Race to exploit pre-salt layer Brazil seeks to harness undersea reserves Page 2 Inside » Uphill battle to restructure Entrenched views could deny Mexico investment Page 3 Rethink over US gas sales to Asia Concerns arise over export licence applications Page 3 Traditional ticket to profitability Rail transport proves it can deliver the goods Page 4 Ecopetrol profile Privatisation has unlocked the Colombian oil company’s potential Page 4 FT SPECIAL REPORT Energy In the Americas Wednesday May 15 2013 www.ft.com/reports | twitter.com/ftreports ‘T here’s a whole ocean of oil under our feet!” When the film There Will Be Blood was released in 2007, that exclamation by anti-hero Daniel Plainview, played by Daniel Day-Lewis, sounded like an echo from a long-vanished time. The age of the heroic oil wildcatter seemed to be over and US oil fields appeared to be heading towards inevi- table exhaustion. Six years later, that view has been transformed thanks to Plainview’s real-life descendants. Technological advances in hydrau- lic fracturing and horizontal drilling, pioneered by entrepreneurial small and mid-sized companies, have opened up shale oil and gas reserves that were not previously viable. As a result, US crude oil production is on course to be about 50 per cent higher this year than in 2008. Analysts have begun to speculate that North Amer- ica – the US plus Canada and possibly Mexico – could become a net oil exporter within 10 years, and even the sober government-backed Inter- national Energy Agency has forecast that the US could overtake Saudi Ara- bia to become the world’s largest oil producer by 2017. Bob Profusek, head of the global M&A practice at Jones Day, the law firm, and lead independent director of Valero Energy, the refining group, says the shale revolution is the biggest change to hit the industry for 50 years. “In the economy as a whole, is it more transformational than the internet and the changes in IT? No, it’s not,” he says. “But I think it’s a pretty close second.” While the conventional wisdom about US oil and gas has been turned on its head, a series of simultaneous but largely unconnected changes have overturned expectations about the energy outlook in much of the rest of the Americas. Although renewable energy is also growing in countries such as Canada, Mexico and Brazil, the principal effect of these changes has been a rise in expectations of future oil and gas production. The developments of the past 10 years have been so dramatic, there is a risk of being overconfident when projecting their impact into the future. It is worth remembering that US oil production has been rising for just four years, after falling for almost four decades. Joe Stanislaw, a veteran energy con- sultant now an adviser to Deloitte, warns that many of the touted bene- fits from the oil and gas revolution have yet to be realised. Nevertheless, he argues that while some observers may be suffering from “irrational exu- berance”, some rational exuberance is entirely appropriate. “Most of us grew up in a world of scarcity,” he says. “But now the mindset has changed: it’s not scarcity, it’s energy security and energy abundance.” To varying degrees, similar ideas are being discussed across the Ameri- cas, from Alaska to Argentina. In Canada, the oil sands industry of Alberta has faced political opposition because of its environmental impact, and economic pressure because of ris- ing costs caused by the attempt to deliver tens of billions of dollars worth of investment in a relatively small area around Fort McMurray. Nevertheless, its output has contin- ued to grow and is expected to carry on growing until the end of the dec- ade and beyond. Canada is also now Continued on Page 2 The power to energise: a shale oil rig in Patagonia Reuters ‘The mindset has changed: it’s not scarcity; it’s energy security and energy abundance’ An industry transformed by politics and science Shale has redefined the region’s prospects, with US crude production likely to be 50 per cent higher than in 2008, writes Ed Crooks
Transcript
Race to exploitpre-salt layerBrazil seeks toharness underseareservesPage 2
Energy In the AmericasWednesday May 15 2013 www.ft.com/reports | twitter.com/ftreports
‘There’s a whole ocean ofoil under our feet!” Whenthe film There Will BeBlood was released in2007, that exclamation by
anti-hero Daniel Plainview, played byDaniel Day-Lewis, sounded like anecho from a long-vanished time.
The age of the heroic oil wildcatterseemed to be over and US oil fieldsappeared to be heading towards inevi-table exhaustion. Six years later, thatview has been transformed thanks toPlainview’s real-life descendants.
Technological advances in hydrau-lic fracturing and horizontal drilling,pioneered by entrepreneurial smalland mid-sized companies, have openedup shale oil and gas reserves thatwere not previously viable. As aresult, US crude oil production is oncourse to be about 50 per cent higher
this year than in 2008. Analysts havebegun to speculate that North Amer-ica – the US plus Canada and possiblyMexico – could become a net oilexporter within 10 years, and even thesober government-backed Inter-national Energy Agency has forecastthat the US could overtake Saudi Ara-bia to become the world’s largest oilproducer by 2017.
Bob Profusek, head of the globalM&A practice at Jones Day, the lawfirm, and lead independent director ofValero Energy, the refining group,says the shale revolution is thebiggest change to hit the industry for50 years. “In the economy as a whole,is it more transformational than theinternet and the changes in IT? No,it’s not,” he says. “But I think it’s apretty close second.”
While the conventional wisdom
about US oil and gas has been turnedon its head, a series of simultaneousbut largely unconnected changes haveoverturned expectations about theenergy outlook in much of the rest ofthe Americas. Although renewableenergy is also growing in countriessuch as Canada, Mexico and Brazil,the principal effect of these changeshas been a rise in expectations offuture oil and gas production.
The developments of the past10 years have been so dramatic, thereis a risk of being overconfident whenprojecting their impact into thefuture. It is worth remembering thatUS oil production has been rising forjust four years, after falling for almostfour decades.
Joe Stanislaw, a veteran energy con-sultant now an adviser to Deloitte,warns that many of the touted bene-fits from the oil and gas revolutionhave yet to be realised. Nevertheless,he argues that while some observersmay be suffering from “irrational exu-berance”, some rational exuberance is
entirely appropriate. “Most of us grewup in a world of scarcity,” he says.“But now the mindset has changed:it’s not scarcity, it’s energy securityand energy abundance.”
