Focusing on the crude tanker market as an example,estimates have suggested that the fleet will expand atup to twice the rate of demand in 2011. Tanker rates areat their lowest since 2008 in broad terms, and as tankersordered in happier economic times through 2007-2008enter the market this year, they are finding returns fallingfar below the necessary levels to repay the debts incurred.Breakeven levels on Suezmaxes (130-145,000 tons) andVery Large Crude Carriers or VLCCs (260-280,000 tons)ordered three to four years ago have been calculatedin the US$46-48,000/day range, based on timecharterequivalent measures. Falling Worldscale spot rates andincreased costs have led to earnings coming down toaround US$2-3,000/day in the middle months of this year,leading many to predict bankruptcies among owners.The industry’s confidence level has slumped, andcoupled with the increased post-credit crisis struggle tofind funds for new investment or to shore up existingoperations, the pressure on owners is intense. There hasnot yet however been a major cull among ship ownersand as shipping company shares have been low for sometime without their becoming the prey of creditors or ofacquisitive companies, there have at least been somecautious suggestions that most shipping companies willmanage to ride out the current storm.Beyond current financial woes, one of the cloudshanging over tanker markets is the growth of theChinese shipping fleet, and the stated aim of the Chinesegovernment that by 2015 half of oil imports into Chinawill be carried on Chinese-built tonnage. It is estimatedthat China’s oil demand for oil imports will increase as apercentage of total consumption from around 50 per centto 65 per cent, but that the increase in its VLCC fleet willbe sufficient to cover the increased demand, and to meetthe government’s target comfortably.Growth in the Chinese fleet is already being felt byowners traditionally working the Mideast Gulf-China route,among them European owners in Greece and Norway.So while increased demand from both China and Indiashould help the shipping market, this may be somewhatoffset by China’s huge expansion of its own VLCC fleet.One of the routes ship owners could take to relieve theoversupply in the market is to increase the scrapping oftankers well before they reach the 15-year cut-off pointwhere a vessel is deemed properly to be ‘old’. The globalfleet is, however, now relatively young, after a round ofscrapping of single-hull ships in 2009-2010 took a largenumber off the market, while the rate of new build hasonly increased in the past few years.Just two years ago, around 35 per cent of the worldfleet was less than ten years old, and now up to 65-70per cent of the total are under ten years old, which clearlylimits the prospects for using an earlier cut-off point fortaking ships into the demolition yards. While there is stilla market for ships up to 25 years old, most oil companieshave already taken the step of not chartering or receivingvessels which are more than 15 years old. But, despitethis, the rate of new ships coming into the market hasstill markedly reduced the average age of ships employedin the international oil trade. Falling prices for older shipsfor demolition also weakens owners’ incentives to scrapthem, and the number of ships of all sizes heading fordemolition is set to fall in 2011.As awareness grows of the part the shipping industrymust play in the goal of reducing emissions – and as costshave risen due to higher bunker fuel costs – slow-steaminghas become more prevalent. More than 200 ship ownershave slowed their vessels down from 25 knots to 20 knots.At least one ship owner has adopted the super-slowsteaming approach, reducing ship speeds to 12 knots, withfuel consumption and therefore emissions reduced by upto 30 per cent.An incidental by-product of slow-steaming is thatthe increased duration of voyages increases a vessel’sutilisation over time. While this means fewer journeysundertaken, it does help to alleviate the oversupplysituation, particularly in relation to long-haul routes, andhas been used by some owners as a means of improvingemployment rates of their ships. The loss of potentialearnings is offset – in theory at least – by decreased costsand a reduction in the time spent idle waiting for the nextcharter party to hire their ship.As rates on many routes for both clean and dirty tankersreached critically low levels in the summer months, talk oflaying up ships re-emerged. This involves taking them out7620th World PETROLEUM Congress

CooperationBuilding a trulysustainable energy systemBy Aron CramerPresident and CEO, BSRThe world’s economy is undergoing severalfundamental transitions at the same time, from arebalancing of political and economic influence,to the digital revolution, to massive urbanisation.Underlying all these changes is the drive to ensure anenergy system that enables economic growth for theplanet’s growing population with sharp reductions incarbon intensity.The public debate over this is often sterile andfacile, characterised by false choices that obscure theoverarching truth: simultaneous action is needed on anumber of fronts. Charting a path to a sustainable energyfuture depends on five key tracks: (1) innovation, (2)efficiency, (3) consumer engagement, (4) public policy,and (5) financial market reform.Energy companies that create strategies based onthis model will be best positioned for a world in whichcarbon-intensive energy becomes more expensive andless politically acceptable. Companies that fail to makethis shift may find themselves on the wrong side of thisgreat transition, risking social and political oppositionthat could be hard to overcome, and relying on productsand technologies that may no longer be viable. Severalleading energy companies are actively investing in exactlythis kind of comprehensive approach, although greateracceleration is needed to achieve anything like the goalsestablished by many countries in recent years.Innovation: New forms of energy are clearly neededif the engine of economic growth is to continue, andcontinue sustainably. Unconventional oil is receivingmuch attention inside in the industry, and renewables areconsidered essential to a low-carbon future. And whileunconventionals have a role to play, the overall mix willonly change if renewables gain more market share. Onekey to making this happen is innovation.It is clear that the energy mix will need to change toachieve both economic and environmental objectives,and innovation will be a big part of this story. The way thisinnovation happens is as noteworthy as the innovationitself. One of the unique features of innovation in the21st century is how “co-creation” of innovative solutionsis growing more important – and more widespread. Inrecent years, we have seen some non-traditional partnersjoin forces to drive innovation faster, further. Examplesrange from Shell and Cosan’s new biofuels venture,Raizen, and Total’s purchase of SunPower, a leading solarenergy producer, as well as many others. There remainsscepticism about how committed industry incumbentsare in following through on these investments. Given theindustry’s long history of joint ventures and cost-sharing, itis positioned very well to embrace the era of collaborativeinnovation, so long as these efforts are directed towardscleaner forms of energy.Efficiency: The energy industry has also made greatstrides in efficiency. While many sustainability strategiesare presented as “win-win” solutions when in fact theymay not be, efficiency is undeniably beneficial botheconomically and environmentally. In 2009, McKinsey& Co. released a well-received study that estimated thatthe United States alone could save US$1.2 trillion by 2020through reasonable energy efficiency measures, with40 per cent of these savings available from industrialoperations. This survey, and many others like it, asserts thatas much as 35 per cent of energy produced in the UnitedStates is wasted, with smaller, but still substantial amountswasted in other economies. Industry observers agree, withExxonMobil for example saying that efficiency “is one ofthe largest and lowest cost ways to extend our world’senergy supplies and reduce greenhouse gas emissions.”Indeed, the IEA estimates that 80 per cent of reductions incarbon emissions through 2030 can be achieved throughefficiency measures.This is why companies like Petrobras have invested inefficiency measures that it estimates to have reducedcarbon emissions per unit of energy consumed by 20 percent, according to IPIECA (the International PetroleumIndustry Environmental Conservation Association). Chevronreports an overall increase of 33 per cent in energy efficiencyin its global operations since 1992. More is needed, andthe phase-out of flaring is one step that the industry canaccelerate to achieve even greater efficiency gains.Consumer engagementThe other aspect of efficiency that receives little attention,but is quite interesting, is how leading companiesencourage consumers to use less. Chevron’s “Will You JoinUs” campaign and Shell’s “Let’s Go” campaign have blazed atrail with the general public to get them to use less of thesecompanies’ core product – an unusual but highly valuableeffort to moderate sales of a core product.The importance of public campaigns to reduce energy useis crucial. With mature economies facing an era of economicstagnation, and rising economies straining to maintaingrowth without incurring economic or environmental7820th World PETROLEUM Congress

Cooperationcollapse, finding new ways to enable consumer efficiency isabsolutely necessary, especially in rising economies wheremillions of “new consumers” enter the marketplace everyyear. It is therefore essential to shift from a sterile debateabout more or less consumption, to one that promotesbetter ways of delivering value to more and more peopleacross the globe. Doing this also requires investment ininfrastructure in smart buildings, smart meters, and newpricing and taxation schemes to enable and incentivisesmarter behaviour that saves consumers money.Public policyVirtually everyone walked away from recent UnitedNations climate summits disappointed, and disagreementbetween governments on whether and how to addressclimate remains intense. While some see this discordas being in the interest of business, in fact, the failureof policymakers to reach agreement introduces veryunwelcome instability into the energy system. Policiesare inconsistent both conceptually and in application.Policymakers in mature economies seem more often torespond to telegenic accidents than long-term needs.Leaders of rising economies prioritise economic growth,and seek technology and financial transfers. These positionsmay well be negotiating stances more than anything, butthey have so far locked the global system in stasis.Business has an interest in promoting long-term thinkingin government, something that has been sorely lackingon energy and climate. To do this, business needs to resistthe temptation to maximise every single dollar today, inan effort to create a more predictable and wise frameworkfor tomorrow. There are good examples to build on, suchas the promotion of regulatory frameworks and disclosurerules for hydraulic fracturing, now being developed inthe United States, Europe and elsewhere, the US ClimateAction Partnership, and “Combat Climate Change.” Energycompanies can also play a role here by encouragingmandates for efficient buildings and transportation systems,which reduce energy demand. And at the end of the day,this also means support for market-based systems thatlead to a steady reduction of carbon intensity. Businessshould embrace such efforts, since they provide the marketcertainty needed to support investments in innovation.markets. Changes in listing requirements for publicly-tradedcompanies would do a great deal to unlock greater potentialfor the innovation and efficiency efforts already underway.There are three specific changes that, if adopted, wouldenable companies to compete on the basis of the long-termshift to a lower-carbon future. First, companies should reporton their strategies to address climate risks. This effort is alreadyunderway, with the US Securities and Exchange Commissiondeciding in 2009 to begin considering rules doing exactly that.Second, companies can support the ongoing integration offinancial and sustainability reporting, as a way of promotinggreater awareness both with investors and within their owncompanies of the links between investments today in a lowercarbonfuture and a competitive future. Finally, companies inthe energy sector can join efforts to puncture the view thatshort-term shareholder advantage is the sole way to definefiduciary responsibility.This agenda is a broad one. The energy industry’s futurerests on its ability to develop energy in more technologicallycomplex, environmentally sensitive, and politicallychallenging environments. But all of the technologicalprowess in the world won’t get the job done without anequal commitment to addressing these “soft” aspects ofthe overall energy system. Companies embracing the fivedimensions presented here will strengthen their ability toproceed with their core business, and will also be the onesthat shape a future that delivers on the vision of sustainableenergy the world needs to achieve comfortable anddignified lives for all. •Reforming financial marketsFinally, one of the fundamental changes needed to enablefurther gains in CO 2reduction is the reform of financialEnergy Solutions For All 79

CooperationDemocracy and oil:A combustible mixBy Dr Keith Myers, partner at Richmond Energy Partnersand adviser to the Revenue Watch InstituteFor the past two years, in my work for Revenue Watch,I have advised parliamentarians in African and MiddleEastern nations that have recently discovered oil orrecently discovered democracy, providing training tomembers of parliament (MPs) and helping analyse oil policiesand legislation. I was motivated by the conviction thatparliaments are central to good governance, representingthe voice of the people, making laws and holding theexecutive to account. I still believe that, but the complexchallenges posed by oil wealth in today’s Africa and in theemerging Middle Eastern democracies means parliamentsacross the continent struggle to fulfil these roles.Oil governance is founded on the principle thatpetroleum rights are vested with the State on behalf ofits citizens and that the State’s primary role is to maximisethe benefit from the exploitation of the subsoil resourcesto the owner of the resources – its citizens. The rulers ofthe state, i.e. its Government, or Executive, is responsiblefor making the policies that achieve this goal whilst theParliament is responsible for making the laws that enactthe policies. The Government creates and enables aseries of institutions, typically a National Oil Companyand a Regulatory Body to implement policy and ensurethe legal and regulatory framework is complied with. TheExecutive is accountable to Parliament, and ultimatelyits citizens, for the effectiveness of its policies and theirimplementation. Parliament therefore plays an essentialrole in the governance of a nation’s petroleum.It can be easy for rulers in oil-rich nations to becomedetached from those they rule as oil revenues flows incentrally from companies rather than through populartaxation. The events of the 2011 Arab spring with the prodemocraticpopular uprisings in Tunisia, Egypt, Libya, Syriaand Yemen (all countries with substantial oil endowments)emphasise that the accountability of rulers to those theyrule is an essential requirement for stability in oil producingcountries. For Egypt, Tunisia and Libya a functioningparliament trusted by its citizens will be essential ifdemocracy is to be effective. So what lessons do I drawfrom my work with parliamentarians?In Uganda a billion barrels has been discovered in the LakeAlbert region on the border with the Democratic Republicof Congo. The next step is to agree a development plan thatmaximises the benefits to the owners of the resource (theUgandan people) and delivers a return for the providersof capital and know-how (the foreign oil companies).However, Uganda has still to create the necessary legaland regulatory framework and the regulatory institutions.In Ghana some two billion barrels have been discoveredsince 2006 and production started in December 2010and is currently around 80,000 barrels per day. Productionstarted before oil management laws were passed andbefore infrastructure to exploit associated gas was built. InIraq, the Baghdad Government has signed contracts withforeign oil companies to increase production to 12 millionbarrels per day whilst the regional authorities in Kurdistanhave signed separately numerous exploration agreementswith no coordination with Baghdad. Iraq has no depletionpolicy – i.e. how much oil does it need to produce? 12million barrels is 4 times its historic OPEC quota. Again nonational oil policy or law is in place – a draft law has beenbefore parliament since 2007. Why do many parliamentsfind it difficult to fulfil their function effectively? I believethe answer relates to three failings – lack of information,lack of expertise and a failure to prioritise the ‘National’interest over self and clan interests.Two years ago, I was invited by a senior MP from aruling party in in an African country to visit the parliamentbuilding after I led an oil workshop for MPs and civil society.His business card listed his parliamentary committeememberships on one side; on the back were his businessinterests in a school, a hotel and a travel agency.“You need to be wealthy to be an MP in Africa,” heexplained. It seems his constituents expected him tofix things for them - pay for schooling for their children,repair the road to the village etc. So African MPs need tobe wealthy, but even this MP found it hard to defend hisconstituents in a rural area where oil had recently beenfound. Consequently, some of his constituents were drivenoff lands they had used for livestock grazing, by outsidersapparently linked to the country’s elite. The MP claimedhe had tried to represent their interests but had beensubjected to many threats. It was too dangerous for himto continue to represent their interests and he wantedan outside NGO, such as Revenue Watch, to take up theircause. African MPs need not only to be wealthy, but alsobrave. This is also true in Iraq where each parliamentarianhas 30 bodyguards to protect them.If representing your constituents interests can bechallenging for an MP, how about the law-making function?Oil is not a renewable resource and its exploitation impactsboth today’s and future generations. Law-making thereforerequires a long-term vision for both national developmentand the role of oil and gas in it. Without this vision,8020th World PETROLEUM Congress

Cooperationlarge oil revenues can be captured for the short-termgain of those in power. However, I have witnessed thatachieving a consensus around a long-term vision is oftenproblematic in many African democracies. The Executivemay try to curtail debate by submitting laws to Parliamentunder emergency powers that severely limit the time forscrutiny. Or else, where national policies are unclear ornot consensual, laws are submitted to parliament but notpassed for years – for example in Nigeria and Iraq.Tribalism is never far beneath the surface and is a majorbarrier to achieving a national consensus. For many Africans,tribal allegiances are strong, and identification with thenation weak. The same could be said of Iraq. Craftingunity in a nation created by imposed colonial boundariesremains a distant concept – witness the breakup of Sudan– and often impedes efforts to garner widespread supportfor a national oil or mining policy. Failed efforts to buildnational consensus around policy objectives can lead tosituations like Ghana’s, where the country has begun oilproduction without coming to agreement on a nationaloil policy, instead following an outdated law drafted in1984 with few regulations to ensure the country derivesthe maximum benefit from its finite resources.Another common weakness in African law-making is thelack of detailed technical regulations and enforcement.An oil law on its own is not enough. Oil production is acomplicated and hazardous business. Without adequatetechnical regulations and an effective regulator, countriescan take on enormous risks. Regulations and a competentregulator are too often absent. Deep water wells, like theBP well in the Gulf of Mexico that spilled millions of barrelsof crude, are regularly drilled off Africa’s shores. Foreignoil companies and their contractors effectively regulatethemselves in places like Ghana and Sierra Leone. The lackof explicit regulations gives too much leeway for officials’discretion in approving activity, and too much risk of theirmaking personal gain from their official position.Any African or Iraqi MP who wants to hold theirgovernment to account for its stewardship of the oilsector will, in my experience, struggle to access oil sectordata and often lack either sufficient knowledge of theoil industry or credible research support to analyse whatinformation they could obtain.Take the example of the billion barrels discovered byforeign oil companies in Uganda. Most Ugandans I metassumed that they had been sold short by either theirgovernment or the oil companies. In fact, in my review ofthe contracts the Ugandan government negotiated, theagreements were tough and compared favourably withother countries. The problem was that MPs did not have easyaccess to the contracts, which had confidentiality clauses,leaving only leaked copies available. In one workshop inUganda, there was an angry and long exchange betweenthe chair of the parliament’s Natural Resources Committeeand its members, as the chair insisted members hadbeen given access to the oil contracts for review and themembers claimed they had not. The argument went onfor over an hour and was not resolved. If MPs can’t evenagree whether or not they can access the contracts, howcan Ugandans have trust in the system? “We don’t needto publish them.” one Ugandan lawyer joked, with tellingcynicism about Ugandan governance. “If you pay an officialat the Ministry a few dollars they will photocopy it for you.Corruption has some advantages.” In fact, the contracts cannow be viewed by MPs in the Parliament library but cannotbe removed even though digital copies are available forthe oil companies and their advisors. There are so manydifficult decisions to make about oil governance and yet somuch energy and time is expended fighting for the rightto access information.I am under no illusions as to the challenges MPs face onoil governance – tribalism,vested interests, temptationsof personal enrichment, national dissent over oil’s role indevelopment, unenforced regulations, and only nominalpower to hold governments to account. However, I havemet many courageous and able MPs, hungry for knowledgeabout oil, who want to make a difference. In Sierra Leone,I saw MPs from the governing party and the oppositioncommit themselves to work for national consensus on oilpolicy. In 2010, Ghanaian MPs rejected the government’sdraft petroleum exploration and production bill followingcross-party training on oil governance, insisting that the billinclude provision for a new independent regulator. After atraining session in February 2010, a group of Ugandan MPssubmitted a petition to publicly disclose oil agreements andhave sought the opinion of the country’s attorney generalon this matter. In Iraq, parliamentarians have called for a haltto further licenses being awarded until an oil law is passed.MPs have a tough job and need much more support fromNGOs, and particularly international organisations. The WorldBank, International Monetary Fund and United NationsDevelopment Programme have neglected parliaments andshould do more to engage with and support parliaments intheir essential role in governance.•Energy Solutions For All 81

CooperationQatar’s mix of long-termcontracts and flexible supplyInterview with His excelllency Dr Mohammed Bin Saleh Al-Sada,Minister of Energy & Industry, Qatar and CHairman, Qatar PetroleumQatar has rapidly increased gas production. Whatis its future production profile? Which new LNGtrains will come on stream?Under the wise leadership of His Highness Emir SheikhHamad Bin Khalifa Al Thani, Qatar has become theworld’s largest producer and exporter of LNG. This is asignificant achievement, particularly when you considerthat, in just 14 years, Qatar has gone from producing noLNG to having an installed production capacity of 77million tonnes per annum.As for the future, our priority is to ensure the efficientoperation of our existing capacity and to complete allmajor projects already under construction.As you are aware, in 2005 a moratorium was placed onfurther North Field projects. Therefore, our productionforecasts for the North Field are limited to projectsapproved under the moratorium. These projects are duefor completion after 2014.A detailed study is currently being conducted on theNorth Field to evaluate the reservoir, and to ensure thatfuture utilisation of the finite resources is done wiselyand effectively.His Excellency the Minister meets with the mediaWhat is Qatar’s pricing policy, given that gasprices are under pressure in some regions, notablyEurope, because of the knock-on effect of US shalegas? How disruptive of the market is US shalegas? Can Qatar keep linking its gas prices to oil inEurope?We understand that prices are not constant and areinfluenced by many factors beyond our control. Theseinclude the drop in demand as a result of the globaleconomic crisis, the unexpected boom in shale gasproduction and the surge in global LNG capacity.When considering the impact of these factors onQatar’s LNG business, there are two important things tonote. First, Qatar is in the fortunate position of having amix of secure long-term supply contracts, and flexiblesupply arrangements. This flexibility allows us to divertvolumes to take advantages of market opportunities. Assuch, we are very confident that the development ofshale gas in the US will not disrupt our current or futureinvestment strategies.The second point to note is that LNG projects are longterm investments. Although today’s gas market is ratheruncertain, the longrun fundamentalsare sound and itis these long runfundamentals thatwill ultimatelydrive investment.On the linkbetween oil andgas prices, it isclear that while wehave seen oil pricesrecover over thepast months, theseprice rises havenot been matchedby increases ingas prices. Thishas resulted in theprice of the gas perBritish thermal unitbecoming far lessthan the price ofits oil equivalent.While we →Energy Solutions For All 83

Cooperation→ hope this is a temporaryphenomenon, we believe it wouldbe prudent for gas producers toexamine the causes that led to thedisparity and in this regard we stressthe importance of open dialoguebetween producers and consumers.Qatar exports to more than 20countries outside the MiddleEast. Given growing gasrequirements of Gulf countries,might Qatar start providing gasto its home region?In addition to being an importantsupplier of gas to markets in Europe,Asia and America, Qatar is alreadyinvested heavily in supplying theGulf region through its flagshippipeline project – Dolphin Energy. This project links theNorth Field with markets in the UAE and Oman via asubsea pipeline which supplies around two billion cubicfeet a day of sales gas.The overall investment in the Dolphin Energy Project hasmade it one of the largest energy-related ventures everundertaken in the Middle East and is a clear illustration ofQatar’s commitment to regional development.How does Qatar see the role of the Gas ExportingCountries Forum, if the forum is not for membercountries to set export prices or agree on exportvolumes?Clearly the purpose of the GECF is not to set exportprices or agree on volumes but rather to provide aforum to enhance dialogue between gas producersand consumers.We view the GECF as a valuable opportunity to discussissues of mutual interest with other major players in theglobal gas market. These issues include investmentopportunities in member countries, the exchange ofcapital, financial data and know-how and the promotionof stable gas markets.In Qatar we host many international energyconferences that address similar issues. You could saythat Qatar is becoming a facilitator to the industry in thatwe are staging events that bring together producers,consumers, industry experts, technology providers andHis Excellency Dr Mohammed Bin Saleh Al-Sada speaks to the pressproject developer. The World Petroleum Congress is aprime example of such an event.Qatar is also an OPEC member. What is its likely oilproduction and export profile?Qatar currently has nine oil fields in production – threeof these being operated by Qatar Petroleum (QP) andsix via production share agreements with major energycompanies. These fields produce some 800,000 barrelsa day making us a relatively small producer amongOPEC members.In recent years, QP has invested heavily in its crudeoil business. This investment is set to continue withplans to invest over QR (Qatari rials) 18 billion at QPoperated crude oilfields and facilities over the next5 years. Over the same period, an additional QR 7.7billion will be invested by QP’s partners in contractoroperatedfields.The latest development phase at the Al Shaheenfield has recently been completed, and to date, QP’sinvestments have added significant production capacity.QP continues to work with the operators of other fieldsto assess their potential and maximise value.In addition to the Al Shaheen redevelopment,Integrated Reservoir Studies are being carried out on allQP operated fields. The end result of theses studies willbe full field development plans, which we expect to becompleted by 2012/2013.•8420th World PETROLEUM Congress

Cooperationgreat deal of activity has taken place with the NigerianContent Development and Management Board(NCDMB) acting as facilitator.The drive to have an appropriate percentage ofthe oil and gas industry’s projected US$20 bn annualexpenditure spent in Nigeria has started yielding thedesired results. So far, the Act’s implementation has laidthe foundation for the creation of over 30,000 directemployment and training opportunities in the nextthree years.The sheer volume of industry work-load previouslyperformed abroad that now has to be done in-country isdriving investments in capacity development. Over US$2bn investment is needed to establish critical facilities andinfrastructure required to support the Nigerian Contentscope in the Act, and plans are already afoot for a healthyproportion of these investments to upgrade existing plantsand establish new ones in the country.Specifically, within the last year, compliance with theAct has guaranteed the utilisation of the only pipe millin Nigeria, the SCC Pipe mill in Abuja which was recentlyupgraded to produce line pipes for the oil and gas sector.Already, pipes produced by the SCC Pipe Mill are beingutilised in the operations of some oil and gas companies.In the area of capacity development, the NCDMB hasbeen collaborating with the Petroleum TechnologyDevelopment Fund (PTDF) and major operators totrain over 10,000 young graduates and technicians inentry level skills. To ensure that the funds available fortraining are optimised, training providers in the industryhave been brought together under the Oil and GasTrainers Association of Nigeria (OGTAN) to standardisethe requirements for the industry and ensure thatlocal training results in internationally recognisedcertification. Similarly, the Nigerian Institute of Welding(NIW) has been empowered by the Board to playtheir traditional role in the training and certificationof welding practice in the country. In summary, theNigerian Content programme has huge potential forthe development of the Nigerian economy.A United Nations Environment Programme reporthas said more should be done to clean up the oilspills in the Niger Delta. What more do you thinkcan be done?For us the issue of health, safety and the environmentis a major focus, not only in the oil and gas industrywhich I supervise but also for the entire machinery ofthe Federal Government of Nigeria. Before the UNEPreport, the Nigerian Government had put in placethe Ministry of the Environment which is saddledwith the responsibility of formulating and enforcingenvironmental policies.The Department of Petroleum Resources (DPR),the government’s regulatory agency for the oil andgas sector, has also launched “The EnvironmentalGuidelines and Standards for the Petroleum Industry inNigeria” (EGASPIN) to regulate safety and environmentalactivities in the oil and gas industry. Operators in the oiland gas sector are expected to fully comply with thisprovision to reduce incidences of crude oil spillage.When the UNEP Report was released, the governmentimmediately set up a Presidential Committee of which Iam the Chairperson to study the report and recommendappropriate implementation plans. The Committeehas since commenced work and will soon present anactionable plan with timelines for the restoration ofOgoni land.A lot of Nigerian gas is still being flared. Do expensivegas export pipeline projects, like the Trans-SaharanPipeline to take Nigerian gas to Europe, make sensewhile this gas is still being flared?Nigerian gas reserves of about 187 trillion cubic feetinclude associated and non-associated gas. However,in the course of crude oil production, some associatedgas that is also produced is flared.The current plan is to harness and utilise both theassociated and the non-associated gas resources to thebenefit of Nigeria.The plan is encapsulated in the Nigerian Gas MasterPlan (NGMP) which is a robust infrastructure blue printthat accommodates all the flared and stranded gas forboth domestic and export market.The Trans-Saharan Gas Pipeline Project is just one ofthe new export projects being considered alongsidethe Brass LNG and OKLNG projects. Other existing gasprojects are the Bonny LNG and the newly completedWest African Gas Pipeline.Already the proportion of gas flared has decreasedfrom 70 per cent in 1999 to 40 per cent today. TheNigerian Gas Master Plan when fully operationalwill eliminate gas flaring, commercialise the gas andimprove the environment.•Energy Solutions For All 87

The Nigerian National Petroleum Corporation (NNPC), isresponsible for harnessing the nation’s oil and gas reservesfor sustainable national development. It explores, produces,refines oil, and markets/retails petroleum products; it also develops itsabundant natural gas for both external and domestic consumption,renders oil & gas engineering services and supervises governmentinvestments in the upstream sector.NNPC is at the starting point of a strategic journey. Our visionin the transformed NNPC is to be the premier Nigerian integratedoil and Gas Company operating at world class levels to create highvalue opportunities for Nigeria and Nigerians.Nigeria is the world’s 7th largest exporter of crude oil and the 7thlargest holder of natural gas reserves. On the African continent, thecountry holds the largest reserves in both oil and gas. It is poised toplay a greater role in the global energy market given the potentialsand opportunities that abound in the oil and gas sector.The petroleum industry today is the mainstay of the Nigerianeconomy. It is the main source of foreign exchange earnings (90 percent) and development finance in the country accounting for 85 percent of total government revenue, 28 per cent of Gross DomesticProduct (GDP) in 2010 and employs a sizeable number of Nigerians,both directly and indirectly.The planned growth and potentials of the industry will createsignificant opportunities for Nigeria and investors. Current crudeoil production is over 2 million barrels per day (mbd), while oilreserves and production capacity are 35.0 billion barrels and 3.0mbd respectively. Natural gas reserves have also increased to 187trillion standard cubic feet. While the sector has remained the pillarof socio-economic development and growth, it is poised to playan even greater role in the larger Nigerian economy with currentefforts to increase crude oil reserves, monetize the vast natural gasresources and integrate the power sector into the nation’s gas sectorin order to expand electricity generation capacity. The on-goinginstitutional and organizational restructuring, capacity building aswell as the local content development strategy will also accelerateoverall national development.Furthermore, the on-going transformation in the petroleumindustry is part of the Federal Government’s overall reform agenda toplace Nigeria on the path of growth and sustainable development.These reforms are therefore intended to revitalize the sector intobecoming a catalyst and engine of growth to national development.The petroleum industry is being opened up for private sectorinvestment in order to infuse capital and technology. Nigeria, beingthe gateway to oil and gas business in Africa and with a record ofstability of agreements in sub Saharan Africa, is the natural choice ofinvestors in oil and gas business.In order to reposition the industry, the Nigerian NationalPetroleum Corporation (NNPC) is being restructured into a worldclass National oil company to mid-wife reforms in the entire industry.The repositioning strategy runs through the entire spectrumof the industry; upstream, midstream, downstream and gas.Natural gasA lot of investment opportunities abound in the natural gas sector ofthe Nigerian petroleum industry. More attention is now being paid tothis vital sector. Government’s aspirations for the gas sector includecreating new industries out of the old oil industry, capturing economicvalue and generating as much revenue from gas as from oil. Others aredeveloping the domestic gas market as well as ending gas flaring.Remarkable progress has been recorded towards the realizationof these objectives. Of the current annual gas production of about2, 000 Bscf, about 40 per cent is flared. This is a drastic drop from the70 per cent proportion flared before 1999.Domestic gas consumption is expanding as a result of the ongoingpower sector reforms while gas export which was non-existentprior to 1999, has received a boost. Comprehensive and integratedgas utilization Master plan/ programmes have been embarkedupon, in which LNG and IPP developments are being given priorityas demonstrated by the launching of the gas revolution by thePresident in March this year.•

Nigerian National Petroleum CorporationMessage from Austen OniwonGroup Managing Director, Nigerian National Petroleum CorporationOn behalf of the Board Chairman, Management and staffof the Nigerian National Petroleum Corporation (NNPC),I sincerely welcome all the delegates to this year’s WorldPetroleum Congress taking place in Doha, Qatar.As you are aware, the World Petroleum Congress is one ofthe biggest industry events conducted every three years. Doha,a beautiful and serene city in the hydrocarbon rich middle EastCountry of Qatar, is no doubt a conducive and well-thought outvenue for this big event.In view of the importance of the oil and gas industry toNigeria’s national economy and those of other countries in theWest African sub-region and in-deed Africa, it is no surprisethat we are witnessing a high level of participation from theContinent.The continued global dependence on fossil fuel dictates thatour Corporation along with other stakeholders across the worldwill continue to map out effective strategies to meet the globaldemand for oil and gas.To this end, NNPC is undergoing a robust transformation whichwill ultimately galvanize into a phenomenal industry growth.And in line with the theme of this year’s conference EnergySolutions For All – Promoting Cooperation, Innovation AndInvestment, it is pertinent to emphasize that with provenreserves of 37 billion barrels of oil, and gas reserves of 187 trillioncubic feet, Nigeria’s onshore, deep offshore and continentalshelves remains highly prolific.It is worthy to note that under the leadership of Nigeria’sPresident Goodluck Jonathan GCFR, our Corporation is morethan determined to ensure the success of the transformationefforts not only in the interest of the Nation’s national oilcompany, but also that of the Nigerian economy.In this regard, concerted efforts have reached advancestages to attract investments across the globe to supplementthose made by the IOCs that have been operating in Nigeria inthe last 50 years.Investment in Nigeria’s vast gas resources also remains oneof the most rewarding ventures for discerning investors. Inrecent time, Nigeria is partnering with world class companiesfrom Saudi Arabia, China and India in the area of investment inpetrochemicals, refining and fertilizer plants to the tune of overUS$10 billlion.At full maturity, the investment promises to be of tremendousbenefit to Nigeria’s industrial landscape with the added advantageof providing job opportunities and also serving as a veritablesource of revenues for economic development of the country.Similarly, I like to state that efforts are in top gear to alsotransform the downstream petroleum sector in Nigeria toensure a level playing ground among participants and to alsoguarantee commensurate cost recovery in order to attract themuch needed investments to the sector.It is in this regard that I like to seize this opportunity to encourageinterested investors in our downstream to take advantage of thefull liberalization of the sector that is currently being pursued bythe present Administration of President Goodluck Jonathan.I will not conclude this message without remindingdelegates and our business partners that the Nigerian ContentAct remains an integral part of the industry’s contribution toour country’s economic growth.Our experience so far with the implementation of the Actshows that the industry has embraced Nigerian Content.Indeed, the Nigerian Content Act has made doing business inNigeria much more exciting and interesting.May I therefore seize this opportunity to disabuse the mindsof those who had thought that the Nigerian Content was an“Investment unfriendly” piece of legislation. It is not and willnever be, as experience has so far shown.I thank the Government and good people of Qatar for theexcellent arrangements made for this conference, while wishingall delegates the best as we savour the rich cultural heritage onoffer in this part of the globe.•

Profile: PerupetroPromoting E&P in Peru’smature and frontier basinsThe Peruvian Government’s goal of making the country a net exporter of oil and gasby 2014 will require fresh investment in both the Amazon and offshore regionsCreated in 1993 by the Organic Hydrocarbon Law(No. 26221), Perupetro S.A. is the State enterpriseof Peru’s energy and mining sector with primaryresponsibility for the promotion of investmentin hydrocarbons exploration and production (E&P),as well as negotiating, underwriting and monitoringLicense Contracts.In its chapter on Environment and Natural Resources, thePolitical Constitution of Peru states that both renewableand non-renewable natural resources are the patrimonyof the State, which is responsible for their sustainable useas well as the conservation of biodiversity and protectedhabitats and the development of the Amazon region.Peru has 18 sedimentary basins with hydrocarbonproduction potential. To date, however, E&P activities takeplace in only six of these, while oil and gas production isconcentrated in just three of them. The remaining basinscontain important unexplored and under-explored areas,as evidenced by the low number of exploratory wellsdrilled thus far.However, the US$ 2,122.32 million of private investmentin exploration activities and US$ 3,917.81 million inproduction activities invested in Peru between 2006and 2011 should serve as a wake-up call to investorsthat the Peruvian market is ready for large-scale privateinvestment in its hydrocarbons industry.The challenge of searching for new reserves is ofparamount importance in order to ensure significantincreases in the country’s oil and gas production levels. Inorder to achieve this, Perupetro has developed a combinedpolicy and incentives programme intended to increase thecountry’s attractiveness to oil and gas companies.One of Perupetro’s main targets is to reach a daily levelof oil and gas production that will enable the countryto become a net oil and gas exporter. In order to reachthis threshold, fresh investment is required in areas witha proven track record of exploration success.Peru benefits from a policy which combines a competitivefiscal regime, a convenient royalty scheme and a first-ordercontract model aimed at reducing risk and uncertainty, aswell as proximity to markets, a developed infrastructureto support E&P activities and the potential for importantcommercial discoveries both onshore and offshore.Once signed, contracts assign companies exclusiveexploration and production rights and ownership of allhydrocarbons produced in their block, subject to royaltypayment. The size of the royalty will be determined byfuture production levels after declaration of commerciality.The contract duration is currently set at seven years for theinitial exploration phase, with an additional 23 years forthe exploitation phase in the case of oil production and33 years in the case of gas production. The explorationphase may be extended to ten years on request.The Marañon, Ucayali and Madre de Dios basins in thePeruvian Amazon and the free areas in the offshore andcoastal regions have attracted the interest of explorationcompanies for many years. To date, the most prolificbasins are Marañon and Ucayali in the jungle and Talara inthe coastal region. However, despite a significant numberof exploratory wells having been drilled in these basins,there remain important areas that are either unexploredor under-explored.Peru’s oil industry dates back to the early 1970s whena number of highly successful discoveries in the jungleregion took place. Since that time, there have been nomajor discoveries with the notable exception of theCamisea natural gas fields, which were discovered inthe 1980s.In the offshore areas hydrocarbon exploration andproduction activities have been concentrated in shallowwaters, at water depths of less than 100 metres. Even inthe northern part of the country, where oil and gas havebeen produced for more than 50 years, exploration hasgone to depths of no more than 120 metres.Due to the application of Perupetro’s new policy,investment in hydrocarbon exploration and exploitationhas increased rapidly in recent years, and this is expectedto rise still further in the near future, especially in theexploration and development of heavy oils in thenorthern jungle and the E&P activities for natural gas andLNG in Camisea and the surrounding areas.As a result, due to the renewed activity in hydrocarbonsexploration and exploitation since 2005, importantdiscoveries have been made in both the Amazon basinsand offshore region. Perupetro continues to organisecampaigns to attract new investment and bolster thecountry’s oil and gas reserves, with new blocks due to beoffered in future rounds.The company has great expectations for theforthcoming bid rounds, bolstered by the news thatPeru has been ranked 76th in the world for oil and gasinvestment by the Fraser Institute. This represents aremarkable leap forward compared to its ranking of 85thplace just a year ago.•9020th World PETROLEUM Congress

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9220th World PETROLEUM Congress

InnovationFrom the inventions of the tricone drill bit and 3D seismic onward, the petroleum industry hassteadily innovated. To maintain this record, Rex Tillerson of ExxonMobil warns of the acuteneed to educate tomorrow’s innovators in the fundamental skills of science, technology,engineering and maths, and in this regard points to the Qatar Foundation’s work in Qatar.Such skills are being tested far from the Arabian Gulf. Perhaps the toughest project currently underwayis offshore Brazil where, as Guilherme Estrella describes, Petrobras and its partners are drilling in deepwaterunder a salt layer up to 2km thick. Petrobras has also set itself the additional task of capturing the CO 2andre-injecting it into the reservoirs – a subject that Brad Page of the Global CCS Institute writes about morebroadly, noting that the oil and gas industry has been the pioneer of CCS technology.On the Arctic, Anatoly Zolotukhin provides the essential perspective from Russia which alone accountsfor around 180° of the Arctic circle. He gives the Barents, Kara and Pechora seas the best potential, butsays their development needs the “indispensable” help of foreign companies. In contrast to Arcticuncertainties, Marvin Romanow of Nexen says that with Canada’s oil sands “we know exactly wherethe bitumen is, so the exploration costs are very low,” in contrast to high production costs which a lot ofinnovative effort is going into reducing.New rules as well as new frontiers may also drive innovation. Michael Bromwich, the new regulator ofthe US offshore, spells out the new post-Macondo regime for the Gulf of Mexico. Among other things itrequires operators to have far greater risk awareness that may only be possible through faster integrationof information between surface and subsurface. John McDonald of Chevron calls it “ingenuity at speed.”But it’s not easy. As Ashok Belani of Schlumberger cautions, “reservoirs are becoming more complex, theirproduction more difficult, their location more remote, and their environmental conditions in terms oftemperature and pressure more extreme.”Everyone is aware of the US revolution in shale gas, but Greg Hill of Hess Corporation reminds us that italso applies to shale oil in the US. If unconventional oil is developed on the low-cost business model headvocates, it could rise to 40 per cent of US liquids by 2015. However, the section focuses more on gas.This is because of shale gas prospects outside the US about which Peter Hughes of Ricardo is cautiousbut Stanislaw Rychlicki and Marek Karabula are more hopeful in Poland; because of the extra gas thatNobuo Seki says Japan will need after Fukushima; because of the relatively “green credentials” of gas asDr Hashim of the IGU puts it; and because of the technical progress in its transformation and transport.Andrew Brown of Shell briefs us on his company’s ground-breaking Pearl gas to liquids plant in Qatar,and David Ledesma on bold projects for Floating LNG.However, innovation may not just add to oil and gas supply. It could also subtract demand by providingalternative means of powering cars. Chris Borroni-Bird and Mary Beth Stanek of General Motors updateus on development of electric urban cars and on biomass or hydrogen propulsion outside cities. Biofueldevelopment will continue, say Anselm Eisentraut and Michael Waldron from the IEA, though taking overless of oil demand growth than before.•Energy Solutions For All 93

