Gas demand

Source: Wood Mackenzie

Cubic metres (bn)

0 200 400 600 800 1000

Asia

North America

Formet Soviet Union

Middle East

Europe

Latin America

Africa

20102020 forecasts

find oil, but higher costs, the pace atwhich producing fields deplete, pluspotential geopolitical shocks andOpec, are keeping the oil price above$100,” says Philip Wolfe, head ofenergy at UBS Investment Bank.

Despite that, the exciting frontiersthat have opened up in the past decadehave provoked breathless reappraisalsof the world’s oil and gas potential,fuelling this rhetoric of abundance.

One example of this revisionism is arecent study by Leonardo Maugeri,the former head of strategy at Italianmajor Eni, which sought to assess

Continued on Page 2

“I haven’t seen Calgary, Houstonand Aberdeen more revved up in my30-odd years in the industry,” saysTony Fountain, head of refining atIndian oil group Reliance.

Yet there is one troubling wrinklein this narrative of abundance: theprice of oil. The shale boom mighthave driven US natural gas pricesdown to 10-year lows, but despite therise in North American oil production,prices remain high. It is no wonder,considering the bulk of the world’scrude continues to come from thevolatile Middle East.

“The industry seems to continue to

The oil industry’s centre of gravity isgradually moving away from “easyoil” in places such as the Middle East,towards new developments of extraor-dinary complexity that will requirehundreds of billions of dollars ofinvestment but hold vast potential foran energy-hungry world – for exam-ple, the tar sands of Canada, heavy oilin Venezuela, and Brazil’s ultra-deep-water “pre-salt” fields.

The emergence of this spectrum ofopportunities – ones that previousgenerations of petroleum geologistsand geophysicists could only dream of– has galvanised the energy world.

the same magic on America’s “tight”oil reserves, creating an oil surge inplaces such as North Dakota’s BakkenShale. According to BP, thanks to itsincreasing output of biofuels, shalegas and unconventional oil, NorthAmerica will become almost totallyself-sufficient in energy by 2030.

Moreover, shale’s proponents areconvinced the revolution will soonspread round the world, as “fracking”opens up the shales of South Africa,China and Argentina.

But shale is only part of the story –one element of a long-term shifttowards unconventional resources.

In 2008, with crude soaring towards$150 a barrel, the world was fullwith talk of peak oil and direpredictions of energy scarcity.Four years later, the rhetoric has

changed. Now it is less of scarcitythan abundance.

The main driver has been NorthAmerica’s shale gas revolution, wheretechniques such as hydraulic fractur-ing have unlocked vast resources. Theshale boom has created a “world ofinfinite gas”, says Tony Hayward,head of oil explorer Genel Energy andformer chief executive of BP.

Now those techniques are working

Exploration costsSupply chain andprice pressureshaunt majorsPage 2

Inside »

East AfricaAn ‘embarrassmentof riches’ may behard to exploitPage 3

AcquisitionsNeed for energydrives the globalthirst for assetsPage 3

Iraq eases gripBaghdad’s relationswith autonomousKurdistan improvePage 4

FT SPECIAL REPORT

Oil & GasMonday October 8 2012 www.ft.com/reports | twitter.com/ftreports

The story ofplenty is yetto be realisedAn increase in opportunities has galvanisedthe energy world, writes Guy Chazan Exciting frontiers: workers on a drilling rig in the Eagle Ford Shale near Encinal, Webb County, Texas Bloomberg

For more than a century,the coal plants of America’sSouthern Company havebeen generating electricityfor towns and businessesthroughout the country’ssouth-east.

Coal, as in other regions,has dominated the energylandscape. Until today.Over the past few yearscoal’s share of Southern’selectricity mix has droppedsharply. Four years ago, itproduced 70 per cent of itsenergy from coal. Last year,this had dropped to about40 per cent, and this year, itis expected to fall to 35 percent.

The newcomer providingcompetition is natural gas.Five years ago gasaccounted for between 10-12per cent of Southern’senergy. The companyexpects this to grow to 47per cent in the future.

The reason for the switchits simple: US natural gasprices have touched 10-yearlows. The discovery of shalegas – trapped in rocks thou-sands of feet under theground – coupled with newextraction techniques havetransformed the country’sgas production.

Ten years ago, Americawas preparing to importgas. Now, some estimatethe new reserves will last100 years.

Low natural gas priceshave prompted many utili-ties to shift large parts oftheir generation from coalto gas. North America’senergy transformation hasbeen watched by the rest ofthe world. After assessingthe potential in 32 coun-tries, the US’s Energy Infor-mation Administration hasestimated shale couldincrease the world’s techni-cally recoverable gasresources by more than 40per cent.

The International EnergyAgency has heralded “agolden age of gas”, predict-ing it will account for morethan a quarter of globalenergy demand in 2035,overtaking coal as the sec-ond largest primary energysource after oil.

Royal Dutch Shell is alsobullish. By 2030, it predictsglobal gas demand will be4.8 trillion cubic metres ayear – up 50 per cent on the2010 level.

“This increase in gasdemand equates to five

Gas replaces coal asthe favoured fuelUS example

Sylvia Pfeifer findsthat North America’ssuccess is down toa unique set ofcircumstances

times today’s global lique-fied natural gas [LNG]industry,” says De la ReyVenter, head of LNG atRoyal Dutch Shell.

It is achievable, he says,citing significant produc-tion expected from Northand South America, Aus-tralia, China and SouthAfrica. Countries such asMozambique and regionssuch as the eastern Mediter-ranean are also coming intoplay as producers.

Not everyone is con-vinced. For one thing,North America’s shale gassuccess has its roots in aunique combination ofcircumstances, including awell-developed, low-costservice industry and accom-modating regulation.

“You have to ask, ‘agolden age’ for whom,” saysNoel Tomnay, head of gasat Wood Mackenzie, theconsultancy. “Globally, wehave more supply options –shale in North America,LNG from Qatar and soonto come from Australia. Butit is still expensive. If youwant cheap gas, you need itto be on your doorstep.”

Europe, he says, is notwell placed to benefit simi-larly. Compared with otherregions, a lack of relativelylow-cost, local gas and anabsence of government pol-icy to promote its benefitsrelative to other energyoptions are discouragingdemand growth.