To varying degrees, similar ideasare being discussed across the Ameri-cas, from Alaska to Argentina.
In Canada, the oil sands industry ofAlberta has faced political oppositionbecause of its environmental impact,and economic pressure because of ris-ing costs caused by the attempt todeliver tens of billions of dollarsworth of investment in a relativelysmall area around Fort McMurray.Nevertheless, its output has contin-ued to grow and is expected to carryon growing until the end of the dec-ade and beyond. Canada is also now
Continued on Page 2The power to energise: a shale oil rig in Patagonia Reuters
‘The mindset has changed:it’s not scarcity; it’senergy security andenergy abundance’
An industrytransformedby politicsand scienceShale has redefined the region’s prospects, withUS crude production likely to be 50 per centhigher than in 2008, writesEdCrooks
2 ★ FINANCIAL TIMES WEDNESDAY MAY 15 2013
Energy In the Americas
The cure for high prices ishigh prices. That venerablefolk wisdom of thecommodity markets hasbeen put to the test in theUS oil industry over thepast decade, and earnedonly partial vindication.
High oil prices havemade possible aspectacular renaissance ofthe US oil industry, whichis rebounding in ways thatwere unimaginable justfive years ago. That surgein production is, in turn,helping to hold world oilprices down. Crude hasbeen drifting lower sincethe summer of 2011.
The outlook depends onmany variables, includingthe health of the worldeconomy and the responsefrom Opec, the oilexporters’ cartel.
Looking at the US alone,however, there is evidencethat while there is littleprospect of oil pricesreturning to their mostrecent trough of $33 perbarrel in 2009, much lesstheir 1999 lows below $10,they could fall furtherbelow today’s level ofabout $95 for benchmarkWest Texas Intermediatecrude.
How much lower theycan go depends on howfast the cost of productioncan be reduced.
Oil is more difficult toextract from shale rocksthan gas because it isheavier and flows lessreadily and, although thereserves respond to thesame techniques ofhorizontal drilling andhydraulic fracturing(“fracking”) that made theshale gas boom possible,extracting shale oil (or thebroader category of “tightoil”) can cost 20 or moretimes as much as for themost easily accessiblecrudes from the MiddleEast.
With oil close to $100 perbarrel, US shale productioncan still be highlyprofitable. ContinentalResources, the USindependent company thatis a leading producer inthe Bakken shale of NorthDakota, one of the hotspots of the new US oilboom, says last year itstotal cost per barrel of oilequivalent, includingproduction taxes,depreciation and depletion,was just $35. Its profitswere up 72 per cent in2012, on production up58 per cent.
That story has beenreplicated by many smalland mid-sized US oilcompanies. In aggregate,the effect has been to liftUS crude oil production byalmost 50 per cent, from alow point of 5m barrels perday in 2008 to 7.2m b/d inFebruary of this year.
The industry expectsthat growth to continue.Continental, for example,has set a target of triplingproduction by 2017.
Statoil of Norway, theonly international oilcompany to have asignificant presence in theBakken shale, has anobjective of more thantripling its North Americanproduction from about150,000 barrels of oil
equivalent today to 500,000boe/d by the end of thedecade and thinks thatshale oil and gas couldprovide more than 300,000boe/d of that.
However, Torstein Hole,Statoil’s vice-president withresponsibility for its USonshore business, warnsthat the price of oil iscritical for that projectedgrowth. “Whether we willdo that is dependent onthe market, and theprofitability of ourproduction,” he says.
Statoil’s Bakkenproduction breaks even atabout $60 per barrel, headds, which is roughly theaverage for the group’sportfolio of projects aroundthe world. That still leavesplenty of room for pricesto fall before the Bakkenstarts to look uneconomic.
If prices fall far enough,though, shale productioncould respond quitequickly. In “conventional”oil, up to and includinglarge offshore projects, themajority of the cost isspent up-front: in findingthe oil and putting aproduction system in place.Once that is done, themarginal cost per barrel isrelatively low.
In onshore shale, a wellcosts much less – perhaps$10m, compared to $100mfor one in deep wateroffshore – but the rate atwhich production declinesis steeper, so continueddrilling is needed tosustain output.
If the price of oil didstart to fall sharply –which would be aconsequence of the worldeconomy slipping back intorecession, for whateverreason – the economics ofUS shale production wouldbe tested.
As the industry expands,it is pushing into morechallenging reserves. InNorth Dakota, for example,there is an increasingfocus on the Three Forksformation, which overlapswith the Bakken but isdeeper.
On the other hand, shaleoil operators are learningmore about how to get theoil out and are becomingmore efficient. Hess, theindependent US oil groupthat is another largeproducer in the Bakken,said it had cut the cost ofdrilling a well there from$13.4m a year ago to $8.6min the first quarter of thisyear. ContinentalResources, similarly, spentan average of $9.2m to drilla well last year, and isaiming for $8.2m.
In the race of improvingefficiency againstdeteriorating geology, MrTorstein says he is “prettypositive” that theproducers will pull aheadover the coming decadeand that the break-evenprices needed will fall.
“It’s such a dynamic andcompetitive industry.Everybody is trying toimprove and everybody islearning from each other,”he says.
Better drillingtechniques lineroad to profitUS shale
New technology andlower costs offerhope, says Ed Crooks
‘It’s such a dynamicand competitiveindustry. Everybodyis trying to improveand learn fromeach other’
developing its own shale oiland gas reserves.
The prospect of being ableto export liquefied naturalgas to Asia from BritishColumbia on Canada’s westcoast has attracted not onlythe leading western oilgroups, including RoyalDutch Shell, Chevron andExxonMobil, but also lead-ing Asian companies,including Petronas ofMalaysia, Mitsubishi ofJapan and PetroChina.
In South America, therehave been spectacular oildiscoveries off the coast ofBrazil, deep below the sea-bed in what are known asthe “pre-salt” layers of rock,that have transformed
Continued from Page 1 expectations about thatcountry’s role in the globalmarket for crude.