InnovationThe need to train theinnovators of tomorrowBy Rex W Tillersonchairman and CEO, ExxonMobil CorporationThe men and women of the energy industry have along and proud history of overcoming challengesall over the world.For more than 100 years, our industry haspioneered technological innovations that have unlockednew supplies of energy, increased safety and energyefficiency, and reduced environmental impacts. The resultof these extraordinary advances has been an unparalleledcontribution to global progress and prosperity.As we look to the future, our industry’s scientific andtechnological breakthroughs will continue to be essentialto meeting the world’s energy challenges. But we mustremember that tomorrow’s innovations will not simplyhappen by themselves. They will require creative thinking,new ideas, and a bold and relentless commitment toscientific research and development.In fact, it is no exaggeration to say that the future ofour industry – and the aspirations of billions of peoplein developed and developing economies – will dependon the ingenuity and innovation of tomorrow’s scientists,engineers, and technology entrepreneurs as we seek todevelop new sources of energy and new levels of energyefficiency.That is why one of the most significant challenges weface as an industry is in working to increase the numberof students pursuing degrees in science, technology,engineering, and mathematics (STEM).At ExxonMobil, we believe now is the time for leadersfrom business and government to come together topromote education in these critical fields, so we canincrease economic opportunity and the potential forprogress in the future. Simply put, education today is thekey to energy tomorrow.The challenges of the futureThe urgent case for new efforts to promote STEMeducation is clear when seen in the global context of theeconomic and energy challenges before us. In fact, asbusiness and policymakers better understand the realitiesshaping our energy markets, it will become evident thatwe will need more citizens and workers who understandscience and engineering than ever before.While markets have been volatile in recent years, thefact remains that we are living in an era of tremendouseconomic development – development that istransforming nations and markets around the world.Reliable supplies of energy are needed to fuel this growth– especially for progress in areas such as Asia, LatinAmerica, India, and Africa.Even now, in the year 2011, 1.4 bn people, 20 per cent ofthe world’s population, live without access to electricityto heat their homes, cook their food, purify their drinkingwater, or power hospitals and schools in their area. Formen, women, and children living in developing nations,the economic growth that flows from reliable energysupplies can be the difference between health andsafety or sickness and death. For more developed nations,reliable energy enhances the robust trade, transportation,and technology that extend and enrich life.This universal need for energy to support humanprogress is destined to drive energy demand for decadesto come. Over the years 2010 to 2030, we project thatglobal demand for energy will increase approximately 25per cent.Meeting this enormous demand will require humaningenuity, sustained investment, and teamwork todevelop technological solutions that keep pace with ourgrowing world.Pivotal role of technologyOur industry can meet this challenge. We have proven ittime and time again. With sound, unbiased, and reliableenergy policies in place, all types of energy companiescan engage in the long-term planning and make thedisciplined investments that are needed. We have alsoproven that we can find and deploy integrated solutionsthat help us bring new supplies of energy to the marketin a safe, secure, and environmentally responsible way.But one lesson that is undeniable is that none of uscan achieve these objectives alone. Over the last 30 years,our industry has proven the value of strong partnershipsbetween national oil companies and international oilcompanies to recover the energy resources found inincreasingly difficult-to-reach and remote places.History also reminds us that new technologies requirerobust and sustained investment. This means in theyears ahead we will need government leaders to playa role in establishing and sustaining energy policiesthat encourage investment, reward cooperation, andpromote the rule of law.And finally, as the importance of teamwork andtechnology increases we will need visionary leadershipfrom business and government to build programmesthat encourage the best and brightest in every nation to9420th World PETROLEUM Congress

Innovationpursue careers in science and engineering.We cannot innovate without innovators.The need for visionary leadershipFortunately, there are proven ways to help encourageeducational opportunity in mathemtatics and science.Attendees at the World Petroleum Congress do nothave to look far to see an example of what visionaryleadership can accomplish in promoting education. Ourhost nation, the State of Qatar, is in the vanguard of suchefforts.In 2008, the Emir presented to his people the QatarNational Vision 2030 – a plan to transform his country intoa knowledge-based economy, an educational leader, anda global technology pioneer. This commitment to thefuture is demonstrated by three particularly visible andsignificant projects – the creation of Qatar’s EducationCity by the Qatar Foundation, the establishment of theQatar Science and Technology Park, and the constructionof the world-class Sidra hospital complex.Each one of these projects creates opportunities forQataris to learn and excel, work and research. In addition,the Emir’s vision has provided a clear direction forgovernment and business leaders to build long-rangeprogrammes that encourage the development of thenext generation of scientists, engineers, and doctors.At ExxonMobil, we are proud to be part of theEmir’s efforts to fully develop Qatar’s economic, social,environmental, and human potential. For the State ofQatar, the success of the National Vision is making thenation even more attractive to international business andinvestment.The key to the Emir’s vision is its boldness and breadth.By involving both government and business, the NationalVision supports science and engineering in schools andthen helps graduates by providing a pro-investmentclimate that supports job creation.In fact, such cooperation is a proven formula for success.Producing scientists and engineers requires disciplineand time, so a comprehensive set of programmes areneeded. Education in science and math must begin inprimary schools and extend all the way to advanceddegrees. In addition, business and academic institutionsare valuable partners because their programmes canencourage government-run schools to use metrics tomeasure success, spread the use of proven curricula, andhelp teachers through training and scholarships.As one example of what can be achieved throughsuch partnerships, ExxonMobil in the United States issupporting two major programmes under the NationalMath and Science Initiative (NMSI). Through the UTeachprogramme, NMSI is working with universities toidentify the most effective ways to recruit and supporthighly qualified teachers in mathematics and sciences.By encouraging teachers who have a mastery of thesefields we can ensure more students are inspired by whatscience, math, and engineering have to offer.A second and equally important part of NMSI is theAdvanced Placement Training Incentive Programme.This is designed to dramatically increase the numberof students taking and passing college-level exams inmath, science, and English. Not only is this promotingSTEM in US secondary schools, it also has a specialfocus on encouraging under-represented students topursue these fields, which create tremendous careeropportunities. Since their launch in 2007, the NMSI hashelped US public school students and teachers achieveextraordinary results.ConclusionFor more than a century, our industry has proven that wecan meet the energy challenges of the future.We have safely unlocked energy supplies beneatharctic tundra, ultra deepwater, and in remote locationsacross the globe. We have harnessed oil and naturalgas resources – and then helped the world use themmore efficiently. And as we look to the future, we seenew technologies continuing to expand access to newsupplies. A case in point is liquefied natural gas, whichis helping enable abundant and affordable natural gasto be the fastest growing major fuel source in the worldwhile its clean-burning properties also provide significantenvironmental advantages.None of these milestones would have been possiblewithout the creativity and ingenuity of scientists,engineers, and technology entrepreneurs.As our industry meets at this year’s World PetroleumCongress, it is our duty to ensure that the world finds waysto develop new energy resources in a safe and secureway. It also falls to us to help the public and policymakersunderstand the importance of technology in achievingthese goals and the role future generations of scientistsand engineers will play in creating the innovations thatwill build a brighter future.•Energy Solutions For All 95

InnovationPre-salt productiondevelopment in BrazilBy Guilherme EstrellaHead of Exploration and Production, Petrobras *Brazil’s ‘pre-salt’ reservoir is a layer of oil-bearingrock of carbonate composition, positioned undera thick layer of salt and located in the Santos andCampos basins (Figure 1). Lying under it are thesource rocks, shale rich in organic matter. These sedimentsare the result of the evolving process of Brazil’s southeastand eastern basin formation, due to the South America-Africa breakup around 120 million years ago.The major exploration and production efforts are beingapplied on the Santos Basin Pre-Salt Cluster (SBPSC), thatinclude six blocks operated by Petrobras with differentpartners: Galp (Caramba and Jupiter) Shell and Galp (Bem-Te-Vi), BG and Repsol (Carioca and Guará), BG and Partex(Parati), BG and Galp (Lula, Cernambi and Iara). The area islocated 300 to 350 km away from the coast, with reservoirdepths between 5,000 and 6,000 metres below the sealevel, in ultra deep water (1,900 m to 2,400 m) under a thicksalt layer (in some areas, up to 2,000 metres).In the Lula and Cernambi fields, the total recoverablevolume was estimated as 8.3 billion barrels of oilequivalent from carbonate reservoirs with highly variablegeological properties. The oil has an API gravity between28 and 30, gas-oil ratio between 200 and 350 m 3 /m 3 andvariable contents of CO 2(8 to 15 per cent). The Braziliangovernment has transferred to Petrobras another 5 billionboe of potential reserves in other parts of the Santos BasinPre-Salt Cluster.Development strategyFigure 1: Pre-salt cluster areas in the Santos Basin, BrazilA phased strategy will be applied to the SBPSC in orderto allow exploration to be carried out with development.The immediate priority is to reduce uncertainties related tothe reservoir – especially the basin’s geological character,hydrocarbon recovery methods, definition of the bestwell geometries, flow of oil through subsea pipelines,separation and use of CO 2, and design of the processingplant, risers and mooring systems. This acquisition ofgeological and production information is the priority ofwhat is called “Phase 0”. This phase involves drilling andtesting of appraisal and reservoir data acquisition wellsand, since 2009, a series of Extended Well Tests (EWTs)performed with two small FPSO (floating production,storage and offloading) vessels. In all, this will lead toproduction of around 100,000 barrels a day.The following phase - Phase 1A, aims to reach theproduction of 1 million barrels a day using usingtechnologies developed in the Campos Basin:• two anticipated spread moored FPSOs pilots in Guaráand Lula NE, scheduled for 2013;• two additional spread moored FPSOs to operate inGuará and Cernambi, scheduled for 2014 and;• eight production systems, comprising new built FPSOswith similar engineering project, to be installed in order tosupport the following projects. For the gathering systems,flexible risers, decoupled rigidrisers or coupled rigid riserscan be applied. These eightFPSOs are scheduled to startoperation gradually, from2015 to 2017.These units will operate withprocessing plants rangingfrom 120,.000 to 150,000barrels a day and 5 to 8 millioncubic metres of gas capacities.Definitive development ofthe fields will start in 2017 withPhase 1B. Further productionsystems will be required forthe optimal exploitation ofthe fields, using technologicaland logistic solutions speciallydeveloped for the conditionsof the SBPSC.9620th World PETROLEUM Congress

InnovationTechnological challengesDue to the oil and reservoir characteristics as well as theenvironmental scenario, the development of the Pre-Salt in the Santos Basin raises technological challenges inseveral disciplines.Reservoir characterisationPre-Salt reservoirs are Aptian rocks, mainly microbial,heterogeneous carbonates (Figure 2). The main challengeposed by the Pre-Salt reservoirs is to use the knowledgeof the paleo-environment where these carbonatesdeveloped, as well as seismic attributes, in order to optimisedrainage of the reservoir. The geological characteristicsof the Pre-Salt raise some difficulties as to the quality ofseismic data, because of the uneven surface of the topof salt, the internal variations within the salt layers whichcause heterogeneous scattering of the seismic energy, andthe limited vertical resolution in the reservoir which, dueto the high velocity of the seismic waves in the carbonate,is very common in deep reservoirs.Oil recoverySecondary recovery must be implemented to improve oilrecovery in the Pre-Salt carbonates. These rocks are usuallyoil wet, and this characteristic affects the performance ofwater injection, which will be tested in the Lula Pilot field.Another complication in the case of water injection isrelated to rock-fluid interaction, which is more important incarbonate. To understand the phenomena and to assess therisks involved, as well as to define mitigation actions, rock-fluidinteraction tests are being carried out with the reservoir rockand the salt cap rock. Alternative recovery methods will beimplemented in the Pre-Salt reservoirs. Gas injection is alreadybeing tested in the Lula Pilot and the water alternating gasmethod (WAG) will also be tested in the field.Well engineeringThe main issue related to well engineering is theconstruction cost. Deep reservoirs in deepwater requirespecial rigs and skilled people to improve the learning curveand reduce well construction duration. In order to reducethe overall cost, several initiatives are being carried outrelated to well design; control and constant improvementof rigs´ performance; using lighter rigs in the initial phasesof the wells, well tests and deployment of ‘Christmas trees’(often referred to as X-Mas trees, the equipment installedon the bottom of the sea that controls the production ofthe wells), and drilling of deviated wells.The great depths of the reservoir and the great distancefrom shore add to well costs that represent approximately50 per cent of the overall cost of a typical Pre-Saltdevelopment project. But there is room for improvement,such as: logistics, optimisation procedures for theconstruction of wells, simplifications in the design of wellsand in the equipment being used in drilling.The penetration both in salt and carbonate rocks hasincreased as wells have been built, with a significantreduction in the average cost of a well. By understandingthe mechanical properties of salt and carbonate rocks andthrough close cooperation with the service companies,the average rate of current drilling of vertical wells is morethan twice the rates obtained in the first wells. Differentconcepts and new technologies that could lead to furtherreduction are being tested.Salt rock shows high creep strain rates, constitutinga potential hazard to well drilling. The evolution of thewell closure with time, caused by creep, can result inimprisonment of the drill string or successive operations tocorrect the diameter of the well. The low temperatures inthe Santos Basin Pre-Salt reservoirs and the predominanceof halite in the salt layer are favorable factors. At the oppositeside the high stresses associated with great depths areconcerns, even when dealing with halite. As mentioned,this challenge is being overcome, at least considering thesalt characteristics in the Lula Pilot area.Another focus is on materials to be deployed in the well,whose supply can add time and cost. Special resistantcasing must be used to avoid well collapse due to the saltmovement, and due to the presence of contaminants inthe reservoir fluids and also characteristics of the formationwater. Corrosion resistant alloys must be considered forcompletion of wells below the salt layer.Expert cementing is also required in the Pre-Salt toguarantee a reliable isolation between the pay zones andalso well integrity considering the cap salt rock. Specialcement slurries are being applied in order to avoid risks ofchanneling and to guarantee that the cement propertieswill not be affected by the produced or injected fluids.Another important issue is the definition of the bestwell geometry for each Pre-Salt area. Small scale reservoirsimulation is used to quantify the benefits of different wellgeometries. Field results are encouraging. Three deviatedwells have already been drilled in the Lula Pilot area, and →Energy Solutions For All 97

Innovation→ the next step will be the construction of a high anglewell in the Lula Pilot.Flow assuranceThe salt layer is a good heat conductor. So, the reservoirtemperatures are lower than expected for rocks at greatdepths but more critical for wax deposition and hydrateblockages. Notwithstanding, with more than two years ofproduction in the Lula Field, no significant problems werereported in pipes.Wax deposits may occur in long flowlines or in the risers.The conventional solutions are to use thermal insulatedflowlines, to manage heating and assure flow from thewellhead to the platform as well as frequent pigging thepipes to prevent wax accumulation. The high pressuresinvolved in the flow, together with low temperatures, canresult in a risk of blockages by hydrates. But the high valuesof gas-oil ratio (GOR) are a positive factor in operationalprocedures during shutdowns, because of the lowerhydrostatic pressure.Thermodynamic simulations have forecast the possibilityof calcium carbonate, barium and strontium sulphateprecipitation. Low sulphate sea water injection is an optionto prevent sulphate scale formation. Chemical treatmentsmay be required to prevent calcite precipitation in theperforations and subsea equipments. To cope with thischallenge, Petrobras’ expertise in the Campos Basin, aswell as support from international institutions, are beingused to define the chemicals to be applied and investigateinteraction that sea water or EOR methods may have withthe reservoir rock.The possibility of hydrates in the water-alternatinggas injectors was thoroughly investigated. Among theimprovements that are being considered are a specialdesign for the standard Pre-Salt X-Mas tree, allowing theinjection of hydrate inhibitors; the use of separate injectionflowlines for gas and water; special procedures to beapplied during fluid change; heating of the injection water,among others.Subsea technologyThe deeper the water, the higher the loads due to theweight of the mooring lines.The use of lighter materialswith higher stiffness is necessary to limit the motion of theProduction Unit. The higher loads due to the risers´ weightimpact the platform structural engineering and possibly theriser lifetime, possibly requiring special materials. A goodalternative solution, which is being applied, is to decouplethe risers from the motions of the production floater.The ongoing qualification process of flexible risers for thePre-Salt environment deserves special attention. Coupledflexible risers have been applied in the Lula Pilot area, andno problems have been detected to date. For the Guaráand Lula-North East Pilots, decoupled steel cathenaryrisers´ system were ordered.CO2 – how to process it and what to do with itPetrobras has decided, for environmental reasons, it willnot vent the naturally produced CO 2. But separating CO 2from the natural gas is expensive and put huge space andweight requirements on the FPSOs. So designing low costplants with reduced footprints and weight and low energyconsumption has been a challenge.The gas processing units have been designed to separateCO 2from the natural gas after which the CO 2rich streamis re-injected into the reservoir. The natural gas is exportedthrough gas pipelines but can also be reinjected partiallyor entirely along with the CO 2rich stream.The sustainable hydrocarbon production from the Pre-Salt reservoirs will require, minimisation of emissions ofits non-anthropogenic CO 2. Alternatives are under studyfor the CO 2capture and storage: reinjection in the oilproducing reservoirs, in salt caves, in salt water aquifers orin depleted gas reservoirs. Special attention was given tothe gas processing plants in the floating production units.In this way, the process known as Carbon Capture andStorage will be applied.The CO 2capture is planned to be done with membranestechnology, which is suitable for high CO 2content. In theLula Pilot the gas will be exported to the fixed platform ofthe Mexilhão field (located in shallow waters, 220 km fromthe Lula FPSO). Currently, the preferred storage option is toreinject the CO 2in the reservoir, pure or with the treatedgas current.Logistical challengesThe Santos Basin is located around 290 km distant fromRio de Janeiro coast and 350 km from São Paulo coast, inultra deep waters. This poses logistical challenges for thesupply of bulk materials, transport of people (helicopters orboats), pipeline laying vessels, drilling & workover rigs, andterminals for oil export through commercial crude carriersAs a result we are studying the selection of existingharbours and airports to be adapted, the design of offshore9820th World PETROLEUM Congress

Innovationoil terminals, in deep and in shallow waters, floatinghubs for fluids and materials, power generating offshorehubs, design of an auxiliary location for helicopter refuel/maintenance, and extensive automation to manage,control and supervise operations from onshore.Logistics challenges for the associated gasThe deployment of large diameter gas pipelines is atechnological challenge for installation vessels, due to theheavy loads involved. In ultra-deep water, the thickness ofthe pipe walls will be greater than 1.4 inches (3.6 cm), towithstand the high pressures at the seabed, resulting inhuge weights. Additionally, the large wall thicknesses ofthe pipes require most accurate welding, as well as controltechniques and inspection.New technologies for exploitation of gas have potentialto give more flexibility for evacuating the gas. In this sense,Petrobras and partners have been evaluating the potentialapplication of technologies such as: FLNG (FloatingLiquefied Natural Gas), CNG (Compressed Natural Gas),GTL (“Gas-to-Liquid”) and GTW (“Gas-to-Wire).Boosting Brazilian economyDevelopment of the Pre-Salt holds greatpotential for the petroleum industry andfor Brazil. In shipbuilding, the opportunitiesinclude construction of several floatingproduction units, offshore drilling rigs andsupply boats; inspection and maintenanceservices for the fleet, and so on. Theequipment industry stands to gain fromthe construction ofsalvage equipment,load transport equipment, compressors,turbines, pressure vases, special valves,equipment with special metallurgy tosupport high pressures and aggressiveenvironments. For the service industrythe opportunities will be enormous,not only due to the increasing demandfor specialised services – drilling andcompletion offshore services, project andconstruction of oil and gas process units,handling of subsea equipments, subseainspection services, project management– but also due to the logistics demands,such as different ways of transportation,load handling and transportation, facilitiesand supply technologies, management and technology formaterial stock.The Brazilian government’s clear policy to promoteincreasing local content both in construction and designof all sorts of material, equipments and services offersan excellent opportunity for the international petroleumindustry suppliers to set up in Brazil, especially whenassociated with Brazilian companies.As for Petrobras, the company and its partners hope tofollow the highly successful experience of the CamposBasin, where, through actions of synergy involving severalareas of competence, Petrobras quickly managed to adapttechnologies and arrange the logistics, in addition to criticalresources, to place the fields discovered in production.The next challenge is to develop the Pre-Salt cluster inthe Santos Basin, with emphasis not only on Lula Field, butalso on the other accumulations discovered, which will beoperating by 2017. Both from the industrial technologyand economic points of view, Petrobras and partners hasall the conditions to explore for and produce oil and naturalgas from the Pre-Salt cluster for a long time to come. •*Co-authored with Alberto de Almeida, Antonio Pinto, Celso Branco, JoséFilho and Ricardo de Azevedo.Figure 2: Slices from Pre-Salt carbonatesshowing the high heterogeneityEnergy Solutions For All 99

InnovationBrazil’s deepwater: A financialas well as a technical challengeBy Gareth ChetwyndSouth America correspondent, Upstream NewspaperWhen Petrobras first broke through the twokilometresalt layer under Brazil’s Santos basinin 2006, few in the industry guessed theenormity of the find. The wildcat well, calledParaty, was almost stratigraphic in nature, designed to findthe easiest passage through the salt rather than looking forthe juiciest structures.For years, a handful of Petrobras geologists had worked onsomewhat unorthodox theories suggesting the presenceof a potentially huge hydrocarbon system beneath saltdeposits left behind when the South American and Africancontinents began drifting apart more than 100m years ago.Their theories trickled down the ranks, generating rumoursabout a “new Campos basin” at deeper horizons, but noteven Petrobras saw the pre-salt as the primary target onthese ultra deepwater Santos basin blocks acquired inBrazil’s early bid rounds.What Petrobras found in 2006 was an unfamiliar microbialitecarbonate reservoir of light oil and gas, with carbon dioxideand sulphur dioxide showing up in unwelcome quantities.The three partners on the Paraty well – Brazil’s Petrobras,Britain’s BG Group, and Portuguese Gulbenkian Foundationoffshoot Partex Oil & Gas – were cautious about the potentialof their find. They had endured a difficult 672-day drillingoperation, with another 200 days for open-hole and casedholetests and the Paraty well cost over US$200m.The immense logistical and technological challengesfor drilling or producing in the pre-salt environment wereimmediately clear. The targeted structures were located inwater depths of around 2,220 metres, about 300 kilometresoff the Brazilian coast and deep-buried beneath the saltlayer. The Paraty well was drilled to 7,628 metres below theseabed. The most daunting challenge was posed by thereservoir itself. “There was a fundamental question markabout whether we could produce from this carbonatemicrobialite reservoir. It departed from all of our previousexperience, which was mainly with sandstones,” recallsRicardo Beltrão, general manager for production with theresearch and development arm of Petrobras.Armed with information from the Paraty well, Petrobraswent on to make some of the biggest discoveries fordecades, including giants such as Lula, Guara and Franco.Estimates now point to at least 50bn barrels of recoverableoil and gas in the Santos basin pre-salt province. A strategyaimed at gathering information from these fields has putthose early conceptual fears to rest. Extended well testsin the Santos and Campos basin showed that the presaltreservoirs can produce at prolific rates using systemsthat have been tried and tested in the Campos basin,including subsea completion and flexible risers and drillingoptimisation. “An initial period of research under our Prosalprogramme and results out in the field showed thatwe were being cautious. The pre-salt fields are much moreproductive than we had imagined,” Beltrão reflects.This is just the beginning of the pre-salt challenge,however, as there is immense scope for applyingnew technology and concepts to reduce costs andincrease safety. Petrobras CEO José Sergio Gabrielli saysimprovements in drilling efficiency have helped push thebreak-even point down to an international crude price ofUS$35-US$40, compared with US$40-US$45 previously.Drilling through the salt is no longer the dauntingchallenge it was, and drill-string optimisation is startingto ease the difficulties of drilling into the hard carbonaterock. Petrobras expects to drill 1,000 pre-salt wells by 2020,when it will have 65 deepwater rigs at work, and activity isnot likely to diminish before 2030.The very scale of the pre-salt operation offers the chancefor efficiency gains. Petrobras is working out how to use amix of higher-end rigs, tophole rigs and specially-equippedintervention vessels to reduce drilling costs on each well,for instance. The company’s ‘Proinv’ drilling efficiencyprogramme has already trimmed the costs of pre-salt wellsto an average US$120m, down from US$180m two yearsago, says Petrobras general manager for well engineeringLuiz Felipe Bezerra. The company believes this sum canbe trimmed back to US$80m. Such claims are impressive,but the pre-salt partners are still in the early stages ofsurmounting the difficulties.These challenges can be divided into three main categories:the technological, the financial and the physical, whichincludes limitations on logistical or industrial capacity in Brazil.Extended well tests and pilot production system may haveovercome the most fundamental technological challengeof getting these reservoirs to produce, but there is stilltremendous scope for reducing production costs throughthe development and application of new technologies.Ground-breaking projects are already taking shape,such as the tethered subsea buoys that will decouplerisers from the huge loads to which they are subjected atthese water depths, or the offshore gas-to-liquids projectthat promises to eliminate flaring on extended well tests.Petrobras is spending about US$1bn per year on researchand development, and other operators are beginning to10020th World PETROLEUM Congress

Innovationfollow suit by virtue of a provision that earmarks one percent of their royalties for this objective.In the medium term Petrobras is aiming for a new eraof highly-automated production and compact processingmodules that allow production units to be “re-configured”during the life span of the fields. The company is alsopursuing ground-breaking subsea processing projects,looking for ways of reducing the manning levels on offshoreplatforms and maximising output on the limited spaceavailable on production platforms. Subsea separation andcompression technologies could eventually extend to thecarbon dioxide that accounts for about 11 per cent of thegas in the pre-salt fields.The financial challengeThe second great challenge Brazil faces in putting the presaltfields into production is a financial one.The pressureson Petrobras were in evidence in 2010 when the companycarried out a US$70 bn re-financing operation on globalstock markets. Only about US$43 bn of this sum wascash. The rest was payment-in-kind when the Braziliangovernment transferred production rights for up to 5 bnbarrels of pre-salt oil on unlicensed acreage.This oil-for-shares mechanism left minority shareholderswary of another refinancing operation and fed perceptionsthat government objectives, such as increasing the federalstake to its current level of around 48 per cent of total capital,might be diverting Petrobras from its production targets.It also increased the capital expenditure commitments onPetrobras, imposing a tight production schedule and rigidlocal content requirements. The re-financing operationtriggered a negative adjustment that has practically wipedout the increase in market capital for the time being.Petrobras has since overcome a budgetary impasse toapprove a US$225bn five-year capital expenditure planthat slightly boosts upstream spending but included amarket-pleasing US$14bn divestiture plan.Petrobras CEO Jose Sergio Gabrielli insists that the stockprice will bounce back over the long-term. Many analystsagree with him, enthralled by uncommonly attractivelong-term fundamentals, especially burgeoning reservesand proven record as a top-notch deepwater operator.Gabrielli points out that debt requirements, estimated atbetween US$67bn and US$90bn through 2015, are easilyfundable. This is based on oil price scenarios of US$95 toUS$80 per barrel. Shorter term concerns are being easedby an exploration project called Varredura detecting morethan 2bn barrels of pre-salt oil beneath existing Camposbasin production infrastructure. These discoveries requireinvestments to extend the life of older platforms. Combinedwith updated topside and subsea processing facilitiesthey imply faster and more economic routes to higherproduction than the greenfield Santos basin discoveries.More pressing financing concerns relate to a supply chainwhere the great majority of companies are small privately runoutfits. “Petrobras currently has 5,500 registered suppliers,60 per cent of which have a turnover of less than US$5m.This is not the ideal foundation for a US$224bn capex plan,”says John Michael Streithorst, head of private equity atBanco Modal. A study carried out by Brazilian national oilindustries association (ONIP) and Booz & Co, concludedthat the domestic supply chain will receive investments ofUS$400bn through 2020. This raises deeper concerns aboutpossible bottlenecking or overheating.This pressure has become more intense as Petrobras isasked to move swiftly to high levels of local content on ahuge domestic rig-building programme. Hydrocarbonsregulator ANP is beginning to enforce local content rulesunder oil and gas concessions more vigorously, affectingPetrobras but also the estimated US$33bn that internationaloil companies will invest in the Brazilian oil sector over thenext five years. Brazilian authorities are working hard to meetthe challenges. Flexible and cheaper new lines of credit arebeing made available to suppliers through the NationalDevelopment Bank (BNDES) and an innovative onlinefinancing mechanism offered by five leading banks. A hostof new private equity funds have been springing up in Brazilto help fill the gap. Brazil is already seeing a big expansion insupply chain investments, including new shipyards such asEstaleiro Atlantico Sul and Estaleiro Rio Grande.Teething problems are not hard to detect, with delaysaffecting the construction of these yards and, as aconsequence, the first wave of contracts. A chorus ofcomplaints can be heard industry wide about skills shortagesand predatory hiring of technically-qualified professionals.Brazilian officials and optimistic industrialists insist thata combination of Petrobras’s contracting zeal, heavyinvestments in automated production and governmentcoordinated training programmes will ensure that Brazil willbuild up toward the kind of productivity that will underpinlong term survival. The extremely negative reaction to thePetrobras re-financing seems to have run its course andinvestors are harking back to the fundamentals that drewthem so strongly to Petrobras three years ago. •Energy Solutions For All 101

InnovationPost-Macondo reforms: Thenew regime in US watersBy Michael R Bromwich, Director, US Bureau of OceanEnergy Management, Regulation and EnforcementIn June 2010, President Barack Obama and Secretary ofthe Interior Ken Salazar asked me to serve as directorof the US Bureau of Ocean Energy Management,Regulation and Enforcement (BOEMRE), the agencyresponsible for regulating offshore drilling and productionin US waters, and the successor to the MineralsManagement service (MMS), which had been responsiblefor those functions since the early 1980s. Our mandate waschallenging, ambitious and above all urgent – to reformoffshore energy development and the agency responsiblefor overseeing it.Two months earlier, the Deepwater Horizon drilling rig hadexploded, taking the lives of 11 workers and unleashingnearly 5 million barrels of oil into the Gulf of Mexico. Thetragic loss of life and the enormous environment damageresulting from the Deepwater Horizon tragedy transformedthe unthinkable into the actual; it served as a wake-up callfor industry and government alike.Since that time, we have been working diligently andaggressively to make the changes necessary to restoreconfidence that offshore oil and gas drilling and productionare being conducted safely and with appropriateprotections for marine and coastal environments.Strengthening regulationsOne of the first challenges was to strengthen the rules andregulations governing offshore drilling in US waters. Thoserules and regulations had not been adequately revised andupdated to address some of the challenges of offshoredrilling, especially in deep water. We promptly recognisedthe need to identify and examine improvements to drillingand workplace safety and to enhance protection of themarine environment.BOEMRE swiftly developed and implemented a numberof new rules to improve the effectiveness of governmentoversight of offshore energy drilling and production.The first rule, the Drilling Safety Rule, created tough newstandards for well design, casing and cementing, and wellcontrol procedures and equipment, including blowoutpreventers. For the first time, operators are now requiredto obtain certification by a qualified engineer of theirproposed drilling process. In addition, an engineer mustcertify that blowout preventers meet tough new standardsfor testing and maintenance and are capable of severingthe drill pipe under anticipated well pressures.A second rule, known as the Safety and EnvironmentalManagement Systems (SEMS) Rule, requires operatorsto systematically identify risks and establish barriers tothose risks. It seeks to fundamentally reduce the humanand organisational errors that lie at the heart of manyaccidents and oil spills. The SEMS Rule, sometimesreferred to as the Workplace Safety Rule, introduced, forthe first time in the US regulatory regime, performancebasedstandards similar to those used by regulatorsin the North Sea. US operators are now required todevelop a comprehensive safety and environmentalmanagement programme that identifies the potentialhazards and risk-reduction strategies for all phases ofactivity, from well design and construction, to operationand maintenance, and finally to the decommissioningof platforms.A second proposed SEMS Rule will require third-partyaudits of operators’ mandatory SEMS programmes andaddresses additional safety concerns that were not coveredby the initial SEMS rule. The proposed rule will enhancesafety for offshore workers and provide greater protectionof the marine environment through additional safetyprocedures, training programmes, notification obligationsand strengthened auditing procedures.In addition to these important new rules, we haveissued Notices to Lessees (or NTLs) that provide additionalguidance to operators on how to comply with existingregulations. In June 2010, we issued NTL-06, which requiresthat operator’s oil spill response plans include a wellspecificblowout and worst-case discharge scenario – andthat operators provide the assumptions and calculationsbehind these scenarios. Our engineers and geologiststhen independently verify these worst case dischargecalculations to ensure that we have an accurate picture ofthe spill potential of each well.Following the lifting of the deepwater drilling moratoriumin October 2010, we issued NTL-10, a document thatestablishes informational requirements, including amandatory corporate statement from the operator thatit will conduct drilling operations in compliance with allapplicable agency regulations, including the new DrillingSafety Rule. For the first time, this includes a review of anoperator’s subsea blowout containment resources fordeepwater drilling,We have also identified the need for the thoughtfulconsideration, development and implementation ofadditional rules designed to further enhance offshoredrilling safety. This process will be broad and inclusive, withthe goal of increasing drilling safety and diminishing the10220th World PETROLEUM Congress

Innovationrisks of a major blowout. It will address improvements toblowout preventers, as well as many other issues.By the time the World Petroleum Congress meetsin Doha, we will have completed a top-to-bottom,comprehensive reorganisation of MMS, or MineralsManagement Service which was the predecessor toBOEMRE. The reorganisation and internal reforms that wehave implemented were designed to recognise the diverseand sometimes conflicting responsibilities of the formerMMS by thoughtfully separating these missions into threenew agencies and providing each of the new agencieswith clear definitions of their respective missions and – forthe first time – needed new resources to adequately fulfilthose missions.These functions will now be carried out by three separateagencies within the Department of the Interior. The Bureauof Ocean Energy Management (BOEM) will manage thedevelopment of the nation’s offshore resources in anenvironmentally and economically responsible way; theBureau of Safety and Environmental Enforcement (BSEE)will enforce safety and environmental regulations offshore;and the Office of Natural Resources Revenue (ONRR),which has been operating separately from the rest of theagency since October 2010, will be responsible solely forcollecting revenues from offshore leases.Weaknesses of the past addressedBut organisational changes alone are not enough toaddress the institutional weaknesses of the past. That iswhy we have taken a large number of important steps tostrengthen key functions. This includes our environmentalenforcement function, our inspections programme, andthe way the agency deals with conflicts of interest.• Strengthening Environmental Enforcement: First, wehave taken a number of steps to strengthen the role ofenvironmental analysis and enforcement in the newregulatory framework. We have created the new positionof Chief Environmental Officer in BOEM to provideinstitutional assurance that environmental considerationswill be given adequate weight in resource developmentdecisions. These decisions include five-year plans, leasingdecisions, exploration and development plan reviews,and other decisions that bear on resource management.In BSEE, we are creating a dedicated environmentalenforcement and compliance programme. Historically,with very limited resources, our personnel have attemptedto determine whether operators have fulfilled theirenvironmental commitments – in the form of stipulationsand mitigations to minimise the adverse impact ofoperations to the environment. But the agency has neverbefore had personnel specifically dedicated to that task.• Improving Inspections: In addition to strengtheningthe role of environmental analysis and enforcement,we have also taken a number of steps to improve ourinspections programme. We will begin to use multiplepersoninspection teams for offshore oil and gasinspections. The new process will allow teams to inspectmultiple operations simultaneously and thoroughly andwill enhance the quality of inspections on larger facilities.In addition, we are creating for the first time a NationalOffshore Training Center led by a training director whomwe selected after a nationwide search. The Director of theNational Offshore Training Center will develop nationaltraining strategies, curricula and programmes to maintainand improve the technical capabilities of offshoreinspections and compliance personnel throughout thebureau. This will be a dramatic improvement. In the past,our inspectors have learned how to do their jobs througha combination of on-the-job training and industrysponsoredcourses aimed at teaching how certain typesof equipment function. The agency has never had atraining centre dedicated to training inspectors on howto do their jobs. Now we will.• Addressing Conflicts of Interest: We are also taking stepsto address conflicts of interest within the agency. Wehave issued a rigorous recusal policy that will reduce thepotential for real or perceived conflicts of interest in ourenforcement programmes. Under the policy, employeesin our district offices, including our permitting engineersand inspectors, must notify their supervisors about anypotential conflict of interest and request to be recusedfrom performing any official duty where such a conflictexists. As a result, our inspectors are required to recusethemselves from performing inspections of the facilitiesof former employers. Also, our inspectors must report anyattempt by industry or by other BOEMRE personnel toinappropriately influence, pressure or interfere with his orher official duties. A recent internal review demonstratedapproximately 50 instances of our inspectors recognisinga conflict barred by the policy and taking appropriateaction to recuse themselves. That is an important stepin assuring the public that our oversight and regulatoryresponsibilities are being carried out in a disinterested andobjective manner. →Energy Solutions For All 103

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InnovationPromoting offshore safety throughinternational collaborationAn important element of our long-term strategy isto maintain and strengthen collaboration with ourinternational counterparts. Offshore regulators and seniorpolicy officials have much to gain from collaborating withtheir counterparts in other countries to elevate the safetyand environmental soundness of offshore operationsaround the world. To this end, in April 2011, the Departmentof the Interior hosted ministers and senior energy officialsfrom twelve countries and the European Union for aMinisterial Forum on Offshore Drilling Containment. Thiswas a historic meeting for the Department – and it led toa fruitful dialogue about best practices and how best todevelop cutting edge, effective safety and containmenttechnologies. The meeting concluded with the unanimousrecognition that this dialogue should continue at thehighest levels of government.We also continue our work to strengthen existingchannels for international cooperation and the sharingof best practices across different regulatory regimes. Forexample, we will continue our participation with theInternational Regulators Forum (IRF), an organisationthat BOEMRE helped to found in 1994 to facilitate thecooperation and sharing of information among theleading offshore regulators. I attended the recent Forumin Norway, and am looking forward to the important rolethat BSEE will play in the IRF.The United States will continue to participate in anumber of government-to-government initiatives to sharebest practices and build regulatory capacity in countriestrying to develop offshore drilling regulatory regimes.Our experts have participated in needs assessments andhave conducted workshops in Suriname, Uganda, PapuaNew Guinea, and Liberia. We will also continue our longtermtechnical assistance with the governments of Iraqand India. This past summer, we hosted a delegation fromMexico for the first of a series of information exchangeworkshops to fulfil the Secretary’s mandate for developingthe highest standards for operating in the Gulf of Mexico.We will continue to collaborate with our foreigncounterparts, both through bilateral governmentto-governmentassistance programmes and throughappropriate multilateral channels, in developing safer,more environmentally responsible drilling in the world’soceans.The Future of offshore drilling in USwatersOffshore drilling in the United States, and indeed aroundthe world, will never be the same as it was a year ago.That much is clear. The changes that we have put in placewill endure because they were urgent, necessary andappropriate. And more change will surely come, althoughnot at the rapid pace of the past year. The process of makingoffshore energy development both safe and sufficient tohelp meet the nation’s and world’s energy demands willnever be complete. It is – and must be – a continuing,ongoing, dynamic enterprise.The central challenge that Deepwater Horizonhighlighted is the need to establish the institutions andsystems – and the processes of cultural change andimprovement– necessary to ensure that neither governmentnor industry ever again become so complacent that theythink no further change is necessary – because that sort ofcomplacency set the stage for Deepwater Horizon.Following Deepwater Horizon, a broad consensusquickly emerged – in government and industry – thatthere was an urgent need for upgrading safety rules andpractices within the offshore oil and gas industry. As wemove forward, we must do everything possible to keepthe complacency from creeping back. We must have thediscipline to continue pushing for improvements that willenhance the safety of offshore drilling. Both industry andgovernment regulators must continue to use the memoryof Deepwater Horizon as a constant reminder of thecontinued urgency of improving safety. •Energy Solutions For All 105

InnovationThe potential in Russia’snew energy frontiersBy Professor Anatoly ZolotukhinGubkin Russian State University of Oil and GasRussia is believed to be one of the richest countriesin the world with its vast oil and gas resources.According to the recent data, its reserve baseamounts to 96 billion tons of oil equivalent (btoe)which is nearly 700 billion barrels of oil equivalent. Theoffshore part of the reserves, defined as what is recoverableunder current economic and technical conditions, is lessthan 10 per cent. Russia’s total resource base is severaltimes larger and is estimated to be 259 btoe (1,890 bboe),and of this amount the offshore part is 96 btoe, or 37 percent. This gives a total estimate of 355 btoe for so-calledconventional hydrocarbons and as shown below.The Russian Arctic is believed to be the area with thehighest unexplored potential for oil and gas as well as forunconventional resources such as natural gas hydrates.Despite a common view that the Arctic has plentifulhydrocarbon resources, there are ongoing debatesregarding the potential of this region as a future energysupply base, raising issues of geopolitics and environmentalconcern as well as assessment and delineation of Arcticresources and the technology and market demand fordeveloping them. However, scarce information andgeological data create uncertainty about the Arctic asmain base of Russia’s energy supply in the second half ofthis century. A further uncertainty is the pace at whichproduction from northern areas including the Arctic, willbe brought onstream – either because of national policy,infrastructure development or investment by the stateand the oil companies. These areas embrace those whereVolga-UralEast SIberiaKhMAOShelvesYaNAO0Russia’s conventional hydrocarbonreserves and resources20 40 60 80 100 120 140Billion toedevelopment has already been started (offshore Sakhalin,northern Timan Pechora) and those awaiting futuredevelopment such as the Barents and Pechora seas, EastSiberia, Yamal, Kara Sea and Kamchatka.The following sections will briefly describe the statusand future prospects in the exploration and developmentof these areas and challenges associated with them.The Northwest of the Russian ArcticThere is a common view that shelves of the Barents, Karaand Pechora seas are considered as the most prospectiveareas for offshore oil and gas field development.Barents and Pechora seasWith almost 31 btoe of oil and gas resources, the Barentsand Pechora seas represent one of the most attractiveareas of the petroleum resources development.So far two gas-condensate fields – Shtokmanskoyeand Ledovoye, and three gas fields – Ludlovskoye,Murmanskoye and North-Kildinskoye have beendiscovered in the Barents Sea. Potentially interestingstructures have been detected in the Fersman-Demidovshoulder, Shatsky and Vernadsky swells, and also in thearea of Medvezhy and Admiralteisky swells.The former “Grey zone”, which was disputed betweenNorway and Russia, has a high potential in the area of FedynskySwell and East-Barents foredeep where quite a number ofstructures are very prospective for both gas and oil.Up to the present time oil has not been discovered inArctic seas except the Pechora Sea, thereforethese locations, including Admiralteiskyswell, are of particular interest.It is anticipated that development of theBarents Sea will start from the Shtokmanfield, which later will be accompanied by thesatellite fields of Ledovoye, Ludlovskoye andTerskoye and later by the fields of the Fersmanand Demidov swells. This concept will enableutilisation of available infrastructure so as toreduce investment costs.The 2010 Norwegian-Russian agreementon delimitation of the Barents Sea can spura new round of active cooperation betweentwo countries on the development of Arcticresources. The new agreement opens newopportunities for active cooperation indeveloping this strategically importantReserveResources10620th World PETROLEUM Congress