Not only are policy sig-nals missing on the demandside, there is constraint onthe supply side. Some Euro-pean countries, such asFrance, have imposedmoratoriums, given wide-spread environmental con-

cerns about hydraulic frac-turing, or fracking, thetechnique used to extractthe gas from the rock.

Fracking involves pump-ing sand, chemicals andwater at high pressure deepinto the rock. Much of theopposition to it has focusedon fears of water contami-nation.

The energy industryinsists its practice is safe,while acknowledging moreneeds to be done toconvince policy makers andthe public.

One of the benefits ofburning more gas, says theindustry, is its lower emis-sions profile compared withcoal. Executives point tothe US, noting that sincemany utilities switched toburning more gas than coalthe country’s carbon diox-ide emissions have dropped.Figures from the IEA inMay showed that CO2 emis-sions in the US in 2011 fell1.7 per cent.

Others caution that overthe longer-term, investingin gas-fired power plantscould take away funding forrenewables. Ben Caldecott,head of policy at ClimateChange Capital, a think-tank, says: “In developedeconomies such as Europe,and Japan, more gas-firedgeneration is a real issue.It could crowd out renewa-bles, making it harder tomeet carbon reductiontargets.”

The deployment of renew-ables at scale is vital, heargues, as only that willdrive down costs.

Given the long-termnature of the energy busi-ness, governments are inthe tricky position of hav-ing to take decisions thatwill determine investmentdecisions for decadesagainst the backdrop oftoday’s economic downturn.

Mr Tomnay says: “If youare looking for a global gasrevolution, the questionyou should ask is: ‘Where isthe next cheap gas going tohappen?’ My bet is China orLatin America. But it’s nothappening quickly.”

‘This increase indemand equatesto five timestoday’s globalLNG industry’

2 ★ FINANCIAL TIMES MONDAY OCTOBER 8 2012

Oil & Gas

As oil and gas gets moredifficult and expensive toproduce, there are almostimperceptible movementsin the relationshipsbetween the owners of oiland gas assets and theservices companies.

These shifts, as subtle asthe movements of thetectonic plates that play akey role in the productionof these natural resources,are changing the wayhydrocarbons come tomarket. As the DeepwaterHorizon disaster in the Gulfof Mexico illustrated,beyond the lead operator –in that case BP – of wellsand platforms lies a supplychain of service companies,including the likes of Halli-burton and Transocean andtheir subcontractors.

But while Deepwater hasled to disputes between BP,Halliburton and Transoceanas to where fault for thedisaster lay, traditional oilmajors and national oilcompanies are increasinglyletting services companiesplay a bigger role in dealsthat let both sides profit.

In this arena oil servicescompanies co-operate asmuch as they compete towin the favours of large oilcompanies.

Schlumberger, the world’sleading oilfield servicescompany, came togetherwith Petrofac, the largestLondon-listed oil servicessupplier by market capitali-sation, at the start of theyear to offer a “one-stopshop for clients in emergingfield development”. Bothsay the alliance is a way ofpitching to “major resourceholders” keen to furtherexploit reserves “against anindustry environment char-acterised by a shortage ofcapability and capacity”.

As Tim Weller, Petrofac’schief financial officer, says:“Things are getting deeper,wetter, and colder.” Thisrequires more contractorexpertise. And while west-ern oil majors are increas-ingly keen to sell on matur-ing fields to smaller inde-pendents, nationally ownedcompanies are also keenerthan ever to compete glo-bally to own and operate oiland gas assets.

The result, says MrWeller, is that an increasingnumber of oil and gasprojects are being left in thehands of owners withoutthe in-house experience toexploit them to the limit.

An example of Petrofacand Schlumberger plugginga skills gap is a deal struckwith Pemex, Mexico’s stateoil monopoly, in June. Theyare being paid on a commis-sion basis for productionimprovements in fields pre-viously operated solely bytheir client.

That deal followed Petro-fac’s success in winningtwo of the first three pri-vate oil production con-tracts granted in more than50 years by Pemex inAugust last year. The grow-ing role played by oil serv-ice companies has helped toestablish them as a growingconstituency in the energysector where their marketcapitalisations can oftenexceed those of their cli-ents.

Schlumberger, for exam-ple, enjoys a market capital-isation just less than BP’s,in excess of ConocoPhillips

and well in excess of thenext tier of US-listed oil pro-ducers such as Apache,Anadarko and Marathon.Companies in this tier com-pare in value with the likesof leading US oil servicescompanies Baker Hughesand Halliburton.

In the UK, too, Petrofac,Amec and John WoodGroup, alongside oilfieldpump supplier Weir Group,have emerged as FTSE 100constituents whose valueoften exceeds those of mid-tier London-listed oilexplorers and producers.

And, while splutteringdemand for fracking equip-ment in North America hasdamped a previously hotsegment for some servicescompanies, many have con-tinued to outperform lead-ing stock market indiceshandsomely in spite ofsome concern over soften-ing oil prices.

Mr Weller argues a shiftin control over oil and gasassets away from so-calledIOCs (western-owned inde-pendent oil companies) toNOCs (national oil compa-nies) has left oil servicescompanies well positionedto fill the skills gap createdby sovereign states wishingto maintain formal controlover their assets ratherthan simply hand themover to western oil majors.

“In the past the NOCshad only one direction to go– the IOCs,” says Mr Weller.“The IOCs have to be ableto take ownership of oil andgas reserves, but that isdifficult and anathema tomany countries as cedingownership of reserves is nota popular thing.”

At Amec, John Pearson,managing director ofnatural resources forEurope and west Africa,agrees this picture of coun-tries keeping control ofassets should benefit thesector. Meanwhile, a shiftaway from majors seekingto control all or most ele-ments on projects, as wellas selling maturing fields,should also strengthen theplace of operators in the oilservices marketplace.

“Assets are being trans-ferred to people with lessrecord of running assets –whether NOCs or smallerindependents – who mayhave less competency,” saysMr Pearson.

Majors that used to domi-nate research and develop-ment and have large num-bers of project managementstaff are now more willingto run “skinny teams” thatbring the best supplierstogether, he argues.