Once seen as likely to beperpetually short of fossilfuels, Brazil is nowexpected to become anincreasingly important oilproducer. A combination offalling production since2010 and rising demand hasturned it into a net oilimporter, though output isexpected to start risingagain this year.
The other great hydrocar-bon success story of thecontinent has been Colom-bia where, helped byimproving security anddeclining violence, oil pro-duction has doubled since2007. Ecopetrol, the coun-try’s national oil company,
has been privatised, andoccasionally has edgedahead of Petrobras of Brazilto become Latin America’slargest listed company bymarket capitalisation. Inother countries, conditionsremain difficult but interestin their potential has beengrowing. Argentina, whichhas been estimated to holdthe world’s second-largestreserves of shale gas,behind China but ahead ofthe US, is the pre-eminentcase here.
The government of Presi-dent Cristina Fernándezappalled foreign investorslast year with its move toseize control of YPF, thenational oil and gas com-pany, from Repsol of Spain.Yet there is still interest
from international com-panies in operating in thecountry and participatingin the development of itsshale reserves, although a$1bn plan for Chevron to dothat with YPF has beenstruggling because of anArgentine court decision infavour of plaintiffs seeking$19bn in damages from thecompany for pollution inEcuador 20 years ago.
In Mexico, there is greatexcitement over the poten-tial of oil and gas reserves –which the country believesare as large as Kuwait’s –and rising optimism thatinternational companiesmay be able to gain accessto them. President EnriquePeña Nieto, who took officein December, is expected
to propose a change tothe country’s constitution,which currently forbids for-eign companies from own-ing any Mexican oilreserves, to allow them toset up joint ventures withPemex, the national oilcompany. Mexico’s oil out-put has fallen by 25 per centover the past eight years,and Emilio Lozoya, thechief executive of Pemex,sees foreign investment asthe way to turn that round.
Rising production fromthe deep water on the USside of the maritime borderin the Gulf of Mexico whilethe Mexican side remainsundeveloped is a sign of thepotential that exists.
The only significantexception to expectations of
rising hydrocarbon outputin the Americas is Vene-zuela, holder of the world’slargest oil reserves thanksto the heavy oil fields of theOrinoco Belt. The death inMarch of Hugo Chávez, thecountry’s demagogic presi-dent, briefly sparked specu-lation that a change of gov-ernment might change Ven-ezuela’s confrontationalstance towards foreign oilcompanies. The narrow vic-tory for Nicolás Maduro inthe presidential election inMay put that speculation onice. For foreign companies,Mr Maduro’s platform of“chavismo” without MrChávez’s charisma and pop-ular appeal threatens theworst of both worlds, sug-gesting the prospect of con-
tinuing suspicion of privatebusinesses without politicalstability.
That significant exceptionaside, the story of energy inthe Americas seems likelyto be dominated by growthin production of oil and gas.
The consequences will benegative as well as positive:there will be job creation,profits and tax revenues butalso spills and rising green-house gas emissions, offsetto some degree by the sub-stitution of coal for gas inpower generation. But,while all the governmentsof the Americas pay at leastsome attention to thosedrawbacks, none believesthey are a reason to stoptheir oil and gas industriesfrom growing.
An industry transformed by politics and science
No one doubts the attrac-tiveness of Argentina’sshale oil and gas prospects,particularly its vast VacaMuerta (Dead Cow) forma-tion, but unlike Eagle Fordin the US, which has rock-eted from near-zero produc-tion to one of the world’stop producing formations infive years, there has beenno rush into Argentina tomimic the US shale boom.
Few countries need tocrank up domestic oil andgas production more thanArgentina. Its energyimport bill, with its relianceon imported liquefied natu-ral gas, was about $9.5bn in2012 and is expected to leapto $13bn-$15bn this year.
The sad reality, however,is that the game does notyet seem worth the candle
for many would-be inves-tors. Argentina is a countryof regulated hydrocarbonsprices, stubbornly highinflation, foreign exchangecontrols, unpredictable eco-nomic policy and a welterof requirements for busi-nesses to buy locally andplough profits back intoproduction.
Nonetheless, state oilcompany YPF says its shaleproject is already “100 percent launched”, with fourtimes as many rigs drillingthan six months ago. It alsoasserts that a planned jointventure with Chevron inVaca Muerta will be inoperation by mid-year aftera freezing of the US com-pany’s Argentine assetsstemming from a $19bnenvironmental judgment inEcuador.
More shale accords are inthe offing, with US chemi-cals group Dow and Sino-Argentine energy companyBridas, for example, butothers want to see YPFdeliver on these projectsbefore following suit.
There have been someencouraging signs. The gov-ernment of Cristina Fernán-dez last year increased theprice of new gas productionto $7.5 per million Britishthermal units, more thantriple the previous basicrate for production at exist-ing wells. Yet, according toChirag Sabunani, an ana-lyst at energy consultancyWood Mackenzie, shale gasstill “isn’t economic even at$7.50 and shale oil isn’t eco-nomic at the $70 per barrelexport price”.
Moreover, Argentina’sstance still appears to be ofthe “bite the hand thatfeeds you” variety. Itsexpropriation of 51 per centof YPF from Spain’s Repsolwithout compensation lastyear sent shockwavesthrough the sector.
“Argentina needs the bigcompanies that have strongbalance sheets to developthis [shale] because it isn’tgoing to be cheap,” MrSabunani says.
Companies such asApache, ExxonMobil, Royal
Dutch Shell, Wintershall,Total and Americas Petro-gas have Vaca Muerta inter-ests but are showing nosign of rushing to largescale development. “Theycould happily sit on thisacreage for years, just con-tinuing to invest the mini-mum levels needed to main-
tain their contracts andkeep other stakeholderssatisfied,” Mr Sabunanisays.
“There’s no doubt of thepotential there,” commentsLaura Atkins, head ofupstream research at con-sultants Hart Energy. Giventhe quality of its geology,Vaca Muerta could replicatethe US shale success.