Innovationregion. Possible large accumulations of petroleumresources in the delineated zone are located closer to theshoreline than the Shtokman field, and this may facilitatea new concept of the whole Barents region development.The shelf of the Pechora Sea is the only one among all theArctic shelves where the oil has been discovered. The mainfields of this region are the Prirazlomnoye, Dolginskoye,Medyn-more, Varandey-more and Kolokomorskoye oilfields, the Severo-Gulyaevskoye oil-gas-condensate fieldand the Pomorskoye gas-condensate field. Besides thesefields there are several large and prospective structureslocated in the south eastern part of Pechora Sea:Yuzhno-Russkaya, Pakhanchevskaya, Sakhaninskaya andPapaninskaya. According to the estimates, total resourcesof the Medyn-Varandey and Kolokomorsky structuresamount to 410 million tons of oil with a recoverable volumeof 80 million tons. It is planned that the Prirazlomnoye fieldwill start the oil production in the Pechora Sea followed bydevelopment of other fields.Kara Sea discoveriesSource: Sherpa Konsult, 2010Kara SeaThe Kara Sea with its 37.4 btoe reserves, of which around75 per cent is gas, is believed to be a sea with the largestpetroleum resources. In the Kara Sea, shelf prospectivelocations are the Yamal shelf with its Leningradskoye andRusanovskoye fields as well as offshore extension of theKharasaveyskoye and Kruzenshternskoye fields. Anotherattractive location is Ob (Severo-Kamennomysskoye,Kamennomys-skoye-more and Obskoye fields, aquatorialextension of Yurkharovskoye, Salekhaptskoye, Yuzhno-Tambeiskoye, Utrennee and Tasiiskoye fields) and Tazov(Chugoriakhinskoye field and aquatic extension ofSemakovskoye, Antipayutinskoye and Tota-Yakhinskoyefields) bays.According to the estimates, gas production from theKara Sea shelf area may reach up to 200 billion cubicmetres (bcm) annually, which could compensate for thedecline in production from fields in Yamal peninsula andenable utilisation of available infrastructure.Ob and Tazov bay areasThe Ob and Tazov bays, now being actively explored,have emerged as another very attractive area of futurepetroleum production with a lot of already discoveredfields and potential structures. According to the estimates,gas fields of the Ob and Tazov bay areas could produce gaswith the annual rate of 75 bcm.Offshore Sakhalin and Caspian Sea areasAccording to Russia’s energy strategy, offshore fieldsshould annually produce around 220-230 million tons ofoil equivalent, and by 2030 up to almost 300 mtoe. It isanticipated that nearly half of that amount will come fromthe Sakhalin and Caspian offshore regions alone.Recoverable petroleum resources of the Sea of Okhotskincluding offshore Sakhalin area amount to 8.9 billion tonsof oil equivalent. Caspian recoverable resources comprisenearly 3.5 btoe. Active exploration programmes withdynamic production growth in both areas maintained byexperienced and internationally recognised companiesgives confidence that this target will be reached.Potential of West and East SiberiaIs there an alternative to the development of oil and gasfields located in the untapped Arctic offshore areas? Thedevelopment of Arctic resources is inevitable althoughthere is no time pressure in doing that right away. Russia hasabundant petroleum resources onshore with technologyfor safe and efficient development available now. There →Energy Solutions For All 107

Innovation→ are two regions, namely, Nadym-Tazov and Krasnoyarskregions that could easily maintain production at requiredlevel on a mid-term and even on a long-term basis andthus, postpone development of the Arctic resources of theYamal peninsula and the northern seas.The Nadym-Tazov region is a new hub of hydrocarbonaccumulations in West Siberia. Recent estimates showedthat this region has potential gas resources up to 20 trillioncubic metres (tcm). Its proximity to the Yamburg gascondensate field with developed infrastructure and withgas pipeline exporting gas to Europe, makes developmentof this region very attractive both technologically andcommercially. According to estimates made by VNIIGAZ(Gazprom’s R&D institute) a high level of production (up to15 bcm per year) can be reached already in the third yearof development.Fields and potential structures ofthe Ob and Tazov bay areaThe second potentially large centre of petroleumproduction is associated with the Baikal region ofhydrocarbons accumulation, which is accessible forindustrial development. According to resource evaluationreported in 2003 , recoverable reserves of oil and gas inthis region amount to 35-45 btoe (approximately 30 percent of which are liquid hydrocarbons). The largest field ofthis region – the Kovyktinskoye gas condensate field withestimated in-place volume of two tcm (with an upsidepotential of up to 10 tcm) could serve as a starting pointfor such a development.Although East Siberia is characterised by the highestreserve replacement ratio, capital investments in thearea need to be almost twice as big as in traditional oilproducingregions, due to the lack of infrastructure and thedistance to the market. For example, one of the key EastSiberian projects, Vankor (developed by Rosneft) is located1,500 km from Krasnoyarsk, the main transportation hub inthis region. Severe climatic conditions limit construction toaround 100 days per year.One can conclude that these large scale projects in newoil and gas regions, like West and East Siberia, the Far Eastand Arctic offshore will provide the reserves to sustainRussian output. According to future planning by 2020Russia should annually produce 1,300-1,350 mtoe, andby 2030 1,415-1,475 mtoe. The offshore share of Russianproduction will grow from around 17 per cent in 2020to more than 20 per cent by 2030. It is anticipated thatnearly half of that amount will come from the Sakhalin andCaspian offshore regions, while the other 50 per cent willbe delivered by the Russian northern seas.However, lack of infrastructure limits the attractivenessfor companies. Development of resources of the northernseas is additionally complicated by the lack of technologyand qualified personnel, operational and environmentalproblems and higher cost. In order to meet this challengea state-coordinated exploration programme is required,with the close cooperation and participation of theinternational community.A stable, transparent and predictable legal frameworkwill be needed for the massive investments required inexploration and production, and for the active involvementof foreign companies, bringing with them indispensablecompetence, experience, technology and health, safetyand environment principles. But Russia’s resources willbe important to sustain oil and gas supplies to westernEurope and the Asia-Pacific region.•10820th World PETROLEUM Congress

RWE DeaSUCCESS THROUGHINTERNATIONAL OPERATIONS.RWE Dea is a top-performing company for the exploration and production of natural gas andcrude oil, operating on an international scale. Exploration expertise, state-of-the-art drilling andproduction technologies and a diverse range of professional experience and know-how acquiredin 112 years of corporate history make RWE Dea a powerful company engaged in numerousoperations at home and abroad. Safeguarding energy supplies, environmental protection andresponsible decommissioning are key objectives. RWE Dea is part of the RWE Group - one ofEurope‘s biggest energy corporations.RWE Dea currently gives proof of this high standard upstream activities in Algeria, Denmark,Egypt, Germany, Ireland, Libya, Mauritania, Norway, Poland, Trinidad & Tobago, Turkmenistanand the United Kingdom – day-to-day.In light over ever-higher global demand and in an effort to expand its international upstreamposition, RWE Dea follows a distinctive growth strategy and is investigating further businessopportunities worldwide.RWE Dea AG l Überseering 40 l 22297 Hamburg l GermanyT +49(0)40 - 63 75 - 0 l E info@rwedea.com l I www.rwedea.com

InnovationThe promise and the problemsof developing the ArcticBy Kieran Cookeeditor, Arctic MonitorEnvironmentalists rail against it. Oil, gas and miningcompanies, shippers and some governments in theregion insist on it happening. People who live thereare in two minds about it all.Resource development in the Arctic – whether it is oiland mining exploration or the expansion of shipping andother services – provokes widely differing emotions. Theoil industry says with an estimated quarter of the world’sas yet undiscovered hydrocarbons likely to be in the Arcticregion, the case for exploration is overwhelming. So alsosay the mining companies: whether it is uranium, ironore, gold or rare earths, the Arctic has massive amounts ofminerals the world urgently needs.Shipping operators, particularly those in Russia, sayroutes through the Arctic seas represent a much shorterand ultimately cheaper way of shipping goods betweenthe Americas, Europe and Asia. Governments in the regionare busy staking claims to vast swathes of ice and ocean inthe face of a regional race for resources.The relatively small but widely diverse populationliving across what’s often referred to as “The High North”are well aware of both the positives and negatives of therush for resources.“Arctic peoples are caught in a bind” says Minik Rosing,a native Greenlander who is a professor of geology atthe University of Copenhagen. “On one hand resourcedevelopment offers the chance of more personal wealth andpolitical independence. But it also threatens to overwhelmus and change our environment and culture for ever.”Environmentalists show no such ambivalence. Theexploitation of fossil fuels has led to changes in climate andthe melting of Arctic ice. Exploration companies are nowrushing in to the region to exploit yet more fossil fuels, onlyadding to climate change problems. “It’s madness” says acampaigner at Greenpeace, the environmental NGO. “Youdon’t put out a fire with gasoline.”Climate Change and the ArcticThere appears to be little doubt that the pace of Arcticwarming is speeding up: According to the latest reportof the Arctic Monitoring and Assessment Programme, aworking group of the Arctic Council, the warming trend inthe Arctic has been twice the global average since 1988.Arctic winter ice seasons are becoming shorter while seaice in the Arctic summer has retreated to its lowest levelssince satellite measurements began in 1979.“The clarity of that trend is very striking” says SebastianGerland, a sea ice expert and one of the report’s contributors.The report also found that the Greenland ice sheet –covering an area of more than 650,000 square miles – ismelting at a very fast rate. While this could mean rising sealevels and be bad news for much of the planet, it does, onthe face of it, seem to be good newsfor the exploration industry.Oil and gasIn the most comprehensiveestimate of Arctic hydrocarbonreserves to date, in 2008 the USGeological Survey (USGS) said therewere likely to be 90bn barrels ofundiscovered and recoverable oilacross the region along with morethan 1,650 trillion cubic feet ofnatural gas – enough respectivelyto meet three and 14 years ofworld demand at present levelsof consumption. More than 80per cent of the hydrocarbons areoffshore in waters of less than 500metres, making them, said theUSGS, accessible to drilling.Longer Arctic summers and less11020th World PETROLEUM Congress

Innovationsea ice means more time and opportunity for offshoredrilling activities. Cairn, the Scottish based explorationbusiness, is the only company so far to have reportedevidence of hydrocarbon findings offshore in the morewesterly Arctic region. In summer 2010 it found indicationsof hydrocarbons off Greenland, and the company hasbeen drilling again in 2011. Other companies includingShell, ConocoPhillips and Statoil of Norway have alsobeen given offshore drilling licenses by the Greenlandgovernment.Elsewhere Shell, BP and other oil majors are busy applyingfor licenses to drill in offshore Alaska: Shell has submittedplans to the US authorities for drilling 10 exploration wellsin the Chukchi and Beaufort seas in the summers of 2012and 2013. In the Barents Sea off northern Norway – dividedwith Russia – Statoil has made what it says are commercialoil finds. A number of other international oil companiesare now either already drilling or applying for licenses inthe area.Russia has been among the most bullish of the Arcticcountries in wanting to press ahead with Arctic oil andgas exploration. With fields in western Siberia expectedto contribute less to Moscow’s oil revenues in futureyears, the big prize is considered to be oil and gas inRussia’s far north – in the Kara and Barents seas. Moscowis making long term plans for exploration in the region.Eight floating nuclear power stations are at present underconstruction in St Petersburg: the plan is to position themalong Russia’s north coast in order to supply power tocommunities in the area and to onshore and offshoreexploration activities.Exploration obstaclesOne of the main problems in the region relates to whoowns what. When Artur Chilingarov, a veteran Russianpolar explorer, placed a Russian flag on the sea bedbeneath the North Pole in 2007, it caused considerableconcern round the region. Though Vladamir Putin, Russia’sprime minister, insists the Arctic should be a region “forcooperation and dialogue,” Moscow claims sovereigntyover vast tracts of the region’s ocean bed. The US,Canada, Norway and Denmark – Copenhagen controlsGreenland’s foreign policy – also have competing claimsin the region. Other countries and groupings – includingChina, India and the European Union – are trying toensure their interests are safeguarded. Analysts point toevidence of a regional military build-up.“For now, the disputes in the north have been dealt withpeacefully” says Admiral James G Stavridis, NATO’s supremeallied commander for Europe. “But climate change couldalter the equilibrium over the coming years in the raceof temptation for exploitation of more readily accessiblenatural resources.”There are also great technical challenges. Equipment isseverely tested in such extreme conditions. There is a lackof infrastructure – and lengthy supply lines. Recent rises inoil and gas prices have cushioned the expense of operatingin the Arctic but the need for environmental safeguards isincreasing costs. In the aftermath of the Gulf oil disaster it’snot just environmentalists who are concerned about howan oil spill, possibly beneath the ice, could be contained inArctic waters. There is a great deal of official nervousnessas well: Shell and other oil companies have had theirlicense applications for drilling offshore Alaska repeatedlyscrutinised by US authorities.Though Russia is considered to have less stringentconditions governing Arctic resource exploitation, itsexploration ambitions are limited by a lack of expertise,particularly in offshore drilling operations. Russianexploration companies are keen to link up with overseasgroups, as in the case of the proposed partnership betweenRosneft and ExxonMobil.Climate change also poses considerable challenges tothe exploration industry: weather patterns are likely tobecome more unpredictable. More icebergs calving offglaciers are likely to pose increasing dangers to oil and gasrigs operating in the region. They will also threaten bothexisting and new shipping lanes.Meanwhile environmental groups are mounting anincreasingly militant campaign against the whole ideaof drilling in the Arctic. Cairn’s operations off Greenlandhave been a frequent target of protesters. Local groups inCanada and Norway are voicing concerns that drilling willadversely impact fisheries and threaten livelihoods.The Arctic does hold out great resource exploitationpossibilities. It is one of the last great untapped areason earth – but it is also one of the most fragile ofenvironments. The Arctic and its complex weathersystems is often referred to as the world’s air conditioner,its waters and winds responsible for cooling down greatswathes of land and ocean. Many exploration companiesare learning that they have to tread carefully: if not,reputations and finances will suffer – and environmentaldisaster could follow. •Energy Solutions For All 111

Innovationtechnology allows us to get the most energy out ofevery barrel of bitumen.Our next oil sands project, known as Kinosis, is expectedto develop a thick, superior quality reservoir starting withtwo smaller in-situ projects – each with a capacity of 40,000bpd. We anticipate approving Kinosis in 2012. Nexen alsoholds a 7.23 per cent interest in the Syncrude CanadaLtd. joint venture that has been mining shallow oil sandsdeposits since the mid-1970s, and is Canada’s largest oilsands operation.The economics of developmentOne of the great advantages of Canada’s oil sands is that thereserves are clearly identified and understood; we knowexactly where the bitumen is, so exploration costs are verylow. This allows the industry to approach production as asteady and reliable manufacturing process – and there isenough supply to keep the “oil sands factory” running fora century or more.Another significant advantage is that the oil sandsdeposits are located in a province, and a country, that isvery appealing to investors due to the combination ofdemocratic traditions, an open economy and a strongrecord of regulatory and environmental oversight (Albertais the only jurisdiction in North America to mandateindustrial greenhouse gas emission reductions). ProducersUnited States and close to half the crude exported is fromthe oil sands. With the right planning and infrastructure,oil sands crude also has the long-term potential to helpsupply energy-hungry Asian markets.But oil sands development also faces some significantchallenges. This is a very capital-intensive industry; atypical in-situ or mining project can take several yearsto move from conception to completion and requiresbillions of dollars in upfront investment. Success dependson superior planning and execution, and the ability towithstand inevitable fluctuations in commodity markets.As a result, many companies have entered strategicpartnerships. For example, the Syncrude joint ventureallows the various owners to mitigate economic risks bycost sharing on infrastructure development as well as thetechnological expertise essential to achieving sustainableenergy development.Responsible developmentThe biggest challenge is managing the environmentalimpact of oil sands development. The industry is energyintensiveand water-intensive and involves significantland disturbance. But while some industry critics havebeen quite vocal in labeling oil sands crude as “dirty oil,” thereality is much less sensational. For example, independentstudies show that oil sands crude is not significantly morecarbon intensive than other North American crude oil →and governments alike remain focused on the goal ofresponsibly developingthe oil sands to provide theenergy our economy – andCanada’s GHG emissions by sectorthe world – requires.All of this helps explainwhy the Canadian EnergyResidential - 5.9%%Research Institute (CERI)recently projected thatManufacturing, Commercialsome US$ 2.07 trillion willand Construction - 11.5%%be invested in building andmaintaining the oil sandsover the next 25 years. CERIalso predicted industry-wideoil sands production willramp up from the current1.7 million bpd to 2.1 millionElectricity andHeat Generation - 14.2%bpd by 2015 and 4.9 millionbpd by 2035.Canada is already theOther Fossil Fuel - 16.1%%%largest energy supplier to theTransport - 27.5%Industrial Processesand Waste - 9.9%%Agriculture and Forestry - 8.4%%Oil Sands - 6.5%%Source: Environment Canada – National Inventory Report 1990-2009Energy Solutions For All 113

Innovation→ imports on a “wells-to-wheels” life cycle basis. Similarly,the oil sands industry is currently responsible for 6.5 percent of Canada’s total greenhouse gas (GHG) emissions –far less than the transportation (27.5 per cent), electricity(14.2 per cent) or manufacturing and heavy industry (11.5per cent) sectors.Moreover, whether it is emissions, water use or landdisturbance, the oil sands industry has acted decisivelyto carry out continuous improvements in environmentalperformance. By harnessing technology, the industryhas virtually eliminated sulphur dioxide emissions whilereducing GHG emissions intensity (the amount of GHGemitted for each barrel of oil produced) by 39 per centcompared to 1990 levels. Oil sands producers recyclebetween 80 per cent to 95 per cent of water used and haveinvested billions of dollars in technology to significantlyaccelerate the pace of tailings ponds and land reclamation(companies are required to restore all disturbed lands to asustainable landscape that is equal to, or better than, itsoriginal state).As Canada’s oil sands industry grows, more must bedone to manage the cumulative impacts of development.To address this, five like-minded oil sands operators,including Nexen, have teamed up to form the Oil SandsLeadership Initiative (OSLI). Each company is providingresources, sharing best practices and working togetheron potential technological breakthroughs to advancesustainable development. The other OSLI participants areConocoPhillips Canada, Suncor, Statoil Canada and TotalE&P Canada.Recent initiatives undertaken by OSLI include advancingresearch into making in-situ oil recovery more energyefficient(a key step to better managing GHG emissions);testing technologies to allow one oil sands operator totake another operator’s tailings wastewater, treat it, andthen reuse it; and collectively planting new trees (600,000to date) across the oil sands region to improve forest coverand better protect woodland caribou from predators.Nexen, along with other oil sands developers, remainscommitted to working with all stakeholders – includinggovernments, non-government organisations,academic researchers, communities and consumers –to seek long-term solutions to environmental and socialchallenges.The oil sands industry is strongly positioned to deliverthe energy our growing economies require in the yearsand decades ahead. It is no silver bullet for meetingglobal energy demands but – in tandem with theresponsible development of a range of conventional andunconventional energy sources – Canada’s oil sands canplay an important role in creating the sustainable energyfuture we all desire.•Total bitumen production (‘000 b/d)6,0005,0004,0003,0002,0001,000Source: OCERI02010201120122013201420152016201720182019202020212022202320242025202620272028202920302031203220332034203511420th World PETROLEUM Congress

It starts with total cooperation.It evolves via nonstop innovation.It produces far greater rewardsfor you.It is your new or mature field. Almost without exception, realizingyour field’s economic potential now takes far more than service-company“business as usual.” It requires extraordinary collaboration, boldtechnology investment, ceaseless innovation, and a powerful holisticapproach that consistently produces greater returns while betterprotecting the environment.You have challenges. Halliburton has what it takes to meet them.Visit us at www.halliburton.com.Solving challenges. HALLIBURTON© 2011 Halliburton. All rights reserved.

InnovationThe power of integration toproduce ingenuity at speedBy John McDonaldVice President and Chief Technology Officer, Chevron CorporationThe ancient Greek mathematician Archimedeswould have loved the modern energy industry.In oil fields dotted with pumpjacks, he wouldrecognise familiar principles of leverage from hisingenious catapult designs. His water-lifting device, theArchimedes’ Screw, revolutionised irrigation and in amanner, evolved through the ages to ultimately give riseto an enormous variety of positive displacement pumpsand compressors. Today, we depend on compressionto do everything from pipeline transport to enhancedoil recovery – and more recently, hydraulic fracturing, atechnology having demonstrated the potential to unlocksignificant new energy supplies.Past generations of technologists, including Archimedes,have given our industry many gifts and have allowedus to achieve our present state – ingenuity at speed.Of course, they faced problems we can’t imagine – norcould they have imagined ours. For example, increasingand diversifying the world’s energy supply in support of 9billion people will no doubt be a monumental challenge.The International Energy Agency forecasts that globaldemand will increase 40 per cent by 2035. Clearly, we’llneed more of every type of energy, especially oil andnatural gas.Ingenuity and integrationThroughout history, the inexhaustible resources of humanenergy and ingenuity have enabled us to do more, and todo it faster with less effort. The energy industry continuesto build on this heritage of technology developmentand deployment. One of the greatest strengths of aninternational oil company (IOC) is integration: linkingtechnologies, knowledge and worldwide experienceto help create the reliable, safe, efficient and affordableenergy supply that fuels human progress.Today, digital technologies and new, efficient processesare transforming our workflows. They are empoweringus to apply our best minds to the toughest challengeseverywhere in the world, and to rapidly integrateinformation and innovate at speed. We connect surfaceto subsurface, past to present and present to future,predicting and optimising performance in reservoirs,wells and facilities measured and monitored in real time.This 21 st century capability will ensure that IOCs andproducing countries will continue to open new frontiers,raise performance to new levels and meet the world’senergy needs.From ramps to robotsHow do we know ingenuity will prevail in meeting theenergy supply challenge?Consider our evolutionary advance into the offshore:To monitor the first near-shore wells over 100 years ago,we walked on wooden piers, while today, we use robotic,remote, autonomous underwater vehicles to monitorsubsea deepwater wells and facilities.The evolution into the deep continues. Facing theincredible pressures inherent in deep water activities, wehave found a way to remove water depth as a pressurerelatedissue. To improve safety and reliability under extremedeepwater conditions, we have been developing and willsoon deploy “dual-gradient drilling.” This technology willsignificantly reduce deepwater drilling costs and improveoutcome predictability. A dual gradient system, in effect,makes the deepwater well comparable to a land well.Some of the tools we rely on today had theirbeginnings before recorded history. Without theinnovations of metallurgists through the centuries,for example, the progression towards sophisticatedalloys used in modern tubulars would not exist. Today,these materials make most of the world’s deepwater oilindustry possible. During the next decade, deepwaterproduction could grow to more than 10 million barrelsper day, according to IHS CERA. Corrosion-resistanttubulars and components also make possible all ofthe world’s sour (high H 2S content) gas production,including growing output from Kazakhstan’s giantTengiz Field and new energy from Chuandongbei, a gasproject in China being developed by a partnership ofChevron and the Chinese National Petroleum Company.It is unlikely that the first metallurgists could haveenvisioned the extension of their technologies to helpenable the Gorgon liquefied natural gas (LNG) project inWestern Australia. This project will significantly enhanceAsia-Pacific LNG supplies while re-injecting much of itscorrosive, produced CO 2into the ground with the largestgreenhouse gas storage project of its kind in the world –enabled by both metallurgy and compression.Measuring time – simulating the futureOne does not think of the hourglass, an ancient invention,and the seismic geophone as related, but in fact both recordtime. By continuously improving our ability to measure thetime required for sound to travel through rock, we are findingnew supplies and recovering more by optimising reservoir11620th World PETROLEUM Congress

Innovationmanagement. Advances in seismic data processing usingGaussian Beam pre-stack depth migration have allowed usto “see” into the past, deep into the subsurface, often belowvolcanics and salt layers. Without this technology, Chevronand others might never have discovered many of thedeepwater fields now contributing significantly to energysupplies around the world.With “4D” or time-lapse seismic, we can measure changein reservoirs and predict behaviour and response. Ourreservoir simulators and predictive tools allow us to travel“virtually” into the future, testing development scenariosand forecasting decades of potential performance.We can even simulate years of deepwater platformoperations and optimise design before we invest – agame-changer in reducing risk and accelerating the timeto peak performance.The awesome power of integrationWhile applying a new technology can improve our work,integrating multiple technologies can create whole newsectors of our business. Evolving separately, horizontaldrilling and hydraulic fracturing have enabled us to addnew oil and gas reserves once thought unrecoverable.Now integrated, they have set off a phenomenal boom inshale gas development. In less than a decade, new outputfrom shale has grown to 25per cent of US gas production,according to the US EnergyInformation Administration(EIA). The industry is stillassessing the global potentialwith exploration programmes,notably in Eastern Europeand China. One recent EIAstudy looked at 48 basinsin 32 countries and foundmore than 6,000 trillioncubic feet of “technicallyrecoverable” gas in 70 majorshale formations. Time will tellhow much resource we canreach. But IOCs by sharing theintegrated technologies andbest practices well proven inthe United States can nowhelp countries everywhere toevaluate the potential – andhopefully, grow their national energy supplies.Steamflooding technology is another integratedsolution poised for growth. After decades of improvingthis method in California and Indonesia, its application fordeveloping heavy oil is now being piloted by Chevron inthe giant Wafra Field located in the onshore PartitionedZone between Saudi Arabia and Kuwait. If successful, theincremental upside potential for this one field could be 6billion new barrels of recoverable oil. While steamfloodingis a proven solution in sandstone reservoirs, the WafraField is a carbonate reservoir requiring the extensionand integration of existing technologies applied in newways, and the development of new technologies to meetthe challenges not seen in sandstone. Additionally, withwater being a scarce commodity in the region, our projectis integrating a technology called “seeded slurry vapourcompression” evaporation – to make pure water distillatefor steam generators from reservoir brine. Successfulintegration of all of these technologies will help createopportunities for arid countries to unlock their heavyresources.The renewables conundrumWe need to grow every form of energy, and renewablesare forecasted to grow the fastest. But they must beArchimedes’ screw: distant ancestor to today’s pumps and compressorsEnergy Solutions For All 117

Innovationcompetitive at scale. By 2035 renewables are still expectedto contribute only a small share of global energy supply.Solar, wind and biomass have been relied upon for energysince ancient times. But these energy sources lack theenergy density of fossil fuels, which nature has pressurecookedover millions of years to create natural energy cellspacked with power.Capturing and densifying renewable resources at scalerepresents a challenge that can only be met by extending,researching, developing and ultimately integratingtechnologies that improve our ability to concentrateand store energy from the resource to final product. Tobe cost effective without sustained subsidies, it is likelythat technologies that can build on existing supply chaininfrastructure to produce “drop-in” bio-hydrocarbonliquid fuels, for example, may succeed earlier than thosethat don’t. Elsewhere, the geothermal industry evolvedby combining and extending technologies from thepetroleum and the power-generation sectors. Chevron,the world’s largest producer of geothermal energy,is deploying this model at scale in Indonesia and thePhilippines.IOCs, including Chevron and many other companies,are working to commercialise and advance renewableenergy. In California, our solar-to-steam demonstrationproject will employ more than 7,000 sun-tracking mirrorsto make supplemental steam for enhanced oil recovery.And at the Qatar Science and Technology Park, we arehelping test solar technologies in desert applications,where many large-scale solar projects are beingconsidered.Connectivity - integration’s new waveOne of the many uplifting stories in our industry’shistory has been the way in which we have embracedinformation technology. The skyrocketing evolutionof computing technology has made early calculatingmachines, such as the slide rule and the abacus, longforgotten. Today, high performance computing makespossible the miracle of reservoir modeling and high-speedsimulation, integrating data, information technologiesand mathematics to show us how best to develop oil andgas fields and extend their lives.The next chapter in information technology promises tobe even more exciting, because it is enabling connectivityand process improvements at an astonishing pace. Thisis driving integration on a whole new level, allowingus to create linked, global networks of experts in realtimewithout travel. A case in point are the visualisationrooms where top explorers and specialists gather tosupport the drilling of complex, deepwater wells whileconnected digitally to teams in control rooms on workingrigs. Everyone sees the same data. We call ours the WellDecision and Execution Collaboration Center – and itensures not just good decisions as drilling progresses, butthe best possible decisions.Meanwhile in the oil and gas fields, digital connectivityis allowing our industry to track operations much as ahospital monitors patients in surgery. Information fromreservoirs, well and facilities feeds decision support centresin real time, guiding the management, well maintenanceand fine tuning of every element of operations. Withinnovations such as continuous downhole sensors andwireless communications becoming common in thefield, we are beyond automation and optimisation. Weare transforming and integrating workflows with newoperating behaviours and technology to enable newlevels of performance.Human energyThe combined potential for connectivity and integrationto accelerate business insight seems endless. Our industryhas been able to link geologic knowledge, geotechnicalexperience and human energy by integrating the bestgeoscientists and their tools. At Chevron, our rigorous processfor rating, ranking, selecting and drilling exploration prospectsworldwide has enabled us to achieve an exploration successrate approaching 50 per cent. Results like these tell us that withingenuity at speed, IOCs have never been better equipped toadd value, reserves and production. Everywhere partnershipstake advantage of the global capability of this integrativemindset and human energy, new energy is sure to follow.Consider again the compressor. Evolving throughoutour industry’s history, it has taken many impressiveforms and created new opportunities. With worldwideconnectivity, we’ve found another way to capture valuefrom this technology. We’ve long known that compressorreliability is a key to performance in individual fields andfacilities. Now we’re going global, with a Chevron centreof expertise in Houston which digitally monitors everymajor compressor in the company – and serves as anon-line, 24 hours-per-day, seven-days-a-week consultantto field operations worldwide. Archimedes would haveappreciated that. •11820th World PETROLEUM Congress

InnovationResearching the futureBy Ashok BelaniChief Technology Officer, SchlumbergerIn 1948, we opened our first research centre in Ridgefield,Connecticut. Located a short drive from New York City,the centre, over the years, became home to more than140 scientists focused on challenges in formationevaluation. Perhaps the location encouraged creativethinking through its relaxed environment, or perhaps itsearly position on the world’s largest oil and gas producingcontinent made it the right place to be. Either way, asthe company grew, so did our needs in research and asecond centre was opened in Cambridge, UK in 1982. Theintervening 35 years had seen considerable change in theindustry with activity beginning to move east to followthe development of new oil and gas areas. The benefitsof Cambridge, however, not only as a centre of academicexcellence but also as a city close to hydrocarbon activityin the North Sea were apparent. Proximity to academiabrought talent, being adjacent to growing businessbrought customers and investment. These two ideasremained as our world of research developed further andthey lie behind the move of our first research laboratoryfrom Ridgefield to Boston, Massachusetts in 2008.At the same time the world of IT enabled communicationaround the world. Remote centres could exchangeinformation more easily and more quickly. Partly as aconsequence, our next research centre openings weremuch smaller – in Stavangar, Moscow, Dhahran andnow Rio de Janeiro. In each case we were following theexpansion of exploration and production activity whileremaining close to customers and close to academiccentres of excellence. It was as if the ideas of the laboratorycould be tested in a customer field almost immediately.Within any technical field, and certainly within oiland gas development, research is an essential activity.This is becoming more and more important as easierhydrocarbon supplies become exhausted. Reservoirs arebecoming more complex, their production more difficult,their location more remote, and their environmentalconditions in terms of temperature and pressure moreextreme. So while research must address harder problems,its real purpose remains unchanged. And that purpose isperhaps twofold. First there must be a certain amount offundamental work, where the question to be answeredis often the question itself and where the impact on thebusiness is difficult to measure. The potential of such aproject is usually large, and failure to succeed should notbe a surprise. Second, we must also engage on projectsthat consolidate earlier work. This sometimes becomeseasier as enabling technologies are developed elsewhere.In this case, the question is known, the impact easier tomeasure, while potential and risk are much better known.We should still not be surprised by failure, however.But above all, research must support new productdevelopment, and while this means solving hard problemsand looking at new technologies, it is driven by needs fromboth inside and out. Advancement occurs by the creativesolution of hard problems and our purpose is to developtechnology for where the business is going to be in threeto 10 years time.This means that our research activity is characterised bythree things.First, taking such a long-term perspective allows us tomake step changes in technology performance. At its best,research allows us to reduce and overcome scientific riskso we can direct our investment in areas of technologywith higher confidence of substantial commercial success.Second, the fundamental scientific understanding wedevelop gives us economies of scope. In other words, thescience developed by research over our history can beapplied to other oilfield businesses. And we can leveragethis fundamental understanding to rapidly develop anddeploy new differentiated products and services acrossour technology portfolio.Third, no company has all the resources to overcomethe technology challenges in the oil and gas industry allby itself. We must choose where we lead, and by effectivenetworking and collaboration on a global basis gain accessto complementary resources to extend our science andtechnology footprint to cover commercially valuable areas.Within Schlumberger, the research and engineeringorganisation exists to deliver the new technologies neededby three product groups – Reservoir Characterisation,Drilling and Reservoir Production. These are aligned withthe workflows of our customers as they move through thenatural stages of exploration, development and productionof oil and gas resources. Our six research centres covera geographical and technical footprint that supports aworldwide engineering, manufacturing and sustainingorganisation of 65 centres in 15 countries employing 15,000people. Such geographical diversity offers a significantadvantage beyond proximity to customers and academiain harnessing particular cultural strengths. Innovation forexample is a key facet of engineering in France; Russia isrenowned for its mathematical strength; China is one ofthe largest investors in nanotechnology while Singapore →Energy Solutions For All 119

Innovation→ is developing expertise in project conception followingits success as a manufacturing baseThe three factors that characterise our research guidealmost all of our current research themes. Perhaps the bestway to see this is to look a number of examples.The first is the optimisation and control of the entire drillingprocess. While integration of the different componentsof the drilling system, both in the drillstring and with thedrilling fluids, can considerably optimise that process, weare now seeking a step change that can best be describedas safe, reproducible drilling performance. The goal isto achieve predictable consistency, assure repeatability,improve efficiency and reduce the cost of well construction.This involves some fundamental science aroundthe mechanics of drilling, as well as in the automaticalgorithms that mirror how humans evaluate data and takesteps to control. The area is sufficiently fertile to have broadapplication and the control and automation of the drillingsystem is only the first in what we see as the deploymentModelling provides rapid-response testing of research theoryof automation and control in reservoir management,particularly in completions and reservoir monitoring.It is particularly timely, since automation is becomingrecognised as essential for the continuous observationand control in oil well drilling.It also involves networking and collaboration. For examplelast December we conducted a test in Texas that compareda human driller against automatic methods for controllinga drillstring. Drillers control the rate of penetration throughthe weight on the bit and the speed of rotation. Humanscan be conservative – too much weight stalls drilling, andtoo much rotation causes excessive shock and vibration. Theexperiment showed that with continuous measurementsof downhole power and motor speed, an algorithm couldoptimise weight on bit and rotation to triple the rate ofpenetration. These are early signs of the potential we see tocreate step improvements in the drilling process. Althoughsome integration of the drilling system components helpedmake this happen, we also need a network to accessthe components for drillingtechnology from a number ofsmall start-ups and academicinstitutions.A second example is thefamily of technologies that isdriving sensor miniaturisation.This is aimed primarilyat the needs of reservoircharacterisation. Industries suchas wireless telecommunicationshave profited from enormousstrides in miniaturisation –the development of mobilephone handsets is one ofthe most striking examplesas devices have becomemore sophisticated with everexpanding functionalities fittinginto ever smaller packages atrapidly decreasing cost to theconsumer.The step change inperformance will come fromachieving comparable changesin oilfield sensors. This is drivenby the need to characteriseever more complex reservoirs in12020th World PETROLEUM Congress

Innovationgreater detail, yet we are currently hampered by practicalengineering limitations of size and weight, and morechallenging environmental conditions of pressure andtemperature – all of which limit deployment – as well asthe prohibitive cost of implementing more sophisticatedmeasurements.Miniaturisation makes possible several technologydirections to address this. The obvious is packing morefunctionality into the same footprint, as well as by makingcompletely new measurements enabled by physics andchemistry at these scales. One of our best examples, whichhas already reached commercial service, is an instrumentthat packs a grating spectrometer along with a numberof other miniaturised sensors capable of measuring thedownhole properties of reservoir fluids in situ. The tool isonly a few inches in diameter but is capable of supplyingreal-time information from the bottom of a well to surface.But more interesting is the fact that the same underlyingtechnology can be deployed on several modes ofconveyance – on wireline, logging-while-drilling,completions instrumentation, and perhaps even drill bits –meaning that downhole sensing has the potential to be farmore pervasive than anything we’ve contemplated before.But most exciting is that our thinking on the architectures ofthe platforms for such sensors has fundamentally changedand that we now see the possibilities for proliferatingmeasurement technologies across many different services.Technologies from other industriesIn terms of fundamental science, we are well-positionedto profit from the enormous advances in academic andindustrial science in the fields of microfabrication insilicon and other materials, driven by electronics VLSI, ofmicrofluidic lab-on-chip developments for the biomedicaland life sciences, and of fiber optics and photonics for thetelecom and instrumentation industries. But it’s not astraightforward transplant from those industries as thereare key challenges in implementing these technologiesin materials and forms robust and reliable enough to bepractical and useful for the oilfield environment.To make this happen we need to tap a wealth of externalexpertise via a network of contacts and collaborations withuniversity partners and with other companies outsidethe oilfield. Over the last three years, we believe we haveestablished leadership in the longer term science themesfor the application of nanotechnology in the oilfield that weexpect to have application in deepwater, in hydrocarbonrecovery, and in unconventional resource development.My last example concerns reservoir production formaterials for applications in cementing and stimulation.Materials form a vast area where myriad needs exist inharsh environments – high pressure, high temperature,corrosive conditions. Above all we seek to make stepchanges in services for well integrity, pressure pumpingand completions. For example for well integrity, we areinterested in making a step change in the performanceof cement by designing composites that can be used inextreme high temperature or extreme low temperatureenvironments where appropriate products do not existtoday. For stimulation and completions we are pursuingdirections in so-called “smart materials”, materials whichcan change their mechanical and chemical behaviour inresponse to environmental triggers, expecting to achievestep changes in efficiency compared to the mechanicalsolutions available today. Our investigation into functionalmaterials has many potential applications – a basic oneis using such materials to cleverly place proppant tomaximise productivity.Like other step changes, this theme too requires somefundamental science. One major change in the last fiveyears has been the ability of computer modelling topredict the macroscopic behaviour of materials. Whenmarried to experimental methods in characterisationthis has allowed us to pursue a couple of major themesaround functionalising new materials – the intelligentcombination of material components to alter properties– in some cases mechanical, in others chemical. Indeedfundamental investigation into cement has allowed usto develop a more complete understanding of its settingunder extreme conditions – leading us to believe we willbe able to design superior cement materials in the future.Each of these examples highlights the principlesthat guide research and engineering in Schlumbergertoday. Whether we are seeking to exact a step change inperformance, gain a deeper understanding of fundamentalscience or develop knowledge through collaboration andpartnership, a common organisational framework ensuresthat the necessary investment is correctly apportioned.When Schlumberger published its first annual report in1957, the report carried the subhead “First in the Field,Foremost in Research”. Today, Schlumberger remainsconsistent in that purpose and intent, although researchhas by necessity evolved in order to serve the future needsof the business. •Energy Solutions For All 121