Claudi Santiago, manag-ing director and chief oper-ating officer of FirstReserve Corp, a privateequity firm that invests inenergy, agrees the sector’stectonic plates continue toshift, but he says that theirfinal destination is stillunknown. “There’s been ahuge transfer of expertisefrom IOCs to NOCs, and theoilfield service companieshave played a key role inthat. Over the next fewyears, we’re going towitness an interestingphenomenon. Will servicecompanies help NOCsbecome totally independ-ent? We will see.”

Closer workinghelps to plugthe skills gapOil services companies

Michael Kavanaghfinds a sector of theindustry is booming

‘Things are gettingdeeper, wetter,and colder’

Tim WellerPetrofac

recent increases in globaloil production capacity. Hisconclusion: “Contrary towhat most people believe,oil supply capacity is grow-ing worldwide at such anunprecedented level it mightoutpace consumption.”

Mr Maugeri, a senior fel-low at the Geopolitics ofEnergy Project at Harvard’sKennedy School, carried outan analysis of the world’sbig oil projects and foundthat additional productionof about 49m barrels a day(b/d) of oil were being tar-geted for 2020, more thanhalf the world’s current pro-duction capacity of 93m b/d.

Continued from Page 1 Risk factors and depletionrates at existing fields bringthat figure down to 17.6mb/d. But that would still, hesays, “represent the mostsignificant increase [in glo-bal oil production capacity]in any decade since the1980s”. It was the result, hesays, of an “unparalleled in-vestment cycle that startedin 2003 and has reached itsclimax from 2010 on”.

But it is a controversialview. Writing in PetroleumIntelligence Weekly, whereMr Maugeri’s essay origi-nally appeared, Sadad al-Husseini, a former head ofexploration at Saudi Ara-mco, the state oil company,begged to differ. He faulted

the Italian’s study for set-ting aside technical realitiessuch as the difference be-tween non-gas liquids andconventional oil. He said MrMaugeri underestimatedthe rate of global oil capac-ity decline, citing Interna-tional Energy Agency datashowing decline rates of 6.7per cent per year for oilfields that had passed theirproduction peak – a rate itpredicted would rise to 8.6per cent by 2030.

Others agree that theissue of accelerating deple-tion rates is critical.

“Existing reservoirs aredepleting three times fasterthan 20 years ago,” saysClaudi Santiago, chief oper-

ating officer of FirstReserve Corp, the energy-focused private equitygroup. “The world issqueezing these reserves ata faster rate.”

Taking the IEA’s 6.7 percent decline level, Mr Hus-seini wrote, the world wouldneed 5m b/d of additionalcapacity annually just tomaintain a flat level of sup-ply, so even the new addi-tions identified by MrMaugeri “would onlyextend current liquids pro-duction on a flat trajectoryto 2021”.

“It isn’t an oil glut by2020 that is keeping oilprices as high as they are,”he wrote. “It is the reality

that the oil sector has beenpushed to the limit of itscapabilities and that thisdifficult challenge will dom-inate energy markets forthe rest of the decade.”

Mr Santiago is also scepti-cal about the talk of abun-dance, predicting that sup-ply will barely be able tokeep up with risingdemand, particularly fromfast-growing Asian econo-mies. “If you assume 1 percent GDP growth per year,then by 2020 the world willneed to find about 40m bar-rels a day of oil,” he says.“So in less than 10 years weneed to bring on four timeswhat Saudi Arabia producestoday.”

And the new reservesthat need to be mobilisedare far more expensive todevelop than what camebefore. “The resource isabundant, but the low-costresources have been run-ning down,” says ChrisSkrebowski, founding direc-tor of Peak Oil Consulting.“So the challenge is how wecope with high-cost energy.”Dealing with that, he says,will entail having to “re-organise our economies”.

The new riches are notonly expensive – they arepotentially more polluting.Environmentalists opposeoil sands because they areenergy-intensive and dirty;deepwater drilling because

of the risk of spills such asthe 2010 Gulf of Mexico dis-aster; and shale-gas extrac-tion because of fears thatfracking may contaminatewater supplies.

Such opposition isexpected to grow, translat-ing into increasing regula-tory problems for compa-nies. Patrick Daniel, chiefexecutive of Canadian pipe-line company Enbridge,says the biggest challengefacing the industry is thedifficulty of winning publicacceptance of oil and gasprojects – what he describesas the “social licence”.

The obstacles are epito-mised by Royal DutchShell’s travails in Alaska.

The Anglo-Dutch major hasspent $4.5bn and sevenyears preparing for anambitious programme toexplore in the ArcticChukchi and Beaufort Seas,but has yet to complete asingle well. Hurdles haveranged from encroachingsea ice to a flurry of legalchallenges by green groupsand indigenous peoples.

Shell’s troubles show thatit is far too early to declarevictory in the campaign forenergy security. “A lot . . .needs to happen over thenext 10 years to bring onthe resources the worldneeds,” says Mr Santiago.“If we don’t hurry up, we’regoing to run out of time.”

The popular story of abundant energy supplies has yet to be realised

Japan’s decision last monthto phase out nuclear powerwill boost its renewablesindustry, but in the shortterm the main beneficiarywill be natural gas.

Japan’s imports of lique-fied natural gas (LNG) arealready at elevated levels.The country’s appetite forLNG increased sharply inthe aftermath of the 2011Fukushima disaster. Butthe Japanese move comesat a time when demand forLNG – gas cooled in mas-sive fridge-like plants to-162C and exported in tank-ers – is rising globally.

BG Group, the UK-listedoil and gas company, saysthe share of LNG in globalgas consumption will risefrom about 9 per cent in2010 to nearly 14 per cent by2025. A lot of that growthwill come from Australia.Companies such as Chev-ron, Royal Dutch Shell andWoodside Petroleum haveinvested $180bn in venturesthat have put Australia ontrack to overtake Qatar asthe largest LNG exporter bythe end of the decade.

Meanwhile, in NorthAmerica, technologies suchas hydraulic fracturing andhorizontal drilling have

opened up vast resources ofshale gas previously consid-ered too difficult or uneco-nomic to develop. Theresulting production risehas forced gas prices to 10-year lows. Terminals builtto import LNG are beingaltered to export instead.Canada, too, is progressingplans to export gas.