Some observers in US oilservices have suggestedthat Argentina might notdrill 1,000 wells until 2020,which would be a drop inthe ocean compared to thethousands needed, MsAtkins adds.
“A bad governmentdoesn’t stop oil companiesfrom doing business,” shesays. “Companies alwaysprefer to work in countrieswith stable, transparentgovernments althoughthere are many bad govern-ments – in Africa, for exam-ple – where companies aredrilling wells. Muchdepends on whether theycan negotiate good conces-sion terms from the govern-ment.”
Such an outcome seemselusive. Despite optimismfrom YPF that its Chevronalliance will be sealed soon,doubts linger about howfast the Vaca Muertaproject can proceed.
Even if Chevron this yearmakes a $600m investmentexpected by YPF as part ofa $1bn shale pilot project,
that probably equates onlyto 50 or 60 wells, says IvanCima, head of Latin Amer-ica upstream research atWood Mackenzie.
Repsol, meanwhile, is notonly suing Argentina for$10.5bn compensation overthe YPF expropriation. Ithas also threatened legalaction against any othercompanies that help YPFdevelop the shale resourcesit says it discovered. Ahoped-for deal with Repsolto bury the hatchet has sofar failed to materialise.
Melissa Stark, a consult-ant at Accenture, which hasstudied shale prospects inArgentina, China, Polandand South Africa, says reg-ulatory and technical prob-lems have to be worked out,too, such as how to sharescarce water resources withfarmers. Yet she still ranksArgentina as the top shaleplay studied, with excellentgeology and an existing oiland gas industry: “I have ahard time believ-ing . . . [Vaca Muerta] willnot get developed.”
Would-be partners worry about the risk of shaleArgentina
A US-style boomhas not happened,reports Jude Webber
What might seem likehyperbole at any othercompany is normal atPetrobras. “Petrobraswill double in size by
2020,” it said in a release last week,citing comments from Maria dasGraças Foster, its chief executive, atthe Offshore Technology Conferencein Houston. She said Petrobras, whichpumps 2.2m barrels per day of oilequivalent, will increase this to 5.7mboe/d by 2020.
“Petrobras’ reserves have the poten-tial to double in size and reach 31.5bnboe in the coming years,” she addedfor good measure. The key to thesestunning projections is Petrobras’ pre-salt oilfields. These lie beneath a two-kilometre thick layer of salt under theseabed in deepwater far off the coastof south-eastern Brazil.
If anyone can meet the technicalchallenges of extracting the pre-saltoil, Petrobras – a specialist in offshoreproduction – can. The greater problemfacing the company, however, is howquickly can it do it and with whatadditional debt.
That is because Petrobras is not justan oil company, it is also seen as atool of government economic policy-making. It serves on one hand to con-trol inflation through fuel prices, andon the other to stimulate industrythrough a rigorous national equip-ment manufacturing programme.
“In Petrobras, the intervention hasbeen quite visible,” says Mariana Par-gendler, of the Getulio Vargas founda-tion law school and co-author of areport on state-run oil companies. Shesays Petrobras’ share price had
dropped sharply in recent years, fromover R$60 in 2008 to under R$20 lastweek, “which is certainly due to aheavier hand by the Brazilian govern-ment in the company”.
Petrobras first announced its pre-salt finds in 2007, provoking anecstatic response from Luiz InácioLula da Silva, the then president.Eager to secure these riches for thestate, he sold rights to 5bn barrels ofpre-salt oil to Petrobras through whathas been hailed as the biggest shareoffering in history. Petrobras becamethe sole operator of the pre-salt fields.
To exploit the finds, Petrobraslaunched what is thought to be thelargest corporate capital expenditureprogramme in the world, amountingto $237bn for the period between 2013and 2017. Its investment has grown byan average 21.5 per cent per yearsince 2000, reaching $42.9bn last year.
However, demand for fuel in Brazilis soaring because of the growth of amiddle class that is pushing car indus-try sales to record levels.
Ms Foster told the conference thatBrazil petrol demand rose 73 per centbetween 2000 and 2012 compared with17 per cent globally, while dieseldemand grew 52 per cent comparedwith 31 per cent internationally.
Aviation kerosene demand rose 58 percent in Brazil in the same period com-pared with a 3 per cent fall globally.
While higher fuel demand wouldnormally be a good thing for an oilcompany, a shortage of refiningcapacity has meant Petrobras has hadto increase imports of fuel at interna-tional prices. Concerned about infla-tion, the government has preventedthe company from passing most ofthese price increases on to consumers,forcing it to sell the international fuelat a discount and putting a strain onPetrobras’ cash flow.
“I think by far the critical issue isreally the refinery pricing,” says NickRobinson, head of the Brazil office ofAberdeen Asset Management. He saysan independent mechanism to set theprice based on international rateswould be better.
The other hurdle Petrobras faces islocal content requirements. The com-pany must incorporate a certainamount of locally made content intoall its equipment, which means estab-lishing an industrial base to producecomponents. With Petrobras requiringthe equivalent of a navy of floating oilplatforms, drilling ships, tankers and
Petrobras mustjump hurdles inrace to exploitpre-salt layer
BrazilGovernment policies presentmore of achallenge to harnessing undersea reserves thantechnical problems, reports Joe Leahy
‘The majors couldhappily sit on thisacreage for years,continuing to investat minimum levels’
,
Drilling down:Petrobras’offshore platformCidade de Angrados Reis taking asample from thepre-salt layer offBrazil in 2010 AP
There will be jobcreation, profitsand tax revenues,but also spills andrising greenhousegas emissions
service ships, as well as the equip-ment for drilling and pumping the oil,this is a truly demanding condition.
Paulo Sergio Rodrigues Alonso,Petrobras local content adviser to thepresident, said on the sidelines of theconference that the biggest challengethe company was facing with pre-saltlay in pushing forward the develop-ment of a shipbuilding industry.
He said locally made content atpresent comprised 55-65 per cent ofcompany equipment.
Analysts say that, after a period ofnegative financial results – Petrobrasmade its first quarterly loss in 13years in 2012 partly because of foreignexchange losses – the company’s pros-pects are improving.
