MEDIUM-TERM
OIL Market RePORT
June
2009 Please note that this PDF is subject to specific restrictions that limit its use and distribution. The terms and conditions are available at www.iea.org/about/ copyright.asp
INTERNATIONAL
ENERGY
AGENCY
June
2009 MEDIUM-TERM
OIL Market RePORT
This fourth edition of the IEA Medium-Term Oil Market Report (MTOMR) confronts an economic landscape unrecognisable from that seen at the time of the release of the summer 2008 edition. Crude prices are now 55% lower as financial and economic meltdown have slashed demand, with worldwide contraction in oil use at levels not seen since the early 1980s. But how long will the downturn last, and what is the likely profile of global and regional demand recovery when economic rebound eventually takes root? Has almost a decade of rising prices and costs changed the demand-side blueprint and forced the world onto a lower oil intensity path for the period through 2014? Equally importantly, the report identifies the impact that weaker demand, low prices and a credit squeeze are having on supply-side investment – in upstream OPEC/non-OPEC supply, biofuels capacity and refining infrastructure alike. The 2009 edition of the MTOMR also delves into the issues of diversifying FSU crude exports, evolving crude and product qualities, the importance of petrochemical markets and perceptions on oil price formation in the down-cycle. Two demand scenarios are presented based on differing economic growth assumptions, with a lower non-OPEC supply scenario also accompanying the lower GDP case. Summary oil balances highlight how OPEC spare capacity could develop during 2008-2014. This year, the MTOMR also consolidates analysis of future crude availability and trade flows, refining capacity and oil products supply implications under one cover. The MTOMR remains required reading for policy makers, market analysts, industry participants and anyone with an interest in oil market trends. It contains detailed statistical appendices and a wealth of insightful graphics. Alongside its monthly sister publication, the Oil Market Report, the MTOMR is a cornerstone of the IEA commitment to enhancing oil market transparency.
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MEDIUM-TERM
OIL MARKET REPORT
June
2009 INTERNATIONAL
ENERGY
AGENCY
IEA member countries: Australia
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© OECD/IEA, 2009 International Energy Agency (IEA) 9 rue de la Fédération, 75739 Paris Cedex 15, France Please note that this publication is subject to specific restrictions that limit its use and distribution. See opposite for more details.
CONTACTS Editor . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . David Fyfe Head of the Oil Industry and Markets Division +33 (0)1 40 57 65 90 e-mail:
[email protected] Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Eduardo Lopez +33 (0)1 40 57 65 93 e-mail:
[email protected] Non-OPEC Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Julius Walker +33 (0)1 40 57 65 22 e-mail:
[email protected] OPEC Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Diane Munro +33 (0)1 40 57 65 94 e-mail:
[email protected] Refining and Product Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .David Martin +33 (0)1 40 57 65 95 e-mail:
[email protected] Crude Trade/Biofuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Michael Waldron +33 (0)1 40 57 66 18 e-mail:
[email protected] Statistics/FSU Exports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Martina Repikova +33 (0)1 40 57 67 16 e-mail:
[email protected] Price Formation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Takenori Matsuoka Editorial Assistant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Anne Mayne +33 (0)1 40 57 65 96 e-mail:
[email protected]
The International Energy Agency (IEA) makes every attempt to ensure, but does not guarantee, the accuracy and completeness of the information, or the clarity of content, of the Medium-Term Oil Market Report (hereafter the MTOMR). The IEA shall not be liable to any party for any inaccuracy, error or omission contained or provided in this MTOMR, nor for any loss or damage, whether or not due to reliance placed by that party on information in this MTOMR. The Executive Director and Secretariat of the IEA are responsible for the publication of the MTOMR. Although some of the data are supplied by IEA member-country governments, largely on the basis of information they, in turn, receive from oil companies, neither these governments nor these oil companies necessarily share the Secretariat’s views or conclusions as expressed in the MTOMR. The MTOMR is prepared for general circulation and is distributed for general information only. Neither the information, nor any opinion expressed in the MTOMR constitutes an offer, or an invitation to make an offer, to buy or sell any securities or any options, futures or other derivatives related to such securities. This MTOMR is the copyright of the OECD/IEA and is subject to terms and conditions of use. These terms and conditions are available on the IEA website at http://www.iea.org/oilmar/licenceomr.html. The graphs marked ‘Source: Platts’ are based on Platts data (© Platts – a division of McGraw-Hill Inc.). Any reproduction of these graphs requires the prior permission of Platts.