Meanwhile, the world hassuddenly seen the emer-gence of two hydrocarbonfrontiers – the eastern Medi-terranean and offshore eastAfrica – that boast largequantities of gas. BothIsrael’s Leviathan field andthe 100tn cubic feet of gasdiscovered off the coast ofMozambique in recentmonths could sustain LNGplants that will vastlyincrease global capacity.

That could have far-reaching implications forthe LNG trade, and particu-larly for pricing. NorthAmerica’s LNG exports willprobably be indexed to USHenry Hub prices, in con-trast to most other long-term LNG contracts, whichare linked to oil prices.

Eurasia Group, a consul-tancy, says the abundanceof supply could acceleratethe move from oil-linked

pricing, leading to a conver-gence of worldwide prices,and opening the prospect ofglobal trade in a commoditythat has, until now, beensplit into regional markets.

But some dismiss the pre-dictions of a supply surgeso large it could disrupt thetraditional LNG trade.

“On the supply side, LNGprojects are getting moredifficult, taking longer andcosting more,” says MartinHouston, BG Group’s chiefoperating officer. He citesstatistics that show a 17 percent drop in supply pros-pects between 2007 and 2011as projects in places such asVenezuela, Iran and Russiawere cancelled or deferred.

The latest example camein August when Gazprom,the Russian gas exporter,shelved plans to develop theShtokman gas field in theArctic Barents Sea, becauseof cost pressures.

Even in places likely todevelop a thriving LNGindustry in the next decade,there are big uncertainties.

The gas finds offshore ofMozambique and Tanzaniahave been staggering: butthese countries are poor,and lack the laws, regula-tory framework and infra-

structure needed to create abig domestic energy indus-try. It is even doubtful oilcompanies now active offeast Africa could reachagreement on how todevelop this gas resource.

Doubts are also emergingabout the prospects forlarge-scale US LNG exports.So far, only one project –Cheniere Energy Partners’Sabine Pass facility in Loui-siana – has won all the nec-essary export permits.

Others have tried: appli-cations filed with the

Department of Energycould put the US on courseto export 150m tonnes ofLNG per annum, nearlytwice Qatar’s output.However, BG thinks only45 mtpa of exports will beapproved.

US officials have said nodecisions will be made onthe other projects until theyhave seen the results of astudy commissioned by theDepartment of Energy onhow allowing companies tosell natural gas overseaswill affect consumer prices.

Gas demand has alreadygrown sharply in the US asthe supply glut encouragesa switch from coal to gas inpower generation and fromoil to gas in transport.Growing consumption willleave less for export.

Political opposition tomore exports is also grow-ing. Some fear exportingLNG could push up US gasprices, sending electricitybills higher and jeopardis-ing the renaissance indomestic manufacturing.

In the near term, theexpansion of LNG capacityin the US “will be con-strained by practical plan-ning considerations andfunding limitations”, saysTim Day, a managing direc-tor at First Reserve Corp,the energy-focused privateequity firm. The US, hesays, “will remain a high-cost producer of LNG forthe foreseeable future”.

Prospects for LNGexports from Canada, andeven for established produc-ers such as Australia, arealso clouding over.

“In the end, the LNGexport market is notexpected to experience theboom some predict,” saysMr Day.

Clouds fog hopes of global export boostNatural gas Some market watchers are dismissive of estimates of a supply surge, says Guy Chazan

The bogeyman of rapidlyrising industry costs hasreturned to haunt thewestern oil majors. Costinflation was a big issue for

oil companies four years ago, whenthe price of crude rose to an all-timehigh of $147 a barrel and the cost ofgoods and services in the resourcesindustry increased in lockstep.

The majors responded with aggres-sive cost-cutting campaigns, andseemed to have slain the demon. Butnow it is back. Labour shortages, therising cost of inputs and sky-highleasing rates for deepwater rigs are allconspiring to increase cost pressuresin an overheated market.

Even a low level of inflation canhave a huge impact on an industrythat is spending more than everbefore to find and produce oil. IHS,the data provider, says capital expend-iture for exploration and productionin 2012 was $641bn, up from $586bn in2011. That is more than the grossdomestic product of Saudi Arabia.

A key reason is that high oil pricesare spurring companies to embark onmore costly and ambitious projects.

“There was a lot of spare capacityavailable post-Lehman Brothers, asprojects were deferred,” says StuartJoyner, an oil analyst at Investec.“But that’s gone now.”

The increase in activity puts pres-sure on supply chains that are alreadytight, especially for the kind of highlyspecialised services and equipmentthe modern oil industry needs.Squeezed vendors and subcontractors

inevitably respond by raising prices.The majors are being squeezed on thedemand side, too, with many receiv-ing less for the oil and natural gasthey sell in the US.

Peter Voser, chief executive officerof Royal Dutch Shell, acknowledgedthe issue in a July earnings call, say-ing costs were going up becauseShell’s production was rising. He alsolinked the increase to a wave ofprojects Shell is working on, each ofwhich needs expensive preparations.These, he said, were “value-generat-ing costs” because they would ensurenew medium-to-longer term growth.

One of the worst-affected places isAustralia. Earlier this year, BGGroup, the UK-listed oil and gascompany, increased its cost estimatesfor its Queensland Curtis liquefiednatural gas project by 36 per cent,from $15bn to $20.4bn.

“Australia is becoming a moredifficult place to operate in,” saysMartin Houston, BG’s chief operatingofficer, pointing to the tight labourmarket and increased costs of compli-ance with toughening regulation.Environmental approvals, he says, area “moving target”.

Simon Henry, Shell’s chief financialofficer, says Australia is a cost“hotspot”, and that the US Gulf Coast,where activity has risen since theObama administration lifted a drillingmoratorium imposed after the 2010Deepwater Horizon disaster, couldalso have an “inflationary bubble”.

Data confirm the cost inflationtrend. IHS says its upstream capital

cost index rose 2.3 per cent over thesix-month period ending March 31 thisyear, to a new high index score of 227.That means that capital costs of $1bnin 2000 would now be $2.27bn.

Operating costs were up 2.1 per centto an index score of 189 over the sameperiod – meaning that if the annualcost of operating an oilfield was $100min 2000, it would be $189m now.