InnovationNatural gas ready to meet theworld’s energy challengesBy Dr Abdul Rahim Hashimpresident, International Gas UnionRising oil prices, the ongoing turmoil in the MiddleEast, and Japan’s continuing nuclear fallout, arehelping to strengthen the case for natural gas.While natural gas has, in the past, played the roleof the bridesmaid and has always been regarded as thediscarded twin of oil, these recent events – along with thecommodity’s inherent qualities – drive home the pointthat natural gas has what it takes to help the world addressits energy and environmental challenges.The natural gas industry is a phenomenal success story. Itsbeginnings can be traced back to more than two millenniaago when around 500 BC the Chinese used natural gas toboil sea water, separating the salt and making the waterdrinkable. However, it was only until the 1800s that theworld began to realise the potential uses for natural gas,for lighting, cooking and heating. Over the centuries, whatbegan as a fuel to provide mere lighting for homes andstreets, has evolved into a powerful resource which wouldhelp countries across the globe meet their rising energydemand. Today, natural gas provides nearly a quarter of theworld’s energy demand.In the power sector, natural gas now accounts for22 per cent of the world’s generation capacity and thisshare is poised to rise further due to the overall aging ofpower plants and the need for replacement worldwide.Natural gas is also expected to be the fastest growingmajor fuel through 2030. According to the InternationalEnergy Agency, global gas demand is projected to growby an average of 1.5 per cent per annum through 2030.While demand is expected to rise across all regions of theworld, growth will be strongest in non-OECD countries,particularly in China.By 2030, China’s demand for natural gas is forecast togrow to six times more than the level in 2005, driven bythe residential/commercial and industrial sectors wheredistribution lines are being expanded and the price of gasis competitive against other major fuels. In India, morethan half the projected growth in gas demand is expectedto come from the industrial sector, where gas providesthe energy to produce steel and other products. Naturalgas is also being used as raw material to produce paint,fertiliser and petrochemicals. In the Middle East, demandhas been growing rapidly in both the power generationand industrial sectors.However, despite being one of the world’s mostimportant energy resources, in recent years, natural gas hasbeen grouped together with the other fossil fuels, namelycoal and oil, and they are viewed together as contributingto the world’s climate change problem. Today, climatechange is considered one of mankind’s biggest challenges,and all efforts are being directed towards achieving a lowcarbonenergy mix. Climate researchers believe the onlyway to limit the rise in global temperatures by 2ºC is tohalve global emissions of greenhouse gases in the longterm. Natural gas can play a key role in helping to meetthis objective.With its low carbon emissions compared to other fossilfuels, natural gas is a solution to some of the world’seconomic and environmental challenges. Cleanerthan coal and oil, and more efficient and reliable thanrenewable energy, energy experts have rightly pointedout that natural gas should not be viewed as a bridgefuel, but is actually an answer to the world’s energy andenvironmental challenges.While nuclear energy has long been regarded as thebest choice for emerging economies like China and theMiddle East, Japan’s nuclear fallout following the March 11earthquake has spurred debate over the safety of nuclearpower plants. China has announced that it is reviewingplans to add 27 reactors to the 13 it now has, while Japan,with 10 per cent of its nuclear power knocked out, willneed to invest billions in new power generation capacity.Green credentialsThese developments serve to emphasise why natural gasshould be the fuel of choice in a low carbon economy.Whenburned to heat homes or for industrial uses, it releases 25-30 per cent less CO 2than oil and 40-50 per cent less thancoal per unit of energy produced. When used to generateelectricity, natural gas can reduce CO 2emissions by up to 60per cent compared to coal. Natural gas also produces littlenitrogen oxide, sulphur oxide or particulates.Other comparative environmental advantages includethe fact that ten times more water is needed to producethe equivalent amount of energy from coal, while ethanolproduction can require as much as a thousand times morewater to yield the same amount of energy.Natural gas is also efficient - modern combined cycle gasturbine power plants are 40 per cent more efficient thancoal plants, and also require only half the constructiontime needed to build a coal plant and less than a thirdof the time needed to build a nuclear plant. Apart frombeing quicker to construct, gas-fired power plants are alsorelatively easy to get regulatory approval for.12220th World PETROLEUM Congress

InnovationThe Inter-governmentalPanel on Climate Change hasrecognised that increasinggas use in power generationcan have an immediateimpact on emissions. In theUS, for example, doublingutilisation rates at existinggas-fired power plants couldWind - 1.2%%displace enough coal tocut coal-related emissionsby 20 per cent. And sinceHydro - 15.3%coal-fired power generationaccounts for 33 per cent ofall US emissions, a reductionof that size is certainly nosmall matter.Natural gas also supportsthe growth of renewableenergy. Since gas turbinesNuclear - 13.3%can be turned on and offrelatively quickly, natural gasserves as a flexible partner forintermittent energy sources,such as wind and solar, inpower generation.In the transportation sector, natural gas can also makean immediate impact to reduce greenhouse gas emissions.The use of dedicated natural gas vehicles can lead to 20-25per cent less CO 2emissions compared to petroleum fuels. Itis only logical that apart from fleet vehicles like buses, moreand more passenger vehicles are now running on natural gas.Recent development in the use of LNG as fuel for shipswill further help reduce emission of greenhouse gases inthe maritime sector. Since switching from diesel to naturalgas can result in at least a 20 per cent CO 2reductionmeasures are being explored to make it mandatory forinland ferries and offshore supply vessels to use LNG. Inaddition, increased use of natural gas in transport canreduce local pollution of, for example nitrogen oxide andsulphur oxide.While natural gas has been widely acknowledged to bea cleaner alternative to other fossil fuels, the adoption ofnatural gas on environmental grounds has been limitedto date. Amongst the possible reasons is the issue ofaffordability, but this may change as countries nowstrive to reduce their carbon emissions. One way is viaOther Renewables - 1.9%Structure of global electricity supplyGlobal electricity generationin 2010: 21,363 TWhCoal - 41.8%Natural gas - 21.7%%Oil - 4.8%the introduction of new environmental policies, such ascarbon trading schemes.Game-changers for natural gasNatural gas has the means to meet the world’s growingenergy needs. The world’s current proven reserves ofconventional gas totals 187.49 trillion cubic metres, with areserve production ratio of more than 60 years.In addition, exploration of the world’s unconventionalgas potential has provided significant boost to availablereserves, extending current production life by a century ormore. The US, for example, sits on a huge unconventionalgas reserve, locked away in difficult-to-reach formations.While it has long been technically possible to recoverunconventional natural gas – the term for gas that is notlocated in porous permeable reservoir rock and whichincludes coal bed methane, tight gas, shale gas, andmethane hydrates – it has not always been economical.Over the last five years, thanks to technological advancesthat have made it easier and cheaper to access theseresources, more and more companies have been jumping →Energy Solutions For All 123

Innovation→ on the unconventional gas bandwagon. Advances indrilling techniques and the hydraulic fracturing or frackingprocess have allowed North American shale gas players toincrease production. According to a recent study from theAmerican Clean Skies Foundation, the US now has 2,247trillion cubic feet of proved natural gas reserves, enoughto last 118 years at 2007 demand levels.This windfall is not only confined to the US. Accordingto Deloitte’s Energy Predictions Report 2011, by 2035, shalegas could make up 62 per cent of the total gas producedin China and 50 per cent in Australia. Canada too is lookingto boost its reserves. While there is also shale gas in Europe,there are also greater challenges to its developmentbecause state ownership of mineral resources giveslandowners little incentive to allow development ontheir land and because the region also does not yet havea robust oilfield service industry to support it. But somestill see the potential of European shale gas resources assufficiently robust to alter the energy supply scenario.Technology also plays an important role in connectinggas supplies to markets. An example of such technology isFloating LNG (FLNG) that allows liquefaction at sea insteadof having to build pipelines to the coast. This will open upresources previously considered too remote or expensiveto exploit. Moreover, with FLNG, the facility can be redeployedto another gas field once production at one fieldhas been completed.Advances in technology are also likely to affect theKawasaki’s 145,000 cubic metre LNG carrier, Energy Frontierconsumption of natural gas. There is an obvious economicincentive for energy-intensive industrial users to useenergy-saving technology. But in the case of the residentialsector, some form of government incentive, and probablyalso disincentives, may be needed to persuade householdsto adopt energy efficiency measures.Advocacy initiativeCertainly, for all its merits natural gas is not the panacea forthe world’s energy problems. Developing countries withabundant, low-cost coal reserves will continue to exploit andmaximise those resources. And the progress of unconventionalgas should not mask the challenges countries face indeveloping their potential shale resources. Open licensing,favourable regulations, and robust competition among manyinnovative firms were an integral part of the unconventionalgas success story in North America, but those conditions arenot yet in place in most regions.The natural gas industry also has much work to do inconvincing the public that natural gas extraction is safeand environmentally sound, and that natural gas has animportant role to play in meeting energy challenges in alow carbon economy. The International Gas Union (IGU)has made natural gas advocacy one of its priorities. To thatend, the IGU has developed a campaign – titled Naturalgas CARES for the world – and a gas advocacy toolkit thathas all the facts that support the argument for natural gasas a fuel of choice.The IGU is also working withlike-minded advocacy groupsand gas associations suchas the American Natural GasAlliance (ANGA), the EuropeanGas Advocacy Forum, and theCanadian Gas Association,to correct the perception ofnatural gas by policy makers,governments and the public.In all our advocacy initiatives,the message is consistent: Thenatural gas industry is ready totake on a larger role in meetingglobal energy challenges, andit is time that policymakers andstakeholders recognised itspotential and allow natural gasto step into the spotlight. •12420th World PETROLEUM Congress

InnovationJapan’s energy positionpost-FukushimaBy Nobuo Sekiformer president of Chiyoda CorporationAs the world knows, on March 11th of this year, amassive quake and tsunami of an unprecedentedscale struck the Pacific coastal areas of East Japanleading to a serious accident at the FukushimaDaiichi Nuclear Power Plant. We, the people of Japan, areworking diligently to recover and rebuild with generoushelp from the peoples and the countries of the world, tobounce back from the immense loss of life and damage.At the same time, the catastrophe has forced us to focusagain on our selection of energy resources. Japan will haveto redouble its efforts to save on energy use and diversifyenergy sources. The country has already made great effortsto develop energy conservation technology and put it topractical use. Japan has promoted nuclear power and LNGfor diversification. Renewable energy is also increasing,though its ratio to the total is very small.The nuclear accident at Fukushima Daiichi NuclearPower Plant has given a big push for anti-nuclear powermovements in Europe. Japan is also under pressure toweigh again the pros and cons of the use of nuclear power.But we also have to consider one important point we hadoverlooked – that it is no simple matter to quit nuclearpower once you start. Nuclear fuel rods including theused ones must be safely stored in permanent locationsand the plants must be safely brought to a close. Whatis more, unlike oil plants, the permanent shut down andmothballing of nuclear power plants is not so straightforward. As with Chernobyl and Three Mile Island, closingthe Fukushima plant will present us with problems we havenever experienced before that we must deal with head on..On the other hand, many emerging and developingcountries consider nuclear energy as an option whenselecting the best energy mix for themselves, and Japanintends to provide technology and support to thesecountries. Moreover, the United States and Russia whichhave been the pioneers in nuclear power generation andhave experienced their own nuclear accidents, maintainthat they will continue to use nuclear power. France, too,which is number one in terms of relative use of nuclearpower at home, intends to expand export of nuclearelectricity to neighbouring countries.Immediate withdrawal from nuclear power is not theway to go. Rather, we should engage more vigorously inthe use of nuclear power. Of course, we should fully bearthe responsibility of solving the problems that we aresaddled with now. In Japan, power companies and majorequipment manufacturers have led and coordinatednuclear power plant projects under the guidance ofrelevant government agencies. Future decisions on nuclearpower will require more vigorous reexamination of safety.To that end, the International Atomic Energy Agency isworking with the rest of the world and is calling for safetyreviews and management based on harmonised globalstandards. I strongly recommend involving in these safetyreviews experienced people from the oil, gas and chemicalindustries and the plant engineering industry which haslong built and operated complex systems and equipment..The other significant issue that needs to be reviewedwhen considering use of nuclear power generation is thatof cost. It is argued that the cost of fossil fuels should reflectall their associated environmental damage. If you do thesame for nuclear power, and add in the cost of used fueldisposal and plant dismantling, and the cost of payingcompensation once a huge accident occurs, then it mayno longer be feasible to fly the banner of “cheap electricity.”We need to conduct correct and accurate economicevaluation that takes all of these factors into accountand we must do it in conjunction with value assessmentsincluding safety.All of us, including the people in the disaster hit areawho froze in wind and snow after their infrastructure wasdestroyed by disaster, and businesses and ordinary peoplewho had to scramble to deal with the sudden electricityshortage after enjoying the benefits of the world’s moststable electricity supply, have had to admit once again whata blessing fossil fuel is as we began to receive emergencysupply of kerosene oil and to hear the news of mothballedthermal power plants reopening. On the other hand, whathas brought on the global warming and climate changeis the accumulation of greenhouse gasses representedby CO 2among others without regard for environmentalbalance. The basic policy that recognises the need fordealing with this particular problem will probably remainin place for the foreseeable future.The current high price of oil is boosting developmentof shale oil and heavy oil, despite geographically difficultlocations and high mining costs. Furthermore, improvementsin mining technology are eagerly awaited as the producersaim to improve the recovery rate. But given the fact thatits own demand of transportation fuel is in decline, Japanis looking into down-scaling its domestic refineries on theadvice of the relevant government agencies. But while thedomestic oil industry is on a downward trend, Japan stillneeds to secure a fixed amount of oil that includes backup12620th World PETROLEUM Congress

Innovationsupplies in case of emergencies. One possible solutionis to deepen economic ties with Asian countries whereenergy demand is still rising, and where the most advancedlarge scale oil refineries could be jointly built. This kind ofinvestment would help Japan’s neighbours and ensureredundancy of our domestic supply.Natural gas is the cleanest fossil fuel. But the price of thisprecious resource seems a bargain compared to the priceof oil. It has fallen over 8 per cent in the past year. Onereason for the falling gas price is that gas has not beenan object of speculative investment. Another reason is therecent increase in production of shale gas in the US. Gas isa clear-cut option as a wise use of resources in the futurebecause gas, like oil, is a vital carbon/hydrocarbon elementas raw material for chemical products. In recent years manyJapanese have been opting for “the all-electric house”when choosing the energy mix for their homes. However,the Fukushima calamity has brought on black outs andpower conservation mandates that the Japanese peoplehad not experienced for several decades. This teachesus a lesson of how we need to prepare diverse energysupply chains and consider the best mix to use. The recenttechnological advances have improved the performanceof equipment such as fuel cell batteries using municipalgas. Such effective uses of gas will expand even more.Either way, Japan remains the biggest importer ofLNG and will continue to enjoy the benefits of thisclean energy for a long time still to come.As for renewable energy, the basis for renewablesystem operation is fundamentally local productionand consumption. Therefore, the foundation ofrenewable energy will be individuals installingequipment in their homes to generate their ownelectricity, and communities jointly operatingcluster-type facilities. Since investing in suchsystems will be made easier if all the excess powerfrom these is purchased at a fixed price, JapaneseGovernment is considering a bill to institutionalisesuch a scheme. Inevitably, there are challengesto be met including the quality of electricitygenerated, keeping the existing supply chain safeand intact, transporting power over long distances,and storing it in large amounts. When we consideroptimising the use of renewable energy in Japan,we soon run into certain limitations becauseof local restrictions on siting and installation ofequipment and facilities.Another option for carbon-free energy is hydrogen.Large volumes of hydrogen have already been used in oilrefining and petrochemical processes, but only recentlyhas hydrogen been proposed as an energy source. Japan ispromoting use of hydrogen by experimenting with smallscaleelectricity generation and automobiles that run onhydrogen fuel cell in specially designated areas.Lack of safe and economical supply infrastructure is abig reason for the slow progress in promoting the use ofhydrogen. The Chiyoda corporation has already completedthe development of technology that allows for easystorage and transportation of large volumes of hydrogenunder ambient temperature and pressure based on thechemical hydride method. Chiyoda has also completedthe development of a technology for hydrogen separationand recovery, and is now preparing to construct a facility todemonstrate and eventually service these technologies. Itis my hope that use of hydrogen for electricity generationand other usage will gain a big momentum once theseinfrastructures are completed.It is vital that we all work together to achieve a sustainablesociety for future generations. For us to be able to do this,it is essential that we continue to develop technologiesand nurture human resources to put these technologiesto practical use.•Fukushima Daiichi nuclear power plant Number One reactor buildingEnergy Solutions For All 127

InnovationUnconventionals: The worldhas and needs tight oilBy Greg Hill, President, Worldwide Exploration andProduction and Executive Vice PresiDent, HessGlobal energy leaders and policymakers face astark reality: world energy demand is forecast togrow sharply over the coming decades, greatlyoutpacing estimated production capacity. Thedanger is that supply will have to ration demand andprices will skyrocket, hobbling the world’s economy.A chief constraint is that OPEC has limited sparecapacity to meet this demand, and the overall shareof non-OPEC crude is forecast to remain constant.Meanwhile, geopolitical issues, such as conflict in theMiddle East, make access to traditional energy sourcesincreasingly difficult.As world energy leaders convene in Doha for the 20thWorld Petroleum Congress, we are all acutely aware ofthe challenges of meeting future energy demand –and averting a potential energy crisis. The US$140 perbarrel oil price we witnessed three years ago was not anaberration – it was a warning.In the United States, these realities pose significantchallenges to our economy and to our energy security.Against this backdrop, and given the promising businessprospects unfolding in the unconventional energysector, key industry players like Hess Corporation areincreasingly focused on the growing opportunities inthat arena.In the last three years in particular, there has beenrapid growth in US unconventional liquids production,and there are strong indicators that the growth inUS supplies of unconventional resources will play animportant role in helping to meet future worldwideenergy demand.These new supplies have the potential to displace agrowing portion of conventional production because ofthe competitive advantages which the unconventionalprojects possess: namely lower supply costs, easieraccessibility and faster time to market. And while theUnited States will undoubtedly be a major supplysource, the opportunities are global.US unconventional development began to acceleratefive years ago. Small E&P companies began leasingacreage in the Marcellus shale formation hoping totap into shale gas to feed the underserved East Coast,and new technologies opened up opportunities in theNorth Dakota Bakken, where Hess had a legacy position.Since 2008, the production of shale oil in the Bakkenhas tripled, and there are projections that oil productionfrom the Bakken alone could be as much as 600,000barrels per day (b/d) in just a few years. Looking ahead,unconventionals will likely account for up to 40 per centof US liquids supply by 2015, up from 10 per cent to 15per cent in 2008, according to Hess estimates.The outlook for the industry is very bright, for both theunconventional oil and the natural gas base. Withouta doubt, this has been a saviour for energy security inthe United States. And the business prospects for thisindustry in the unconventional space are very significant.But to be a successful player in the unconventionalarena will require a different business model and uniquecapabilities – which is where independent oil and gascompanies are particularly advantaged.Unconventionals: a different businessThe resources are much more challenging to producethan their conventional counterparts and require adifferent and, in particular, low-cost business model.While chances of success for unconventional wells arehigher when compared, for example, to deepwater Gulfof Mexico fields, there are generally less hydrocarbonsper well, decline rates are greater, and the drilling andcompletion capital expenditure per well as a percentageof total expenditures is significantly higher.When one looks at the growth in US unconventionalsupplies over the last two decades, North America hasbeen an incubator in which the independent oil and gascompanies have been setting the pace, accounting for70 per cent of total production in the 1990s, rising to an80 per cent share over the last 10 years.Independents are uniquely advantaged: they havethe capabilities required in drilling and completionsexpertise, lean manufacturing approaches, fast-pacedinnovation and a low-cost philosophy that make themwell suited to take advantage of these opportunities.Independents are also more flexible, operatingsuccessfully as niche players with a corporate agility anda greater focus given that their opportunities may be amore material part of their portfolios. They are smaller,and they are often better networked.Being able to continuously improve and rapidlyinnovate is a fundamental key to success. Advances, forexample, in horizontal drilling and fracking have madeunconventional development possible. Even more areneeded, and continuing advances in other technologyare needed to address concerns regarding fracturingfluid composition and water usage.12820th World PETROLEUM Congress

InnovationThe importance of being leanIn the unconventional arena, we at Hess believe thecompany is uniquely positioned, and we have made it partof our core strategy to be a global leader. In particular, Hessis focused on leveraging its success in the Bakken in NorthDakota across other unconventional projects in the US andabroad by being recognized as the partner of choice.Last year the company completed two key acquisitionsin the Bakken, where it now holds 900,000 net acres in thisbooming oil and gas play to become the largest acreageholder in North Dakota. It also acquired over 100,000 netacres in the Eagle Ford shale play in South Texas, whereit has just begun producing oil. In October of this year,Hess acquired about 185,000 net acres in the Utica Shale,further strengthening its portfolio of unconventionalresources in high-quality assets.Hess’ strategy in the Bakken has been to expand andupgrade its acreage, exploit its infrastructure advantageand execute through a lean manufacturing strategy. AsBakken has demonstrated, unconventional projectsgenerally have faster time frames and higher successrates, but nevertheless, because of the fast pace andheavy manpower and resources involved, they requirea leaner, lower-cost manufacturing approach to drillingand production.Hess has been perfecting our capability in applyinglean manufacturing principles to our unconventionalbusiness, and as a result our operations are becomingincreasingly more efficient and profitable.Toyota set the standard for this approach tomanufacturing, but the methodologies and practicesare directly applicable to the unconventional energybusiness, particularly since success is becomingincreasingly dependent upon acquiring acreageearly and executing swiftly, under conditions whereinfrastructure and resources are often constrained. Inaddition, while operating these large-scale drillingand fracturing and completions programme, there is aneed for continuous learning and improvement. Finally,given the nature of large-scale drilling and completionprogrammes there are many gains to be had bystandardising approaches.Hess is employing the fundamental principles of leanmanufacturing to get the most from our human andcapital resources to achieve faster, more efficient, andlower-risk developments.Lean manufacturing practices are also beingleveraged to our overseas operations, where we arenot only replicating our operating success in theBakken, but are also leveraging our global scale andreputation for being a trusted energy partner. Unlikemost other independents, Hess is an experienced globaloperator, doing business in 23 countries. We also prideourselves on serving the communities in which weoperate, investing heavily in social programmes such aseducation in Equatorial Guinea.Those attributes have helped Hess to gain access and formpartnerships in unconventional plays overseas. Specifically,we formed a partnership to explore for unconventional oilon 1m acres in the Paris Basin in France, a play that sharesmany of the Bakken’s attributes. We also signed three jointstudy agreements with Chinese national oil companiesto evaluate unconventional oil opportunities in severalmillion acres in China, and have farmed-in to over 6 millionacres in the Beetaloo basin of Australia.Improving stakeholder managementWhile the prospects for the unconventional businessare bright in the US and abroad, there are significantstakeholder challenges in managing the above-groundrisk and concerns of the many stakeholders involved,including policy makers, governments, lease holders,and citizens. This is where the industry can do a muchbetter job.Unconventionals are increasingly “in the news”, andhighly publicised incidents and misinformation haveheightened concern amongst citizens and communitieslocated near unconventional plays.Meeting the stakeholder challenges requires threeimperatives. First, we need to communicate what we doand how we do it to address the safety and environmentalconcerns. Second, companies need to employ responsiblepractices – particularly in the areas of well control and casingand cementing practices. Finally, we need a consistent andpredictable regulatory framework that also punishes poorperformers. Most states do a good job at regulating ourpractices, but there is room for more standardisation andapplying consequences to the violators, rather than thewhole industry. The unconventional oil and gas businessis not for the faint of heart. However, I remain optimisticthat the oil industry will overcome all of these challengesand supply the world with affordable energy for prosperity– just as we have done for well over 100 years. •Energy Solutions For All 129

InnovationCan the US shale gas revolutionbe repeated elsewhere?By Peter HughesDirector, Head of Energy Practice, Ricardo Strategic ConsultingIt is a remarkably short time since the outlook in the USand Canada was one of an irreversible decline in thedomestic production of natural gas, and a correspondingsteady increase in the need to import LNG in order tokeep the market supplied. Significant investments weremade in LNG import terminals, and in liquefaction capacity,particularly in Qatar, on the back of this, universally shared,outlook. However, one result of the move of the HenryHub price into double digits occasioned by the tighteningsupply/demand balance was to motivate a number ofindependents to take another look at the shale gas resourcethat was known to exist but, with a few local exceptions,had been considered much too costly to exploit.Those independents soon discovered that, by applyingthe latest that the industry had to offer in terms ofdrilling (horizontal/directional), imaging (3D seismic) andcompletion (hydraulic fracturing) technology, they couldradically improve the production economics of shale gas.The rest is already history, in the shape of the spectacularsurge in activity that has completely transformed theoutlook for domestic gas supply, leading, amongst otherthings, to talk of Reserve/Production ratios heading forthree figures, as compared to less than ten no more than afew years ago. In other words the prospect now is of selfsufficiencyin gas for the foreseeable future, to the extentthat there is now much talk of the possibility of buildingTable 1: Recoverable shale gas reservesCountry/RegionProven gasresources (end ofyear 2010) - tfcR/P Ratio (endof year 2010)USA 272 13 862Mexico 17 9 681Canada 61 11 388Latin America 262 46 1225Africa 520 70 1000+China 99 29 1275India 51 29 63Australia 103 58 396Other (5224) (639)new liquefaction capacity to export, as LNG, those volumessurplus to domestic market requirements.The North American supply surge has already been feltelsewhere in the global gas market, with the displacementof the LNG volumes originally destined for the US markethaving contributed to generalised over-supply overthe last two to three years, at least until the boost todemand from Japan post-Fukushima. The key questionnow is whether, in a world where security of supply hasbecome a preoccupation of increasing importance, theNorth American experience can be replicated elsewhere,generating significant new sources of domestic supply inthe major consuming nations and thereby reducing theirdependence on imported gas.The answer has little to do with the existence orotherwise of a resource base – the geology in question isnot limited to North America, and resources on a similarlyimpressive scale are known to exist elsewhere. Illustratingthis is the study published earlier this year by the USEnergy Information Agency (EIA), which provided an initialassessment of technically recoverable shale gas reserves ina total of 48 basins in 32 countries outside the USA. Table1 reproduces some of these figures, and compares themwith the current estimate of proven (conventional) gasreserves in the selected countries in question.The figures are undoubtedly impressive. But “technicallyrecoverable” does not mean thesame thing as “economicallyTechnicallyrecoverable shalegas reserves - tfcWorld 6609 59 6622 (butbased on only33 countries)recoverable”, and says nothingabout the cost of developingand producing the resource inquestion. So the vital questions areto what extent the cost structurecreated in North America canbe replicated elsewhere, andhow does the resulting coststructure compare to that ofalternative, imported sourcesof gas – remembering that theworld overall is not running shortof conventional gas.An answer to these questionswould start by considering thefactors that came together tounleash the shale gas revolution inNorth America – the technologyfactors were clearly critical, but were13020th World PETROLEUM Congress

Innovationby no means the only ones – and assess the extent to whichthese factors are present elsewhere.• Existing pipeline infrastructure. Building up supplyfrom shale gas involves the drilling of many wells one afterthe other (in a process that has been described as “gasfarming”) and the ramp-up of production is accordingly along, relatively slow process. Slow ramp-up rates depressthe economics of new pipelines, and so the absence ofneed to create major new infrastructure, at least in theearly stages of development, effectively removed oneobstacle to its development in North America.• Proximity to end-use market. This clearly relates to theavailability or otherwise of existing infrastructure. Whereno such infrastructure exists, the greater the distance ofthe shale resource from its intended market, the morechallenging the economics will be.• Drilling cost. This will, first and foremost, be a functionof geology. A huge amount of work remains to be donein terms of deepening understanding of shale gasformations outside of North America, but initial indicationsin, for example, Europe and China are that the identifiedformations are in general likely to prove more challenging.Features such as greater depths and more complicatedgeology will mean that individual well costs will be higher,and often significantly so.• Liquid spot and forward market. This factor has perhapsbeen under-appreciated, as it provided the independentsin the US with both the signal and the confidence to lookagain at shale gas, in the knowledge that they would beable to monetise whatever gas they were able to produce,whether it be for one month or five years, into a fullyfungible market and at a known price.• Supply side factors. These refer in particular tothe technical support industry that is a feature of theNorth American scene, and which is such an enabler ofentrepreneurial behaviour. Drilling rigs available for hire inNorth America can be numbered in the hundreds, whilein Europe only in the tens. Nor does Europe have anythinglike the oilfield service infrastructure that North Americaenjoys. Another supply side constraint is the availability ofwater, given that the hydrofracking technology that is socrucial to the economics of shale gas production requiressuch significant quantities. Much attention has focussedon the possible danger of hydrofracking contaminatingground water sources (though the evidence tends tosuggest that the real issue lies with waste water handlingand treatment). But it may be the absence of availablewater supplies in the first place that presents a significantimpediment to development.• Favourable regulatory environment. A large numberof elements go to make up a favourable regulatoryenvironment, and these for the most part remain to bedefined outside North America. In Europe, the situation islikely to be far less favourable, as evidenced by the case ofFrance, which has recently imposed a total ban on shale gasdevelopment involving the use of hydrofracking. In general,NIMBY (not in my back yard) factors are certain to be far moreprevalent, especially in the absence of the mineral rightsthat American landowners tend to enjoy and which serveto incentivise their cooperation. Outside the US landownersgenerally do not own the minerals under their land.An early assessment, therefore, is that whereas all thesefactors successfully came together in North America toenable the shale gas breakthrough, nowhere else has thesame combination today. This may change over time. Butone can conclude that it will in all probability take moremoney and time to develop shale gas outside NorthAmerica than inside it.A key question, then, is how will the cost of shale gasoutside North America compare to the cost of conventionalgas, even if imported from distant sources. While thesecurity of domestic supply certainly has attractions,such attractions tend to diminish when they involvea significant price premium. This may be particularlypertinent in Europe, where the shift to a more “normal”traded commodity pricing structure suggests that priceswill increasingly be set by fundamentals and thereforereflect the cost of supply. In such a scenario, with Gazpromin the role of marginal supplier, the market price target thatunconventional gas would have to aim at would be thelong run marginal cost of Russian gas, probably from theYamal peninsula. With such a price likely to be in singledigits, the target may prove a challenging one. In China,too, shale gas from the Tarim basin in the north-west ofthe country, relatively disadvantaged when compared tothe shale resources existing in the Sichuan basin in thesouth-west, might find it hard to compete with importsof conventional gas from neighbouring Russia if thatcompetition were purely cost-based.The real challenge, then, facing the development ofshale gas resources outside North America may be thefact that, unlike in North America, rival conventional gasshould not be in short supply, even if not necessarily froma domestic source. •Energy Solutions For All 131

InnovationShale gas: Polandstarts prospectingBy Professor Stanislaw Rychlicki,AGH University of Science and Technology, Krakowand Marek Karabula, Vice-President, PGNiGIn the light of America’s shale gas success, prospectingfor shale gas has started in many parts of the world,including Poland. Drilling a shale gas well entails a greatertechnical risk than in the case of conventional gas. Thosecharacteristics of rock mass considered to be useful in thecase of conventional deposits can become an obstacle.Among the most common technical challenges arisingfrom geological conditions are the appearance of naturalfissures that could cause captured gas to escape, theswelling of clay minerals under the influence of drillingliquids or materials used for hydraulic fracturing, andinsufficient silica content resulting in poor fracturingefficiency, low total organic carbon content and thermalmaturity, and possible local yield of nitrogen.In Polish conditions, an additional difficulty is the lack ofspecialised and experienced companies on the Europeanmarket able to perform all the necessary services. In Poland,the cost of a single shale gas well including stimulationtreatment and well testing is estimated at US$15-20 million.Stimulation treatment requires large amounts of water. Anaverage vertical well requires 2,000-4,000 cubic metres ofwater, while a horizontal well may need 8,000-20,000 cubicmetres of water, as well as 2,500 metric tons of proppant.There are many companies operating in the territoryof Poland which altogether hold 87 exploration licensesShale and tight gas prospective areas in Polandprimarily for shale gas, but also for tight gas (Table 1).The Polish company, PGNiG, has been awarded 15licenses in several oil provinces from Central Pomeraniato the Lublin area. In the area of the Gdańsk PetroleumProvince, exploration work will be carried out by PGNiGSA in the Wejherowo, Kartuzy-Szemud and Stara Kiszewawithin Ordovician and Lower Silurian formations.PGNiG has started with a first exploration well withinthe Wejherowo license area. Drilling work was precededby seismic acquisition. On this license area, the Lubocino-1well was drilled up to depth of 3,000m. At present, thedrilling results are being evaluated. The initial results arevery promising.On the other PGNiG licenses, geological analyses ofOrdovician and Silurian shales progress. Geophysicalsurveys have also been started (magnetotelluric,gravimetric, seismic acquisition). In the Pionki – Kazimierzlicense area, the Markowola-1 well was drilled in 2010.The well tests have not confirmed the presence ofunconventional gas deposits, however the tests werecarried out in the Carboniferous and Devonian sediments.Parallel geological analyses of Silurian and Ordovicianshales were performed. Additionally, a gravimetric andmagnetotelluric survey has been started.The target of the exploration for tight gas in theRotliegendes formations is theWielkopolska Petroleum Province,under the Szamotuły, Kórnik-Środa,Murowana Goślina-Kłecko, Pyzdry,Gniezno and Ślesin licenses. Inthis area, seismic acquisition andexploration drilling are planned.The challenges associated with theexploration of unconventional gasdeposits in Poland include unknowngeology, urbanisation of the area,restrictive environmental regulations,opposition of local authorities,especially in the case of attractivetourist destinations such as Pomorzeand Roztocze, access to adequatewater reserves, a very high capitalcost (cost and number of wells, largeproduction facilities), and the cost ofappropriate technologies.It was obvious from the beginningthat exploration for unconventional13220th World PETROLEUM Congress

Innovationnatural gas deposits would not be easy, but one has to Table 1: Polish exploration licensesremember that it also creates opportunities for both Poland,Companyand for companies which hold licenses in our country andhave started the exploration work.Among the potential benefits of shale gas explorationare possibly enormous natural gas resources, which willPGNiGMarathon OilSan Leon Tehcnology15119allow Poland to become independent from external 3Legs Resources 9gas sources, development of the PGNiG Group’s drillingExxonMobil 6companies, and the opportunity of significant profits forPGNiG and other licence-holders.In the US, shale gas exploration has proved very successfulin terms of documented in-place reserves and of financialBNK PetroleumLotosOrlen666returns. However, one has to keep in mind that exploration DPV Service 5in Poland may be harder than in the US, not only becauseChevron 4of different geological conditions, but also because oftougher fiscal conditions for unconventional gas projects,higher costs of drilling, more highly urbanised or cultivatedagricultural license areas, and a higher percentage ofRealm Energy InternationalENICuadrilla Polska332environmentally protected areas.Composite Energy 1Poland’s projected shale gas reserves have beenAurelian 1variously evaluated as 1.4 trillion cubic metres by WoodMackenzie, at 3 bn cubic metres by Advanced Resources,and at 5.29bn cubic metres by the US Energy InformationAdministration. But one has to remember that producibleresources in the case of shale gas deposits are estimatedStrzelecki EnergiaOgółemSource: EIA, Ministry of Environment187at 10-20 per cent.UnconventionalPGNiG’s licenses in Polandsources of hydrocarbons– tight gas and shale gas– will play an increasinglyimportant role in theplanned explorationwork in Poland andin the long term canresult in a significantincrease in resources,both geological andnatural gas production.Cooperation of Polishcompanies, especiallycompanies from thePGNiG Group, withforeign companies willensure access to moderntechnologies, necessaryfor economically feasibleshale gas production. •No. of licensesEnergy Solutions For All 133

InnovationAiming to meet needs at home& sustain market share abroadInterview with Nordine CherouatiChairman and CEO, SonatrachWhat is Sonatrach’s current policy on gas and oilproduction, and on investment in future capacity -upstream, midstream, downstream?The primary production of hydrocarbons of Sonatrachand its partners reached about 214m tonnes of oilequivalent (toe) in 2010, of which 55.3m tonnes of crudeoil and 145.8 billion cubic metres (bcm) of natural gas.Sonatrach plans to increase its production capacitiesgiven the significant potential of the Algerian subsoilyet to be developed. It should thus continue to meetthe domestic market needs and maintain its position ininternational markets.In order to do so, Sonatrach has launched an ambitiousdevelopment plan in the medium term, involving atotal investment of more than US$40 billion (bn) in theupstream. These investments should enable us to exceeda total production volume of over 1bn toe over the period2011 to 2015.Among the main elements of this plan, are development,starting in the last two years, of Gassi Touil by Sonatrach onits own, and of El Merk in association with Anadarko. Tobe launched in 2011 and 2012 are development of newdeposits, including those of Hassi Tarfa and Hassi Dzabat,Touat Gas, as well as fields located to the south of In Salahand In Amenas satellite fields.Sonatrach and its partners have also listed severalprojects to increase the production plateau of some fields,such as the oil rings of Alrar and Rhourde Nouss and InAmenas Gas deposit, and to optimise the recovery ofproducts through projects such as water alternating gasinjection in Ourhoud.In addition, the new gas pole in the South West regioncontinues to be developed, where at least six newprojects of significant size are under development withproduction set from 2015. These projects, operated bySonatrach alone or in association with its partners BG,Statoil, Total, Repsol and GDF Suez, will help guaranteethe supply of Algeria’s markets. Sonatrach is alsointerested in developing unconventional resources inpartnership, with the two first “shale gas” pilot projectscompleted in 2011.For the hydrocarbons pipelines transportationsegment, the investment planned in the medium term isaround US$6bn and mainly focuses on the developmentof transmission capacities to meet the commitmentsand on ensuring the security and reliability of facilitiesand infrastructures.In the oil and gas downstream, the current portfolioof projects underway and new for the period 2011-2015amounted to about US$8bn, most of which relate tothe continuation and completion of the constructionof the two new LNG trains at Skikda and Arzew, and tothe programme of rehabilitation, modernisation andadaptation of the northern oil refineries that will contributeto raise the refining design capacity of 20m tonnescurrently to around 24m tonnes in 2014, representing anincrease of 18 per cent.What should or will be the role of foreign partnercompanies, and their share in hydrocarbonproduction? Will this grow? Equally, whatinternational presence does Sonatrach seek for itselfin, for instance, regasification terminals?Partnership is an integral part of Sonatrach’s strategyand is confirmed through the various hydrocarbons lawsenacted by the Algerian State. The synergy between thenational and international companies has enabled accessto advanced technologies developed by the internationalmajors, and sharing of financial and technical risks inherentin hydrocarbons exploration and production.Results recorded so far are very positive, given themany partnership contracts entered into since 1986.Today, no less than 41 contracts signed by Sonatrachand its partners, 13 of which in the Exploration phaseand 28 in the Development & Exploitation phase. Thesecommit Sonatrach and its partners to an investment levelexceeding US$6bn for 2011.In 2010 production from fields operated by Sonatrachand its partners reached 59.1m toe, representing almost 28per cent of total hydrocarbons primary production. I wouldlike to underline that crude oil produced in partnershipduring 2010 represented more than half the total crudeoil production, a fifth of which returns to partners. As fornatural gas production in partnership, it is more than onesixthof the total natural gas production.These shares will grow in the medium and long termdepending on partner’s activity and discovery potential.Sonatrach continues its policy and ambition to become aglobal player particularly in the upstream and downstream.One may mention, for instance, the presence of Sonatrachin Peru (Camisea blocks 88 & 56) where it holds a 10 percent share in the upstream and in Tunisia, with a 21 percent interest in pipeline transportation through a mixedactivity holding company called ‘‘Numhyd’’.13420th World PETROLEUM Congress

InnovationIn the Sahel neighbour countries (Niger, Mauritaniaand Mali) Sonatrach operates alone and in partnershipon exploration acreages located in one of the largestsedimentary basins of Africa – Taoudeni. Sonatrach is alsopresent on the wholly-owned Kafra acreage, two explorationperimeters in Mauritania and two others in Mali.In the downstream, the reservation of regasificationterminal capacities in expanding markets may prove aproductive strategy to maintain and even increase marketshares in target countries.Algeria has three pipelines for gas to Europe and isbuilding a fourth, but is also building two more LNGtrains because it was aiming to have raise the shareof LNG to 50 per cent of all exports, in order to havemore flexibility in choice of markets especially toexport to the Atlantic basin and the US. Is Algeria stillaiming at this 50/50 split between LNG and pipelinegas, or has saturation of the North American marketbecause of shale gas there reduced Algeria’s interestin LNG? What about LNG exports to Asia?Algeria has played an important role in the supply andthe security of European energy markets for the past40 years. Sonatrach has responded to the natural gasdemand mainly from its natural market that is Europe, andhas initiated the construction of three transcontinentalpipelines, strengthening the ties between Algeria and itsMediterranean neighbours. These are essentially:• The Enrico Mattei Pipeline (GEM), linking Algeria to Italyvia Tunisia, came on stream in 1983 with an initial capacityof 8 bcm/year. This level has now reached the 32.5 bcm, thusfollowing the changes in demand on the European market;• The Pedro Duran Farell Pipeline (GPDF), commissionedin November 1996, is increasing volume every year toreach today a capacity of 11.6 bcm. The gas pipeline is nowsupplying the Iberian Peninsula via Morocco;• And most recently, the Medgaz pipeline, with a capacityof 8 bcm/year, linking Algeria directly to Spain.Drawing on its positive experience and strong relationshipswith its Mediterranean neighbours, Sonatrach todaycontinues to work for the consolidation and developmentof its energy partnership especially through new pipelineprojects such as:• The Galsi project which will link Algeria directly to Italywill have a capacity of 8 bcm/year from 2014;• The Trans-Sahara Gas Pipeline (TSGP) project that will linkNigeria to Algeria via Niger and will allow gas to be broughtto Europe. The capacity of the pipeline will be between 20and 30 bcm and its commissioning is expected from 2018.In addition to the LNG capacities developed in Algeria overthe years, reaching today a level of 26.7 bcm, two megaprojects are under construction: the first one “GL2K”, inSkikda, with a capacity of 4.5m tonnes /year, expected tobegin production in late 2011, the second one in Arzew,“GL3Z”, with a production capacity of 4.7m tonnes/yearshould start production in early 2013.As you can see, beyond the 50/50 rule, the NG/LNGportfolio balance is motivated by various considerationsincluding those of flexibility, security and opportunities tobe seized. As for Asia, Sonatrach is firmly interested in thismost dynamic market.What is Sonatrach’s view of the decoupling of gasprices from oil, and of a move away from longtermcontracts?Let me remind you that since the petroleum crisis of the1970s, natural gas has imposed itself as a first choiceenergy source. The breakthrough of natural gas hasbeen spectacular thanks to the traditional contractualmodel which was developed by buyers and sellers.This has enabled consumer countries to provide fortheir gas supplies safely and almost continuously atvery competitive prices on balance compared to othersources of energy. It also helped financing importantinvestments to carry gas on thousands of kilometresand make it available to consumers. This model hasbeen able to provide for a balance of the parties’ longterminterests.The structure of these contracts provides for the sharingof risks between buyers and sellers: in broad outline, theformer accept a volume-risk as they commit to pay forquantities that they will not need if demand is lower; thelatter accept a price-risk as they commit to supply thecontracted quantities even if the price falls.Actually, take-or-pay clauses provide for importantflexibility items. Hence, the buyer may carry forward,over several years, the quantities he does not wish to lift.Moreover, he is often given the opportunity to lift only 80per cent of the contracted quantities. The buyer then bearsonly part of the volume-risk.This ‘’harmonious’’ and ‘’balanced’’ relationshipbetween producer and consumer countries, betweenbuyers and sellers of natural gas, has led to thedevelopment of this industry.→Energy Solutions For All 135