www.oilmarketreport.org
T ABLE OF C ONTENTS
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TABLE OF CONTENTS
TABLE OF CONTENTS ................................................................................... 4
EXECUTIVE SUMMARY ................................................................................. 7 Overview – Oil Markets at a Crossroads .................................................................................................. 7 Demand .................................................................................................................................................... 9 Supply .....................................................................................................................................................10 Biofuels ...................................................................................................................................................11 Crude Trade ............................................................................................................................................11 Refining and Product Supply ..................................................................................................................12 Price Formation ......................................................................................................................................13
DEMAND ................................................................................................. 14 Summary ................................................................................................................................................14 Global Overview .....................................................................................................................................16 Mind the Gap: Global Demand Scenarios .............................................................................................18 Higher GDP Case .....................................................................................................................................18 Lower GDP Case .....................................................................................................................................18 OECD North America ..............................................................................................................................22 OECD Europe ..........................................................................................................................................23 The Demand Conundrum: From Suppression to Destruction ...............................................................24 OECD Pacific ...........................................................................................................................................31 Asia .........................................................................................................................................................32 Middle East .............................................................................................................................................33 Petrochemicals: Feedstock Requirements for the Ethylene Market ....................................................35 Latin America ..........................................................................................................................................38 Former Soviet Union ..............................................................................................................................39
SUPPLY ................................................................................................... 40 Summary ................................................................................................................................................40 Non‐OPEC Supply Overview ...................................................................................................................41 What Has Changed Since Last Year? ......................................................................................................42 A New Picture Emerges ..........................................................................................................................43 Downside Risks to Non‐OPEC Supply Due to Lower Investment? .........................................................44 Is Sluggish Non‐OPEC Performance Irreversible? ..................................................................................45 New IEA Research Finds 2009 Upstream Spending Down 21% .............................................................46 Revisions to December 2008 Outlook and Regional Breakdown ...........................................................47
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North America ........................................................................................................................................47 Canadian Oil Sands – Down But Not Out ...............................................................................................48 OECD Europe ..........................................................................................................................................49 OECD Pacific ...........................................................................................................................................49 Former Soviet Union (FSU) .....................................................................................................................50 FSU Exporters Branching Out .................................................................................................................51 China .......................................................................................................................................................53 Other Asia ...............................................................................................................................................53 Latin America ..........................................................................................................................................54 Middle East .............................................................................................................................................55 Africa ......................................................................................................................................................55 The Evolution of Crude Oil Production by Quality .................................................................................56 OPEC Crude Oil Capacity Outlook...........................................................................................................57 Significant Gains for Middle East OPEC Producers .................................................................................58 Political and Security Problems Temper Iraq’s Capacity Outlook ..........................................................60 OPEC’s African Producers Struggle to Meet Targets ..............................................................................61 Nationalism Undermines Outlook for OPEC’s Latin American Members ..............................................63 OPEC Gas Liquids Supply ........................................................................................................................63