The group attributed the rise to themuch higher day rates for deepwaterrigs, which are increasingly indemand as oil companies venturefurther offshore and into ever deeperwaters to explore for and extract oil.Rising fuel and labour costs mean rigsdemand premium rates.

Michel Hourcard, head of develop-ments at Total, the French major, toldinvestors last month that he gotseveral calls a day from competitorsasking: “’Have you got a rig? A subseaplatform? A crane?’ “Everything isshort,” he said. “The market isextremely tense.” He added that thereare cases of contractors trying to takeadvantage: some cost increases were

“absolutely not justified”, he said. IHSadded that skilled labour for construc-tion, drilling teams and operationscontinues to be in short supply, withemployers struggling to retain crews.It says labour is the top concern foroil operators: they can always askvendors to build them an extra pieceof equipment, but training competentworkers takes months or years.

Companies such as Shell say theyare trying to address the cost issue.Shell talks of its “strategic enterpriseframework agreements” with long-term suppliers, which it claims reduceprices by between 10 and 25 per centagainst market benchmarks in impor-tant categories of spending such aspipes and valves.

Mr Henry says Shell’s 24 upstreamdevelopments had already locked incosts ahead of the latest bout of infla-tion, but “we are being very carefulabout the next wave of investmentprojects”. The company was, he said,developing suppliers in China, Turkeyand Mexico to ensure “sufficientcompetition” to keep costs down.

Supply chainand pricepressureshaunt majors

Exploration costs Big western companiesare squeezed on all sides, says Guy Chazan

Tightening up:the costs ofdevelopingprojects arerising

Inbound: an LNG tanker brings its product to Japan Bloomberg

FINANCIAL TIMES MONDAY OCTOBER 8 2012 ★ 3

Oil & Gas

For decades criticised asoverstaffed, uncompetitiveand politically driven,national oil companies havelong been recognised asimportant but dull playersin the energy industry.

For many, America’s Exx-onMobil and Europe’s RoyalDutch Shell still count as“Big Oil” compared withthe smaller independentsbut the term largely ignorestheir equally big, if notsometimes bigger, nationaloil company (NOC) peers.

All that is changing. Overthe past two decades manyNOCs have engineered aremarkable transformation,thanks in part to an aggres-sive acquisition spreearound the world.

This year, for the firsttime, NOCs are on track tospend more on buying inter-national oil and gas produc-tion and exploration assetsthan their private sectorrivals, according to WoodMackenzie, the consultancy.

The estimate – 55 per centof the total value of M&A

production and explorationdeals – is up to Septemberthis year and includes therecent high-profile $15bnbid by China’s Cnooc totake over Canada’s Nexen.

The dominant position iseven more striking whencompared with NOCs’ shareof 19 per cent in 2010. In2005, it was just 4 per cent.

What has driven thisthirst for assets iscountries’ need for energy,notably in Asia.

“Most of the Asian coun-tries have a supply deficit,”says Simon Flowers, headof corporate research atWood Mackenzie. “Theprimary driver is capturingsecurity of supply against arising import bill.”

The International EnergyAgency, the westernnations’ oil watchdog,predicts that over the next25 years some 90 per cent ofthe projected growth inglobal energy demand willcome from non-OECDcountries. China alone willaccount for more than 30per cent, consolidating itsposition as the world’slargest energy consumer.

Chinese NOCs, such asCnooc, Sinopec and Sinoc-hem, have been involved insome of the most high-pro-file acquisitions since 2009.

But the deal that hasmade the rest of the indus-try sit up and take note isthe bid for Nexen. Sevenyears ago Cnooc made head-

lines for all the wrong rea-sons, launching a hostilebid for US oil group Unocal.Political opposition inWashington eventuallyforced it to drop the bid.

By contrast, the Chinesegroup’s approach to buyingNexen is “a sea change”away from the last time,says one London-basedenergy banker.

“The two are almostworlds apart in terms ofsophistication,” he says,noting that this time roundCnooc has ticked all theright boxes. Under theproposed takeover Cnoocwill list the shares inToronto and make Calgaryits North American hub.

If the deal structureshave changed, so have thetargets. Where mature pro-ducing assets were once onthe shopping list, over thepast five years many NOCshave adopted a differenttactic, buying up long-lifeassets such as shale gas inNorth America or deep-water fields in Brazil.

Many of the NOCs have“become more nimble inthe last decade”, agreesAmy Myers Jaffe, executivedirector for energy and sus-tainability at UC DavisGraduate School of Manage-ment. She says that “inves-tor scrutiny” faced by gov-ernment-led companies rais-ing funds from interna-tional financial markets has“corporatised” them.

Many NOCs took advan-tage of the weak dollar in2005-06 to pick up interna-

tional assets. That trendaccelerated after the finan-cial crisis in 2008-09 whencompanies began to “chasevalue as investors asopposed to for political rea-sons”, she adds.

Yet progress has not beensmooth in every case. AnNOC is often the largestcommercial institution in acountry so, when the gov-ernment needs funds, acompany’s plans can oftenbe derailed by the state.

Robin West, chairman ofPFC Energy, cautionsagainst generalising.

Ecopetrol of Colombia, forexample, has managed torestructure its contractsand encourage the privatesector to invest. The com-pany’s share price soared asa result. And Saudi Aramcois “a serious, well-managedcompany”. But he adds:“There are some successstories but many still sufferfrom state interference.”

NOCs are making lots ofacquisitions but the dealshave so far “not reallychanged the balance ininternational competitionwith the dominant IOCs”.

Mr West says that, whileNOCs still have a hugehome advantage in accessto domestic resources andmarkets, the internationalmajors have the ability todevelop large capital-inten-sive, long-life engineeringprojects that require skilland cash to get completedon time and on budget.

And despite the recentflurry of M&A in explora-tion, in the internationalarena the NOCs are stillsmall. Of the 35 Asian com-panies that Wood Macken-zie tracks, their combinedexposure to global explora-tion hotspots such asAngola or Brazil is thesame as that of a smallinternational major. “Theyare tiny on an individualscale,” Mr Flowers says.

This could change overthe coming decade as NOCsmove deeper into capturingexploration assets as wellas more technically chal-lenging resources.

If there is one thing therecent deal flurry hasunderlined it is that NOCsmay be big beasts but theyare certainly not dull.