Innovation→ Furthermore, indexing gas prices to petroleumproducts within long term contracts has been justifiedthrough the fact that these products could replace gasin its various uses – heavy fuel in industrial processes,domestic fuel for heating in households. Such amechanism offers a protection to both buyers and sellersagainst different market risks. Although affected by theeconomic crisis, this situation has not changed basically.The relation between the prices of both energies shouldregain the proportions historically observed. Even if longtermcontracts are momentarily more expensive thanmarket prices, they should remain over the longer term,as the market trends should be reversed in a relativelyshort horizon around 2013.According to the scenario drawn up by the InternationalEnergy Agency, gas natural consumption on a global scaleshould rise by 50 per cent by 2035. In the first position,we find emerging countries with soaring energy needs:China’s demand in natural gas should be equal to that ofthe entire European Union in 2035, whereas that of Indiashould increase fourfold.This spectacular boom lies in the fact that natural gascombines a series of unparalleled benefits. It has also beenspared by the natural disasters that cast opprobrium onpetroleum and nuclear – the Deepwater Horizon explosionand Fukushima nuclear disaster.What is the policy in the domestic downstream,especially as regards subsidising the domestic costof gas feedstock?As far as we know, there is no subsidy applied to the naturalgas price on the domestic market. The selling price usedis regulated and supported by a legal framework. The gasselling price intended for the national market is calculatedon the basis of the long-term gas economic cost for thedomestic market and a premium to cover the needs tomobilize the required resources to meet the very long rundemand.The gas selling price for the domestic market includesproduction costs, costs of domestic infrastructure,operating costs of any export infrastructure used to meetthe domestic market needs, and a reasonable margin.Is Sonatrach interested in developing renewablesources of energy, such as in the Desertec solarinitiative?Sonatrach has created in 2002 the company New EnergyAlgeria (NEAL) in partnership. The company constructed inthe gas field of Hassi R’Mel, with a Spanish partner, a powerplant based on solar thermal CSP energy and natural gas,with a capacity of 150 MW including 25 MW from solar. Theplant was commissioned on July 14, 2011. As regards theDesertec project, Sonatrach is not associated. •13620th World PETROLEUM Congress

InnovationPearl GTL: Making liquidsout of gas on a grand scaleBy Andrew BrownExecutive Vice-President, Shell QatarPearl GTL, the largest, fully integrated “gas to liquids”project, has risen from the sands of the Arabiandesert under the Development and ProductionSharing Agreement (DPSA) between the State ofQatar and Royal Dutch Shell. The project covers offshoreand onshore development and operations, with Shellproviding 100 per cent of the project’s US$18-19 billionfunding – the largest equity investment made by Shell in asingle project. Pearl GTL will add around 8 per cent to Shell’sproduction worldwide and will be a major contributor togrowth for the company in 2012 and beyond. It will alsoprovide the state of Qatar an opportunity to generate largequantities of high quality liquid fuels and products from itsabundant gas resources for many decades to come. Fromannouncing Final Investment Decision (FID) on 27 July2006, it has taken less than five years to see the first cargoleave the plant.Pearl GTL is the largest and the most complex energyproject launched in Qatar. At the height of construction,over 52,000 people were employed on site. Building QPand Shell’s biggest engineering project to date in RasLaffan, a vast industrial zone on Qatar’s east coast, has beena major achievement. Around two million freight tonnes ofequipment and materials have been imported to the site,some 800,000 cubic metres of concrete have been poured,and 13,000km of cables have been laid. At the peak, pipingand steel equivalent to two and a half Eiffel Towers werebeing erected every month. The project is not only thelargest GTL plant, it also features the largest oxygen plantever built, the largest hydrocarbon industry process watertreatment facility with zero liquid discharge capability andthe largest high quality baseoil plant in the world.KBR and JGC were the main contractors in a JointVenture agreement. The JV was awarded contracts toprovide the Basis of Design (BOD) / Basis Design Package(BDP), Front-End Engineering Design (FEED), projectmanagement and start-up support of the overall onshorecomplex, along with engineering, procurement andconstruction management of the GTL synthesis, utilitiesand infrastructure sections of the complex. But manyother major contractors from the US, Europe and theFar East were also involved. During detailed design, 13design offices in 10 different countries were designingdifferent sections of the plant. By the end of 2010 majorThe Pearl Gas-to-Liquids (GTL) plant in Qatar13820th World PETROLEUM Congress

Innovationconstruction was complete. On 23March 2011 the wells, 60km offshore,were opened and gas began flowinginto the plant. 13 June saw the firstcargo of on-spec GTL gasoil sail awayfrom Ras Laffan Port.When fully operational, theintegrated project will produce 1.6billion cubic feet of gas per day fromthe North Field, considered to be thelargest single non-associated gasreservoir in the world with estimatedrecoverable resources in excess of 900trillion cubic feet.Once onshore the gas will then beprocessed into 140,000 barrels a day(b/d) of GTL products, comprising mainlyGTL gasoil which is clear, odourless,has low emissions and can be used inmodern diesel engines; GTL kerosenefor aviation fuel; high quality baseoils foradvanced lubricants; GTL naphtha usedin the production of plastics and normalparaffin for detergents. The plant willproduce enough diesel fuel to fill over160,000 cars a day and enough syntheticoil to make lubricants for more than 225million cars every year. Additionally, Pearlwill produce 120,000b/d of upstream products includingethane, sulphur, LPG and condensate.The technology which supports the two train PearlGTL plant is called Shell Middle Distillate Synthesis(SMDS). In the 1920’s, German scientists Franz Fischerand Hans Tropsch invented a chemical synthesisprocess to convert syngas into liquids. Some 50 yearslater, Shell developed this into an advanced proprietaryversion – SMDS. This technology was tested andproven at the SMDS GTL plant in Bintulu, Malaysia in1993 and has evolved over three decades of researchand development. The Bintulu plant has a capacity of14,700b/d and is operating reliably and profitably.Pearl GTL will use technology to limit its environmentalimpact. It features one of the largest steam systems inthe oil and gas industry which will circulate 8,000 tonnes/hour of steam, capturing as much heat as possible fromthe chemical reactions to reuse the energy to drive thelarge quantity (1.2 GW) of rotating equipment on theFull integration from offshore to refined productsOffshorePlatformsFeedgaspreparationTwo trainGTL plantNatural Gas Liquids/EthaneEthaneLPGCondensateGas-to-LiquidsNaphthaN-ParaffinKeroseneGas OilBase Oilplant. In addition, the water processing plant allows allthe water produced to be recycled, giving it a zero liquiddischarge capability.The process on Pearl GTL begins with two 30 inchpipelines carrying the natural gas onshore from the twoplatforms standing in water up to 40 metres deep. Onreaching the plant it enters the gas separation unit whichextracts all the naturally occurring hydrocarbons such asnatural gas, ethane and condensate. This separation processalso removes contaminants like metals and sulphur.The pure methane that remains will then flow to theGTL section of the plant where it will be converted towax. Finally, the liquid hydrocarbon wax is upgraded usingspecially developed catalysts into a range of high qualitygas to liquid products.Making syngas: In the gasifier at around 1,300°C,methane and oxygen from the air separation unit areconverted into a mixture of hydrogen and carbonmonoxide called synthesis gas (syngas). The reaction →Energy Solutions For All 139

30ºGas PipelineBizerteTUNISROMETazerkaVALLETTAHannibalLa Skhira AshtartÎle de JerbaGabesZarzisBouriAz ZawiyahMellitah TRIPOLISPECIAL EDITION PRODUCED FOR THEGulf of SirteMarsa El BregaRas LanufAs SidrahGas Processing PlantOil Pipeline ClosedGas FieldOil RefineryOil and Gas FieldOil FieldNatural Gas Liquid PipelineTanker TerminalGTL RefineryDivided ZoneLNG Export PlantPower StationLNG Import Plant0200400600800 km0200400600 miles© 2011 FIRST / WORLD PETROLEUM. ISBN 13: 978-0-9546409-4-1.Reproduction in whole or part of this map without prior permission of the copyright holders is strictly prohibited. Gas and oil pipeline information primarily sourcedfrom OPEC, OAPEC and Pipelines International and used with permission. Geographical Map base © Lovell Johns LtdThe information contained on this map is derived and crosschecked from a number of authoritative public and private sources. Although all reasonable effortshave been made to verify information in the compilation of this map, the publishers and sponsors of this map cannot offer any guarantee or warranty as to theaccuracy or accept any liability or responsibility for any loss or Primary damage arising Reference from decisions Sources: made on the basis of this www.theodora.commaterial. International and otherboundaries, as well as pipelines and petroleum facilities, depicted www.opec.orgon this map should not be taken as evidence of the existence www.pipelinesinternational.comof territorial rights, rights ofpassage www.oapecorg.orgor use of the same.World Gas Map 2011www.worldoil.comWorld Oil & Gas Map 2009Produced by FIRST / World Petroleum in association with the sponsor: ChevronDesigned and produced by Lovell Johns Limited, Oxford, United Kingdom. Bathymetry data supplied by The British Oceanographic Data Centre.Natural Gas ProductionData sourced from IEA Natural Gas Information 2011 © IEA 2011150200920101209060300SubbaDarquainRumaila BasrahAr RatawiPRIŠTINA SOFIAAl Luhays PODGORICA TubahSibaRumailaZubairSKOPJE AbadanAr RakiRatqaAbdaliJerishanTIRANËRaudhatainMutribaSabriyahKhwar AlAmayahBahrahAl BasrahKra Al MaruMedinaKhashman KUWAITDharif (AL KUWAYT)RugeiAbduliyahMina Al AhmadiMinagishShubia ATHENSMina AbdullaUmmGreaterDorraGudairBurganMina Saud Hout(Al Zour)WafraRimthanKhafjiSouthFuwarisRas Al KhafjiDibdibahSafaniyahBenghaziZuietinaSarirMars Al Harigah(Tobruk)For sustainable energy.15ºE 30º 45º 60ºOil PipelineNDJAMENANatural Gas ReservesData sourced from IEA Natural Gas Information 2011 © IEA 20113000020102500020000150001000050000IsraelIraqIranLibyaSyriaUAEMANAMA (AL-MANAMA)SitraAwalRas LaffanDukhanIzmirMarmaraEreglisiIzmitEregliAntalyaAlexandriaSidi KerirEl HamraIdkuNorthFieldRas AlFontasMesaieedNajwatNajemDolphinPipeline 48”To Taweelah, UAEIdd El ShargiSouth DomeNatural Gas ConsumptionData sourced from IEA Natural Gas Information 2011 © IEA 20111501209060300IsraelIraqIranLibyaSyriaHalul IslandIdd El ShargiNorth Dome20092010UAEBaniasNICOSIAHomsTripoliBEIRUTSidon DAMASCUSHaifaAshkelon'AMMANZarqaAshdodDamiettaTantaMostorodEilatCAIRO SuezRas SidrAqabaAin SukhnaMersa BadranWadi FeiranRas GharibRas ShukheirSharm ElSheikhAsyut30ºEl ObeidTo Heglig &To Baleela Unity Oil fieldsANKARAKirikkaleAswanElzeitIcelCeyhanKHARTOUMTo Melut BasinOil fieldsUnyeDortyolArab GasPipeline 36”Port SudanEleazigDortyol LineYanbuRabighJeddahASMARAOmarBatmanT'BILISIYEREVANBazarganOrumiyehMosulRas IsaTabilizKirkukBaijiKermanshahHadithaBAGHDADDaurahBAKUSangaehal(Baku)AstaraQazvinArakEsfahanTurkmenbasyNekaNajafSamawahRumaila BasrahKhaur Al AmayaShirazKUWAIT MINA SAUDKhargsee KuwaitRasInsetAlKhafjiSouthJubailParsKhursaniyahHululJu’aymahLavanRas TanuraDasMANAMA Sitra RAS LAFFENBAHRAINSirriShedgumDOHAJebel AliMESASEEDABURIYADHsee Qatar InsetDHABIZirku RuwassHabshanToTrans Caspian PipelineTEHRANMaribSAN'A'As ShihrBir AliBalhafAden45ºCrude Oil ProductionData sourced from IEA Natural Gas Information 2011 © IEA 2011500000200920104000003000002000001000000IsraelIraqIranLibyaSyriaUAE300250200150100500SalalahSuqutra ̧ASGABATKhangiran SarakhsZahedanBandar-e Abbas IranshahrFetehJaskFujairahSoharMina Al FahalMUSCATQalhatTibalSiah RawlOil ReservesData sourced from OPEC/OAPEC © 2011IsraelIraqIran2010Jaz ratMas¸rahPak-Iran PipelineTASHKENTDUSHANBE60ºOil ConsumptionData sourced from IEA Natural Gas Information 2011 © IEA 201112000020082009100000800006000040000200000UAE30º23º30’15ºNWorld EnergyInsight 2010Of cial Publication of theWorld Energy Councilto mark the 21stWorld Energy CongressOFFICIAL PUBLICATION 2010ANDORRALA VELLAMenorcaMallorcaIslas BalearesLOMÉACCRAF R A N C ES W I T Z E R L A N D R O M A N I AIbizaPORTO-NOVOCorsicaTo Hassir’melGas FieldTrans-Medite ranean PipelineSardinia32”Pipeline16”PipelineWestWestLibya GasLibya OilTo NorthernItalyTo Gela,SicilyGreen Stream 32”SicilyLJUBLJANAZAGREBBELGRADE BUCHARESTTo Baumgarten,AustriaToThessaloniriCreteBosporusRhodesBLACKSEANabucco Gas PipelineM E D I T E R R A N E A N S E ATo VarnaSouth Va ley Gas PipelinePipeline 28”(To Port Sudan)Arab GasPipeline 36”Sea ofAzovBlue Stream PipelinePDOC Pipeline 32”(To Port Sudan)To Dzhubga,RussiaMedstreamTipline 42”Baku-Tbilisi-Ceyham (BTC) Pipeline 42”R e d S e aHaifa PipelineTrans-Arabian Pipeline (Tapline)South Caucasus PipelineIraq-Saudi Arabia Oil Pipeline (IPSA)NIAMEYS A U D IA R A B I AB U R K I N AOUAGADOUGOUOil production in total by region and byOil reserves in total by region andDJIBOUTIMIDDLE EAST OIL AND GASGas production in total by region and bycountryby countrycountryF A S ORESOURCES MAP 2011 DJIBOUTIN I G E R I AABUJAADDIS ABABAG H A N AE T H I O P I AC E N T R A LC A MA -F R I C A N R E P U B L I CS O M A L I ABANGUIYAOUNDÉBiokoMALABOB E N I NT O G OProduction Billion CU/MA L G ER I AVATICANCITYTUNISIAProposed/UnderConstruction Gas PipelineSLI T A L YOMALTAC RToHadithahI R AN I G E RSyriaSudanSaudi ArabiaQatarOmanLibyaLebanonKuwaitJordanIsraelIraqIranEgyptBahrainUAETurkeyTunisiaYemenOIraq Strategic PipelineQIraq-Saudi Arabia Oil Pipeline (IPSA)S A U D IA R A B I ATo YanbuMONT.KOS.MACEDONIA(F.Y.R.O.M)To TehranI R A NALBANIAK U W A I TGREECEEast-West NGL PipelineIraq Strategic PipelineL I B Y A S A U D IA R A B I AE G Y P TReserves Billion CU/MProposed/UnderConstruction Oil PipelineEgyptBahrainLebanonKuwaitJordanSudanSaudi ArabiaQatarOmanTurkeyTunisiaYemenShaybah - AbqaiqPipelineBAHRAINProduction Billion CU/MQ A T A RDOHA(AD DAWHAH) ,EgyptBahrainLebanonKuwaitJordanSudanSaudi ArabiaQatarOmanTurkeyTunisiaYemenS U D A NC A S P I A NS E AAbadanAl BasrahKazakhstanThe GulfY E M E NShaybahKTI Pipeline-Abqaiq PipelineNeka - Jask PipelineADCOP 48”ToRussiaSouthern O man Gas Line(Socotra)AralSeaCentral Asia-Center PipelineGulf of Oman48”Central Asia-China Gas PipelineTo ChinaTAPI PipelineARABIANSEATo IndiaTo MultanGas reserves in total by region andby countryLakshadweep(Laccadive Islands)BISHKEKT U R K E Y A NCYPRUSLEBANONISRAELS Y R I AJORDANERITREAG E O RGIAARMENIAI R A Q000 metric tonsEgyptBahrainAZERBAIJANLebanonKuwaitJordanKUWAITSudanSaudi ArabiaQatarOmanI R A NTurkeyTunisiaYemenQATARBillion BarrelsT U R KUNITED ARABEMIRATESEgyptBahrainO MM EANN I SYemenUAETurkeyTunisiaSyriaSudanSaudi ArabiaQatarOmanLibyaLebanonKuwaitJordanU Z B E K I S T A NT A N000 metric tonsAFGHANISTANPAKISTANTurkeyTunisiaSyriaSudanSaudi ArabiaQatarOmanLibyaLebanonKuwaitJordanIsraelIraqIranEgyptBahrainYemenM A L D I V E S

Innovation→ produces heat which is recovered to produce steamwhich in turn powers the process via the large steamturbines.Making liquid waxy hydrocarbons: The next stage inthe process sees the synthesis gas entering one of 24 reactorsin the plant. Each reactor holds tens of thousands of tubescontaining a Shell proprietary cobalt synthesis catalyst. Thesurface area of the catalyst used in the plant would coveran area equivalent to 18 times the surface area of the Stateof Qatar, and if the tubes were laid end to end they wouldstretch from Qatar to Japan. The catalyst serves to speed upthe chemical reaction in which the synthesis gas is convertedinto long chained waxy hydrocarbons and water. Shell hasfiled over 3,500 technical patents for its GTL process. For thePearl GTL project, Shell will have spent approximately fouryears using dedicated facilities in full-time production toprovide the thousands of tonnes of catalysts required.Making GTL Products: Using another Shell proprietarycatalyst, the long hydrocarbon molecules from the GTLreactor are fed into the hydrocracker where they are cut(cracked) into a range of smaller molecules of differentlengths and shape. The process changes the molecularstructure of the very heavy long chained hydrocarbonsinto products with lighter, shorter chains. They are thenfed into a distillation column to separate the variouscomponents. In liquid form they are safe, ready to be usedand easily distributed around the world.SafetyHSE on Pearl demonstrates a performance of 10 timeslower lost time incidents than the Industry average1.000.5000.660.23 0.230.55Oil and gas producers2007 2008200920100.100.45Despite the massive number of workers involved and thecomplexity of the construction of Pearl GTL, a strong andfocused safety culture has helped Qatar and Shell achieve arecord-breaking 77 million hours onshore without injuriesleading to time off work.A benchmark for worker welfare has been set on Pearlwith the introduction of Pearl Village, a 170 acre residentialarea that was specifically built to house constructionworkers. It was designed to meet rigorous standards insanitation, health, safety, catering, recreation, IT, multi-faithworship, and banking facilities. Central to the Pearl Villageis “Al Muntazah”, the Arabic word for park.This recreation area forms the backbone of the villageand provides extensive sports facilities including cricket,football and baseball pitches, an outdoor cinema, safetytraining centre and shaded seating areas.The ethos of the facility is to create a “home awayfrom home” where the welfare of each and every workeris looked after holistically. A community environmenthas been formed with a Mayor and a dedicated teamwho are responsible for welfare, cultural festivals andact as advocates within the community. To overcomecommunication barriers, courses have been given atthe onsite training centre in seven languages includingHindi, Arabic and Tagalog. By early 2011, workers hadparticipated in some 367,500 training sessions. At thepeak of construction, it took a huge workforce of over1,800, including 500 cleaners and over 1,000 kitchen staff,to ensure that the village ran smoothly.Research demonstrates that this uniquePearl GTL0.04village community has greatly helpedto consolidate, motivate and focusthe workers and in doing so increaseproductivity, efficiency and output. QatarShell’s commitment and focus on safetywas recognised by HE Dr Mohammed Al-Sada, Minister of Energy and Industry, on16 May 2011, when it was awarded theinaugural Oil and Gas Industry Gold Awardfor Safety.In terms of advances in new technologies,the number of new patents raised, themagnitude of the scale of construction,significant developments in worker welfare,outstanding health and safety records,Pearl GTL is a colossal and remarkableachievement by all those involved. •Energy Solutions For All 141

InnovationFloating Liquefaction (FLNG):How far will it go?By David Ledesmasenior associate, Oxford Institute for Energy StudiesSource: ShellThe liquefaction of gas offshore utilising floating LNG(FLNG) has been the nirvana of LNG developerssince the basic concept was developed in the1990s. Companies saw the potential of FLNG asa means to access stranded gas fields that could nototherwise be economically developed, either becausethey are too far from shore, or too small to support aneconomic land-based liquefaction project. In May 2011‘theory’ took a huge step closer to ‘fact’ as Shell took thefinal investment decision on its 3.5 million tonne Preludeproject in Australia with start-up in 2016/7, a strategicmove as the company aims to replicate the concept forother projects in a “build one build many” strategy. Othercompanies have also announced that they are planningto move ahead with FLNG projects. Flex and Hoegh haveeach claimed that they will launch rival projects in PapuaNew Guinea by 2014, though neither company has takenFinal Investment Decision (FID), and no sooner had Shellannounced its decision to move ahead with the projectthan Malaysia’s Petronas announced it was going aheadwith Technip to develop a smaller 2 million tonne projectto commercialise offshore Malaysian gas fields. FLNGprojects are certainly gathering momentum, but whichprojects will go ahead and why?Why FLNG?Growing demand for clean energy, recent policy movesArtist’s impression of the Shell Prelude FLNG Projectaway from nuclear and a perception that gas pipelines maynot necessarily give the assurance of security of supply thatgas buyers seek, underpins a good growth story for LNG.Estimates are that LNG demand will double by 2025 and,in reality, if an economic project can be developed thenbuyers will be in place for the volume – but where are theprojects that will supply this demand? Discovered offshoregas reserves, which have been defined by many developersas “stranded” due to their remoteness or location in deepwater often cannot be developed commercially usingonshore facilities. Where this is associated gas it is often reinjectedor simply flared – thus foregoing the market valueof the gas. Liquefying the gas offshore can access morereserves and stop flaring, thereby giving a low opportunitycost for the gas compared with liquefaction. Offshore LNG,therefore, saves building a sub-sea pipeline to move gas toshore, gives access to smaller reserves economically andtheoretically the unit can be moved to a new location oncethe exploitation of the original field is completed.Project promoters also argue that the costs of marineliquefaction and loading facilities are lower than those ofonshore plants – some developers claim 20-30 per centcheaper – and that construction time can be up to 25 percent shorter than land based projects, as the facilities canbe built in yards that have purpose built facilities, not inthe remote greenfield locations that are typical of manyonshore projects. Permitting and approval processes areseen as easier than similar onshoreplants as offshore projects aresubject to different regulationrequirements. Floating Storageand Re-gasification Unit (FSRU)projects potentially open upthe business to newer smallercompanies to participate in theLNG sector. In a business that,to date, has used economies ofscale as a means to reduce unitcosts, (which has meant that theabsolute cost of the projects hasincreased), size and, therefore,high costs have acted as a barrierto entry. The involvement of newplayers can only be good news toa contractor capacity constrainedbusiness. Project developers alsoargue that the lack of onshore sites14220th World PETROLEUM Congress

Innovationfor liquefaction plants means that they are being pushedoffshore to develop new projects. FLNG thus removes amajor obstacle to bringing these gas fields to market.OptionsThere are two designs that are being considered by projectdevelopers:Barge based facility that would carry the size of plantthat could be built onshoreUnder this design, the liquefaction facilities are mountedon a barge-like structure, with the LNG stored in the hullunderneath. On 20th May 2011, Shell announced its intentionto go ahead with this design concept in the world’s firstFLNG project at the Prelude field 200km offshore WesternAustralia in 200-250 metres of water. The project has beendesigned to produce 3.6 million tonnes of LNG, 1.3 milliontonnes of condensate and 0.4 million tonnes per annum ofliquid petroleum gas (these liquids providing an importantrevenue to support the project’s economics). The vessel isbeing constructed in the Samsung yard in South Korea bya joint venture of Samsung Heavy Industries and Technip.The construction is scheduled to be completed in 2016with start of production planned for late 2016 or early2017. The liquefaction unit will be 488 metres long - thelength of which is equivalent to four soccer pitches or thefirst hole at Augusta golf course, Georgia, USA (home ofthe annual US Masters golf ) and weighs 600,000 tonnes.Shell is promoting a second FLNGvessel to be used for the developmentof the Sunrise field in the Timor Sea inthe Joint Development Area betweenAustralia and Timor Leste. This projectis not currently proceeding, as theTimor Leste Government wouldprefer the project to be developed asan onshore plant. Until this is resolved,the project is unlikely to move forward.Petrobras has also been consideringfloating LNG as a means to evacuategas from the huge pre-salt associatedgas reserves offshore Brazil. Japan’sInpex is planning an FLNG project tocommercialise gas in the Masela blockin Indonesia. In July 2011 it announcedthat Shell had taken a 30 per centstake in the Masela block, and Inpex inits statement said that Shell’s expertisein large-scale offshore gas development activities and itsFLNG experience were factors in its decision to involveShell as a partner. At the same time, Inpex announced thatit intends to award front-end engineering and design inthe first half of 2012, which would suggest a 2013 FID andstart-up in 2018.Ship based design, where the liquefaction plant is builton a purpose built vessel that is sized as a conventionalLNG shipThis design is being pursued by several companiesincluding; Flex LNG; SBM/Linde/IHI; Hoegh LNG/Lummus(CB&I)/Aker; Teekay; Excelerate Energy; MalaysianInternational Shipping Company and GDF Suez. All thesecompanies are looking at developing FLNG projects in the1.5-3.00 million tonnes per annum range. Flex orderedfour FLNG vessels from the Samsung yard in South Koreain 2007, and at that time announced that they would beproducing LNG by 2011 - to date none have been deliveredas the liquefaction projects are yet to be firmed up. Noother production units have been ordered.Companies were initially looking at developing these FLNGunits as offshore projects, but the focus of two companies,Flex and Hoegh, has moved to placing the FSRUs inside aharbour, therefore reducing some of the technical risks ofoperating in open water. Both companies have plans touse in-harbour FSRUs for the commercialisation of gas in →Artist’s impression of Flex LNG Papua New Guinea proposed FLNG projectSource: Flex LNG presentation to the FLNG Conference. London, 2011Energy Solutions For All 143

Innovation→ Papua New Guinea. In April 2011, Flex LNG announcedthe signing of firm agreements with InterOil Corp, PacificLNG, LNGL and SHI to develop an inland FLNG jettylocation for a 2.0 million tonnes FLNG facility with acondensate stripping plant to use gas from the Elk andAntelope Gas fields. In May 2011 Hoegh LNG announcedthat it had established a holding company “PNG FloatingFPSO Ltd” with Petromin PNG Holdings Limited and DSMEE&R Limited to develop a LNG FPSO project in Papua NewGuinea and to develop a FLNG project, to be constructedat the DSME ship yard in South Korea, capable of producingup to 3 million tons of LNG annually, with a storage capacityof 220,000 cubic metres.Other companies are developing FLNG projects; forexample in February 2011 Malaysian state-run Petronas andMalaysian International Shipping Corporation awarded afront end engineering and design contract for an FLNGproject to Technip and Daewoo for a project in Malaysia.GDF Suez is developing the Bonaparte FLNG project inNorth-Western Australia, targeting first LNG in 2018, andExcelerate is looking to develop a 3 million tonne facility,using three one million tonne LNG trains, and havingcompleted front-end engineering and design (FEED), theyare currently evaluating which project to proceed on.Challenges to developmentThe list of challenges to the development of FLNG hasbeen long discussed at LNG conferences and used bytraditional LNG project developers to gain advantage overoffshore projects. Yes, the challenges are many, but theindustry needs change and access to new liquefactioncapacity and certainly FLNG projects will be developed –the key question is when and how many?All LNG projects, floating or land based, are capitalintensive and structured around long-term, offtakeagreements to provide the necessary revenue flow tosupport the project economics and, in many cases, thefinancing of the project. FLNG is a new technology andthis means that lenders, who are often conservative intheir approach, will seek support guarantees from projectsponsors. Finance will, therefore, be difficult to obtainunless the shareholders are large creditworthy companies;indeed in such cases the companies will probably preferto finance off their own balance sheets. This will meanthat smaller companies without deep balance sheets willnot be able to develop such projects or will have to bringlarger companies or governments in as shareholders togive the necessary credit support.FLNG also faces local in-country challenges – oftengovernments see LNG projects as a means to develop theirinfrastructure and create jobs. Can FLNG projects achievethe local content requirements that governments seek,especially as a key advantage of FLNG is that the vesselscan be constructed in specialised shipyards, thus avoidinglocal costs of development and potentially speeding upthe project? Can the cost savings be achieved? Will therebe cost overruns as developers start implementation?Developers also face technological challenges. Can thefacilities economically manage the treatment of liquidsand impurities? Will the facilities have enough flexibilityto manage changes in gas quality, in the feed gas eitherat the first location or, if moved to an alternative location,from new gas fields of a different quality? In such casesadditional equipment may be required. But if so, will thereArtist’s impression of Flex LNG Papua New Guinea proposed FLNG project Source: Hoegh LNG presentation to the FLNG Conference. London, 201114420th World PETROLEUM Congress

Innovationbe space on the FLNG for such changes? Will space onthe vessel be a limiting factor? There has also been a lotof discussion by project developers about the operationalchallenges facing FLNG – will the workforce be safe? Howto manage the transfer of LNG between two floatingstructures using flexible hoses? How will the liquefactionequipment perform when the vessels are in motion onthe sea? All these challenges will have to be resolved andproven as manageable to the sponsors and financiers. And,finally a key point, how will they impact on the projecteconomics. Developers are indicating unit costs in therange US$700m to US$1bn per million metric tonnes 1 (theShell Prelude project is reported to potentially be abovethis range), and at these costs, is FLNG still attractive toproject developers? If costs were to be substantially abovethis range, it may move developers towards favouringland- based liquefaction projects.Commercial structuresFLNG projects are likely to include a range of differentstakeholders including upstream participants, nationaloil companies (or equivalent), FLNG vessel owners and/or operators, buyers of LNG (and natural gas liquids),vessel suppliers to move the liquids and suppliers ofservices to the FLNG and Federal/State/Local governmentbodies. Some of these stakeholders are new to the LNGliquefaction business and this could give rise to structuringcomplexities. Economic viability and cost of procuringthe vessel and the allocation of risk for failure to performacross the LNG chain, as a result of the FLNG not operatingcorrectly, will mean that lenders will seek extensivecompletion guarantees which may not fall away until along time after start-up. For example, if an FLNG has beendesigned to withstand a specific strength of storm, lendersmay insist that shareholder guarantees do not fall awayuntil such a storm has been experienced, and this may onlyhappen every 5 or 10 years, then the guarantees wouldhave to remain in place for that period of time.This would encourage the development of these newtechnology projects by large credit-worthy companies whocan finance from their own balance sheet, without recourseto third party debt. This is what Shell has done with thePrelude FLNG project, keeping 100 per cent of the equityand using corporate debt to finance its construction. Shellwill also take all the output into its LNG portfolio and thereported LNG sales of 0.8 million tonnes to Osaka Gas and2 million tonnes to CPC will be supplied from this portfoliowithout a link to the Prelude project as a single supplysource. This will mean that Shell can develop the projectwithout “partner drag” and so focus on the technical aspectsof the project without the distractions of marketing of theLNG and project financing. The LNG buyers also have thecomfort that if Prelude is late for any reason, then theystill get their LNG from the Shell portfolio of aggregatedvolumes. It will be difficult for smaller companies to structurea similar deal: their commercial structure would have to beestablished such that the risks are allocated specifically togive the buyer the necessary supply assurances that theLNG will be produced from the FLNG facility, while givingthe developer the contractual and technical freedom todevelop the project. These joint challenges may explain thedelays in many FLNG projects to date.ConclusionsCompanies have been looking at FLNG as a means toproduce LNG since the 1990s, and maybe earlier, with 2011seeing the first FID. There are several other projects beingconsidered with many companies seeking to succeed inthis next frontier for LNG.The key challenges are technology and financing,and these are inextricably linked. Once the first projecthas been successful the technology risk will reduce andbankers will be more pre-disposed to lend money, thusopening up the sector to smaller companies who aspireto be project developers. Projects with large backers, orother economic drivers (such as the Brazil pre-salt wherethe gas has to be moved to enable vast oil reserves to betapped) will proceed; others where technological risks canbe reduced (such as locating the FLNG facility in a harbour)may also proceed. But the number of “true” offshore FLNGunits will be limited until the industry has seen a trackrecord of successful operation.The industry needs new technology to access andmove remote deep water gas to market. FLNG is such atechnology and is here, hopefully, to stay. That said, itsimpact on overall LNG production will be limited andby 2025 could represent only 5-10 per cent total LNGproduction globally.•1. The industry compares liquefaction costs using an indices of $ /metric tonneinstalled capacity (i.e. the capital cost of a project divided by its capacity).Whereas in the period up to 2005 liquefaction costs were $300-600/metrictonne installed capacity (MTIC), newer projects are proceeding at far highercosts. Over the period 2008-2011 projects have taken investment decisionson the basis of capacity costs in the region $1000-1800/MTIC or higher (withexpansion projects $700-900/MTIC).Energy Solutions For All 145

InnovationCarbon capture and storageand the oil and gas sectorBy Brad PageChief Executive Officer, Global CCS InstituteOften overlooked has been the petroleumindustry’s own important role in developingcarbon capture and storage, and deploying CCSin the future in order to stabilise carbon emissionsin the atmosphere. The need for stabilisation of emissionshas been starkly underlined by the IntergovernmentalPanel on Climate Change’s (IPCC) Fourth TechnicalAssessment Report (2007). This contained three importantfindings about global warming:• warming of the climate system is unequivocal;• most of the observed increase in global averagetemperatures is very likely due to human-inducedgreenhouse gas (GHG) emission concentrations in theatmosphere and• it is likely that there has been significant human-inducedwarming in the past 50 years.The IPCC estimates the global temperature increase inthe coming century could be between 1.8-4.0°C, which ismuch more rapid than any temperature changes knownto have occurred during the past 10,000 years .To limit climate change, GHG emissions need to bereduced significantly.In 2010, the United Nations Framework Conventionon Climate Change (UNFCCC) Conference of Parties 16(COP16) adopted a non-legally binding goal to limit globaltemperature increases from pre-industrial levels to 2°C. Thisis equivalent to stabilising greenhouse gas concentrationsin the atmosphere to about 450 parts per million of CO2equivalent by 2050 (with CO 2concentrations stabilisedat less than 400 parts per million). This compares to anestimated concentration of CO 2in the atmosphere ofaround 395 parts per million in June 2011.Achieving the degree of decarbonisation implied by theabove statistics – no further growth in the concentrationof CO2 in the atmosphere over the course of a generation– is a challenge that can only be met by using a number oftechnologies in parallel.Scenarios by the International Energy Agency (IEA)indicate that CCS could account for some 19 per cent ofenergy-related GHG emission reductions, on a par with thecontribution from renewable energy and other efforts, ifgreenhouse gas concentrations in the atmosphere are tobe stabilised by 2050. CCS is particularly important if thisstabilisation is to be achieved at least cost.CCS involves capturing bulk CO 2from large stationarysources, transporting the CO 2often via pipeline or othermeans (e.g. barge or tanker) and storing the CO 2in ageological formation (for example, a depleted oil and gasreservoir, deep saline formation or an oil field suitable forenhanced oil recovery).Much of the public policy discussion surrounding CCSin recent years has focussed on the power generationsector. This focus is understandable. It is prudent thatgovernments take action to improve the costs anddemonstrate the performance of CCS in the powergeneration sector, where future emissions will eclipseall other industrial sectors and where the application ofcapture technologies is considered to be immature and inneed of “demonstration”. This is also the case in other highemitting industries such as iron and steel and cement.The origins of CCS are found in the oil andgas sectorThe same capture technologies considered not yetmature in power and many industrial applications havebeen commercially deployed by the gas processing andchemical industries for decades.Substantial pipeline networks already exist fortransporting CO 2. Most are in North America and are usedto supply CO 2for Enhanced Oil Recovery (EOR), with morethan 5,900km of operating pipeline infrastructure.In terms of storage applications, CO 2use in EOR has a longhistory and represents an area of significant experienceand expertise as well as an annual injection in the US ofover 50 million tonnes per annum (Mtpa) of both naturaland anthropogenic CO 2.Through its annual survey of large-scale integrated CCSprojects in 2010, the Global CCS Institute has identified eightoperational projects. All of these projects have direct links tothe oil and gas sector although the drivers for each are diverse.One of the first operational projects was ExxonMobil’sShute Creek Facility in 1986 in Wyoming. Using naturalgas separation, today, this facility separates around 7Mtpa of CO 2and pipes it over 120 miles to a number ofpurchasers, including Chevron and Anadarko for EOR. Theneed to separate the CO 2from the methane to create amarketable product, use of commercially available naturalgas separation technology and significant EOR potentialhas made this project viable.The same model applies to Occidental’s Century Plantand the Val Verde Gas Plants in Texas, both of which use CO 2from natural gas separation to provide millions of tonnes ofCO 2each year for EOR. In addition, the Great Plains SynfuelPlant and the Enid Fertiliser plant both have similar models14620th World PETROLEUM Congress

InnovationLarge-scale integrated carbon capture and storage projects in operation and constructionName Location Capture type Volume CO 2(Mtpa)Operation stageStorage typeSleipner CO 2Injection Norway Gas processing 1 Mtpa Deep saline formation Statoil ASAKey proponentsSnøhvit CO 2Injection Norway Gas processing 0.7 Mtpa Deep saline formation Statoil ASAIn Salah CO 2Injection Algeria Gas processing 1 Mtpa Deep saline formation BP, Sonatrach,Statoil ASAGreat Plains Synfuel Plant and Weyburn-Midale Project United States/Canada Pre-combustion(synfuels)3 Mtpa EOR Dakota Gasification,Cenovus Energy,Apache CanadaShute Creek Gas Processing Faiclity United States Gas processing 7 Mtpa EOR ExxonMobil, Chevron,AnadarkoEnid Fertilizer Plant United States Pre-combustion(fertiliser)0.68 Mtpa EOR Koch Industries,Chaparral, AnadarkoOccidental Gas Processing Plant United States Gas processing 5 Mtpa (and 3.5 Mtpain construction)EOROccidental PetroleumVal Verde Natural Gas Plants United States Gas processing 1.3 Mtpa EOR Blue Source,PetroSource EnergyConstruction stageEnhance Energy EOR Project Canada Pre-combustion(fertiliser and oil refing)1.8 Mtpa EOR Agrium Fertiliser,North West Upgrading,Enhance EnergyGorgon Carbon Dioxide Injection Project Australia Gas processing 3.4 - 4 Mtpa Deep slaine formation Chevron,ExxonMobil, ShellPlant Ratcliffe United States Pre-combustion(power)Saskpower Boundary Dam 3 CCS Project Canada Post-combustion(power)2.5 Mtpa EOR Mississippi Power,Denbury Resources1 Mtpa EOR Saskpowerusing CO 2separated by commercially available technology(synfuel and fertiliser production respectively) for EOR.In Norway, there are another two operational projectsbut the motivation for storing CO 2is quite differentto enhanced oil production. In 1991, the Norwegiangovernment established a tax on GHG emissions. Inresponse to the US$51 per tonne of CO 2tax, the Sleipnerand the Snohvit projects have been injecting around1 Mtpa and 0.7 Mtpa of CO 2into offshore deep salineformations since 1996 and 2007 respectively. While theyboth use natural gas separation technology, the storageof CO 2into deep saline formations has been prompted byhaving an adequate price on carbon.Another operating project is In Salah in Algeria, whichseparates and injects around 1 Mtpa of CO 2into a deepsaline formation.. This project has no external financialincentive driving the CO 2storage component of the gasfield operation. While there are subsurface lessons thatcan be transferred to other CCS projects), there is anexpectation that this project could receive carbon creditsthrough the UNFCCC’s Clean Development Mechanism(CDM). This is an important point for many potentialCCS projects in developing countries. The CDM is meantto allow emission-reduction projects in developingcountries to earn certified emission reduction (CER)credits. These CERs can be traded and sold, and used byindustrialised countries to meet a part of their emissionreduction targets under the Kyoto Protocol. While no CERshave been received to date for any CCS project, in 2010 atCOP16 the Meeting of Parties agreed (subject to generalrecommendations from the Subsidiary Body for Scientificand Technological Advice which is advising the UN) toinclude CCS as an eligible project activity under the CDM.This may eventually provide a financial incentive for CCSprojects in developing nations.In addition, the four CCS projects currently in constructionalso have direct links to the oil and gas sector. Over the pastyear an important development has occurred in that →Energy Solutions For All 147