“From now on, it gets better,”Credit Suisse said in an analyst noteafter first-quarter results that werebetter than expected. It cautionedthat, in the long-run, everything willdepend on Petrobras persuading thegovernment to set a market-basedpricing policy for fuel sales.
“We believe pursuing that, andachieving it, should be a fiduciaryduty of both management and theboard,” the brokerage said.
Petrobras is not just an oilcompany; it is also seen asa tool of governmenteconomic policymaking
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When Cheniere Energy in2008 completed the 1,000acre expanse on the Louisi-ana coast of tanks, pipesand roadways that makesup its Sabine Pass liquefiednatural gas (LNG) terminal,it could hardly haveexpected what was about tohappen. New technologybeing applied to gas reser-voirs in shale rock acrossthe US was on the point ofannually bringing hundredsof billions of cubic feet ofgas out of the ground.
US natural gas prices –which stood at more than$10 per million British ther-mal units (mBTU) in 2008 –had fallen as low as $3 by2012. The import terminal’seconomic rationale was, ineffect, destroyed.
The turnround has sentCheniere scrambling toreorganise the terminal andto build further equipmentto let it turn US-producedgas into a super-cooled liq-uid for export round theworld. Sabine Pass looks allbut certain, when it isready, to start exportingLNG – probably in late 2015– and to become the coun-try’s first LNG exportterminal.
The question is whetherSabine Pass will be a trend-setter and the first of manyUS LNG export facilities, oran outlier. It is the only oneof about 20 potential USLNG export sites that havesought permission for wide-spread exports to havereceived it.
The answer has implica-tions for the US’s energymarkets and still greaterconsequences for energymarkets worldwide.
According to research byDeloitte, the consultancy, astart to widespread exportswould slightly raise theUS’s still-low natural gasprices, while significantlyreducing prices in some ofthe countries that receivedgas.
The export facilities thathave applied for exportlicences from the US wouldhave a total export capacityof about 200m tonnes ayear, Erik Stavseth, an ana-lyst for Oslo-based ArcticSecurities, points out. Onlyabout 240m tonnes ofLNG are currently shippedworldwide annually.
“If everything were to beapproved, it would havea tremendous impact,”
Mr Stavseth says. Evenapproval of between 45mand 90m tonnes annually ofLNG exports – the levelthat the US Department ofEnergy has forecast willwin approval – would createbig changes, Mr Stavsethcontinues.
“It could have a substan-tial impact on both the mar-ket and the global trade forLNG.”
One person involved, whodeclines to be namedbecause of client sensitivi-ties, suggests the USDepartment of Energy –which is considering themany export licence appli-cations – may have to buildin safeguards to prevent abig rise in US gas prices.
“The Department ofEnergy will have to createcertain standards about theextent to which they willapprove LNG exports tosecure the national inter-ests of the United States,”he says. “If the natural gasprice shot up and they hada shortage in the UnitedStates, they will need tostop exporting.”
The rationale for startingUS LNG exports has beenespecially clear since the2011 tsunami smashedashore along Japan’s east-ern coast, dealing a shatter-ing blow to infrastructureand causing much of itsnuclear power output toshut down. The disasterpushed up demand for LNGin Japan – already theworld’s biggest importer ofthe product – and widenedthe price gap betweenAsian LNG importers suchas Japan and Korea andthe US.
East Asian prices remainabout $14.50 per mBTU. Theprice at Henry Hub (thebenchmark junction on theUS gas pipeline network)remains about $4.10, despitesome recent price rises.
“There’s an apparentarbitrage between HenryHub prices and all-in priceselsewhere,” says AsishMohanty, a senior analystat consultants Wood Mac-kenzie.
A rise in LNG exportswould probably not onlylower high natural gasprices in importing coun-tries, but also start to breakthe long-standing – andoften illogical – linkbetween natural gas and oilprices in long-term con-tracts.
Contracts for LNG ship-ments from the US wouldprobably be priced againstHenry Hub rates or someother gas benchmark,rather than against oil.
Advocates of widespreadLNG exports argue theywould create jobs in the USgas sector and boost theeconomies of some key UStrading partners while hav-ing relatively little effect onUS gas prices.
Deloitte’s research foundJapan’s gas prices mightfall by as much as 60 centsper mBTU if the US startedexporting significant quan-tities, while the exportswould increase the US priceby only about 15 cents.
A US Department ofEnergy report last year con-cluded exports would be anet benefit to the US econ-omy.
President Obama on May5 signalled his apparentsupport for increased LNGexports, despite the objec-tions of some chemicalmanufacturers and otherswho would prefer the newgas production to stay inthe US.
The president’s apparentapproval could prove deci-sive in persuading the USDepartment of the Environ-ment to approve furtherapplications.
Mr Mohanty cautions thatinvestors will still have tothink carefully – particu-larly in light of the experi-ence of companies thatinvested heavily in US LNGimport terminals – aboutthe long-term risks inherentin investing in LNG exportfacilities.
Few expected shale gasextraction technology toadvance as fast as it did, hepoints out.
“It’s important to identifythese risks,” he says. “It’simportant for all the stake-holders to work out howthat might impact theirinvestment decisions.”
However, Mr Stavsethsays that, even after recentUS gas price rises andfactoring in the cost ofmoving the commodity on$200m ships, the businesscase for exporting US LNGstill looks strong.
“The economics of ship-ping to Asia are still veryattractive,” he says.
Shipments to Asiaremain lucrative lineLiquefied natural gas
In 1976, Rudesindo Cantarellarrived at Pemex’s offices in theMexican Gulf city of Coatzacoal-cos demanding compensation fordamage that crude oil seepage had
caused to his fishing nets.His complaint alerted officials of the
state oil company to what wouldbecome one of the world’s five biggestoil finds. For Mexico, it promisedenergy security and tens of billions ofdollars a year for the state.