Need for energy is driving forcebehind global thirst for assets

Cnooc’s offices in Shanghai

Afew years ago, any mentionof the Rovuma Basin wouldhave been met with a blankstare. Not any more. In theboardrooms of oil compa-

nies in Houston, London and Tokyo,the words elicit a level of excitementrare in the tightly buttoned world ofpetroleum geology.

The reason is the extraordinaryspate of gas discoveries made in thearea in the past few years. So far,some 100tn cubic feet (tcf) of gasdeposits have been found in thewaters off Mozambique and Tanzania,equivalent to nearly all of Iraq’s gasreserves, with the bulk of that in theRovuma Basin.

It is now considered to be one of themost prolific conventional gas playsin the world, with enough to supporthuge liquefied natural gas (LNG)plants aimed at energy-hungry Asia.

The frenzy was underscored thisyear by the bidding war for Cove

Energy, a small London-listed oilexplorer with an 8.5 per cent stake inthe Rovuma Area 1, site of one of thebiggest finds. Thailand’s PTT Explora-tion and Production eventually won itwith an offer valuing Cove at £1.22bn.

Some 25 companies were in Cove’sdata room, taking a close look at itsassets, ranging from western majorsto state-owned Asian energy groups.

“It was highly sought after and verycompetitive,” says Philip Wolfe ofUBS, who advised PTTEP on its bid.

That is not surprising, consideringthe huge international interest. “Youalmost have an embarrassment ofriches in Mozambique and Tanzania,in terms of the volumes of gas beingdiscovered,” he says. “In Mozambique,they’ve only scratched the surfaceand have already found so much gas.”

Indeed, Wood Mackenzie, theconsultancy, estimates there could beas much as 80 tcf to be found inMozambique and 15 tcf in Tanzania. It

says there is enough gas to support upto 16 LNG trains, as liquefaction facil-ities are known.

Yet huge obstacles will have to beovercome before such developmentscan go ahead. The region is remote,notes Giles Farrer, senior LNGresearch analyst at Wood Mackenzie,it has no skilled workforce and willhave to build deepwater ports capableof servicing big tankers.

Then, Mr Farrer says, there isthe question of government capacity,“whether there is sufficient impetusand capability within the govern-ments and national oil companiesto advance the huge legislative,bureaucratic, customs and financialchallenges that such a developmentwould bring”.

Despite the obstacles, foreign inter-est remains intense, and the comingmonths could see much more activityin mergers and acquisitions.

A lot of attention is focused on what

Anadarko and ENI, two of the biggestcompanies in Mozambique, will dowith the big finds they have made inadjacent blocks in Rovuma – Areas 1and 4. The two are talking of poolingtheir assets into one big project – so-called unitisation – and will probablyjoin forces on a single big LNG plant.

Analysts say that, once unitisationis complete, they will both reducetheir stakes, so providing opportuni-ties for others seeking exposure toMozambican gas. Such “farmingdown” will allow them to share thecapital burden, mitigate the risk of

the project and improve creditratings, making financing easier, saysSimon Ashby-Rudd, global head of oiland gas at Standard Bank.

“The equity structure of theseprojects now looks set to change,” MrAshby says. “Some of the existingpartners will sell down and otherswill exit entirely.”

Those considered likely to sell outcompletely are the small companiessuch as Videocon Industries, control-led by the Indian mobile-phonebillionaire Venugopal Dhoot, whichhas a 10 per cent stake in RovumaArea 1. Such small outfits do not havethe appetite for the multibillion-dollarLNG plants needed to process Mozam-bique’s gas for Asian markets.

Matt Ash, energy lawyer withNorton Rose in South Africa, says:“The first movers want to offloadbecause the cost of getting the gas outof the ground will be so high.”

Wood Mackenzie estimates a two-

train, greenfield LNG development inthe region will cost at least $25bn.

Possible acquirers of parts of ENIand Anadarko’s stakes include big oilmajors with experience of buildingLNG plants such as Shell, which lostout to PTTEP in the Cove bid, BP andTotal. Other interested parties includeJapanese “off-takers” or buyers ofLNG, which have started investingdirectly in upstream energy assets.Sumitomo Corp, Marubeni and Mit-subishi have all been buying intoshale plays in the US and Canada.

The Asian appetite for east Africangas is understandable. “It’s veryimportant for Asian customersto secure gas free of the Strait ofHormuz risk,” says Pascal Menges,energy fund manager at LombardOdier, an investment firm.

That risk has grown as fears rise ofa potential Israeli military strikeagainst Iran, which could paralyse theflow of oil and gas from the Gulf.

‘Embarrassment of riches’ hard to exploitEast Africa Finds off Mozambique and Tanzania have caused excitement, but the remote region presents big challenges, says Guy Chazan

No smoke without fire: an Anadarko vessel hunts for gas off the Mozambique coast. Estimates are that there could be as much as 80tn cubic feet to be found in Mozambique and 15tn cubic feet in Tanzania Anadarko

‘The first movers want tooffload because the costof getting gas out of theground will be so high’

Guy ChazanEnergy Editor

Sylvia PfeiferSpecial Correspondent

Michael KavanaghCompanies Reporter

Adam JezardCommissioning Editor

Chris TosicSteven BirdDesign

Andy MearsPicture Editor

Elizabeth DurnoSub-editor

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NOCs

National playershave shaken off theirdull image to go onan acquisition spree,writes Sylvia Pfeifer

4 ★ FINANCIAL TIMES MONDAY OCTOBER 8 2012

Oil & Gas

The economic and politicalrepercussions of mechanicalfailures on offshore rigs andplatforms were well illus-trated by the blowout at theElgin installation, operatedby Total of France, in theNorth Sea in March.

In August, the UK’sOffice of Budgetary Respon-sibility blamed the Elginshutdown in large part foran unexpectedly sharpdecline in North Sea outputthat had depressed UK taxreceipts in July.

No one was killed orinjured in the emergencyevacuation from the Elgincomplex, 150 miles east ofAberdeen, which onceaccounted for nearly 10 percent of UK gas output.

The evaporation of 3,000tonnes of gas condensate,and the escape of 3,000tonnes of gas in a wellblowout that took weeks tobring under control, hasbeen matched by the evapo-ration of funds from Treas-ury coffers. Six months on,production has yet torestart at one the UK’sbiggest gas producingplatforms.