Innovation→ the inclusion of captured CO 2from power facilities is nowa factor. The two projects of note are Mississippi Power’sPlant Ratcliffe and Saskpower’s Boundary Dam project inSaskatchewan. In both projects CO 2captured from powerplants will be injected for EOR.These 12 projects, as well as the broader CO 2EORexperience, highlight the extensive contribution of the oiland gas sector. This contribution includes:• the commercial scale separation of bulk CO 2to near purity;• the compression, safe handling and transport of CO 2overlong distances at high pressure and extreme temperatures;• the exploration and appraisal of suitable EOR injectionsites and suitable storage sites in deep saline formations;• CO 2injection well design and development and• reservoir management practices, including measurement,monitoring and validation.All of these activities are central to the oil and gas sectorand all of these will be required in demonstrating CCStoday and deploying CCS into the future.The future of CCS and the oil and gas sectorThe above analysis of projects also provides a valuablestock of information that can be drawn upon to supportthe current demonstration of CCS. While this knowledgeneeds to be applied to a broad range of industries (power,cement, iron and steel, fertiliser production, refining, gasseparation, ethanol production, etc), much of the effort,skills and expertise of developing CCS projects resides inthe foundations of the oil and gas sector. By sharing thisGreat Plains Gasification and CO 2Capture Plantknowledge, the oil and gas sector can support acceleratedtechnology diffusion, improved public understanding ofCCS, cost and risk reduction and accelerated innovation.Overall, these active projects provide knowledge, insight,and lessons into developing CCS projects that can assistothers to do so more effectively.These projects also show that the drivers for CCS arediverse and growing. In some limited instances theapplication of CCS was commercial. In others, a price oncarbon was sufficient and indicates that CCS can be morecost effective than paying to emit. Current studies similarlyshow that in some industries, for example, natural gasprocessing, fertiliser production and ethanol production,the cost of applying CCS could be as low as US$20 pertonne CO 2according to a 2011 report by Worley Parsons,commissioned by my institute. This cost represents thecost of adding compression, transport and storage wherea pure stream of CO 2already exists.Building on this, the CDM provides promise for thearrival of CCS projects in developing countries, especiallyin industries where the costs of applying CCS are lowerand only a modest incentive is required. Ultimately asignificant price on carbon will be required to see CCSdeployed in future high emitting industries and countries.As governments move towards this, it is likely that new CCSprojects will be developed, greater innovation will emergeand that the oil and gas sector will be heavily involved.Since the beginning, the oil and gas sector hasresponded to incentives that apply to CCS. This has beenshown through developing thefirst set of operational CCS projectsand through the current suiteof projects being developed todemonstrate CCS in industries suchas the power sector. All of the currentdemonstration projects and thosein the future that arise in responseto new incentives will require anumber of the core skills (individualand work practices) contained in theoil and gas sector. The past, presentand future of CCS and the oil and gassector are intertwined. Perhaps thiscombination can make significantinroads into the mountainous taskof decarbonising the energy sectorand reducing global warming. •14820th World PETROLEUM Congress

InnovationThe challenge ofsustainable biofuelsBy Anselm Eisentraut, Renewable Energy Divisionand Michael Waldron, Oil Industry and MarketsDivision, International Energy AgencyBiofuels have a long history that tracks back to thelate 19th century, but it was not until the 1970sthat the sector witnessed some growth in Braziland the US which both put support policiesin place. In most other regions, a significant growth inbiofuel production took place only in the last 10 years.Global biofuel production grew around five-fold duringthis period reaching 1.8 million barrel/day (mb/d), drivenby concerns over energy security and climate change, aswell as governments’ will to create new sources of incomein rural areas.Medium-term outlookDramatically rising oil prices in the first half of 2011would appear to be a boon to biofuels production goingforward. Indeed, from 2010-2016, the IEA’s Medium TermOil & Gas Markets 2011 forecasts that biofuels output willrise by 0.5 mb/d, a near 30 per cent increase. Yet, marketconditions and production economics have also becomemore challenging, even with high oil prices, underminingproduction in Brazil and Europe in particular. Difficultweather conditions, strong emerging market demand,increased energy costs, and to some extent usage from thebiofuels industry itself have all tightened balances in manyagricultural commodities. As such, biofuels productiongrowth is expected to slow in 2011 after a strong 2010.Over the medium term, biofuels will still help satisfy asignificant part of oil demand growth, though less thanbefore. From 2004-2010, biofuels supply growth, on anenergy-adjusted basis, met 23 per cent of global incrementalgasoline and gasoil demand, with ethanol at 48 per cent ofgasoline and biodiesel at 10 per cent of gasoil growth. From2010-2016, with combined gasoline and gasoil demandgrowing by 4.3 mb/d, biofuels supply growth should meetonly 9 per cent, with ethanol constituting 24 per cent ofgasoline and biodiesel accounting for 4 per cent of gasoilgrowth. By 2016, ethanol and biodiesel should displace 5.3per cent and 1.5 per cent of total global gasoline and gasoildemand, respectively, on an energy content basis.Feedstock prices and production economics forconventional biofuels will likely remain volatile in themedium term. Conventional biofuels, often referred toas first generation, are produced from starch, sugar or oilburningcrops. As such, government policies – blendingmandates, production subsidies and blenders’ credits– will continue to serve as key production supports. Inan environment of fiscal austerity, financial incentivesare increasingly at risk, particularly in the US. However,mandated quotas and targets continue to rise, withEU Member States, Argentina, Canada, Thailand, Peru,and Malaysia all increasing required blending volumes.Notably, the fulfilment of government usage targets asthey currently stand suggests production upside. Our2010-2016 growth forecast of 520,000 b/d undershoots by670,000 b/d the potential supply increases, were nationallevel policy targets in major biofuels markets to be met.Biofuels will face a number of challenges, including botheconomic as well as non-economic ones such as policyuncertainty, competitiveness of biofuels, sustainabilityrequirements and consumer acceptance that might affectpotential output. It is therefore important to identify thesepotential challenges and address them in the short term toachieve long-term targets. The IEA – in its recently launchedtechnology roadmap Biofuels for Transport – assesses keyactions and milestones that need to be taken to allow fora large-scale development of the biofuel sector to 2050under an ambitious emission reduction scenario, cuttingenergy-related CO 2emissions by 50 per cent in 2050 over2005 levels. The roadmap analysis indicates that biofuelscould provide up to 27 per cent of world transportationfuel by 2050 and thus avoid about 2.1 Gigatons (Gt) ofCO 2emissions in the transport sector when producedsustainably. Despite considerable potential for energyefficiency measures, and electrification of light dutyvehicles, biofuels will play an important role to providelow-carbon fuel in particular for airplanes, marine vesselsand other heavy transport modes.The roadmap envisions an increase in global biofuelconsumption from 55 million tonnes oil equivalent (Mtoe)today to 750 Mtoe in 2050 with demand for biofuels expectedto pick up considerably in all world regions. Engagingdeveloping and emerging economies in technologydevelopment and capacity building will therefore be crucialin meeting the roadmap targets.Efficient technologies neededConventional biofuels have been criticised in recent yearsregarding their limited potential to save greenhouse gases,their high production costs and potential competitionfor land and grain for food production. It is important tonote, however, that some biofuels perform well in termsof land-use efficiency, life-cycle greenhouse gas savingsand production costs. Nonetheless, deployment of moreenergy- and land-efficient conversion technologies, in →Energy Solutions For All 149

Innovation→ particular advanced biofuels produced fromlignocellulosic energy crops and residues , is required toachieve a significant contribution of biofuels to futuretransport fuel demand. Support for advanced biofuelresearch, development and demonstration is still neededin the short term. Most crucial, however are specific supportmeasures that address the high investment risk associatedwith pre-commercial advanced biofuel technologies.Government action will be crucial to provide a stable,long-term policy framework for biofuels will be vital totrigger industry investments in first commercial plants andsustained investments in sustainable biofuel expansion.Sustainable biomass supplyTo produce the amount of biofuel envisaged in the IEABiofuel Roadmap will require biomass feedstocks of morethan 3 billion tonnes of dry biomass, in 2050. This feedstockdemand could well be met with low-risk biomass sources,such as residues and wastes as well as sustainably grownenergy crops. The latter still have great potential for yieldimprovements, in particular in developing countries, asmany potential feedstock varieties have not yet beensubject to commercial breeding efforts. This could limitthe amount of land needed in 2050 to around 100 millionhectares of land, a three-fold increase of the gross areaunder biofuels compared to the current level. In addition,better efficiency of biomass use, for instance throughintegrating biofuel and bio-material production inbiorefineries, will also be vital to reduce land competitionand associated negative land-use changes, and helpimproving the economics of biofuel production. Meetingthe targets of the IEA biofuel roadmap will requiresubstantial investments in crop breeding and large-scalefield trials for promising biofuel feedstocks as well as thevigorous adoption of best agricultural practices to achievesustainable yield improvements. Improved land-usemapping will also be vital to identify those areas with goodpotential for feedstock cultivation and little risk of foodcompetitionand indirect land-use change.Having a sound international policy framework in place isa prerequisite to ensure the required amounts of feedstockand land can be made available in a sustainable way, withoutcompromising food security, threatening biodiversityor limiting smallholders’ access to land. SustainabilityEJ353025201510Figure 1: Demand for biofuels (left) and resulting landdemand (right) in the IEA Biofuel RoadmapMha110100908070605040302051002010 2015 2020 2025 2030 2035 2040 2045 2050 2010 2015 2020 2025 2030 2035 2040 2045 2050Biomethane Biojet Biodiesel – advanced Biodiesel – conventionalEthanol – cellulosic Ethanol – cane Ethanol – conventional15020th World PETROLEUM Congress

Innovationcertification of biofuels, following internationally agreedsustainability criteria, and involvement of all stakeholdersalong the production chain will be vital elements to ensuresustainability of the biofuel sector. Since many sustainabilityissues related to biofuels are in fact concerning the wholeagricultural sector, biofuel policies should be aligned withthose in agriculture, forestry and rural development. In thelonger term, an overall sustainable land-use managementstrategy for all agricultural and forestry would help toavoid land-use changes with negative impacts on theenvironment and CO 2emissions, and to support the widerange of demands in different sectors.Economics of biofuel production and useWith substantial investments in place, most biofueltechnologies could get close to cost-competitivenesswith fossil fuels, or even be produced at lower costs inthe longer term. Production costs for advanced biofuelscould reach cost-competitiveness with gasoline or dieselaround 2030 in optimal cases. However, future productioncosts will depend on the impact of oil price on feedstockand capital costs. Depending on the actual productioncosts, total expenditure on biofuels required to meet theroadmap targets is estimated between US$ 11-13 trillionover the next 40 years, representing a modest share of11-12 per cent of total spending on transport fuels. Evenwith a strong correlation between rising oil prices andfeedstock and capital costs, the additional costs of biofueluse compared to use of diesel/gasoline are in the orderof 1 per cent of total costs of transport fuels over the next40 years. With lower production costs, biofuels could evenlead to actual fuel cost savings.International collaboration is vitalInternational collaboration, to ensure technology transfer,capacity building and involvement of all stakeholder, inparticular in developing countries, will be critical to realisingthe vision of a sustainable, large-scale biofuel deploymentlaid out in the IEA Biofuel Roadmap. In order to stimulatefinancing on the scale required to realise the deploymentof sustainable biofuels envisioned in this roadmap,governments must take the lead role in the coming years tocreate a favourable climate for industry investments. •IEA Biofuel Roadmap is available at the IEA website: www.iea.org/roadmaps.Brazil harvests sugarcane for biofuelsEnergy Solutions For All 151

InnovationFuture propulsion forpersonal mobilityBy Chris Borroni-Bird and Mary Beth Stanek,General MotorsMore than half the world’s population now lives incities and, according to the United Nations, thisfraction is expected to increase to 60 per centby 2030. Moreover, 80 per cent of the world’swealth is expected to be concentrated in urban areas in2030 so that issues influenced by wealth (such as materialsand energy consumption and greenhouse gas emissions)will be increasingly determined by urban dwellers. In short,it will not be possible to solve these global issues withoutaddressing the challenges posed by urbanisation.Mobility enhances our lives by allowing contact withothers, offering new experiences and supporting theexchange of ideas and goods. Cities facilitate connectingpeople and goods but their roads are becoming increasinglycrowded. This is particularly acute in emerging markets,with increased migration from rural to urban areas andwith increasingly wealthy people aspiring to automobileownership. Despite heavily congested roads, there is stilla desire for personal mobility in urban centres because noother means of transport has so far offered the same mixof freedom, comfort, utility and security as the automobile.However, to achieve sustainable urban mobility wewill need to fundamentally reinvent the automobile topreserve the basic appeal of personal mobility (“go whereyou want, when you want with whom you want”) whileaddressing the societal challenges of congestion, land usefor parking, air pollution, greenhouse gas emissions androad accidents.EN-V concepts outside the SAIC-GM Pavilionat 2010 Shanghai World ExpoA proposed solution from General Motors is the EN-V(Electric Networked Vehicle, pronounced “envy”) conceptthat was introduced at the 2010 Shanghai World Expo asa vision to support the Expo theme of “Better City, BetterLife”. EN-V is a battery electric vehicle that can reduceenergy consumption and environmental emissions. Ituses a dedicated short range communications, sensingand Global Positioning System (GPS) platform to enablevehicle networking to reduce congestion and accidents. Itis a small footprint, highly manoeuvrable vehicle that canreduce parking space requirements, energy consumptionand ownership costs.EN-V type vehicles could weigh around 500 kgand consume around 100 Wh of electricity per km(approximately 200 miles per gallon on a gasoline energyequivalent basis). This is possible because the vehicles mayonly need to have a range of 30 miles (not 300 miles), mayonly need to travel at speeds of up to 30 mph (not 100mph) and may only need to accommodate 1 or 2 people(not 5 or 6). Compared with today’s vehicles, they canprovide safe, convenient personal urban mobility at aboutone quarter the total cost per mile, and will need only onefifth of the land for parking. The same technology thatallows them to network and sense each other to reducecollisions will also enable autonomous driving and helpprovide accessibility to address another megatrend – theincreasingly aging population.This new DNA for the automobile, based on electrificationand connectivity, rather than today’s petroleum-fueledvehicles that operate as stand-alone transportationproducts, will also improve the integration of personal andpublic transport so that a new mobility system, offeringthe best features of both, can be realized. The convergenceof electrification and connectivity, tied to the modestdriving needs for urban dwellers, creates the opportunityto reinvent automobiles and fundamentally change howwe move around. This quantum leap may be what isneeded to meet the urgent sustainability challenges thatface densely populated urban centres around the world,where the world’s population is increasingly living.The situation outside the densely populated cities isdifferent. Mobility needs for daily travel can be longer (morevehicle miles travelled), duty cycle requirements can begreater (more movement of goods over longer distances),and roads and terrain can be uneven and unpredictable.Electrically-driven vehicles could also play a significantrole outside cities. However, to overcome range anxiety15220th World PETROLEUM Congress

Innovationand the limited recharging infrastructure, the source ofelectricity may need to come not only from a battery butalso from an on-board range extender (as on the ChevroletVolt or its European equivalent, the Opel/Vauxhall Ampera)or from a hydrogen fuel cell.For most non-urban applications, other energy andpropulsion options may be even more attractive thanelectric-drive. Where biomass is abundant, for example,liquid and gaseous bio-fuels may be more affordable thanelectrified options. Recent examples include bio-ethanolin Brazil and bio-diesel in Europe. For liquid fuels, a flex-fuelvehicle is preferred for early commercialisation. Advancesin biomass conversion may allow future bio-fuels to havecomparable energy density to gasoline and diesel. Thiswould allow relatively affordable, local energy resourcesto be used without sacrificing vehicle utility in anyway.Biomass can also be used to produce hydrogen. Thisconversion holds promise in supporting fuel cell vehiclecommercialisation, enabling vehicles of all sizes to havezero tailpipe emissions and to be fuelled from renewablesources. Additional studies on biomass conversion arerequired, but because the fuel cell vehicle may have twicethe efficiency compared to a similar sized gasoline engineequivalent the well–to-wheels greenhouse gas emissionsfor the fuel cell vehicle could be reduced.Whether the biomass is used to make biofuels for use inan engine or to make hydrogen for fuel cells, “well-to-tank”energy conversion efficiency has to be combined withthe vehicle’s “tank-to-wheels”efficiency to understand themost energy efficient solution.There is also renewedinterest towards usingcompressed natural gasand liquid petroleum gas inseveral regions of the world.This is likely due to recentdiscoveries of large reservesand new processes forextracting gaseous fuels fromshale. It is generally acceptedthat there is approximatelya 20 per cent reduction ingreenhouse gas emissions,compared to gasoline, wheninternal combustion enginesuse natural gas. Althoughcompressed natural gas has a lower energy density thangasoline, it is possible to develop vehicles having a rangeof hundreds of miles. In particular, medium and heavy dutyvehicles that can accommodate the packaging of gaseousfuel tanks may be promising applications. In the long-term,as with biomass, these gaseous fuels could be convertedinto hydrogen and would support the development ofzero emission fuel cell vehicles.Lastly, the venerable internal combustion engine, withor without hybridisation, will continue to serve consumersaround the world due to widespread fuel availabilityand relative affordability, especially for long-distance,high speed operation. Affordability will continue to driveconsumers to this option although regulations coulddrive the market in terms of “carrots” (incentives for otheralternatives, price controls, etc.) and “sticks” (feebates,penalties and taxes).As shown below, it is expected that there will be anincrease in the variety of energy and propulsion choicesfor vehicle usage outside densely populated centresbecause of consumer needs for range, performanceand utility and governmental needs to promoteenergy diversity, domestic energy sources and cleanerenvironments. For urban centres, however, urban dwellersand cities may increasingly support a move towards smallelectric, networked vehicles that can address the energy,environment, safety, congestion, parking, affordability andaccessibility challenges. •Vehicle application map for various propulsion optionsEnergy Solutions For All 153

WPC New Member ProfileTrinidad and Tobago:First mover, still in the gameBy David RenwickCariBbean Energy Correspondent, World PetroleumPhotograph courtesy of Paria ArchiveTrinidad and Tobago’s entry into the World PetroleumCouncil (WPC) is long overdue – after all, it was theearliest country in the world to attempt to explorefor oil.In 1857, a well was drilled to a depth of 280 feet in thevicinity of the world-famous Pitch Lake in south westTrinidad by the Merrimac Company.Though no oil was found, this was two years before ColonelEdwin Drake sank the well in Titusville, Pennsylvania, whichis generally credited with launching the international oilindustry. This secured Trinidad and Tobago’s place firmly inthe annals of the global hydrocarbon sector.The small, 5,155 sq km, two-island state at the bottomof the Caribbean archipelago, with a population today ofa mere 1.3 million, did achieve exploration success whenWalter Darwent, an English mechanical engineer who hadserved in the Union forces in the American civil war andwas later sent to Trinidad by the West Indies PetroleumCompany, sank a well at Aripero, 6.5 km east of the PitchLake and encountered 20 feet of oil-bearing sands, whichyielded two and a half barrels over a period of seven hours.But drilling difficulties and shareholder scepticism causedthe operation there eventually to be wound up. Darwenthimself died two years later but his descendants are stillliving in Trinidad and Tobago today.Ships loading pitch at La Brea, Trinidad, circa 1870Further productive wells were drilled in Guayaguayarein south east Trinidad between 1902 and 1907 bybusinessmen Randolph Rust and John Lee Lum, whosefirst hole, Guayaguayare 1, produced 300 barrels before itwas shut in (apparently, the duo could find no shippingline willing to carry the low-flashpoint oil to marketsoverseas). Rust and Lee Lum drilled nine wells during theperiod, the third of which introduced rotary equipment tothe country, an improvement over the cable tool methodemployed up to then.Though Rust and Lee Lum are regarded as having putthe oil industry on an operational footing for the first time,actual commercial production, when it began in 1908,took place near the site of the original 1857 well.“Commercial” as used here means an oil strike thatenables the exploration company to sell its product, recoverall costs and declare a profit. The Trinidad PetroleumCompany (TPC) qualifies as the first commercial producer,with its Guapo 3 well at the south west coastal town ofPoint Fortin. The New Trinidad Lake Asphalt Company wassimultaneously drilling nearby and its Point Fortin West4 well, completed in 1909, was demonstrably a majordiscovery, flowing at what was then the extraordinary rateof 12,000-15,000 barrels a day (b/d).The first cargo of Trinidad crude (we’ll call it that becauseno oil has ever been identified in Tobago)was shipped out the following year andby 1911, the country already had its ownrefinery, at Brighton, near Point Fortin,which possessed a functioning port.As oil discoveries were made in otherparts of south Trinidad, processingcapacity grew and another refinery wasestablished further up the west coast in1917, at Pointe-a-Pierre, adjacent to themain southern town of San Fernando.This still survives today, as the onlyrefinery left in the country.Finding crude on land in Trinidad wasnever an easy task because of the island’scomplex geology and, indeed, Trinidadwas at one time, dubbed “the geologist’sgraveyard” by frustrated practitioners ofthe art.As the country’s Petroleum Associationdeclared in a review of the industry in1952: “Trinidad must be among the15420th World PETROLEUM Congress

Trinidad and Tobagomost difficult places in which to find and produce oil incommercial quantities. All professional geologists may notagree that Trinidad is the grave of geological reputations butthey will be the first to agree that geological conditions arehighly complex and unpredictable.”Even so, by 1934, 26 years after commercial production ofcrude had commenced, Trinidad and Tobago had actuallybecome the world’s eleventh biggest oil producer, aheadof Iraq, Canada, Ecuador, Egypt and Bahrain, among others.That eminence was to be short-lived, however.Peak oil production on land reached 111,883 b/d in1967 and then went downhill rapidly. Peak productionin the Gulf of Paria, which separates Venezuela andTrinidad on the west and was the first offshore locationfor exploration, was 76,948 b/d in 1986 and then alsodeclined. Peak production in the Columbus Basin off theeast coast, attained the level of 139,163 b/d in 1978 andstarted to decrease thereafter.It should be noted, however, that discoveries off theeast coast gave the Trinidad oil industry a new lease of lifein the early 1970s, just about the time that both land andwest coast production was falling. The identification ofthree major oilfields – named Teak, Samaan and Poui – bythe then Amoco Oil Company (subsequently absorbedby BP plc) sharply reversed the decline from land andGulf of Paria sources, to the extentthat Trinidad and Tobago’s overall oiloutput rose sharply to 240,000 b/din 1978, six years after Amoco hadcommenced production.Alas, this was the highest it hasever reached and today it is downto around 70,000 b/d (althoughthe country’s Ministry of Energyand Energy Affairs – MEEA – hasambitious plans to address thissituation, which we will come tolater in this article).Fortuitously, Amoco had alsofound natural gas reserves duringits intensive exploration programmeand that began laying the foundationfor Trinidad and Tobago’s switch froman economy dominated by oil to onewhere gas has become dominant(indeed, if condensate is added tocrude production, the liquids figureNGC ‘slug catcher’, Beachfield, south Trinidadrises to around 90,000 b/d).For example, whereas the oil refiners never seriouslyconsidered taking their product further down thevalue chain into petrochemicals, the gas sector hasdone precisely that, with gas being employed at theinternationally renowned Point Lisas industrial estate inwest-central Trinidad to produce methanol, ammonia,urea, gas liquids and other products further downstream.Indeed, Trinidad and Tobago today is one of the world’slargest producers of both methanol and ammonia,almost all of which is marketed abroad.Liquefied natural gas (LNG) was added to the mix in1999, when Trinidad and Tobago became the first countryin Latin America and the Caribbean to produce LNG. Theground-breaking project was financed by BP, BG Group,Repsol, what is now GDF Suez and the local, state-ownedNational Gas Company (NGC). They called the companyAtlantic, and train one, at 3 million tonnes of productiona year, was then the largest, single-train LNG facility inthe world. Three more trains have since been added, trainfour, at 5.2 million tonnes a year, itself, for a time, beingthe biggest in the world.Though well over 160 companies have, in their time,shown keen interest in exploring in Trinidad, only thebigger names, such as BP, BG, BHPBilliton, Repsol and →Photograph courtesy of NGCEnergy Solutions For All 155

WPC New Member Profile→ Centrica are left today, along with a growing groupof feisty Canadian independents and some small localupstream firms (of which more later).Notable about the shift from oil to gas in Trinidad andTobago (gas production is now at least eight times thatof oil on a barrel-of-oil equivalent basis) is that it has beenled, at least on the production side, by the internationalplayers, such as BP and BG.BP produces about 2.5 billion cubic feet a day (bn cfd)and BG around one billion a day, out of total gas productionnow topping 4.1 bn cfd, 59 per cent of which is devotedto LNG and 41 per cent to the petrochemical and metalscompanies, electricity generation and smaller users.BG, which opened up a new gas province off the northcoast of Trinidad in 2003, has never shown much interest infinding oil in Trinidad (unlike its attitude to Brazil, where it is apartner with Petrobras in giant deep water discoveries).BP, for its part, actually exited the oil business in Trinidad in2005, preferring to focus all its attention on gas explorationand production.BHPBilliton, which arrived in the late Nineties, departedfrom the international company norm in Trinidad andTobago by actively seeking out oil, though it did also findsome gas, which it began monetising in 2011. Its Angosturadiscovery in block 2c off Trinidad’s north east coast, was,however, a disappointment, with the original estimate ofrecoverable reserves having to be downgraded to about60 million barrels. Its output is now only about 15,000 b/da day. Repsol took over BP’s Teak, Samaan and Poui fieldsin the mid-Nineties along with its state-owned parters,Petrotrin and NGC, but production there has never muchrisen beyond 15,000 b/d.National companiesIt is really the state-owned Petrotrin that has been obligedto carry responsibility for revitalising the oil industry inTrinidad and Tobago.It now lifts around 40,000 b/d of crude from its land andGulf of Paria fields, some 44 per cent of total liquids output.Of course, the company has a vested interest in so doing:its refinery at Pointe-a-Pierre requires 160,000 b/d of crudeto turn out the six different types of fuel it produces and localcrude will always be cheaper than the imported variety.So the role of state companies in the maintenance andgrowth of the energy sector in Trinidad and Tobago, 104 yearsafter commercial oil production began, is a key one today.Petrotrin is both the biggest crude oil producer andthe only refiner, while NGC is the sole owner of onshorepipelines and only trader of domestic gas. Gas destinedfor LNG, in which NGC has no hand, travels through thecompany’s major east-west onshore pipeline. A third statecompany, NP, is the major petroleum products distributorand retailer in the country.Free marketers may argue that the state should stay outof the oil and gas business but that thesis falls down inTrinidad and Tobago when it is considered that Petrotrinactually exists because foreign majors, like Texaco andShell, decided of their own volition to quit the refiningbusiness and left the state with little choice but to step in.NGC, for its part, has been the catalyst, through its whollyowned subsidiary, the National Energy Corporation (NEC),for the rapid development of the gas-based downstreamindustrial sector by deliberately promoting the country’sattractions as a site for modestly-priced gas.NGC has been the intermediary between the gasproducers, like BP and BG and the gas users, like Methanex,PCS Nitrogen, Methanol Holdings Trinidad Ltd. (MHTL) andArcelorMittal. It negotiates the price to the producers andthe price to the consumers and has structured the latterin such a way that a low base price is augmented for NGCwhen prices of the methanol and ammonia made from thegas rise on the international market (if vice versa, of course,the returns to NGC fall).With BP having opted out of oil production in Trinidadand Tobago, BHPBilliton’s output having fallen far belowexpectations and Repsol not having done much with itsTSP block, Petrotrin is the mainstay of the oil part of thecountry’s energy industry.It is little wonder then that the Minister of Energy andEnergy Affairs, Kevin Ramnarine, who took over that job inJune, 2011, describes Petrotrin as “a company very near anddear to my heart” and has vested it with the task of turningaround the country’s collapsing crude production, which,as earlier noted, now stands at around 70,000 b/d (another20,000 b/d or so should be added for the condensate whichcomes with gas production and increases the liquids total).Petrotrin is in the best position to do this, if only becauseit holds the vast majority of the onshore acreage in Trinidadand most of the offshore acreage in the Gulf of Paria as well. Itis likely to receive strong support in this effort from the smalllocal companies mentioned earlier, as well as from someof the Canadian independents now taking a renewed →15620th World PETROLEUM Congress

Trinidad and Tobago→ interest in Trinidad, such as Parex Resources, Niko andTouchstone, as well as a bullish UK arrival, Bayfield Energy.As the minister admits, however, Petrotrin’s handicap hasbeen that of cash flow, partly the fault of the governmentitself, which, as he says, “has built up a debt to the companyin excess of TT$4 billion (about US$665 million) which arisesbecause of money owed to it in relation to the petroleumsubsidy that has crippled Petrotrin to the point where it isimpacting even on its ability to pay its taxes.”The minister is referring to the government’s policy ofsubsidising the price of gasoline and diesel at the pumpand the state’s obligation to meet the real cost to Petrotrinof refining those products.However, Petrotrin did manage to gather enough fundsto support a recent 3D seismic survey over 312 sq km of itsland acreage that is expected to lead to a major explorationprogramme which has not been undertaken on land for along time. This is likely to commence in January, 2013.Simultaneously, the state company will launch a reactivationeffort in South West Soldado (SWS), one of itsfour fields in the Gulf of Paria. This area has great potentialbut has been neglected for some time. Minister Ramnarinehimself describes SWS and the other fields in what isknown as Petrotrin’s Trinmar unit as being “central” to thecompany’s resurgence. The Trinmar fields have yieldedover 710 million barrels of crude since production began in1955 and it is widely believed there is much more to come.Trinmar also contains substantial reserves of heavy oil(API gravity 18 degrees or less), which Petrotrin has neverseriously attempted to recover, along with the mediumgravity oil it has traditionally extracted for decades.The SWS campaign will pre-empt most of the US$1.2billion Petrotrin intends to spend on its revival programmeover the next five years, with the money going toupgrading ageing infrastructure, drilling many new wells,reactivating non-producing wells, undertaking workoversand replacing flow lines. Sixteen wells were to be sunk inTrinmar in 2011, most of them development wells.Lindsay Gillette (pronounced with a hard “G”), the billionaireTrinidad and Tobago businessman who was appointedPetrotrin’s chairman when the People’s National Movement(PNM) government was replaced by the People’s Partnership(PP) coalition in the May 2010 general election, is confidentthat the company will make a significant contribution to thegoal of raising crude oil production.“We are most definitely up to the task,” he insists, “andTrinmar will be an important part of that process.”Petrotrin has, for decades, brought in partners to help itmaintain oil production, principally on land, where its jointventures (JVs), fall into various categories, such as LeaseOperatorships (LOs), Farm Out (FOs) and, most recently,Incremental Production Service Providers (IPSCs), all withlocal upstream firms (though some of these have beenbought out by foreign independents recently).Between them, LOs and FOs contribute about 5,500 b/dto the local refinery, while IPSCs currently provide about400 b/d.Petrotrin has also handed over operatorship of some ofits fields to small companies from overseas, such as the UK’sBayfield Energy, which has already succeeded in doublingproduction (to about 1,500 b/d) from the Galeota blocknearshore the south east coast.JVs initiated by Petrotrin (some have been mandated bythe MEEA as part of the effort to maintain “local content”in larger land and offshore blocks) will continue, sayschairman Gillette, “but we need better synergies andcomplementaries in the relationship.”On the gas side, NGC and NEC will continue to pursuetheir respective role of gas transporter/trader and gasbasedindustry promoter, respectively.Current developmentsOne of the big challenges ahead for NGC, as its president,Andrew Mc Intosh freely admits, is negotiating newcontracts with the gas producers, as current agreementsexpire in the next five to six years.Rising development drilling and production costs –Derek Hudson, president of BG Trinidad and Tobago,estimates it will require a minimum of US$750 million todevelop the one trillion cubic feet plus of gas in the 5cblock offshore south east Trinidad of which his company isthe operator – mean that the sale of this gas to NGC will bemore costly than has historically been the case.But at the same time, the petrochemical companies arepressuring NGC to reduce its prices to them, because theysell methanol and ammonia principally in the United States,where bountiful shale gas production has driven down thegas price, thus giving their US competitors an advantage.“In light of the competitiveness of US gas, NGC has tobe very concerned about, and very sensitive to, how westructure our gas price regime going forward, so as toremain competitive in international markets,” Mc Intoshpoints out. Equally disconcerting is the strong possibility ofall that gas enabling the US to turn the tables on Trinidad →Energy Solutions For All 159

WPC New Member Profile→ and Tobago and resume the export of LNG itself. Indeed,Cheniere Energy of Houston, which, up to now, has beenan importer of LNG has already successfully applied to theUS Department of Energy (DOE) to add exporting capacityto its Sabine Pass, Louisiana, terminal. It is also said to havesigned up its first client, an electricity generator in theDominican Republic called Basic Energy, which will requireup to 600,000 tonnes a year of LNG from about 2015.To accelerate this about-turn in its business model,Cheniere is preparing for as many as four LNG trains, eachwith a nominal capacity of up to four million tonnes ayear and built in phases. Should all of that go ahead, it willmean that Sabine Pass will have more LNG capacity thanAtlantic in Trinidad, an eventuality that would have beenunthinkable only a year or two ago.What’s more, both Dominion and BG Group, operators ofthe Cove Point, Maryland and Lake Charles, Louisiana LNGimporting and re-gasification terminals respectively, havealso applied for permission to become LNG exporters. Bothwill probably turn around imported LNG cargoes at thebeginning and then establish new liquefaction plants aftera while, using surplus US gas.What all this means for Trinidad and Tobago and NGCin particular, since it is the only local company currentlyinvolved in the LNG business as 10 per cent shareholderin train one and 11.1 per cent shareholder in train four,which also carries with it the entitlement to a liquefactionquota of 88 million cubic feet a day (mmcfd), is that thenew US LNG exporters will want to target the nearest LNGmarkets in the first instance and that means, followingCheniere’s example, countries in the Caribbean andCentral America.Analysts in Trinidad feel that, having lost out on its gasprocessing venture in Ghana, NGC should be thinkingof taking advantage of the smaller LNG markets that arelikely to develop in its own backyard, as regional utilitiesmove to replace heavy fuel oil and diesel with natural gasfor power generation.Mc Intosh is aware of the opportunities but cautious at thisstage. “The small LNG market in the Caribbean is a possiblething,” he says. “However, the logistical and physical facilitiesrequired in Trinidad to achieve that, would not be easy.”All of which may be true but many observers of the localenergy scene fear that the market will be lost over time ifNGC does not take it seriously, since delivery of the smallerLNG cargoes (say about 15,000-20,000 cubic metres) willthen gradually slip into the hands of US exporters, maybeeven some of the very companies, like BG, which areinvolved in the LNG industry in Trinidad itself.Capturing small LNG markets would seem to fit neatlyinto minister Ramnarine’s vision for “internationalising” thestate-owned energy companies.The Ghana gas processing initiative was seen as the firstmove in that direction but now that China has apparentlyput in a more attractive bid for its construction, NGC hasbeen left with only the offer of being hired to operate theplant after it has been built. Discussions on the matterwere continuing up to late October, when this article waswritten, but insiders think that NGC will not want to operatea complex facility which it has had no hand in installing.If neither Ghana not the small gas trades work out inNGC’s favour, the internationalisation thrust will not beaborted. “The time has come for ‘Brand Trinidad andTobago’ to go global,” the minister insists. “Instead of onlyseeking to attract investment to this country, we mustbecome investors in energy projects around the regionand in Africa. That is the idea and that is the vision.”If it eventually gets the green light (and it has beenstalled for several years), the Eastern Caribbean gas pipelinebetween Tobago and Barbados, in which NGC holds a 10per cent share, will be one such project.With offshore oil exploration about to re-commencein Guyana and the prospect of larger tankers eventuallyneeding to call in, Ramnarine sees prospects for NEC tobecome project manager, and operator, of a new portthere, based on the expertise it has long acquired in portconstruction and management in Trinidad.Grenada has also been examining the possibility ofTrinidad helping it with oil exploration on its side of themaritime delimitation line in the Caribbean Sea and theminister has received this suggestion enthusiastically.Further afield, in other countries of Africa, where Trinidadand Tobago’s success in gas monetisation is highlyregarded, other initiatives are also possible.Ramnarine has in recent months entertained a delegationin Port of Spain from Mozambique and made a presentationto African leaders at the recent Commonwealth Headsof Government Meeting (CHOGM) in Perth, Australia.“Africa is looking to Trinidad and Tobago for help andguidance in establishing its own oil and gas industry,” hesays. “This presents an opportunity to actualise South-South co-operation and the transfer of technology.” →16020th World PETROLEUM Congress