Today, the discovery is a distantmemory. Production, which topped2m barrels a day in the early 2000s, isnow about 400,000 barrels.
Against this backdrop, EnriquePeña Nieto, Mexico’s reform-mindedpresident, has proposed what could bethe biggest shake-up of his country’senergy industry since the governmentnationalised the sector in the 1930s.Before he assumed power in Decem-ber last year, Mr Peña Nieto said
Mexico had been a hostage to ideologyand it was time to open up oil toprivate investment.
Even with the Cantarell field’sdecline, there is no doubt Mexico isstill one of the world’s most promisingoil-producing nations. According toEmilio Lozoya, head of Pemex andconfidant of Mr Peña Nieto, Mexico issitting on an estimated 115bn barrelsof oil equivalent, which compareswith Kuwait.
One thing is clear, says Mr Lozoya:“We need to change Mexico’s legalframework so that companies canshare risk.”
This is probably music to the ears ofthe world’s oil majors, which havehad no discernible presence in Mexi-can hydrocarbons.
When Mexico in the 1950s reinforcedlaws making it illegal for Pemexto enter into joint ventures withthird parties, it closed Mexican oil to
private capital, foreign or national.Experts say the apparent determina-
tion of Mr Peña Nieto and his centristInstitutional Revolutionary party toopen up the country’s oil industrycould prompt tens of billions of dol-lars of investment a year.
Developing the potentially hugereserves of shale gas could also lowerenergy costs, cementing Mexico’snew-found competitiveness as a man-ufacturing centre for the Americas.
According to the US Energy Infor-mation Administration, Mexico hasthe world’s fourth-largest gasreserves.
Yet at least two big obstacles totheir development remain. The first isPemex itself. Created in 1938 in theaftermath of the 1910 revolution, theonce-shining symbol of Mexico’s 20th-century confidence is a shadow ofwhat it was. It is better known todayfor its inefficiency, corruption and
huge losses. Only its exploration andproduction arm, one of its four subsid-iaries, regularly turns a profit – about95.5bn pesos ($7.9bn) last year, accord-ing to preliminary results. Its otherthree subsidiaries produced a com-bined net loss of 111.6bn pesos(roughly the same as the annual statebudget of Bolivia). All this wasagainst Pemex's reported sales lastyear of about 1.6tn pesos.
Pemex’s refining subsidiaryaccounts for about 40,000 of the com-pany’s roughly 150,000 employees andthe average workforce at a Pemexrefinery is three times that of onewith comparable output abroad.Refining capacity has not increased inyears and Mexico imports almost halfof its gasoline. All of this leads JohnPadilla, energy expert at consultancyIPD Latin America, to conclude: “Youneed a new model for a new age.”
Then there is the political
dimension. Every March 18, childrenall over the country celebrate theexpropriation oil industry, dressingup in oil workers’ uniforms andparading around school playgrounds.
Such celebrations are embeddeddeep in Mexico’s political culture,with many opposition parties reject-ing any hint of privatisation. In par-ticular, the leftwing Democratic Revo-lution party balks at allowing privatecompanies a foothold. But Mr Padillasays this must happen if Mexicowants oil to spur higher economicgrowth.
In the few months Mr Peña Nietohas been in power, he has displayed atalent for bringing traditionally war-ring political parties together to backa range of reforms.
When it comes to reforming Pemexand the oil industry, most peoplewould agree he still has a lot of per-suading to do.
Uphill battlejoined in effortto restructureoil industry
MexicoEntrenched views stand to complicatereforms, writesAdamThomson Pemex’s Ku-Maloob-Zaap wells, the country’s most productive, in the Gulf of Mexico Bloomberg
4 ★ FINANCIAL TIMES WEDNESDAY MAY 15 2013
production expenses. “If you can railyour barrels to markets where you getpremium pricing, then you see a pre-mium over what you’ve been receiv-ing in the past,” Mr Garrett says.“Now you’re getting $85 a barrel,rather than $75.”
Similar calculations lie behindchanges in coal movements by rail,according to Fredrik Eliasson, chieffinancial officer of CSX. Coal from theIllinois river basin, which CSX serves,can compete with natural gas forpower generation when natural gasprices are about $3.50 per million Brit-ish thermal units (mBTUs).
Appalachian coal competes onlyfrom about $4.50 per mBTU. A recentrise in gas prices has taken rates onlyup to around $4.10 per mBTU, com-pared with $13 at their summer 2008peak.
The best hope of finding a profitablemarket for more expensively-producedcoal lies outside the US – althoughCSX still experienced a 3 per centdecline in its coal export volumes forthe first quarter against last year. Itsdomestic coal volumes fell 14 per cent.
“While the US is going through this
big energy renaissance as a result offracking and horizontal drilling, therest of the world isn’t going throughthat energy renaissance,” Mr Eliassonsays. “Coal is still the baseload capac-ity in most countries for electricitygeneration.”
In the longer term, both Mr Moor-man and Mr Eliasson express hopethat rising gas prices and the gradualrunning down of big coal stockpiles atpower stations should mean demandfor their domestic coal services has atleast hit bottom.
For railroads in the western US,meanwhile, the outlook in energy ismore positive.
Matt Rose, BNSF’s chief executive.says there is no immediate prospectthat, even if some rail volumes moveto new pipelines, a pipeline will bebuilt to move crude oil from NorthDakota to the US east coast.
“Our markets will move around alittle bit,” Mr Rose says. “We don’t seeat all that our business is going to goaway.”
Energy In the Americas
On the waterfront in theport of Lamberts Point,Virginia, the activity ismore intense than for sev-eral years. Two machines,
owned by Norfolk Southern (NS), oneof two big railroads in the eastern US,haul railcars two at a time up to a bigrotating drum. With a sudden twist,the drums turn, tipping out coal fromthe cars on to a conveyor belt thatleads to a waiting ship. A plume ofcoal dust fills the air.
The activity at Lamberts Point, adedicated coal port that NS owns,reflects the state of the US coal mar-ket. Faced with slumping domesticcoal demand, NS, according to WickMoorman, its chief executive, has cutits prices for handling export coal toboost volumes.