CRUDE TRADE .......................................................................................... 65 Summary ................................................................................................................................................65 Overview ................................................................................................................................................65
BIOFUELS ................................................................................................ 68 Summary ................................................................................................................................................68 Medium‐Term Growth, Despite Many Uncertainties ............................................................................68 Key Revisions to the Supply Outlook ......................................................................................................70 Economic Crisis Increases Production Challenges ..................................................................................71 Biofuels Expansions May Hinge on Industry Consolidation ...................................................................72 Outlooks and Policies Differ Across Regions ..........................................................................................73 US and the Americas ..............................................................................................................................73 Europe ....................................................................................................................................................74 Asia‐Pacific ..............................................................................................................................................75 Biofuels Continue to Provide a Relief Valve for Oil Markets ..................................................................75
REFINING AND PRODUCT SUPPLY ................................................................ 76 Summary ................................................................................................................................................76 Refinery Investment Overview ...............................................................................................................77 Global Product Balances .........................................................................................................................78 Regional Refinery Utilisation ..................................................................................................................81
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Global Crude Throughput: Refiners ‘Play The Game’ ................................................................ 8 2 OECD North America ..............................................................................................................................82 Refinery Investment: A Victim of the Global Recession? ......................................................................84 OECD Europe ..........................................................................................................................................85 Joined‐Up Thinking ............................................................................................................. 8 7 OECD Pacific ...........................................................................................................................................87 China .......................................................................................................................................................89 Other Asia ...............................................................................................................................................90 Middle East .............................................................................................................................................91 Africa ......................................................................................................................................................93 Former Soviet Union ..............................................................................................................................94 Latin America ..........................................................................................................................................95
PRICE FORMATION . ................................................................................... 96 Overview ................................................................................................................................................96 The Speculation Versus Fundamentals Debate Persists ........................................................................96 Speculators – Who Are They? ................................................................................................................97 The ‘Speculation View’ ...........................................................................................................................97 Oil Market Fundamentals Revisited .......................................................................................................99 Stock Levels ............................................................................................................................................99 Arbitrage – Cashing in on a Contango . .................................................................................. 