O P E NB G T T /C E N T R IC A /E M IO P E N(A )(B )S ca rb oroughC H E V R O NB G T T /C H E V R O N6 (b)B G TTS O N D ER E S O U R C E SC O R PT T D A A 3 01 0 4 2 9 2 H aO P E NT T D A A 3 19 9 6 8 8 H aO P E NT T D A A 3 21 1 3 0 4 3 H aO P E NTrinidad and TobagoT T D A A 2 41 1 2 0 4 2 H aO P E NT T D A A 2 51 0 0 0 8 6 H aO P E NT T D A A 2 61 0 0 0 8 6 H aO P E NT T D A A 2 71 0 0 0 8 6 H aO P E NT T D A A 2 81 0 0 0 8 6 H aO P E NT T D A A 2 91 0 0 9 6 3 H aO P E NB L O C K 2 11 3 2 0 1 5 H aO P E N3 0 7 8 3 H aB L O C K 2 2C E N T R IC A / P E T R O T R INB L O C K 2 3 (a )2 5 7 2 4 0 H aO P E NO P E NO P E N4 4 2 5 4 H aT T D A A 1 41 0 0 1 4 4 H aO P E NT T D A A 1 51 0 0 1 7 6 H aO P E NT T D A A 1 61 0 0 4 5 3 H aO P E NN C M A 21 0 1 ,9 3 1 .8 H aN IK O R E S O U R C E S (C A R IB B E A N ) LIM IT E D / R W E D ea A G /P E T R O T R INN C M A 4B L O C K 2 3 (b )2 5 7 4 4 0 H aO P E NT R IN ID A D & TO B A G O & V E N E Z U E LA1N C M A 11 8 2 ,9 4 6 .2 H aV E N T U R E N O R T HS E A O IL LIM IT E D /P E T R O T R INN C M A 3 N C M A 52 1 0 ,6 2 2 .5 H a2 3 1 ,0 9 8 .8 H aO P E NN IK O R E S O U R C E S /P E T R O T R INB L O C K 2 43 4 0 1 1 4 H aO P E NT T D A A 1 11 0 0 4 2 2 H aO P E NT T D A A 81 0 0 0 8 3 H aO P E NT T D A A 1 21 0 0 1 4 2 H aO P E NT T D A A 91 0 0 0 1 7 H aO P E NT T D A A 1 31 0 0 1 5 1 H aO P E NT T D A A 1 01 0 0 2 5 6 H aO P E NT T D A A 1 71 0 1 1 9 8 H aO P E NT T D A A 1 81 0 1 1 5 3 H aO P E NT T D A A 2 01 0 1 5 3 7 H aO P E NT T D A A 2 21 0 5 2 2 7 H aO P E NB L O C K1 (a )C E N T R IC A /P E T R O T R ININ T E R N A T IO N A L B O U N D A R YLIN E B E T W E E NN O R T H M A R IN E2 0 5 7 9 H aP o rt o f S painO P E NB L O C K 1 (b )C E N T R IC A /P E T R O T R INC E N T R A L R A N G EB L O C KP A R E X / V O Y A G E R / P E T R O T R INB L O C K 1 (b )S a n3F e rn a n do2484H E R R E R AO P E N8T R IN M A R588O P E NO P E N5 7 364 0 0 4 8 H aH aB L O C K 3 (a ) B L O C K 3 (b )B H P / K E R R M C G E E1 2T A LIS M A N / T O T A L 6 4 5 1 3 H aO P E NB L O C K 2 (a b )O P E N9 6 1 4 H aN IK OC E N T R IC A R E S O U R C E S(A R M A D A ) LIM IT E DB L O C K 4 (a )b pT T / R E P S O LE O G R E S O U R C E SP R IM E R A9O P E N1 37 4 3 4 5 H ab pT T / R E P S O L1 5 1 61 01 01 1O P E N7 4 3 4 5 H aB L O C K 4 (b )7 5 3 2 8 H aN IK O R E S O U R C E S(C A R IB B E A N ) L IM IT E DB L O C K5 (c)B L O C K 5 (d )6 8 4 1 5 H aO P E NB L O C K 2 5 (a )1 3 8 8 6 0 H aO P E NB L O C K 2 5 (b )1 3 9 1 2 9 H aO P E NB L O C K 2 61 1 9 5 6 9 H aO P E NB L O C K 2 71 1 7 9 1 5 H aO P E NT T D A A 41 0 0 2 8 5 H aO P E NT T D A A 21 0 4 5 7 0 H aO P E NT T D A A 61 0 0 4 3 3 H aO P E NT T D A A 51 1 0 5 9 2 H aO P E NT T D A A 11 1 4 8 8 3 H aO P E NT T D A A 71 0 0 4 8 4 H aO P E NT T D A A 31 0 7 2 1 1 H aO P E NT T D A A 1 91 0 2 9 1 7 H aO P E NT T D A A 2 11 0 1 1 9 4 H aO P E NO P E NO P E N67S O U T H M A R IN E5 2 3 8 4 H aO P E NN IK OV O Y A G E R E N E R G Y(T R IN ID A D ) LIM IT E DP E T R O T R INb pT T / R E P S O LS E C C 1 4E O G R E S O U R C E Sb p T T / R E P S O LB L O C K 6(d)B G T T /C H E V R O N1 7L O W E R R E V E R S E 'L '3 6 3 7 8 H aO P E NBalancing the Energy Mix for a Sustainable FutureTrinidad and Tobago has been in the business of commercial hydrocarbonproduction for more than one hundred years. The country has produced inexcess of three point fi ve billion barrels of oil during this period, attaining a peakof 227,527 barrels of oil per day (bopd) in 1978. Since then oil production hasconsistently declined with production now at 85,000 bopd. In stark contrast(as seen in the chart below) as the oil fortunes have declined production of gashas gained momentum, and as of 2009 reached a peak of 4.2 billion cubic feetper day (bcf/d).However, a major issue which concerns the Government of the Republicof Trinidad and Tobago (GORTT) is ensuring that the downstream demand fornatural gas is met while attracting new industries to the country. It is with thisin mind that the 2010 Competitive Bid Round offered mainly gas prone blocks.The resulting work programme from the bid round will see nine seismicacquisition projects being undertaken; one processing project and sixexploration wells being drilled within the next three to four years. Expectedresource fi nds will be in the region of 4-8tcf of natural gas.On examination of the global reality, the Minister of Energy and Energy Affairs,Senator The Honourable Kevin Ramnarine, is quite correct in enunciating thatthe money earned from a barrel of oil exceeds that from natural gas by a factorof 10. The chart below entitled, “Hydrocarbon Production in T&T” indicates thatTrinidad and Tobago’s production is skewed in favour of natural gas. However,given the earning power of oil it would be to the country’s advantage to reversethis trend and the Minister has stated on numerous occasions that reversingthe decline in oil production is one of his major priorities. Hence, the reasonwhy the philosophy underpinning bid offerings has had different foci over time.It is on the basis of the 2005/2006 bid round that eleven exploration wellsare to be drilled in the 2011/2012 period, which include fi ve wells onshore andsix offshore. The onshore wells are all oil prospects and the offshore wells maybe a combination of both oil and gas.There are also short-to-medium-term projects in the Gulf of Paria which wouldaddress the decline in oil production. These are the East Brighton project beingundertaken by SOOGL Antilles Trinidad Ltd (operator) and the Point Ligoure/Guapo Offshore/Brighton Marine project being undertaken by Ten DegreesNorth. These projects will stem the decline in the short term while we commenceexploration in the deep water areas, which is a longer term initiative.Deep Water ExplorationThe Trinidad and Tobago Deep Atlantic Area is located beyond the alreadyproducing oil and gas fields and has an area of 40,000 sq km. Waterdepths range between 1,000 to 3,500 metres. The area is divided into 39blocks of approximately 1,000 sq km each. (See “Energy Map of Trinidadand Tobago” above.)In the 2010/2011 bid round eleven blocks were offered and fi ve bids werereceived for three blocks:Block 23(a) – 3bids, BPEOC, BHPB/Total/Repsol, Niko ResourcesBlock 23(b) – BHPB/RepsolBlock TTDAA 14 – BPEOCBPEOC was awarded two blocks (23(a) and TTDAA 14) and with respectto Block 23(b), the Minister exercised his right to negotiate with BHPB/Repsolto arrive at a mutually acceptable arrangement. It is expected that explorationwould be started in these areas by early 2012 – a very welcome start to ourfrontier exploration.Additionally, another deep water competitive bid round will open inNovember 2011 with bids to be submitted in March 2012. A maximum ofsix blocks will be offered, based mainly on nominations by the companies.Companies are being asked, on the basis of the map to nominate a maximumof fi ve blocks.It is the stated desire of the GORTT that any exploration in the deepwater of Trinidad and Tobago would discover commercial quantities of liquidhydrocarbon; from our reading of the reports and data this is highly likely.While some companies may not agree with that view based on their previousevaluation of the data, the Ministry is supplying some new data which shouldresult in a more positive view by the sceptics and serve as reinforcement tothose who are inclined to share our viewpoint.•Hydrocarbon Production in Trinidad & TobagomboedLNGproduction12001000OILGASNatural gas used toproduce ammoniaMajor industrial estatecommissioned800600Natural Gas usedto produce power400First oil refineryestablished200019101920193019401950196019701980199020002010Level 26, Tower C - Energy Trinidad and Tobago, International Waterfront Centre, #1 Wrightson Road, Port of Spain, Trinidad and Tobago.Tel: (868) 62-MOEEI, 623-6708 • Website: www.energy.gov.ttEnergy Solutions For All 161

Photograph courtesy of MEEA→ In the meantime, the immediate priorities for ministerRamnarine’s four more years in office are unquestionablyhalting the haemorrhage in crude oil production byencouraging as much exploratory drilling as possible,especially in deeper water and deeper land horizons –as well as the determined application of enhanced oilrecovery (EOR) methods.A 20 per cent investment allowance for EOR in landfields was introduced in 2010, covering such applicationsas water flood, steam injection and carbon dioxide(CO 2) sequestration. Geologists feel there is potential forrecovering another one billion barrels of oil this way.The big prize for oil, however, may well lie in waterdepths between 1,700 to 2,000 metres out in the AtlanticOcean to the east of Trinidad.Two such blocks were awarded in 2010 – 23a and TTDAA14 – both to BP plc, through a special purpose vehicle, BPExploration Operating Company Ltd. A third, block 23b,is the subject of direct negotiations between the MEEAand BHPBilliton/Repsol, since the consortium’s bid did notmeet the original ministry threshold.Another deep water round is due in March 2012, at whichsix more blocks are to be offered for competitive biddingby companies, and the MEEA hopes to use its appearanceat the WPC’s Doha congress to promote this.There are 36 open deep water blocks currently in theMEEA’s inventory and Ramnarine has pledged continuousacreage auctions, both of deep and shallow water blocksas well as deep land blocks.LNG tanker docking at Atlantic, Point Fortin, TrinidadExtensive reprocession of seismic data by MEEA andfiscal concessions, such as 60 per cent cost recovery anda reduction in petroleum profits tax (PPT) from 50 percent to 35 per cent, are all expected to make deep waterexploration more attractive to companies.As for gas, while Trinidad and Tobago still has a fairlycomfortable reserves and exploratory resources cushion ofabout 55 trillion cubic feet (tcf ), the proven and probablecomponents continue to fall and were down a combined1.1 tcf in 2011, according to the annual natural gas auditby the Ryder Scott Company.With the downstream gas based industrialisationprogramme now being revived – a second ammonia-tomelamineproject is under construction and methanolto-polypropylene,methanol-to-petrochemicals, bitumenupgrader and another direct reduction iron plant are allunder consideration – it would be prudent to have moreproven gas reserves.Three major exploration initiatives in north coast offshoreblocks 2, 3 (by Niko of Canada) and 4 (by Centrica of the UK)are considered to have a good chance of identifying newproven gas accumulations.Yet another challenge for the minister in the near tomedium term will be to get cross-border gas developmentbetween Trinidad and Tobago and Venezuela off theground. The unitisation agreement for the reservoirsconcerned – Manatee in block 6d in Trinidad and Loranin block 2 in Venezuela – has already been signed andreserves identified (2.1 tcf on the Trinidad side), so itsonly a matter of deciding how the gas willbe monetised, before actual developmentcan begin. Minister Ramnarine is due to holddiscussions on the matter with his Venezuelancounterpart before the end of 2011.If cross-border gas can be unlocked, itwill make an important contribution to themaintenance of production, perhaps evenprovide the input for possible expansion ofthe LNG industry in Trinidad, though tiltingthe imbalance even more in favour of gas.But as the country enters its second centuryof uninterrupted petroleum production,it may well be on the verge of a revival ofcrude output and Minister Ramnarine will behoping that his faith in Petrotrin, and others, tobe able to achieve that objective is eventuallyshown to be justified.•16220th World PETROLEUM Congress

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InvestmentThe petroleum industry and resource holders can make huge profits, but they also needto make huge investments; this includes investing in the next generation of leaders ashighlighted in our Special WPC Youth Magazine. According to Iain Brown of Wood Mackenzie,capital spending in the global upstream industry has strongly recovered from the trough of2009 – possibly hitting an annual rate of US$ 500bn by 2013 – for a mix of reasons. There is growingconfidence in a sustained high oil price putting value into unconventional projects, but also areturn of cost inflation eating into profit. At the top spending league are ExxonMobil, Chevron andPetrobras, while most national oil companies with lower cost reserves are much lower down.Fatih Birol of the IEA puts investment into a broader context with a warning that just to offsetdecline from existing fields, the world will need gross capacity additions of 47million barrels a day(mb/d), or twice current output of all OPEC countries in the Middle East. The IEA chief economistsays almost all extra medium-term oil supply will have to come from Middle East and North Africacountries, which should cut domestic energy price subsidies to curb use and free more for export.Sufficient investment stimulus should come from the oil price, suggests Amrita Sen of Barclays Capital.Growth in developing country demand will press up against the limits of global supply, and togetherwith shrinking spare supply capacity and minimal buffer stocks, keep the oil price buoyant but volatile.Howard Rogers of the Oxford Institute for Energy Studies tackles the complex regional price differencesfor gas, but suggests these could narrow with bigger flows of LNG a around the world.Where is the money for all this investment to come from is a question addressed by Peter Gawof Standard Chartered Bank. He provides a relatively optimistic answer. Oil and gas companies,especially the majors, had no problem raising capital in the bond and equity markets throughthe 2009 recession. However, project financing has become harder, and banks are increasinglyconstrained by Basel III capital regulations and maybe now by new eurozone measures in whatthey can lend. Overall, however, “the favourable risk outlook for the industry combined with thepositive market perception (flight to quality) place the oil and gas sector in an enviable position.”The section ends with some prudent advice or rather advice about prudence. The explanation byWilhelm Mohn of Norway’s finance ministry of his country’s ‘government pension fund’ shows whyit is widely considered the gold standard among sovereign wealth funds. All Norway’s petroleumrevenue goes first into the pension fund, and only then on a parliamentary vote can a portion betransferred to the budget. While acknowledging the somewhat special case of Norway being adeveloped democracy before it hit oil, he cautions countries with a perishable source of income“not to spend it all at once.”Philip Daniel of the IMF echoes the same message to resource-rich governments, but also offersadvice to companies negotiating with such governments. Contracts, he suggests, will not bedurable unless governments get some revenue as extraction takes place and gain a share of anyincrease in a project’s profitability. Fiscal terms should also take account of the relative ability ofcompanies and governments to bear risk.“A poor country with a limited portfolio may be less able to tolerate deferral of revenue than amajor company.” •Energy Solutions For All 165

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InvestmentGlobal upstream spendinghits new heightsBy Iain BrownHead of Regional Upstream Research, Wood MackenzieAs 2011 draws to a close, capital spending in theglobal upstream industry has fully emerged fromthe dark days of 2009. The recovery has kickedon strongly and global capital spending willreach a new record high. The annual total will be close toUS$450bn (billion) – US$35bn higher than in 2010, andover US$25bn above the previous record in 2008. If thisrate is maintained, annual upstream investment couldreach US$500bn by 2013.North America sets the paceHigh levels of investment are being implemented acrossmost of the world’s oil and gas sectors. Many sectors andcompanies are planning spectacular growth, whilst thereare few countries where investment has slowed. There aremany reasons for this restoration of investor confidence,although three are particularly strong:• Growing confidence that the oil price will remain at orabove US$80 a barrel (/bbl) in the medium and long term• Improving value propositions for a range ofunconventional resource plays, broadening the range ofopportunities for international oil and gas companies• Rapidly increasing demandfor materials and services andthe return of cost inflationThe onshore US GulfCoast region, especially theliquids-rich Eagle Ford Shalein south Texas, is the largestsingle sector of activity, withplanned upstream investmentof around US$140bn overthe next four years. Andthe Gulf Coast experienceis repeated across most ofNorth America. Total upstreamcapital investment in Canadaand the US will be aroundUS$600bn between 2011 and2014 – up from US$480bn inour previous forecast. A keyfeature in this remarkableturnaround has been therestoration of Canadian OilSands to the prominence itenjoyed before the economiccrisis. Several giant projects areUS$ billion480460440420400380under construction, in parallel with huge commitments tocurrent production and facilities de-bottlenecking.The rise of unconventionalsThe major shift in industry spending trends in thepast five years has been the rapid growth in a range ofunconventional gas and oil resources, primarily in NorthAmerica. Oil sands and coalbed methane have beenprominent parts of the North American industry for manyyears, but shale gas and shale oil have taken centre stagemore recently.The huge impact of the unconventionals sector isillustrated by its share of global upstream spending.Ten years ago, the combined contribution fromunconventional plays was less than 10 per cent of globalexpenditure, primarily in coal bed methane and oil sands.Now, in the period from 2011 to 2014, they will accountfor over a third of global upstream investment. And it is apattern that looks set to continue, as the opportunity setfor international companies in conventional, onshore andshallow-water reserves remains constrained by a range ofpolitical and economic factors. →Figure 1 - Actual and planned globalupstream spending*, 2008-20133602008 20092010201120122013* Future development capital expenditure in 2011 real terms.Exploration and appraisal spend not included.Source: Wood Mackenzie Corporate Analysis Tool and Upstream ServiceEnergy Solutions For All 167

InvestmentSource: Wood Mackenzie Corporate Analysis Tool and Upstream ServiceMajors and NOCs lead the wayExxonMobil has the largest capital spend of all oil and gascompanies in 2011, at around US$22bn, and is planning tocontinue increasing investment over the next few years.Even so, it will be run close in 2012 and 2013, by Chevronand Petrobras. Chevron has several major projects underdevelopment in Australia, the Gulf of Mexico and US Lower48. Its total upstream spending could exceed US$25bnby 2013. Several of Petrobras’ giant oil discoveries in theSantos Basin should be progressing through developmentin a similar timeframe and its annual capital expenditurecould reach US$28bn by 2014.Most of the larger oil and companies are planning highlevels of capital spending in the next few years. This reflectsan increased expectation that, whilst oil prices may fall backfrom current levels, they are likely to remain at or aboveUS$80 per barrel. This outlook provides confidence in thevalue proposition for a wide range of unconventionaldevelopments, including oil sands, shale oil, shale gasand tight gas. Most major international companieshave expanded their portfolios in the past three yearsto develop a higher representation in unconventionalresource themes.National oil companies (NOCs) and governments ownFigure 2: Share of capital spend* by company typeMajors - 26%Others - 23%NOCs andGovernments - 35%International large-caps 8%North American largeandmid-caps - 8%* Cumulative upstream development spending for the period 2011-2014around 67 per cent of the world’s oil and gas reserves andare responsible for over 55 per cent of production. Five ofthese (Saudi Aramco, Gazprom, Qatar Petroleum, NIOCand PDVSA) account for cumulative reserves of around1.2 trillion barrels of oil equivalent (boe) – more than 40per cent of the global total. Even the largest internationalcompanies fall far short of this scale – we estimate thecombined reserves of ExxonMobil, Shell, BP, Chevron andTotal at around 244 billion boe (on a working interest basis).Despite this prominence in reserves and production,NOCs and governments proportionately spend far less onupstream development than the international industry –accounting for just over one-third of the global total. Thereare many reasons for this apparent inconsistency:• Some of the most prolific NOCs (Saudi Aramco, QatarPetroleum, Iraqi Government, and KPC) own the world’slowest-cost oil and gas reserves. Their developmentcosts are much lower on a unit basis than in other partsof the industry.• Development costs for the international industry aregetting higher; as the constraints on access to conventionalreserves cause companies to increasingly pursue newreserves in deepwater or unconventional oil and gas.• While many NOCs and governments continueto spend proactively to maintain or expand theirproduction capacity, others have underinvesteddomestically for many years,with capital availability dictated by statebudgets.• Production capacities in some NOCterritories are in terminal decline and theNOCs have not been able to replenishtheir investment options outside theirdomestic industry.The highest-spending NOCs are thosewith the highest-cost reserves, in theearly stages of development. Over thenext five years, Petrobras and PetroChinahave by far the highest capital budgets.Both companies have a significantinternational presence, but most oftheir development spending – 91 percent and 95 per cent respectively – is ontheir domestic portfolios. Their assets aredominated by technically-challenging,high-cost reserves. These are deepwaterreserves in the case of Petrobras, while16820th World PETROLEUM Congress

InvestmentPetroChina is developing a range of deep and difficultreservoirs in its home territory.The cost of new production capacity in the MiddleEast has been rising steadily over the past 20 years,as the shallower, higher qualityreservoirs have been depleted andnew developments focus on deeper,poorer quality reserves. We estimatethat the capital cost of the nextphase of developments in the majorproducing countries of Middle EastOPEC will be between US$2/boeand US$10/boe. This is many timeshigher than in the past, but these arestill amongst the lowest cost oil andgas reserves in the world today. Thisis confirmed by the low cost of newincremental production capacityfor Saudi Aramco, NIOC, KPC andthe Government of Iraq, even bycomparison to their NOC peers.Costs are on the rise againThere is growing evidence that thecost of services and manpower isincreasing in response to the rapidgrowth in development activity.Renewed cost inflation is now evidentin most producing areas, althoughthere are significant sectoral andregional variations. The most obviousimpact at this stage is in Australiaand Canadian Oil Sands, wherethe proliferation of developmentapprovals has placed unprecedenteddemands on fabrication capacity,materials and labour. Capital costs inthese sectors have increased by atleast 10 per cent in the past year, andby considerably more for specialistequipment and manpower.Another area where demandis putting pressure on supply isdeepwater. Activity is steadilyrecovering in the Gulf of Mexico,whilst aggressive developmentplans have been maintained overUS$ billionTight gas - 10%Shale gas - 9%100806040200CBM - 2%Acid gas - 3%ExxonMobilthe past few years, in Australia, Latin America and WestAfrica. Demand for deepwater rigs, facilities and servicesremained high, despite the economic crisis and the post-Macondo moratorium. Current evidence suggests →Figure 3: Global distribution of upstreamcapital spend* by resource themeDeepwater - 15%Tight oil - 6%Oil sands - 4%Figure 4: Top ten companies by plannedcapital investment* 2011-2014ChevronPetrobrasShellPetroChinaTotalBPOther conventional - 51%Global total= US$ 1.8 trillion* Cumulative upstream development spending for the period 2011-2014* Upstream development spending, not including exploration and appraisal costs,capitalised interest, non-integrated LNG projects or investments in equity subsidiariesStatoilPemexSinopecSource: Wood Mackenzie Corporate Analysis Tool Source: Wood MackenzieEnergy Solutions For All 169

Investment→ that overall development costs for deepwater projectshave risen by between 5 and 10 per cent in the past year.There is less evidence of extreme cost inflation inshallow-water and onshore provinces, where demandfrom new projects is lower. But some areas are particularlytight. In the US Lower 48, the flood of investment into tightoil plays has taken up all of the ‘slack’ that had developed inthe service sector in the aftermath of the economic crisis.Equipment and personnel required for ‘fracking’ wells areback in high demand. These demands are unlikely to easeover the next few years and cost inflation for these servicesis expected to run above 5 per cent.Clouds on the horizonThe economic crisis of late 2008 shook the foundationsof the global upstream business. Many higher cost capitalprojects were delayed, shelved or abandoned, and annualspend dropped by US$50 bn. Now, just 30 months later, theindustry has proven remarkably resilient. Plans have beenrestored and expanded and many new projects approved,in the presumption that demand and commodity priceswill remain relatively robust over the longer term.For many years, international companies have pursuedever more challenging and costly sources of oil and gas,in both conventional and unconventional sectors. Mostof the major NOCs are now making greater demandson their state budgets, seeking to produce from deeperand poorer quality reservoirs, in progressively morechallenging locations. As the industry strives to ensurethat supply keeps pace with demand, upstream spendingseems set on a relentless upward trajectory, producingmore barrels and cubic feet every year, at a steadilyincreasing cost per barrel.But there are significant risks and uncertainties whichthreaten this positive view. The macroeconomic outlookhas deteriorated markedly since the summer of 2011.Europe could be on the brink of recession and the USis projected to enjoy only weak economic growth. Thisoutlook could worsen further if European sovereign debtissues turn into a full blown banking crisis. The investmentplans of the upstream industry are ambitious andencouraging, but they could yet be undermined by thefragility in the global economy.•Read more from Wood Mackenzie by visiting www.woodmac.com/wpc2011Figure 5: Planned upstream capital spending* by countrySource: Wood Mackenzie Corporate Analysis Tool and Upstream Service> US$50 billionUS$20-50 billionUS$10-20 billionUS$5-10 billion< US$5 billion* Cumulative upstream development spending for the period 2011-201417020th World PETROLEUM Congress

InvestmentMeeting rising demand andoffseting production declineInterview with Fatih Birolchief economist, International Energy AgencyWe have seen a recovery in oil and gas investmentwhich seems to reflect confidence in the buoyancyof the long term oil price and of oil demand – is thisconfidence justified?We expect global upstream oil and gas investment tocontinue to grow strongly in 2011, hitting a new record ofover US$550 billion. Moving forward we will continue toneed a substantial amount of investment in the oil and gasindustry. There are two major drivers of this. One of them issignificant growth in oil demand which in our new WorldEnergy Outlook (WEO) for 2011 we project to rise from 87million barrels a day (mb/d) in 2010 to 99 mb/d in 2035.Almost all of this new demand will come from the transportsector in emerging economies, as economic growthpushes up demand for personal mobility and freight.The total number of passenger cars is set to more thandoubles to almost 1.7 billion in 2035. No doubt, alternativevehicle technologies will emerge that use oil much moreefficiently or not at all, but it will take time for them tobecome commercially viable and penetrate markets. But,as important as investment to meet rising demand, weneed a lot of investment just to compensate for the declinein production from existing fields as they mature. One ofthe major findings of our WEO is that between now and2035 we will need gross capacity additions of 47 mb/d,to compensate for declining production at existing fields,twice the current total oil production of all OPEC countriesin the Middle East.Can the world achieve this?I believe that oil prices will remain at levels sufficient tomake most of these new projects that we expect to bedeveloped profitable. Even at the end of 2008, when asa result of the financial crisis and the oil price was goingdown to US$40, I said the era of cheap oil was over. Todaywhen the world economy is in a very shaky state, we stillhave the price of oil at around US$100/bbl for Brent. Sofrom a project financing viewpoint, there will be enoughincentive for those projects to be developed. However, I alsosee some challenges. One is whether the key producingcountries will make, or can make the investments in atimely and adequate manner. According to our latestWEO, close to 90 per cent of the growth in global oilproduction over the next two decades will need to comefrom Middle East and North African (MENA) countries.In terms of physical resources, this does not represent amajor challenge, theoretically. However, investments inthese countries might be deferred. This could have farreachingconsequences for global energy markets. Sucha shortfall could result from a variety of factors, includinghigher perceived investment risks, deliberate governmentpolicies to develop production capacity more slowly orconstraints on upstream domestic capital flows becausepriority is given to spending on other public programmes.What happens if Middle East and North Africancountries cannot deliver all this?We have made a special investigation in our latest WEOaround our projection that MENA countries need upstreaminvestments of US$100bn a year over the next decade. Weasked what would happen if this investment were onethird lower? The results show that MENA production wouldbe more than 6 mb/d lower by 2020 and we could face asubstantial near-term rise in the oil price to US$150/barrel(in year-2010 dollars). This would not be good news for theglobal economy. Therefore it is in the interest of everyonethat the investment in the key producing countries takesplace in a timely manner. There is a significant responsibilityhere on the oil producers, but of course I also see theywill face certain hurdles. Therefore it is very importantthat consumer countries should help – by for instancenarrowing down the uncertainties on the oil markets – theproducing countries to have the best possible investmentframework to get the oil to the market.What about production prospects elsewhere?One of the trends we have highlighted in our latest WEOis the increase in US oil output. As a result of two majordevelopments in the US we see a trend that is very differentto most other countries in the OECD. With the recentefficiency measures taken by the Obama administration inthe transportation sector, we expect a slowdown in US oildemand growth. This greater efficiency, together with theincrease in new supplies, leads us to expect a substantialreduction in US oil imports in the decades ahead. One ofthe promising new sources of production in the US is lighttight oil which we think may actually become a secondAmerican “revolution”, the first one being in shale gas. Lighttight oil provides a great example of how the industrycontinues to innovate, developing new techniques andtechnologies to tap previously uneconomic resources.High oil prices would give very strong incentives to thefurther development of light tight oil in the US and mayalso result in production taking off in other plays or in other17220th World PETROLEUM Congress

Investmentparts of the world. This could have implications for themajor oil producing countries by eating into thier marketshare. I mention this to make the point that it is not alwaysin the interest of the major oil producing countries to havevery high oil prices.The IEA recently published a report called “Are weentering a golden age of gas?” Why the questionmark?It is true that there is much less uncertainty over theoutlook for natural gas than there is for other fossil fuels.Factors both on the supply and demand sides point toa bright future, even a golden age, for natural gas. Gasconsumption rises in all three scenarios presented inour new WEO, underlining how gas does well under awide range of future policy directions. We now have gasreserves equal to around 120 years of current production;but adding unconventional recoverable resources bringsthis figure to nearly 250 years. And unlike oil, gas is widelydispersed around the world. You have the US and Canada,and of course the Middle East, North African and Russia,but China and Australia are also coming along verystrongly. Based on currently operating and sanctionedprojects, Australian LNG export capacity could exceed 70bcm soon after 2015, making it the second largest globalLNG exporter after Qatar.But in terms of unconventional gas production, thereare significant local environmental problems, due to thetechnology used, and this has raised a lot of questions inEurope and in the US which are well-justified. However,the good news is that with existing technologies theseproblems can be taken care of – though this will increasethe cost of production for unconventional gas. So if weare to enter a golden age of gas, companies must applygolden standards to their extraction technologies. This willincrease the cost of production somewhat, but it will openthe door for gas to play a growing role in the global energymix. This is why to the question of a golden age for gas myanswer is yes so long as the gas industry is able to produceit in a sustainable manner.What is the prospect for gas price harmonisationaround the world?I expect that the growing share of LNG in global gas supplyand increasing opportunities for short-term trading ofLNG will contribute to a degree of convergence in pricesacross the main markets in North America, Europe andAsia. Nonetheless, I still think we will see fairly significantprice differentials, reflecting the relative isolation of thesemarkets from one another and the cost of transportbetween regions.The IEA has expressed general concern about theimpact of subsidised oil consumption on exports.Where is this particular concern?It is not only us who have expressed concern. Indeedin 2009, the G20 leaders actually agreed to phase outsubsidies that “encourage wasteful conumption, reduceour energy security, impede investment in clean energysources and undermine efforts to deal with the threat ofclimate change.” But progress on this worldwide is slow.Subsidies that artificially lower the prices of fossil fuelsamounted to over US$400 bn in 2010 with around halffor oil products. In many cases they were introduced withthe well-intentioned objective of improving access tomodern energy services for the poor. In practice, however,they have often proved to be an inefficient means ofachieving this goal. Typically those who consume the mostenergy benefit the most from subsidies, such as thosewho can afford to own a vehicle or electrical appliances.The removal of these subsidies would improve energysecurity, reduce emissions of greenhouse gases and bringeconomic benefits.Light tight oil provides a great example ofhow the industry continues to innovateAlthough subsidies for oil exist in many parts of theworld, they are particularly prevalent in the Middle East. Atthe same time, oil demand in the Middle East is increasingsubstantially. There are three reasons for this – two of whichare justified, and one is not. Growth in economies and inpopulation justifies an increase in energy consumption.But the third reason is not justified – the fact that retailenergy prices are artificially low. This results in lowefficiency in domestic energy use which leads to reducedavailabilities for export. Over time, such subsidies mayeven threaten to curtail the exports that earn vital staterevenue streams. At US$81 billion, Iran’s subsidies werethe highest of any country in 2010, although this figurecould fall significantly in the coming years if the sweepingenergy-pricing reforms that commenced in late 2010 areimplemented successfully and prove durable. I hope othercountries in the region follow the example. •Energy Solutions For All 173

InvestmentOil: Changing tidesBy Amrita SenOil Analyst, Barclays CapitalSource: Barclays CapitalAn increasing loss in confidence in globalpolicymakers to deal with the sovereign debtsituation, along with worries of global growth,have thrown oil markets into disarray. The recentworsening in conditions has led to a widespread andsevere downwards lurch in risk appetite. Oil, like mostmarkets, seems to be trading in a maelstrom of information,where any headline is immediately subjected to oppositeand contradictory interpretations, with unpredictableconsequences for prices. Indeed, much of the immediateaction in oil is simply based on the same climate ofeconomic fear that is battering equities.For many, the key question is whether this is a repeatof the 2008-09 cycle, and what is the downside to prices.Despite the gloomy picture concerning sovereign debtin both Europe and the US, the corporate bond marketsare functioning normally and most forms of credit remainbroadly inexpensive – a key difference from 2008. Second,the backdrop of the oil market is significantly different from2008. The supply side of the market is performing far morepoorly now than three years ago. Libya still remains outof the market, with the cumulative loss of Libyan barrelsnow moving close to 350m barrels, and declarations offorce majeure have reduced Nigerian supplies while oilembargoes are set to stymie Syrian exports. Moreover,the unrest in North Africa and the Middle East is leadingto higher break even price requirements to balancevastly higher spending programmes in most of theGlobal oil demand growth, mb/dGulf countries. Thus, the threshold for active producerinvolvement in the market is some US$20 -25 higher,lending support to an oil price at around US$90-100 perbarrel. Finally, the structure of the demand compositionof the oil market is significantly different now than it wasin 2008. In 2008, global oil demand was contracting, withthe burden of OECD demand declines a large 1.7 millionbarrels a day (mb/d). So far, despite the revisions to currentand projected US oil demand, the scale of decline in theOECD is a far more modest 0.5 mb/d.But it is really the scale and speed of non-OECD demandincreases that makes a significant difference to the globalpicture. The share of non-OECD demand has risen fromabout 44 per cent in 2008 to 48 per cent this year, andis en route to almost 50 per cent by next year. Withinthat, China’s share of global oil demand has increased bymore than 2 per cent. In fact, Chinese oil demand growthaveraged around 0.4 mb/d across 2008-09, half the levelof growth seen across 2010-11. Thus, China and emergingmarkets are in general far more important for the oildemand trajectory, and while measures to tackle highinflation have undoubtedly tempered the growth profilein the short term, structural factors should keep economicand oil growth at elevated levels in these countries.Perhaps most importantly, the main reason why we donot expect a repeat of the 2008-09 oil price cycle, shortof a macroeconomic discontinuity, is what that cycle toldus about the structure of the oil industry. Below US$90,investment dried up and was frozen; below US$70, theindustry was visibly struggling, with unconventional oil –increasingly the marginal supply on the non-OPEC front –the worst affected. On the demand side, lower prices fedinto a sharp global demand upswing, leading to the fastestdemand growth for 30 years, with it running at least twice asfast in 2010, and perhaps three times as fast, as the maximumthe supply side could cope with in the medium term. Sparecapacity of 6.5 mb/d quickly became spare capacity of just2.5 mb/d. The lesson of the last cycle is that the further pricesare forced below US$90 and the longer they stay there, thefaster the market tightens in the upswing.Over the next five years, a steady annual growth ratecorrected for distortionary base effects of 1.3-1.5 mb/dappears to us to be the status quo, short of a majormacroeconomic discontinuity, and non-OECD countriesare set to provide the bulk of that growth. Within thatsolidity, the main components of growth are those thathave become the regular ones in recent years (i.e. China,17420th World PETROLEUM Congress

InvestmentIndia, Saudi Arabia and Brazil). Indeed, it appears 2012 willbe no different. We project oil demand growth of 1.31mb/d in 2012, marginally higher than the current 1.13mb/d forecast for 2011, with the absolute level of demandaveraging 90.2 mb/d, a record high and the first timeglobal oil demand would achieve an annual average ofabove 90 mb/d. The oil demand profile is likely to continueto be dominated by non-OECD demand growth, which weexpect to be 1.57 mb/d.OECD demand, not surprisingly, is expected to slip backinto negative territory this year and follow through nextyear, on the back of increased energy efficiency and oildemand suppression policies together with significantlyhigher price averages compared to the past decades.However, structural trends tend to dominate the profileof non-OECD demand growth, which now constitutes afar larger share of global oil demand and all of global oildemand growth. In fact, straight after the financial crisisof 2008-09, the sheer scale of non-OECD demand growthresulted in global oil demand surpassing 2007’s peaks by1.7 mb/d last year, a good five to seven years earlier thanconsensus expectations. Indeed, in 2013, we expect non-OECD demand to overtake OECD demand in absolutelevels for the first time. The marginal consumer in the oilmarket is increasingly showing reduced sensitivities tohigher prices, evident in the robust growth in global oildemand even in the face of US$100+ average prices. Atthese price levels, it is not surprising that OECD oil demandis running lower, year on year, by over 200,000 b/d inthe year-to-date, with elements of destocking havingmagnified the extent of that fall somewhat.However, the fact that global oil demand is stillrunning higher, year on year, by 7 mb/d underlinesthe shift in the marginal barrel of oil demand. Whilethe blame for inflation, tighter policy response andpatchier economic growth has often been laid atthe door of high oil prices, the fact remains that weexpect global economic growth to average a solid3.8 per cent this year and 3.9 per cent next year(alongside an annual increase in oil prices of 39 percent and 3 per cent, respectively). Have higher oilprices tempered economic growth in some partsof the world? Yes, we think they have. But have theybeen the sole factor for the recent softness in themacroeconomic data? No, they have not, with factorssuch as the earthquake in Japan, a patchier recoveryin manufacturing and food inflation playing a hugelyimportant part. While the jury is still out on this debate, inour view, given the bias of inelastic non-OECD demand inthe global profile, the world can sustain a US$100 averageoil price without necessarily suffering from negativeeconomic growth in the short term. The juxtaposition oftriple-digit oil prices and 3-5 per cent economic growthis likely to remain a debate that continues in policy circlesthrough 2012.The supply side of the market is performing far morepoorly now than three years ago. We remain doubtfulabout the speedy re-incorporation of Libyan oil into theworld market. The first task of a new Libyan governmentwill be to repair the damage caused to the oilfields andother oil installations by a lack of investment funds,imported spare parts, and equipment and insufficientmaintenance. The second task will be to negotiate withforeign oil companies the terms of production-sharingagreements for investments and operations in new andold oilfields. The new government will be in dire needof revenues and will not be in a position to give moneyaway to foreign investors unnecessarily in our view. Theproblems of Libya will not necessarily be solved by thedeparture of Gaddafi; indeed, that might just be the startof some long-lived difficulties. The resumption of 250-500,000 b/d of production seems possible by year-end andinto the first quarter of 2012, in our view, but extrapolatingfrom this to the early restoration of full output volume of1.7 mb/d from Libya would be a mistake. →Annual changes in key demand centres in 2012Source: IEA, EIA, Barclays CapitalEnergy Solutions For All 175

InvestmentSource: NPDS, DECC, Barclays Capital→ Non-OPEC supply growth, too, seems to have entered aturning point, after the upsurge in new projects start-upsin the past two years. We expect a slightly higher growthprofile for non-OPEC supply in 2012, with a growth of 0.48mb/d following a growth of 0.15 mb/d in 2011. The fallin North Sea production is expected to continue nextyear, as technical problems aggravate the already sharplydeclining mature oil fields. Former Soviet Union output,along with China, has faced considerable technicalproblems this year and poses downside risk to ourforecasts for 2012, should the problems continue. Indeed,there is now a clear demarcation in non-OPEC supply, withgrowth largely concentrated in the Americas, and declinescontinuing elsewhere. The key theme going forward willbe how much and how fast production in the Americascan grow to offset declines in other parts of the world assignificant further increases from current levels remain adifficult enterprise for these non-OPEC supply countries.Outside Latin America, most of the growth in Americanproduction involves what would largely be classifiedas unconventional oil. As with most unconventionaloil plays, the break-even price required is significantlyhigher than the bigger, better behaved conventional oilfields, and thus, incrementally, non-OPEC growth is set tocome from higher cost areas in 2012 and beyond. Further,while exploitation in reserves in ever deeper waters hadin recent years been the key focus, there appears to bean emerging trend that is witnessing the cutting-edge ofNorth Sea oil production growthoil production techniques move back on-shore. Increaseduncertainty about costs and regulation after the Macondospill have imposed a pause on the growth in offshoredrilling, and while we expect offshore drilling to continueoff South America and Africa, we would expect onshore oilproduction to generate most of the incremental growthover the next two years.Finally, the combination of persistent strong demandgrowth continuing to outpace the momentum in non-OPEC output increases is set to keep the pressure on OPEC,and in particular, Saudi Arabia, high. Thus, unilateral Saudipolicy will remain key in 2012. Currently, the Kingdom, muchlike many OPEC countries, faces extremely challenginggeopolitical situations and has been spending heavily.The already high level of spending is set to remain for nextyear at the very least (we expect a 5 per cent year-on-yearincrease), given the commitment to pay out extra cashfor up to two years. We see little reduction in its defencespending, given the situation in neighbouring Yemenand Bahrain and its heightened tensions with Iran. Basedon this planned new expenditure, we estimate that totalgovernment spending will increase to 48 per cent of GDPand 45 per cent in 2011 and 2012, respectively. Thus, in ourview, current prices are roughly what Saudi Arabia is aimingfor; we do not detect any wish to sustain prices at lowerlevels. The extra spending has pushed price aspirations upby some US$25 per barrel, with US$100 becoming the newUS$75 in terms of the midpoint of producer expectations.Saudi Arabia will likely continue to try to preventany explosive breakaway in prices, but given thechances of the global imbalance tightening tothe extreme, this is likely to remain the biggestchallenge for the Kingdom over the coming years.All this has clear implications for oil prices. Ingeneral, the trend of steady growth in demand,with supply attempting to play catch-up at best,creates an environment for higher prices. This isaided further by changing producer aspirationsand a heightened geopolitical backdrop. Thegrowth in demand is rather rapidly likely to pressagainst the limits of global supply, with most ofthe work needed to be done by prices in order tobalance the market. In the more immediate term(i.e. 2012), eroding spare capacity and an almostnon-existent inventory buffer is likely to keepprices infused with a large degree of dynamismand volatility.•17620th World PETROLEUM Congress