It is one of many examples of howtransport providers’ investments innew capacity and changes to ratestructures have helped to facilitateand smooth the big changes underway in US energy markets. NS andCSX, its bigger rival in the easternUS, have both sought to boost coalexport volumes to make use of theirextensive networks in the coal-produc-ing parts of the Appalachians and Illi-nois River Basin.
In the western US, the two big rail-roads – Union Pacific and BNSF –have invested heavily in the region’sbooming oil production. Railroadsacross North America increasinglyhandle sand and other material goingto wells that produce natural gas byhydraulic fracturing. The question iswhether the recent big changes arelikely to become permanent, with coaltraffic depressed and significant oiltraffic by rail, or whether coal vol-umes will rebound and oil revert topipelines.
For NS the price cuts in the firstquarter produced a 21 per centincrease in export coal volumes thatslowed the overall decline for all coaltraffic – including domestic volumes –to 4.4 per cent. Revnues from trans-porting coal, however, fell 17 per centto $635m.
“There’s some US coal that justdoesn’t compete in the global marketthat well,” Mr Moorman says.
The company has changed its ratestructures to improve such coal’scompetitiveness. “It’s still a good busi-ness,” Mr Moorman says. “But therates are down 25 or 30 per cent.”
At the heart of NS’s coalconundrums and energy transport inNorth America lies the question ofhow most cost-effectively to bringproducts to the markets that will
deliver the highest prices. The effecthas been particularly marked, accord-ing to Jonathan Garrett, an upstreamanalyst at Wood Mackenzie, theenergy consultancy, for producers ofoil from the vast Bakken Shale inNorth Dakota and Montana.
Wood Mackenzie estimates thatalthough it costs about 60 per centmore to move crude oil by rail thanby pipeline, the benefits have more
than outweighed the costs. Producersmoving the Bakken’s light sweetcrude by rail have been able to sell itto coastal US refineries at the inter-national benchmark price of BrentCrude.
If they had moved it by pipeline, itwould have sold at the price at theinland pipeline junction of Cushing,Oklahoma, which has been consist-ently running $13/bbl lower than
Brent. Wood Mackenzie calculatesthat Continental Resources, the big-gest holder of Bakken production andexploration acreage, has boosted thePV10 value – an industry standardmeasure – of its holdings by $574m byusing rail to reach coastal refineries,rather than only pipelines. PV10measures the net present value of anarea’s future revenues, discountedby 10 per cent annually and net of
Rail offers a traditional ticket to profitabilityTransport Investment in extra capacity and rate changes illustrate the continuing potential of coal, oil and gas, writesRobertWright
Production line: a BNSF coal trainnear Pacific Junction, Iowa AP
Legend has it that ElDorado, the lost city ofgold, was built in what isknown today as Colombia,luring foreignconquistadors who neverfound its riches. Fivecenturies later it was theturn of oil explorers. Theirhopes were high until the1980s, when years ofdecline in production andexploration began, partlybecause of the country’sinternal armed conflict.But in the past decade,Colombia has takenadvantage of acommodities boom and asecurity crackdown thathas put guerrillas on theretreat. In a country thatwas long a byword forpolitical violence andinstability, in recent years,energy investors havestarted to make progress.
The reduction in violencehas coincided withgovernment moves to openup the oil industry,particularly the partialprivatisation of Ecopetrol.Tapping fields discovereddecades ago, the group’sfortunes have improvedsince 2007, with outputdoubling from 400,000barrels of oil equivalent aday then to almost 800,000boe/d this year. Today,Ecopetrol produces about60 per cent of Colombia’soil. Aiming for more, it hasan $80bn investment planin place aimed atproducing 1m barrels a dayby 2015 and 1.3m boe/d in2020.
Colombia’s oil boom,largely part fuelled byEcopetrol’s growth, hastransformed the nationinto the region’s fourth-largest oil producer. It hasalmost doubled its
production in the past sixyears, to over 1m barrelsof oil equivalent a dayearlier this year and hasproven reserves of 2.4bnbarrels.
“Since Ecopetrol wastaken out of the fiscalaccounts things haveradically changed,”explains Javier Gutiérrez,Ecopetrol’s chief.
The privatisationunlocked Ecopetrol’spotential, expanding bothits ability to borrow moneyand its exposure to capitalmarkets. Since its initialpublic offering in Colombiain 2007 – followed a yearlater by a listing in NewYork and in Toronto in2010 – the company’smarket value has risenmore than fourfold tomake it the eighth-largestoil company by marketcapitalisation.
“The company alreadyhas about half a millionshareholders, mostlymiddle class Colombians,betting for a Colombiancompany, that is thebeauty of it,” says MrGutiérrez. What manyinvestors like is that twicein the past 12 months
Ecopetrol briefly surpassedthe market capitalisationof Brazil’s Petrobras, whichproduces three times asmuch oil and is consideredthe region’s benchmark oilproducer.
Ecopetrol has increasedproduction 16 per cent ayear since 2008 and isamong the best-performingenergy groups in LatinAmerica. In search of newfields, Ecopetrol hasembarked on internationalventures. It holdsexploration blocks inBrazil, Peru and the Gulfof Mexico, where itacquired BP’s participationin the Noble Energy-operated Gunflintdiscovery. “Ecopetrol is afantastic story, in LatinAmerica, [it] is one of therising stars,” says FedericoRengifo, Colombia’s energyminister, who sits on thecompany’s board.
The Colombian state stillholds an 88.5 per centstake in Ecopetrol, withthe rest publicly traded.The company has room fora further 8.5 per centissuance but Mr Gutiérrez,has already said it has noneed to sell this year. For
him, his group is followingan efficient model similarto Norway’s Statoil. With areform aimed at openingthe hydrocarbons sector toprivate investment inMexico, some believePemex, the Mexican state-oil monopoly, should followthe lead of Colombia’sgiant.