1 00 Spare Capacity ..................................................................................................................................... 100 Inelastic Supply and Demand .............................................................................................................. 101 Elasticity Matters . ............................................................................................................. 1 02 The ‘Peak Oil’ Thesis, Geopolitics and Access to Oil ........................................................................... 103 A Mismatch: Crude Availability, Refining Capacity and Required Product Mix ................................. 103 The Dollar Effect .................................................................................................................................. 104 The CFTC and the IMF Find Little Evidence for the Speculation View ................................................ 105 Other Considerations .......................................................................................................................... 106 Other Commodities ............................................................................................................................. 106 How Does the Spot Market Work? ..................................................................................................... 106 Policing Speculators ............................................................................................................................ 108 Conclusion ........................................................................................................................................... 109
TABLES . .................................................................................................. 1 10
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EXECUTIVE SUMMARY Overview – Oil Markets at a Crossroads The 2009 edition of the MediumͲTerm Oil Market Report (MTOMR) includes two oil demand scenarios,reflectingahigherandalowerGDPtrack.Thisacknowledgesthewidespreaduncertainty overtherecoverypathlikelytoemergefromtheworstglobaleconomicrecessioninhalfacentury. The higher scenario is based on the IMF’s April 2009 World Economic Outlook, while the lower scenarioassumesanyreboundintheglobaleconomywillbeslowerandattainlowertrendgrowth thanintheIMFprojection.WeretainthehigherGDPscenarioasourworkingcaseforcalculating potentialdownstreamoilmarketimplications.Dataandcommentondemandinthisreportreferto thiscaseunlessnotedotherwise.However,manyseethelowervariant,orsomethingclosetoit,asa more likely outcome, so profound could be the fallout from recent financial and economic market turmoil,amidconcernoverballooninggovernmentdeficitsandthestatusoffuturecreditmarkets. For comparison, the higher scenario sees world GDP growth regaining nearͲ5% annually for 2012Ͳ 2014,andthelowercaseseesgrowthataround3%annuallyinthesameperiod. Global GDP & Crude Oil Price Assumptions Higher GDP (y-o-y chg) Low er GDP (y-o-y chg) Nom inal Crude Oil Price ($/bbl)* Real Crude Oil Price (2008 $/bbl)* Average IEA Im port Price (2008 $/bbl)* * Assumption for both GDP scenarios
2008 3.1% 3.1% 100.1 100.1 97.2
2009 -1.4% -1.4% 51.0 48.5 44.9
2010 1.8% 1.1% 58.9 54.8 50.7
2011 4.2% 2.7% 64.4 58.6 54.2
2012 4.8% 3.0% 68.3 60.7 56.2
2013 4.8% 3.0% 70.4 61.0 56.4
2014 4.7% 2.9% 72.4 61.2 56.7
Thedatabaselineforthesupply/demandprojectionsisthe14May2009OilMarketReport(OMR). Bothscenariosarebasedonapriceassumption(notapriceforecast)centredonthecrudefutures curveatendͲApril.Forthelatteryearsoftheoutlookthisequatestoaround$60/bblinrealterms ($70/bblnominal).Atthetimeofwriting,crudefutureshadalreadymovedcloseto$70/bbl,inpart following fledgling signs that the global economy might be levelling off after erstwhile free fall. Nonetheless,whileacknowledgingthepotentialforhigherpricestofurthercrimpdemandgrowth,it is likely that the shape and extent of the economic recovery will remain the primary driver of oil market balances for the foreseeable future. Indeed the presence of intense economic uncertainty couldsupportpersistentoil,andothercommodity,pricevolatility,despitenowhigherlevelsofspare capacitywithinthesystem. Thestructureandimplicationsofthe market balances under the two scenarios are significantly different. In the higher GDP scenario, oil demand growth averages +1.4% per year after 2009. Oil intensity is expected to improve gradually as efficiency gains slowly begin to take effect. In this scenario, with nonͲ OPEC supply growth levelling off in 2011/2012, the market begins to
mb/d
Medium-Term Oil Market Balance (Higher GDP Scenario)
7.0 6.0 5.0 4.0 3.0 2.0 1.0 0.0 -1.0 -2.0 -3.0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 Effective OPEC Spare Capacity
World Demand Growth
World Supply Capacity Growth
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tightenagainsharplythereafter,witheffectiveOPECsparecapacityagainfallingsubstantiallybelow5% ofglobaldemandin2013/2014.RelativetothemediumͲtermprofilespresentedinpreviousyears,this scenariopaintsadelayedpictureofthreatened‘supplycrunch’laterintheprojectionperiod.Inthe earlieryears,downwardrevisionstodemandduetotheeconomiccrisisexceedthoseforsupply.Buta spare capacity margin of only 3Ͳ4% by 2013/2014 is narrow by any measure, and represents a tightening,andpotentiallyincreasinglyvolatile,marketoncemore. Global Balance Summary (Higher GDP Scenario) (million barrels per day)
2008
2009
2010
2011
2012
2013
2014
85.76
83.21
84.33
85.59
86.76
87.90
88.99
Non-OPEC Supply
50.60
50.31
50.59
51.12
50.70
50.41
50.22
OPEC NGLs, etc.
4.66
5.21
6.07
6.62
6.90
7.09
7.32
Global Supply excluding OPEC Crude
55.26
55.53
56.66
57.73
57.60
57.50
57.54
OPEC Crude Capacity
34.15
34.71
35.46
34.96
34.84
35.48
35.84
Call on OPEC Crude + Stock Ch.
Global Demand
30.50
27.68
27.68
27.86
29.16
30.41
31.45
Implied OPEC Spare Capacity1
3.64
7.03
7.78
7.10
5.68
5.08
4.39
Effective OPEC Spare Capacity2
2.64
6.03
6.78
6.10
4.68
4.08
3.39
3.1%
7.2%
8.0%
7.1%
5.4%
4.6%
3.8%
Global Demand
-0.39
-3.16
-3.08
-2.96
-3.07
-3.35
Non-OPEC Supply
-0.11
-1.07
-0.78
-0.49
-0.91
-1.60
OPEC NGLs, etc.
-0.24
-0.44
-0.10
0.16
0.21
0.25
Global Supply excluding OPEC Crude
-0.35
-1.51
-0.88
-0.33
-0.70
-1.35
as percentage of global demand Changes since December 2008 MTOMR
OPEC Crude Capacity
-0.23
-0.61
-0.52
-0.83
-1.50
-1.46
Call on OPEC Crude + Stock Ch.
-0.04
-1.65
-2.20
-2.64
-2.37
-2.00
-0.18
1.05
1.67
1.81
0.87
0.54
Implied OPEC Spare Capacity1 1 OPEC Capacity minus 'Call on Opec + Stock Ch.'