InvestmentTrends in global gas pricingBy Howard V Rogers, Director, Natural Gas ResearchProgramme, Oxford Institute for Energy StudiesOil and gas are both fluid hydrocarbons. Theirexploration and development technologiesare in general very similar and indeed in somecircumstances they are both produced from thesame well. With crude oil traded as a global commodity(albeit as benchmark regional blends) since the 1980s, onecould be forgiven for assuming that natural gas would alsohave a global reference price. While this is not the case atpresent, this paper explores how a more ‘price connected’future for gas may evolve in ways that will be the focus ofdetailed research by the Oxford Institute in 2012.Source: IGUA world of difference in gas pricingNatural gas suffers, however, from being, well, a gas, i.e. itsenergy per unit of volume (at atmospheric pressure) is only0.1 per cent of that of liquid crude oil. Transporting and storinggas will involve higher infrastructure investment relative to oil.Liquefied Natural Gas (LNG) is gas that has been cryogenicallycooled to minus 163 degrees Centigrade where it exists asa liquid at atmospheric pressure. In this state its energy perunit volume is 65 per cent of liquid crude oil and LNG can beshipped vast distances between the point of production anda destination market. This is only possible, however, throughthe construction and use of purpose-built liquefaction plant,loading and unloading facilities, insulated storage tanks andocean going LNG tankers. At the destination market the LNGis re-gasified to enter the distribution grid. This supply chainis capital intensive and its construction confined to relativelyfew specialised contractors.Oil price escalation - 20%No price - 1%Figure 1: World gas price formation2007 - total consumptionRegualtion below cost - 26%Gas-on-gas competition - 32%Bilateral monopoly - 8%Netback from final product - 1%Regulation cost of service - 3%Regulation social and politcal - 9%Given its relatively high cost of transportation andstorage, it is unsurprising that historically, natural gasproduction has tended to grow to supply nearby nationaland regional markets. Accordingly each developed its ownapproach to natural gas price formation. A comprehensivereview of regional policies is contained in ‘Wholesale GasPrice Formation – A global review of drivers and regionaltrends’ by the International Gas Union, as shown in Figure1. While 52 per cent of global gas consumption is priced onthe basis of gas on gas competition or by reference to oilor oil products prices, much of the remainder is regulated,often at levels significantly below those prevailing inthe OECD markets of Europe and North America. This isillustrated dramatically in Figure 2 which shows that in2009 gas prices in the Middle East, Latin America, Africaand the CIS were in the range US$0.80/mmbtu to US$2.50/mmbtu, levels significantly below the world average ofUS$4.00/mmbtu.The rise of the long-distance gas tradeAs growing regional gas markets outpaced the availabilityof indigenous and proximate supplies the growth of‘long distance’ gas (trade-flows of pipeline gas and LNG)became established. This is shown in Figure 3. Longdistance gas is classified as LNG (blue) and pipeline tradeflowsfrom Russia, North Africa, Iran and Azerbaijan intoEurope and pipeline flows within Asia and South America(red). In the period 1995-2010 both grew with LNG on acontinuous trajectory. The recent economic recessionresulted in a fall in global gas consumptionand pipeline trade-flows in 2009. However,LNG consumption increased markedly over2008 levels in 2009 and 2010.The main regional markets impacted(or potentially impacted) by the growth inlong-distance gas are North America (US,Canada and Mexico), Europe and the mainLNG importing countries of Asia (Japan,South Korea, Taiwan, China and India). Theintriguing question is “given the differingmechanisms of price formation in eachregion, what happens when you ‘plug themtogether’ with long distance gas?”To explore this we need to understandhow gas pricing is formulated in each ofthe regions and the nature and degree offlexibility of pipeline gas and LNG.17820th World PETROLEUM Congress

InvestmentRegional price formationNorth AmericaGas prices in the US are in the first instance driven by gason gas competition and are discoverable at the manyregional trading hubs. The best known is Henry Hub (HH)which is viewed as the marker for US natural gas prices.The US has a ‘porous’ gas trade border with Canada andMexico, both of which have prices influenced by the USmarket. Due to the potential for inter-fuel competition inthe power generation sector, gas prices can at times beinfluenced by residual fuel oil. However, this has not beena factor since 2006. In the expectation that the US wouldrequire significant LNG imports some 125 bcm a year ofLNG regasification capacity was built in the mid to late2000s. With the dramatic growth in shale gas productionsince 2006, re-gas utilisation rates are extremely low andthe industry is currently pursuing the conversion some ofthese facilities to LNG export facilities.EuropeWith the exception of the UK market which became liberalisedin the 1990s, Europe began the 2000s with a market structuredominated by long-term oil indexed contracts for its pipelineand LNG imports and also its domestic production. Pipelinegas purchased under long term contracts from Russia andNorth Africa is priced according to formulae which includesix to nine month rolling averages of gasoil and fuel oil prices.The pricing terms are subject to periodic review (typicallyevery three years) and may be amendedthrough negotiation. The buyer commits tobuy at a minimum the ‘Take or Pay’ level (TOP)within a contract year running from October toSeptember of the following calendar year. Thetake or pay level is typically 85 per cent of theEuropeAnnual Contract Quantity (ACQ).Asia-PacificGas market liberalisation in continentalTotal WorldEurope has been a slow and tortuous process.However, the gas demand reduction caused North Americaby the economic recession coinciding withAsiaa rapid growth in LNG supply from Qatar hasCISresulted in vigorous activity in the nascentgas trading hubs of Northern Europe andAfricaa growing challenge to the oil-indexedLatin Americaparadigm for gas pricing. A buyer of gas inMiddle EastContinental Europe can choose whether ornot their requirements for gas above the oilindexedcontract Take or Pay level can be met by optionaladditional oil indexed contract gas or ‘spot’ gas purchasedon a trading hub (much of which physically originatedfrom the UK market via the UK-Belgium Interconnectorpipeline). When conditions for arbitrage have beenfavourable this has resulted in period of price convergencebetween UK gas prices and those linked to oil productsprices on the European continent.Asian LNG marketsThe majority of LNG trade flows in Asia are sold under longtermcontracts with price related by formulae to a timeaveragedvalue of crude oil. The coefficient linking LNGprices to oil prices differs between contracts and somecontracts also contain price ceilings and floors or an ‘S’curve which moderates the more extreme oil price impacton the LNG price. Asian importers also purchase spot LNGcargoes to supplement contracted supplies. Unlike thesituation in Europe, there is no explicit provision in thesecontracts for a periodic price review. Each contract pricingformula is in effect ‘fossilised’ for the life of the contract – a‘snapshot’ of the negotiated view of buyer and seller as tohow the future LNG price should respond to oil price. Overtime the differences in formulae relating LNG prices to oilprice have led to a wide range of LNG contract prices. In2004 contract prices were reasonably bounded but in 2011the spread is between US$4/mmbtu to US$15/mmbtu.The spread of Asian LNG contract prices also meansthat there is no obvious regional benchmark for spot →Figure 2: Average wholesale gas prices by region, 20090 1.00 2.00 3.00 4.00 5.00 6.00 7.00 8.00US$/MMBTUSource: Mike Fulwood, 2009 IGU Survey of Wholesale Gas PricesEnergy Solutions For All 179

InvestmentSource: BP Statistical Review of World Energy 2011, Own Analysis→ LNG cargoes purchased. In the absence of an obviousalternative, Asian spot LNG cargoes are often priced relativeto the UK gas price (National Balacing Point) plus a marginwhich presumably reflects a distance-related shippingcost and possibly, as the market becomes tighter, a furtherpremium to attract cargoes.The flexibility of lngIn order to consider how the regional markets of NorthAmerica, Europe and the Asian LNG importing marketsmight behave when ‘plugged together’ let us firstconsider the flexibility of LNG supply. The majority of LNGis sold under long term contracts. However, the trend hasbeen towards more flexible arrangements.Even LNG under long term contract can be diverted ifthe contract buyer and seller agree to divert cargoes for ahigher sales price and share the proceeds. This is especiallythe case in European LNG supply contracts.Interaction between regional gas marketsThe schematic in Figure 4 is a depiction of the gas marketsof North America, Europe and the Asian LNG Importingmarkets in 2011. Global LNG supply is represented bythe tap at the top of the diagram. The Asian markets arebcma3,5003,0002,5002,0001,5001,000500Figure 3: Global gas supply channels 1995 - 2010019952000Production consumed within regionLNGLNG % of total2005assumed to take whatever LNG they require to meettheir demand (Japan, Korea and Taiwan having no othersources of natural gas). The remaining LNG is available forEurope and North America. At the moment however, dueto the growth of shale gas production in the US, NorthAmerica only takes minimal quantities of LNG. Europe isthus absorbing the balance by virtue of its ability to reducepipeline imports of oil-indexed gas to Take or Pay levels.What we have in this situation in mid-2011 is:• North America as an isolated, self-sufficient gas marketwith prices around US$4.50/mmbtu.• A ‘hybrid’ European market with traded hub spot pricesat US$9/mmbtu and oil indexed contract prices at US$11/mmbtu to US$12/mmbtu, with buyers trying to satisfytheir contract TOP commitments whilst maximising theirtake of cheaper spot gas.• Asia with a range of LNG contract prices from US$4/mmbtu to US$15/mmbtu with supply supplemented byspot cargoes at a price of around US$12/mmbtu, apparentlylinked to European hub spot prices with a transport marginand premium.The next stage of the evolution of the system dependscrucially upon the US and the future trajectory of US shalegas production. Proponents of US shale gas see potentialfor supply growth well in excessof the country’s consumptionrequirements. A number of LNGexport projects are under active20%consideration. The economics18%of exporting LNG from theUS appear to require a price16%difference of some US$3.50/14%mmbtu between US natural12%gas prices and those of thedestination market. In broad10%terms US$2.00/mmbtu for the8%cost of the liquefaction plant,US$1.00/mmbtu for shipping6%and US$0.50/mmbtu for4%regasification at the destination2%market. If enough LNG exportcapacity is built for the ‘system’ to0%reach equilibrium, the outcome2010(probably around 2020) wouldbe:In Europe (if oil indexedcontracts survive) gas pricesLong distance pipelineLong distance pipeline % of total% of total supply18020th World PETROLEUM Congress

Investmentwould be determined by the present two tier arrangementwhere hub spot prices are either below oil-indexed pipelineimport contract prices (as they are in 2011) or above them(due to tight market conditions); or, in a balanced market,hub and oil-indexed prices converged through arbitrage.If long-term contracts transition to adopt hubs as theirpricing basis, European prices would be driven in the firstinstance by supply-demand considerations.Asia’s oil indexed LNG contracts would continue toexhibit a wide price range, The interesting question iswhether the LNG spot market becomes deeper and moreliquid. Whilst Asia might continue to use European hubprices as a reference, the competition between Europeand Asia for spot cargoes would in turn influence Europeanhub prices.In North America, assuming regulatory authorities donot limit the scale of LNG exports, US prices could beexpected to stabilise at a level US$3.50/mmbtu belowEuropean hub prices.If however, as some commentators expect, US shaleproduction is unable to fulfil the potential describedabove, the US will at some point revert back to being animporter of LNG. The outcome (again probably around2020) would entail active LNG arbitrage between Europeand North American. Inthis alternative view of2020, US prices couldconverge with those ofEurope in periods whereEurope was able to closethe price gap thougharbitrage by optimisingLNG and pipeline imports.In practice there wouldprobably be a differentialLNG transportation costdifference of betweenUS$0.50/mmbtu andUS$1.00/mmbtu. Europeanpipeline import volumeconstraints and the needto meet Take or Paycommitments would attimes, however, preventarbitrage from closing theprice gap. If oil-indexedcontracts survive in Europethe net effect would be an arbitrage dynamic which wouldseek to bring US prices up to oil-indexed levels wherephysical factors permitted this.ConclusionsThe discussion of the potential for greater pricing linkagebetween regional gas markets broadly in the 2020 timeframeabove is predicated upon the dynamic interaction betweenthe liberalised markets of North America and the UK and thenewly formed trading hubs of Continental Europe. The keymedium-term uncertainty relates to the future performanceof US shale gas and whether this results in North Americabecoming a net exporter or importer of LNG.We are at present in the midst of an evolution in thenature of natural gas markets where, despite the inherenthigh costs of transporting and storing this commodity,differences in price level between regional marketsprovide a strong motivation for arbitrage via flexible LNG.As such arbitrage plays develop and intensify we mayalso expect to see a ‘Darwinian’ competition between oilindexation and hub-based pricing systems. For now sucha competition is likely to be confined to Europe. Howeverin time, through a deepening of its LNG spot market suchchanges may also influence the Asian market. •Figure 4: System dynamics 2011Energy Solutions For All 181

InvestmentEnergy project finance andbank capital constraintsBy Peter GawManaging Director, Global Head of Oil & Gas, Standard Chartered BankSource: FactSetThree years have passed since the meltdown ofthe financial markets and the virtual collapse ofthe international banking system that continuesto overshadow the global economic recovery tothis day. The myriad of regulations and controls in theglobal banking system in 2008 failed to identify and rectifyserious flaws inherent in the financial markets. Under theBasel II accord, in place during the run-up to the crisis,banks were discouraged from lending to risky enterprisesand encouraged to hold apparently ‘risk-free’ assets thatrequired minimal capital. In this lay the seeds of the crisisas many of the ‘risk-free’ assets banks held turned out tobe packages of assets that were anything but risk-free.Unfortunately, the best of regulatory intentions appear tohave been a contributing factor to the depth and durationof the 2008 financial crisis.The crisis revealed deficiencies in financial regulationsthat have led to the development of the Basel IIIAccord, which aims to further strengthen bank capitalrequirements and introduce new regulatory obligationson bank liquidity and leverage. Basel III will come into effectin 2013 and will take many years to be fully implemented.However, the situation is further complicated by the factthat local regulators will likely have the flexibility to impose6%5%4%3%2%1%Fed funds target rate vs LIBOR and other benchmark rates (%)Ben Bernaketestimony that the USsub-prime crisis couldcost up to $100bn30 lenders alreadycollapsedNo liquidity insub-primestricter measures as they deem necessary, although EUregulators, for instance, are trying to impose a single set ofrules on their banks. The question we must ask is whetherthis new regulatory regime will prevent a repeat of the2008 global financial crisis and more importantly, will theproposed ‘cure’ have the unintended consequence ofstifling liquidity and hence future economic growth? Inthis article, I will examine the expected impact of BaselIII on the financial markets as well as the impact on bankfinance available to the oil and gas sector.Post-crisis financingSubsequent to the 2008 crisis, financial markets worldwidewitnessed a severe shortage of liquidity and a significantjump in credit spreads despite the virtual collapse ininterest rates.The widening spread in rates between the US Fed FundsTarget Rate and one-month USD Libor rate, exemplifiedthe instability during the period of the crisis. Post-crisis, theabsolute level of the rates decreased substantially and thegap closed with the US Fed Funds Target Rate at 0.25 percent, and the one-month USD Libor rate has remained ata similar level with only slight deviations. The market hasclearly stabilised and spreads have contracted from thepeak of 2008-2009.0%Jan07 Jun 07 Dec07 May08 Nov08 Apr09 Oct09 Mar10 Sep10 Mar11Fed funds target rateLehman Chapter 11Freddie Mac andFannie Mae bail out1 month USD LIBORGovernment responseOctober 2008• US$700bn rescue planfor US financial sectorUK rescue package• £50bn plus up to £200bnshort-term support• UK takes direct stake inRBS, Lloyds/HBOSUS$250bn plan to purchasestakes in banksWhile central banksacross the globeincreased money supplyand bank access tocapital, the bankingmarket significantlycontracted, preservingexcess liquidity tomanage down theirown, often toxic,portfolios. This had asevere dampening effecton economic growthand global demandwhich, combined withthe collapse of thecommodities market,reduced access toliquidity in the oil andgas sector.Oil and gas companiesfared rather better than18220th World PETROLEUM Congress

Investmentother sectors due to their collective strong balance sheetsand cash flows even though the industry was faced withconstrained bank liquidity at significantly higher pricing.Across all sectors, access to corporate credit will be a vitalfactor in the recovery of OECD countries but with banklending still restricted, bonds have become increasinglyimportant. The timing of bond issuance is critical, especiallywith market volatility being exacerbated by sovereigndebt uncertainties.Oil and gas companies were able to raise capital in thebond and equity markets during the crisis because theenergy sector was perceived to be underpinned by strongdemand growth from China and other emerging markets.The oil and gas sector successfully raised over US$200 billionin new bond issuances in 2009 alone, which was higher thanin 2010 and 2011 to-date. It is interesting to note that therewas varying ease of access to capital within the industry.While large oil and gas companies with sizeable balancesheets and cash flows witnessed no major problems, thesmaller, more entrepreneurial players, with limited cashflow and large capital expenditure programmes, faceda more daunting challenge. A number of these smallerplayers faced severe liquidity shortages and in some caseswere forced either to raise emergency equity, consolidatewith other players orto restructure in orderto fund relativelylarge expenditureprogrammes.16%being experienced by companies with different creditratings. Large corporates with strong balance sheets andcash flows have ample access to capital in the currentmarket.Overall impact of Basel IIIDuring the financial crisis, an over-leveraged bankingsystem was unable to absorb the systemic trading andcredit losses. The interconnectedness of the financialinstitutions caused the weakness in the banking sectorto spread rapidly to the rest of the financial system andto the wider economy. As a result, the public sector hadto step in with liquidity injections, guarantees and capitalsupport that exposed taxpayers to significant burdens. Theobjective of the Basel III reforms is to improve the bankingsector’s ability to absorb such shocks arising from financialand economic stress and hence reduce the potential spilloverfrom the financial sector to the real economy.However, the likely net result of Basel III for the bankswill be that they will be required to hold more capitaland liquidity, and reduce their balance sheet leverage.Banks will be required to hold significantly more liquid,low-yielding assets, which will have a negative impact ontheir profitability. This has the potential to reduce banks’ →Corporate spreads (averages of Europe and US - %)Stabilisation in2011The spreads oncorporate debt ofAAA and BB ratedcompanies (acrossall industry sectors inthe US and Europe)widened over asimilar period buthave stabilised in2011. The implicationis that the marketnow has significantdifferentiation inthe loan pricing andaccess to capital14%12%10%8%6%4%2%0%Jan07 Jun07 Nov07 Apr08 Sep08 Feb09 Jul09 Dec09 May10 Oct10 Mar11BBAAASource: IMF World Economic Outlook 2010Energy Solutions For All 183

Investment→ lending ability. In addition, banks will also need to reducetheir dependence on short dated funding and increasedthe proportion of their funding with a maturity of over ayear. These two measures will lead to an increase in thecost of borrowing that could eventually feed through tothe wider economy and world trade. Once again, the law ofunintended consequences can be quite harsh. The realitiesof Basel III will likely be higher costs, more selective loanportfolios, shorter tenors and less structured financings.It is also possible that the banks may be required by themarket and the rating agencies to maintain a lower degreeof leverage than required by the regulator.In such circumstances, weaker banks may find it difficultto raise the required capital and funding, leading to areduction in competition. Investors may also be lessattracted by bank debt or equity issuance given thatdividends will likely be reduced to allow firms to re-buildcapital bases, and therefore the banks will have no optionbut to shrink their balance sheets.Implications for the oil & gas industryWhile we have seen that the oil and gas industry hasweathered the financial crisis rather well, we should beaware that the situation can easily take a turn for the worse.To illustrate how the acceptability of certain financingscan change rapidly, the precipitous drop in projectfinancing in the oil and gas sector during 2009 reflectedthe realities of the stress that the banks were under and, tosome extent, the reduction in discretionary spend by theindustry. During this period the number of project financebanks diminished due to the risk profile, longer tenors andgreater complexity of the asset class. Many banks rejectedstructured deals, looking more to ‘plain vanilla’ financingin order to improve their respective loan portfolios.The vast majority of oil and gas project financing dealswere for assets located in emerging markets but manybanks pulled back from such markets in order to repositiontheir portfolios. Moreover, regulatory requirements in thesemarkets demanded increasing local bank participation inthe financings. The shortage of liquidity in these smaller,local banks, led to higher pricing for borrowers than couldbe offered by international banks – something which maybe exacerbated by the regulations under Basel III. Theirony of this strategy of pull-back from emerging marketrisk is that the financial crisis of 2008 had nothing to dowith emerging markets or the project finance asset class.The knock-on effect of higher capital ratiosCutRisk-WeightedAssets (RWA)To achievehigherrequiredcapital ratioIssue NewEquityHigher costof fundingto banksHigher lendingspread toprivate sectorborrowersIncreaseRetainedEarnings18420th World PETROLEUM Congress

InvestmentRegardless, liquidity has returned to the market and theinfluence pendulum between issuers and banks that hadshifted to the banks during the crisis is now shifting backto the issuer side.Despite concerns about the possible impact of BaselIII it must be remembered that the pricing of financingswill continue to be dependent on credit quality andthe availability of alternative sources of financing suchas export credit agency (‘ECA’) financing. Changes totreatment of risk-weighting under the Accord mightincrease the price of ECA-backed loans as it is proposedthat certain assets, such as ECA-backed loans shouldbe exempt from the calculation of the 100 per centconversion factor leverage ratio. This might negativelyimpact banks’ ability to provide export credit facilitiesand trade finance. Recent history suggests however,that if the Basel III regulation had the effect of increasingcorporate lending margins, we may see a shift fromcorporate lending to bond issuance.ConclusionThe balance sheets and cash flow of the oil and gasindustry are in very good shape following two years ofrobust commodity pricesand the increasing non-OECD demand. This putsthe industry in a positiveposition to raise capital,relative to many othersectors, as demonstratedby the rash of M&A activityover the past 18 months,increasing by 40 per centafter two consecutiveyears of decline.Massive amounts ofcapital from multiplemarkets are requiredover the coming decadeto meet the insatiableappetite of oil and gasdevelopment projectsfor both International OilCompanies (IOCs) andNational Oil Companies(NOCs). With such highcapital requirements(US$0.5 trillion of upstream expenditure is anticipatedthis year alone) it is possible that the banks’ increasedcapital and liquidity requirements might constrain creditlines and reduce country limits. The knock-on effectmight be a reduction in banks’ lending capacity for the oiland gas sector overall or potentially in certain countrieswhich will likely increase the overall cost of future capital(debt and equity).Robust and relatively stable oil prices, underpinnedby growing demand from emerging markets remain thedominant factors determining the financing appetite ofthe oil and gas industry. The impact of new financial sectorregulation will likely have a greater impact on banks andless on the oil and gas sector as a whole.Capital is unlikely to be a serious constraint for theindustry over the medium term. The favourable riskoutlook for the industry combined with the positivemarket perception (flight to quality) place the oil and gassector in an enviable position. However, it is dangerousto assume that we are ‘out of the woods’ just yet. Thefragile global economy, sovereign debt problems andanaemic Western economic growth, are clear warningsigns for the future.•Bank loans and project financing in the oil and gas sector (US$ bn)Source: DealogicEnergy Solutions For All 185

InvestmentPutting money aside:The Norwegian exampleBy Wilhelm MohnMinistry of Finance, NorwayThe history of modern Norway was altered by thediscovery of oil during Christmas 1969. Norway hadbeen a relative laggard in Western Europe in termsof industrialisation, and the economy was largelyinfluenced by a geography favouring hydro-electric power,fisheries and shipping. The oil discovery roughly coincidedwith end of the post-war reconstruction period and theestablishment of the welfare state. It was realised earlyon that the one-off monetisation of the nation’s resourcewealth should also benefit future generations. Figure 1illustrates the challenge faced by resource-rich countries intheir management of resource windfalls: how to transformfluctuating and perishable revenues into a permanentincrease in consumption? A financially motivated fund isone answer to this. By investing the fund solely in foreignassets, the threat of overheating the domestic economycan also be reduced.The Government Pension Fund Global (GPFG) wasestablished in 1990 as a fiscal policy tool to support a longtermmanagement of the petroleum revenues. Due to theFigure 1: The natural resourceextraction path does not providefor a smooth consumption pathExtraction patht oConsumption pathafter discoveryConsumption path beforepetroleum discoveryTimemacroeconomic situation, the first transfer to the Fundhappened six years later. The Fund has an important rolein facilitating government savings to meet the rapid risein future public pension expenditure (Figure 2). The Fundis, however, not earmarked for pension expenditures. TheFund’s objective is to maximise long-term internationalpurchasing power. The Fund’s size at year end 2010 wassome US$525bn, and it owns around one per cent of theworld’s listed equities.The Fund’s structure and governanceThe Fund’s income consists of all state petroleum revenues,net financial transactions related to petroleum activities, aswell as the return on the Fund’s investments. The Fund’sexpenditure is the sum needed to cover the non-oil budgetdeficit. Transfers can only be made following a vote in theNorwegian parliament. Net allocations to the Fund reflectthe total budget surplus (including petroleum revenues).The Fund cannot be earmarked for specific purposes andcannot be invested in Norway (and thus is not a secondarybudget). Consequently, the allocation of fund liquidityforms part of an integrated budgetary process, and rendersthe State’s use of petroleum revenues visible. Fiscal policyis anchored in the guideline that over time the structural,non-oil budget deficit shall correspond to the real returnon the Fund, estimated at 4 per cent. Whilst this is not alegal requirement, it enjoys broad political support. It is atransparent and simple rule, which should ensure that theFund remains a permanent fund.In the Government Pension Fund Act, the NorwegianParliament made the Ministry of Finance responsiblefor the management of the GPFG. Key changes toinvestment guidelines are presented to Parliamentbefore implemented. There is a clear division of roles andresponsibilities between the the Ministry of Finance, andthe operational management, which is carried out byNorges Bank (the Central Bank) based on a mandate givenby the Ministry (see figure 3). In the mandate, the Ministrysets guidelines, including benchmark, provisions onresponsible investment and risk limits. The Ministry reportsyearly to Parliament on the management of the fund.A sound governance structure is necessary for successfulstrategy implementation; it must ensure that importantdecisions relating to fund management risk have thesupport of the Fund’s owners, the Norwegian people asrepresented by the Parliament. There must also, however,be sufficient delegation of authority to allow day-to-day18620th World PETROLEUM Congress

Investmentdecisions in the operational management to be made closeto the markets. Efforts are made to achieve this balance bysubmitting decisions of material significance to the Fund’srisk level to the Storting before their implementation,while the mandate issued by the Ministry to Norges Bankis based, insofar as possible, on principles and frameworks.In this way, a necessary and high degree of delegation iscombined with the ”owner” having a good understandingof, and ultimate responsibility for, all major strategydecisions. Such a balance can only be achieved througha clear division of roles and responsibilities between allgovernance levels involved in the management. Oneneeds to make every level of management resposible forthe decisions delegated to them, and have good controland supervisory bodies in place.Over time, there should be interaction between thegovernance system and the Fund’s investment strategy.The investment strategy must take into account thedistinctive institutional features of the Fund. The need tosecure the support of political bodies for important aspectsof management means, for example, that it is difficult todesign investment strategies based on taking quick, timecriticaldecisions. On the other hand, the strategy must alsobe able to exploit the Fund’s distinctive characteristics, inorder to improve the trade-off between return and risk.Investment strategyThe Ministry receives advice on the investment guidelinesfrom Norges Bank, the Ministry’s advisory council oninvestment strategy and external consultants. The Ministryuses external consultants for controlling performancemeasurement and peer group benchmarking.Investment strategy must be based on a combinationof how the markets in which the Fund invests work, andwhat distinctive characteristics the Fund has as an investor.The most important characteristic of the Fund as a wholeis probably its long horizon, size, state ownership and verydiversfied portfolio.Avoiding risk is not an objective for the managementof the Fund. On the contrary, risk-taking contributes toreturns over time. The GPFG has considerable ability tobear fluctuations in the Fund’s returns from year to year. Theinvestment strategy is therefore not aimed at minimisingshort-term value fluctuations.Diversification is a powerful mechanism which allowsone to realise better risk-adjusted returns. The power ofdiversification underlies the entire investment strategy, andalso the motive behind the Fund; to reinvest the windfallgain from a perishable resource into a diversified portfolioof foreign assets which will provide a more stable andsecure, income stream. Developments in the investmentstrategy has meant the fund has become more diversifiedover time. A portfolio of property investments is currentlybeing built up.The value of transparencyThe Fund is subject to a high degree of transparencyand much public interest. The management of thepetroleum revenues in general and the Fund in particularis characterised by a high level of disclosure. The Ministryof Finance emphasises transparency and public access toinformation. We see transparency as crucial to buildingtrust and confidence in the management of the Fund –both domestically and internationally. Internationally,there has been considerable attention paid to the factthat some sovereign wealth funds (SWFs) have littletransparency about their activities and to the possibility →Figure 2:Pension expenditure andexpected Fund real return as a share ofmainland (excluding oil and shipping) GDP181512963PensionsExpected real returnon the Fund02005 2020 2035 2050Energy Solutions For All 187

Investment→ that they may have non-financial objectives for theirinvestments. Domestically, transparency is a preconditonto secure public support for sound management ofNorway’s petroleum wealth. Anchoring the strategy, andexplaining the various sources of risk, has been a particularfocus in public documentation.The Ministry reports to Parliament on all importantmatters relating to the Fund, such as the size ofpetroleum revenues and the Fund; the outlook for fiscalsustainability; changes to the investment strategy; theFund’s performance, risk and costs. The Ministry publishesadvice and reports received from Norges Bank andexternal consultants. Norges Bank publishes quarterlyreports on the management of the Fund, as well as anannual report, an annual listing of all investments andannual voting records. The reports include performance,risk and costs and is published on the website. In additionthe asset manager publishes live simulated total assetsunder management on its website.Figure 3: Division of roles and responsibilitiesin the management of the GPFGStortinget (Norwegian Parliament)• Government Pension Fund ActMinistry of Finance• Mandate• Regulation on risk management and internal controlNorges BankWhilst transparency is fundamental, there is probablyalso such a thing as ”too much transparency”. On thestrategic level this can lead to an execessively short-termfocus or under-utilisation of financial risk limits. It can alsothreaten the efficiency of the GPFG’s ownership efforts, asit might reduce the topics NBIM, the fund managers, couldengage in dialogues with companies, external managersand other stakeholders. Finally, specifically when it comesto regimes for rebalancing or transfers to the fund, toomuch transparency might lead to harmful “front-running,”where advance knowledge of transactions can lead tomarket share abuse.External assessmentsThe Generally Accepted Principles and Practices (GAPP),or Santiago principles, for SWFs establish a set of sensibleprinciples for the organisation and management thatcan build trust with recipient countries and in financialmarkets. The Ministry of Finance view the principles as aminimum standard which• National Budget• Annual Report to Stortinget• Quarterly and annual report• Investment strategy adviceall SWFs should adhereto where applicable. TheMinistry has publisheda self-assessment of theGPFG’s adherence to theprinciples.The Fund has beenassessed by externalbodies which addressmany of the same issuesas the GAPP. The GPFG hasconsistently scored well inthese assessments. Whilstnot directly comparableto the recently publishedself-assessment, thesecorrespond well with theconclusion that the Fundadheres satisfactorily to theGAPP. The transparency ofthe petroleum revenuesbefore they reach the Fundhas also been assessedexternally by the ExtractiveIndustries TransparencyInitiative (EITI), of whichNorway is a member.18820th World PETROLEUM Congress

InvestmentThe work of the International Forum for Sovereign WealthFunds (IFSWF) and the continued implementation of theGAPP are important. At the same time, it is clear that themembers of the forum are a very heterogenous group, andso the application of the principles will legitimately andnecessarily differ from SWF to SWF – an obvious exampleis that some of the IFSWF member do not invest in equities,making equities related principles largely irrelevant. It isalso clear that some of the issues that concern us as aninvestor, for example good corporate governance orother factors leading to well-functioning markets are notaddressed through the principles.Responsible investing and active ownershipThe Pension Fund is managed on behalf of the Norwegianpeople. Shared ethical values therefore form the basis forthe responsible management of the Fund. Generatinggood long-term returns is a fundamental obligation, andmay depend on a sustainable development in economic,environmental and social terms, and on well-functioningfinancial markets. The Fund is a long-term owner withassets spread across a large number of companies inmany industries and countries. In this way, the Fundindirectly owns a share of the world’s production capacity,it is what has been referred to as a ”universal owner”. TheFund therefore has a comprehensive RI strategy whichincludes both exclusion (as a measure of last resort) andobservation of companies, financially motivated mandatesspecifically targeting environmental investments, researchand international collaboration. Perhaps the main and mostappropriate RI tool for a diversified and long-term investoris active ownership. The overall purpose of active ownershipis to safeguard the Fund’s financial values by contributingto good corporate governance and by striving to achievehigher ethical, social and environmental standards in thecompanies. Good corporate governance is important forthe Fund’s returns over time and to ensure the owners realinfluence and dialogue with the companies in the portfolio.Norges Bank has chosen to concentrate its ownershipactivities in certain key areas of significance to the portfolio.With relatively small individual holdings, such a strategyprovides a better opportunity for making an impact. Themanager has made it a priority that the areas should berelevant for investors generally and the Fund’s portfolioin particular. They should also be suitable for dialoguewith companies and/or regulatory authorities, provide anopportunity for making a real impact and be justifiablefinancially, since the manager acts in the capacity of investor.The focus areas include the equal treatment of shareholders,shareholder influence and board accountability, wellfunctioning,legitimate and efficient markets, climatechange, water management and children’s rights.The NBIM has developed publicly available principles forvoting, and aims to vote at all annual general meetings,currently around 10,000 a year. The manager votes on allissues, including those that fall outside the focus areas. Thevoting records are made public.ConclusionLarge petroleum revenues have resulted in substantialfinancial assets in the GPFG, to the point where it is nowamongst the largest SWFs in the world. In the more than 15years that have elapsed since the first transfer to the formerGovernment Petroleum Fund, there have been majorchanges to the Fund’s strategy. This seems likely to continue.The Norwegian experience is rather unique. Norwayhas realised its resource wealth from an alreadyenviable position, as a small, stable, democratic andeconomically developed country. This, and previousexamples of economies over-heating and succombingto so-called dutch disease, has enabled the country tochoose what is hopefully a more sustainable and longtermmanagement of the country’s resource wealth. Forthis reason, while the Norwegian model has been wellreceived in internationally, and to some extents inspireddevelopments elsewhere, it is inappropriate to use anyone country’s experience and set-up as a blue print fordevelopments elsewhere. The general principle probablyholds for most countries, however; if you find yourselfwith substantial and perishable source of income, it mightmake both current economic and inter-generationalsense not to spend it all at once.The Fund is already a major owner in the global equitymarket. On average, the GPFG owns around one percent of all listed equity in the world. In many companiesit numbers amongst the largest individual owners.Projections for the Fund for the period to 2020 showthat the Fund’s ownership shares will continue to grow.This, however, does not alter the Fund’s role as a financialinvestor. But it does strengthen the need for the exerciseof ownership as a necessary effort to protect the Fund’seconomic interests. The Fund’s management cannot bebuilt on the assumption that this important work will beadequately taken care of by other owners. •Energy Solutions For All 189

InvestmentPetroleum fiscal terms:Old and new challengesBy Philip Daniel, deputy division chief, fiscal affairsdepartment, International Monetary FundPotential for transformative new projects in theupstream petroleum sector (crude oil and naturalgas) remains – notably in Africa, and also in Brazil. Thelast few years have also seen dramatic developmentin exploitation of shale gas. Despite concerns about “peakoil” and difficulties of access for international oil companies(IOCs) to new reserves, countries are emerging – new to thepetroleum industry –where projects massive in relation tothe size of the existing economy are in prospect. In Africa,these are reality in Ghana, Niger and Uganda, and possibilityin Liberia, Mozambique, Sierra Leone, and Tanzania. Designand implementation of fiscal regimes for future petroleumexploration and extraction is a vital interest for these countries.This article outlines these challenges from the perspectiveof countries seeking international investment, using taxand royalty schemes, or production-sharing contracts, orrisk service contracts, under which companies take risksand share in rewards. 1 More than half of world output,however, comes from wholly or substantially state-ownedsystems, where private companies participate, if at all onlyon fee for service terms, and different issues arise.What’s special about petroleum?Relative to most host economies, the sheer size of thepetroleum sector, and of individual projects, distinguishesit. Government revenue is most often the central benefit,and stimulating ancillary economic development is acontinuing challenge. The industry has high sunk costs priorto production, and long production periods, creating whateconomists term the “time-consistency” problem: termsthat seem welfare-maximising when a project is negotiatedare tempting for governments to change once investmentis sunk and production started. Petroleum production haspotential to generate substantial rents – in the sense of asurplus over all necessary costs of production including aminimum required return on capital. This is the public financeideal of a non-distorting, immobile tax base. At the same time,however, international tax considerations loom large: not onlythe interaction of host country and corporate home systems,but also tax competition in attracting investment.Uncertainty faces both governments and companies:uncertainty over geology, technology, price volatility, and– for companies – sovereign actions. Volatility in oil prices iswell-known; less well-known is the enormous difficulty ofmaking useful forecasts. Attempts to design fiscal terms onthe basis of price forecasts will founder. Uncertainty facesthe parties differently, however, under the problem of“asymmetric information” – typified by the likelihood thatgovernment will know less about a prospect at the timeof award of a contract than a company does. Asymmetricinformation compounds the time-consistency problem –introducing potential for instability into fiscal terms.Few of these features are unique to petroleum, thoughthey often have bigger impact than in other sectors.Exhaustibility is unique to petroleum and minerals. Whatis extracted today cannot be extracted tomorrow (theopportunity cost of extraction includes future extractionforegone). Views differ on how important this is in practice,but the fiscal terms will probably affect the pace ofextraction. Wise government regards petroleum revenuesas transformation of a finite asset in the ground intofinancial, physical and social assets with enduring benefit.Fiscal terms for private investmentSuitable fiscal terms will differ with prospectivity, costconditions, or other factors – no one size is likely to fit all.Nevertheless, some principles can widely apply. Because ofuncertainty, and price volatility, terms that are robust andflexible in the face of changing circumstances are likelyto be more durable. A stream of revenue should accrue togovernment whenever extraction occurs – whether therationale is the opportunity cost of extraction, or simply thepolitical unacceptability of extraction without revenue. Termsalso need to be progressive, in the sense that as projectprofitability increases the government’s share of it alsoincreases.Transparency calls for fiscal terms to be set in legislationor in published contracts; both can be combined withbidding over an initial bonus payment as a means ofallocating rights. Sound tax policy requires avoidance ofspecial incentives where possible, though cases whereimport duties or poorly-administered value-added taxsystems bear heavily on investment costs may justifyexceptions. The balance struck between companies andgovernments should be stable and credible.Tax and royalty, production sharing, or state participation canall be made fiscally equivalent. A participation share assignedto the state without payment, for example, approximates atax on profit distributions at the same rate. Different contractstructures, however, apportion risks differently between theparties and thus affect stability and credibility. Whatever thescheme, the data for key assessments of fiscal instruments →Energy Solutions For All 191

Investment→ must be observable or verifiable, and opportunities foraggressive tax planning minimised.The fiscal design should take account of the relativecapacity of companies and governments to bear risk.A poor country with a limited portfolio of projects maybe less able to tolerate deferral of revenue than a majorcompany. The combination of requirements suggests thatthe fiscal scheme should have multiple instruments: thecombination of a royalty, or its equivalent under productionsharing, normal corporate income tax, and some form ofadditional rent taxation (or production sharing, or stateparticipation) is thus common.Issues for the futureHow far should petroleum taxes be progressive? The questionis the degree to which the government share should be rise, orfall, with prices or profits or lifetime project return. Progressivesystems yield more volatile revenues and can thereforecreate problems for countries not able to bear that risk.Political pressures, however, may make progressive systemsmore robust and credible. The issue is how far to go. Angolaor Azerbaijan, for example, introduced multi-tiered systems,while Norway operates a single rate of special petroleum tax.What type of rent tax? Production sharing schemesgeared to the daily rate of production have historically beenpopular, but the rate of production is an inadequate proxy foroverall profitability. A matrix of production rates and pricesis possible, though specifying the values is a challenge.In either case, costs must still be assessed, opening theway to consider more efficient forms of tax (sometimesimplemented through production sharing). All rent taxesin cash flow form involve some “refund” of the tax valueof losses – most clearly seen in the abandoned Australianproposal of 2010 for a Resource Super Profits Tax. In Norway,exploration losses are refunded and overall losses on oneproject offset against another. Perhaps the simplest schemeis the UK surcharge on corporate income tax, where nointerest is deductible but capital expenditure is immediatelydeducted in full, The resource rent tax (RRT), where lossesare uplifted at an accumulation rate until recovered, featuresin Australia, Angola, and other places. But setting thataccumulation rate does not prove straightforward.Capital gains on sales of rightsTaxation of gains became a big issue in Ghana, Uganda, andelsewhere, when large premiums were paid on transfersof rights or on indirect sales through shares of companieswith interests in petroleum rights. The presence of largegains suggests the fiscal regime is not expected to tax rentssufficiently. One solution, therefore, is better fiscal regimedesign, but that does not solve an existing problem. Thefirst question is whether domestic law and tax treatiespermit taxation of gains on direct or indirect sales ofpetroleum rights (usually treated as immovable property).Secondly, what tax (income tax or capital gains tax) applies,and against what income or gains can the premium paidbe deducted? Thirdly, how is the tax authority to learnabout an indirect sale? Probably the only means will be aprovision in a petroleum license that triggers default if asale is not notified – but then, what size of sale qualifies?International taxation and treatiesBorder withholding is the main way to tax flows to nonresidents(dividends, interest, service or management fees,royalties), which are significant in petroleum projects. Taxtreaties have often eroded permissible rates – sometimes tozero. This phenomenon raises questions about the value oftreaties to capital-importing countries, while at minimumit requires governments to have a strategy for negotiationof treaties that avoids erosion of the domestic tax base. Analternative answer is to focus on the domestic taxation ofthe underlying rents from petroleum extraction.Pricing of infrastructureMany petroleum projects (especially for gas) cannotdevelop without large ancillary investment in infrastructure.The fiscal regime usually deals with upstream production,valued at the field export point (or some similar concept).Where transport and processing infrastructure (midstreamand downstream) requires establishment of a non-arm’slength transfer price, there is risk of diversion of rent tolower-taxed segments of the operation. New petroleumproducers may need to invest as much effort in dealingwith this issue as with the basic design of a fiscal regime.This article has sketched principles and raised questionsabout design of petroleum fiscal regimes. Acceleratingthe pace of exploration and extraction requires mutuallybeneficial (to investors and governments) application of theprinciples, and answers to these outstanding questions. •Views expressed in this article are those of the author and should not be attributedto the International Monetary Fund, its Executive Board, or its management.1. These ideas are distilled from The Taxation of Petroleum and Minerals:Principles, Problems and Practice, edited by Philip Daniel, Michael Keen, andCharles McPherson, Routledge/IMF, 2010, and from recent experience of IMFFiscal Affairs Department technical assistance projects in member countries.19220th World PETROLEUM Congress