If one clear message hasemerged from the Elginincident, it is that althoughUK oil and gas output fromthe maturing North Seabasin is well past its peak,the fiscal health of one ofthe world’s leading econo-mies remains prone to thesuccess or failure of its off-shore industry.

Fortunately there aresigns that, while theUK sector of the North Searemains in genteel decline,there is life in the olddog yet.

Last month US groupApache Corporation beganinstallation of a £400mextension of its FortiesAlpha platform, aimed atextending the life of one ofthe UK’s most prolific

fields, first developed byBP. Meanwhile, at the endof July, Premier Oil con-firmed two orders worth£140m for oil platform com-ponents destined to be usedin production at the Solanfield west of Shetland. Bothdevelopments typify a two-pronged approach to ekingout the remainder of theUK’s rapidly depleting oiland gas resources.

While Premier is attempt-ing to bring to shore one ofthe UK’s remaining unex-ploited resources in remotewaters, much of Apache’sfocus is aimed at extendingand improving recoveryrates at fields manythought would be aban-doned by now.

Apache’s decision toextend its Forties Alphaplatform, installed its 1975and designed to last 25years, will be the most visi-ble of a wave of furtherexploration and well drill-ing undertaken as part of a$3.5bn investment pro-gramme in the field sinceits acquisition in 2003.

Apache aims to repeatthis trick of sweating assets– developed by oil majors –at its Beryl field, which itbought through a $1.75bnpurchase of oil and gasassets from ExxonMobil lastSeptember

Such large-scale invest-ments in physical kit comedespite warnings last yearafter a £2bn tax raid by theUK government on NorthSea oil and gas operators –which raised marginal taxrates to between 62 and 81per cent – created fiscalburden and uncertainty.

Industry leaders arguedsuch a move would under-mine the confidence of oper-ators in investing to ensurethe UK’s remaining hydro-carbon resources wereexploited to the maximum.

Since then the chancellorhas responded to lobbyingfrom oil operators with theintroduction of a range oftax allowances. While notreversing the increasedrates of tax charged formany operators, they areaimed at reducing the taxbill for those attempting to

access more difficult,remote, or smaller pocketsof hydrocarbons that mightotherwise be left in theground.

The latest moveannounced in September –to extend allowances tocompanies planning exten-sions to existing fields – sig-nalled an “absolute determi-nation to get more invest-ment in the North Sea, ahuge national asset”,according to GeorgeOsborne, the chancellor.

Simon Lockett, chief exec-

utive of Premier Oil, saysthe North Sea remains anattractive arena to exploreand develop projects, manyof which can benefit frompiggybacking on infrastruc-ture developed decades ago.However, tax raids by theformer Labour and currentcoalition governments havenot been forgotten.

According to Mr Lockett:“It’s possible to get more oilout of the North Sea that istaxed at a decent rate andcreate jobs for people soyards are getting work.”

He adds: “What the gov-ernment has done byputting in plans for cer-tainty over abandonmentliabilities, the introductionof small field allowancesand brown field allowances,are a good package of incen-tives for the industry. Butthe problem is confidence –and people still rememberwhen the governmentchanged things negatively.People are looking forstable playing fields.”

Graham Stewart, chiefexecutive of Faroe Petro-leum, which is drilling inboth the Norwegian and UKsectors of the North Sea,agrees. He also argues theUK has still some way to goto creating the “feelgoodfactor” being enjoyed inNorway following severalrecent oil discoveries.

“The UK has drilled a lotmore, so what’s left in theUK is much more difficult[to reach],” he says. Andattempts to repair the dam-age done to the sector’s con-fidence “through a patch-work quilt of [tax] allow-ances” has not beenentirely successful.

Nonetheless, the businessconfidence index fromindustry lobby Oil & GasUK shows optimism at itshighest since the surveybegan four years ago. Thestart of some large projectsshould see investment inthe sector rise from £8.5bnin 2011 to £11.5bn this year.

Calls for lowerrates of tax toaid productivityNorth Sea

Michael Kavanaghfinds some relief forinfrastructure plans

Large investmentsin physical kitcome despite thechancellor’s£2bn tax raid

Shutdown: the Elgin platform, right, before the blowout AFP

For centuries little has disturbed thetiny island of Melkøya, near Hammer-fest, the world’s northernmost town.Over the past five years, however, ithas been transformed into a transporthub for gas, with huge tankers pick-ing up cargos of liquefied natural gas(LNG) and taking them to Europe,Asia and South America.

The reason for this change lies off-shore, 300m beneath the icy waters:Statoil’s Snøhvit gasfield in the Bar-ents Sea – the first Norwegian energyproject in the Arctic. Since openingthe LNG terminal on the island in2007, Statoil has pointed to Snøhvit asproof of the exploration potential ofthe Norwegian continental shelf.

And Statoil insists it remains com-mitted to oil and gas exploration inthe Arctic, even though it decided ear-lier this month not to expand thecapacity of the Snøhvit project afteragreeing with its partners there wasnot enough gas to justify the move.

Exploration first began in the 1980sand Snøhvit took 20 years to developand bring into production. At the timethe company started it did not havethe LNG technology to do it, says TimDodson, head of exploration at Statoil.

However, the company’s persever-ance has paid off. Recent significantdiscoveries in a newly explored areaof the Barents Sea – the Havis oilprospect and another oil find at Skru-gard, an adjacent but geologically sep-arate prospect – have “truly openedup” the region, says Mr Dodson. Esti-mated recoverable reserves across theSkrugard and Havis structures arethought to be between 400m-600mbarrels of oil equivalent.

The discoveries have helped vindi-cate more than 30 years of explorationin the Barents Sea, during which Stat-oil has been involved in all but five of94 exploration wells drilled in the area.

According to the Norwegian Petro-leum Directorate, up to 6bnbarrels of oil equivalent could exist inNorway’s portion of the Barents Sea.This does not include an area half thesize of Germany, which is set to beopened to exploration after last year’s

resolution of a four-decade borderdispute between Russia and Norway.