“Ecopetrol makesdecisions that are purelymarket rational,competitive,” says MrRengifo. “Ecopetrol is acompany that hasinternationalised itself, it isa good partner and we areworking to make it evenbetter.”
Some like it as is. In abidding round last year,Ecopetrol securedexploratory blocks inColombia for oil andunconventional fuels, forinstance shale gas, in jointventures with groups suchas ExxonMobil, Repsol,Anadarko and Hocol.
Some local analystsargue Ecopetrol’s profitshave been shrinking morethan expected, partlybecause of lower globalprices for crude oil, butalso because violence –although not as ubiquitousany more and mostly inremote border areas withVenezuela and Ecuador –continues to take its toll ofoilfields and pipelines.
Attacks from rebels ofthe Revolutionary ArmedForces of Colombia and theNational Liberation Armynearly doubled last yearcompared with 2011, whichcost the company about 1per cent of its production.
But with violencenothing like the levels of adecade ago, and thegovernment in talks toclinch a peace deal withinsurgents that could soonend the 50-year conflict inthe land of El Dorado, MrGutiérrez is hopeful. “Itwas necessary to invest insecurity,” he says, “butpeace would contribute alot to generate adequateconditions for operations.”
Colombian group looks to buildon post-privatisation boomProfileEcopetrol
Market value hassoared since IPO,says Andres Schipani
On a busy day in Brazil’smain port of Santos at theheight of the soyabean har-vest, the relentless convoyof grain trucks is forced tostop suddenly.
Coming down the road issomething so large it couldbe the fuselage of a medi-um-sized passenger jet.Instead, it is the propellerof a wind turbine.
This type of cargo hasbecome a common sight atBrazilian ports these daysas the country launches oneof the most ambitious windprogrammes of an emergingmarket country.
Brazil is already a globalforce in renewable energyand is seeking to broadenits energy mix to keep pacewith rising demand forpower from a growing mid-dle class. Most of its elec-tricity comes from hydro-power.
“Brazil is buildingmomentum and has demon-strated an impressive com-mitment to wind energywith installed capacity andoutput growing at a fastrate,” says Mauricio Bermu-dez Neubauer, global headof offshore wind energy atAccenture.
According to the Brazil-ian association for windenergy, Abeeólica, Brazilhad 1431 megawatts of windpower capacity in 2011, ris-ing to 2508MW last year.This had risen to 2693MW
by May this year. The asso-ciation estimates that,based on existing contracts,the country will have9000MW of installed capac-ity by 2017.
“Combined with Brazil’ssignificant hydroelectriccapacity, with which windenergy has considerablesynergies, the countrycould become one of thecleanest electricity produc-ers in the world,” says MrNeubauer.
Brazil’s rapid emergenceon the wind power scenehas been partly thanks tothe success of operators inthe industry in a series ofgovernment power auctionsin 2011 and 2012.
Wind energy operatorssnapped up 55 per cent ofthe contracts to sell powerin these years, outcompet-ing conventional electricityproducers on price, accord-ing to Bloomberg data.
The strong winds in thecountry, particularly in thenortheast, mean that tur-bines can operate for agreater amount of timethan in Europe and else-where.
Abeeólica says the aver-age capacity factor – powergenerated compared withthe installed capacity ofBrazil’s wind farms – was 38per cent as of December lastyear. But the capacity fac-tor of the country’s newwind turbines, known asphase 2, which are tallerand have greater generationcapacity, was 57 per cent.
“Projects planned for thesector will attract $10bn ininvestment between 2013and 2017,” the associationsays.
The industry’s potentialcould be raised if Brazil is
able to exploit its expertisein offshore oil and gas todevelop offshore wind gen-eration, argues Mr Neu-bauer.
Although this is a newtechnology and thereforedoes not yet have a cost-effective supply chain, off-shore wind farms in Brazilwould have the potentialto generate more windenergy without the expense
and inconvenience of theonshore option.
“Brazil has a significantwind resource onshore butalso a very important windresource offshore,” Mr Neu-bauer says.
The problem for Brazilwill be to maintain its com-mitment to wind energy,which presently accountsfor only about 2 per cent ofthe country’s electricitygeneration, at a time whendroughts at its big hydro-power dams are making itmore urgent to build
gas-fired thermal powerplants.
Marcio Zimmerman, Bra-zil’s deputy energy minister,said the country would con-tinue to emphasise renewa-ble sources but this wouldnot always be possible.
New rules mean thatwind energy producers willnot be bidding for the samepower contracts as coal andgas-fired producers, whichcould sharply reduce theamount of wind capacitysold this year.
There are also questionsover the viability of somewind projects in Brazil,according to research firmGlobalData.
Jonathan Lane, Global-Data’s head of consultingfor power and utilities, saidrecently: “Brazil’s latestwind auction, held on 14thDecember 2012, producedsome of the lowest pricesfor wind generation outsideof China.”
He added that pricesawarded at the auction ofR$87.94 per megawatt hour($43.3/MWh) were on a parwith the average 2012wholesale electricity pricefor a US power pool ofUS$42.2/MWh. This priced“Brazilian wind generationon a par with shale gas-fired US generation,” hesaid.
Wind gathersforce in mixof renewablesourcesBrazil
Joe Leahy reportson a country strivingto keep up withmiddle class demand
‘The country couldbecome one of thecleanest electricityproducers inthe world’
Harnessing power: turbines are a landscape feature Bloomberg
It is no longer news that the surge in North American oiland gas production has transformed global energy markets.Many commentators have failed to examine why the surgehappened and what can be learnt. The lesson is simple:given the opportunity, markets work, writesRobin West, chief executive of PFC(pictured).Beginning with rocketing prices
after the Arab oil embargo of 1973,the world became obsessed withthe scarcity of oil and gas supplies.This had profound implications foreconomics and national security. USproduction began to fall and importssurged to meet demand. The US wasan energy glutton but hasredeemed itself.
This commentary appears in fullon FT.com/reports
‘While the US is goingthrough this big energyrenaissance . . . the restof the world is not’