As the first large development onthe Norwegian continental shelf with-out any installations on the surface –every day a mixture of natural gasliquids and condensate hydrocarbonsis transported 143km through a sea-bed pipeline to the LNG plant – Snøh-vit is also proof of the technical andlogistical capabilities needed in theArctic.

One of the reasons why the BarentsSea has seen more success than otherareas in the region is because of theabsence of ice. Long regarded as thelast great frontier for the world’senergy industry, the Arctic remainsrelatively unexplored and there areonly a handful of producing areas.

The tough physical conditions andenvironmental concerns remain bigchallenges. In a recent note on theArctic, analysts from Société Générale

cited cost control, ice and the need forinfrastructure as key issues facingcompanies exploring in the region.

Royal Dutch Shell last month had topostpone until next year an attemptto drill into oil-bearing rock off theAlaskan coast after a vital piece ofsafety equipment was damaged intests. The company has so far spent$4.5bn and seven years preparing todrill.

Yet the delay has not altered Shell’sview of its Arctic programme. Thepotential prize is too great. Accordingto a 2008 study by the US GeologicalSurvey, the area within the ArcticCircle may hold 90bn barrels of oiland 1,669tn cubic feet of natural gas,respectively 13 per cent and 30 percent of the world’s estimated undis-covered reserves.

Cost remains a problem. In August,Gazprom halted its ambitious Shtok-man natural gasfield in the BarentsSea. The group said the company andits partners – Statoil and France’sTotal – had decided the project devel-opment costs were too high. Gazprominsisted talks would continue with itspartners about how to best progress.

Industry battles tofulfil Arctic potentialBarents Sea

Despite some setbacks thereis great optimism for thefuture, writes Sylvia Pfeifer

The area within the ArcticCircle may hold 1,669tncubic feet of natural gas

The quicksands of Iraq’s fed-eral constitution are a quag-mire for companies seekingto do business there – partic-ularly in the autonomous

region of Kurdistan.Protracted disputes between the

Kurdistan Regional Government(KRG) and federal authorities inBaghdad over who holds sway over oiland gas in the north of the country,close to energy-hungry Turkey,continues to constrain attempts toimprove Iraq’s exporting potential.

But, after years of legal dispute andmonths of an embargo over exportsfrom Kurdistan that have left reservesin the region largely excluded frominternational markets, there are signsof change in Baghdad.

Last month Iraq’s federal cabinetratified an agreement to increase oilexports from the region and therelease of payments due to companiesoperating in the area.

This followed the partial resump-tion in August of oil exports fromKurdistan through Iraq’s federallycontrolled pipelines in a move by theErbil-based KRG aimed at securing$1.5bn of payments it claimed was duefrom the federal oil ministry.

Ashti Hawrami, minister of naturalresources for the Kurdistan RegionalGovernment in Iraq, told the FTGlobal Energy Leaders conference inLondon last month that the deal couldlead to oil exports through the feder-ally controlled pipeline system reach-ing 200,000 barrels a day by the end ofthe year and 250,000 b/d in 2013.

Both sides have agreed on a high-level committee to sort out draft oillaws aimed at ending disputes overthe legitimacy of licences and reve-nue-sharing agreements betweenIraq’s provinces.

The apparent thawing of relationsbetween Erbil and Baghdad follows adecision by several major western oilcompanies to follow the lead takenlast year by ExxonMobil to strikeexploration and development dealswith the KRG. This was in spite ofthreats from Baghdad to exclude themfrom working in the rest of Iraq,where most of the nation’s hydrocar-bons have been exploited.

Chevron of the US, Total of Franceand Gazprom of Russia this summerjoined early stage investors in Kurdis-

tan, including London-listed GenelEnergy, led by former BP chief execu-tive Tony Hayward.

The drift among oil companies incommitting to production-sharingcontracts with the KRG has echoes ofan agreement between Erbil andAnkara to build a pipeline to theTurkish border capable of exporting1m b/d, to be operational by 2014.

That would tackle the bottleneckover exports stranded in the regionwithout recourse to Baghdad’s feder-ally controlled network.

But the legal disputes continue – inlate July Iraq’s oil ministry called onChevron to cancel its “scandalouscontract” with the KRG, calling itillegal, contradictory to Iraq’s 2005federal constitution, and unfairlyskewed to give the company too higha share in oil revenues.

But Baghdad’s seeming lack of suc-cess in preventing oil majors dealingwith the KRG comes as its ownapproach to partnering foreign compa-nies to extend and rehabilitate fieldsin the south and east of the country iscoming into question. Royal Dutch

Shell, BP, Eni and ExxonMobil wereamong the first oil companies thatstruck technical service contracts(TSCs) with Iraq’s oil ministry.

But there was limited interestamong western companies in thelatest auction of TSCs this summer –contracts that might offer little more

than $5 a barrel royalty and relativelylimited incentives for boostingretrieval rates.

The willingness of Baghdad tosoften its stance towards the KRG,and ease the relatively parsimoniousterms of its TSCs to attract morewestern interest, remains hard togauge. After all, in August the Inter-national Energy Agency confirmed

Iraq had overtaken Iran as the second-largest Opec oil producer for the firsttime since the late 1980s.

Though this was partly based onsanctions depressing demand forIranian oil, it also reflected a steady ifslow improvement in Iraqi productionsince the disruptions caused by theUS-led invasion 10 years ago.

According to Ben Holland, partnerat law firm CMS Cameron McKenna,commercial terms on offer to thenorth are attractive in spite of politi-cal risk. “ It’s estimated that up to aquarter of the easy-to-reach oil in theworld lies under the unexplored acresin Iraq,” he says. “That’s worth therisk of uncertainty about the legalityof the oil concessions in Kurdistan.”

But this slow increase in output istaking place against a story of grow-ing social need, pressures onfederal budgets, and halting progresson tackling bottlenecks in exports ofproduction directly under its control.This could yet prompt more pragma-tism along with hostile public rhetoricin its dealing with the KRG and west-ern oil interests.

Baghdad eases Kurdistan gripIraq The federal government’s relations with the region are easing, saysMichael Kavanagh

Opening the pipeline: an employee at the Tawke oilfield in Dohuk province, in the autonomous region of Kurdistan Getty

Iraq had overtaken Iranas second-largest Opecoil producer for the firsttime since the late 1980s