2 Historically effective OPEC spare capacity averages 1 mb/d below notional spare capacity.
ThelowerGDPcaseisdrivenbytrendGDPgrowththatreachesamoremodest3%peryearinthe lateryearsoftheprojection.ThislowerdemandscenariohasbeentwinnedwithalowernonͲOPEC supply variant, which simulates a Medium-Term Oil Market Balance (Lower GDP Scenario) protracted period of curtailed mb/d 7.0 upstream investment. This scenario 6.0 implies sharply weaker oil demand 5.0 4.0 growth (below 0.5% annually postͲ 3.0 2009) and the potential, therefore, 2.0 1.0 forlowerprices.However,theprice 0.0 assumption has been left unchanged -1.0 inconstructingthelowerGDPcaseto -2.0 -3.0 showmoreclearlyhowpredominant 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 income effects drive oil demand Effective OPEC Spare Capacity World Demand Growth growth, and also reflecting relatively World Supply Capacity Growth limitedpriceelasticity. The lower GDP scenario presents a picture at odds with our erstwhile message on impending supply tightness,atleastfortheperiodconsidered.However,thepossibilitythatglobaleconomicgrowthwill remainbelowrecenthistoricaltrendlevelscannoteasilybediscounted.AlthoughnonͲOPECsupplyby thetailendoftheprojectionisafurther500kb/dlowerinthisscenario,asextendedprojectslippage and steeper decline rates due to lower upstream spending feed through, this does not markedly
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diminish prevailing levels of OPEC effective spare capacity. This remains above 6mb/d through the projectionperiod,characteristicofarelativelycomfortablemarketand,moreimportantly,amarketthat couldpotentiallywithstandunexpectedsupplyshocksmoreeasilythanifsparecapacityweretorevert totheverylowlevelsseenformuchofthe2003Ͳ2008period. Global Balance Summary (Lower GDP Scenario) (million barrels per day)
2008
2009
2010
2011
2012
2013
2014
85.76
83.21
84.03
84.53
84.80
84.91
84.92
Non-OPEC Supply
50.60
50.17
50.22
50.55
50.09
49.85
49.72
OPEC NGLs, etc.
4.66
5.21
6.07
6.62
6.90
7.09
7.32
Global Supply excluding OPEC Crude
55.26
55.38
56.29
57.17
56.99
56.94
57.04
OPEC Crude Capacity
34.15
34.71
35.46
34.96
34.84
35.48
35.84
Call on OPEC Crude + Stock Ch.
Global Demand
30.50
27.82
27.75
27.36
27.81
27.97
27.88
Implied OPEC Spare Capacity1
3.64
6.89
7.71
7.59
7.03
7.52
7.96
Effective OPEC Spare Capacity2
2.64
5.89
6.71
6.59
6.03
6.52
6.96
3.1%
7.1%
8.0%
7.8%
7.1%
7.7%
8.2%
Global Demand
-0.39
-3.16
-3.38
-4.02
-5.04
-6.34
Non-OPEC Supply
-0.11
-1.21
-1.15
-1.05
-1.52
-2.16
OPEC NGLs, etc.
-0.24
-0.44
-0.10
0.16
0.21
0.25
Global Supply excluding OPEC Crude
-0.35
-1.66
-1.25
-0.89
-1.32
-1.90
OPEC Crude Capacity
-0.23
-0.61
-0.52
-0.83
-1.50
-1.46
Call on OPEC Crude + Stock Ch.
-0.04
-1.51
-2.13
-3.13
-3.72
-4.44
Implied OPEC Spare Capacity1
-0.18
0.90
1.60
2.30
2.21
2.98
as percentage of global demand Changes since December 2008 MTOMR
1 OPEC Capacity minus 'Call on Opec + Stock Ch.'
2 Historically effective OPEC spare capacity averages 1 mb/d below notional spare capacity.
Moreover,evenforthosewhoenvisageaglobaleconomicreboundclosertothehigherGDPcase, thistypeofoilmarketprofilecouldstillemergefordifferentreasons.Proactivepolicymeasuresby both producer and consumer governments could help generate this more balanced spare capacity picture. This could derive from more benign investment policies among OPEC and nonͲOPEC host governments currently struggling to sustain output levels. Allowing widespread access to reserves and providing a level playing field for joint IOC/NOC investment to better harness their respective skills,aretwopossibleroutestothisoutcome.Alternatively,this‘bank’ofsparecapacitycouldalso emerge from demandͲside policies stressing still further the importance of more efficient oil and energyusefornewcapitalstock.Sothetightervehicleeconomystandardsinherentinsomerecent governmentstimuluspackages–perhapspartofanascentcleanenergynewdeal–makesense. Ourmethodologyfocusesoninvestmentplansandpoliciesastheystandtoday;anticipatingresults fromtheCopenhagentalksinDecemberisbeyondthescopeofMTOMR.Also,thereisthequestion of timing and whether decisions made at endͲ2009, and potentially not implemented until much later, would significantly affect 2012Ͳ2014 demand. But the sorts of savings in oil use that are possiblefromsuchactionsmightnotbedissimilarfromthoseshowninthelowerGDPcase. Demand Worldwide demand contraction in 2008 and 2009 distorts the trend for the 2008Ͳ2014 outlook period,suggestingaveragesixyeargrowthofbetweenͲ0.2%peryearand+0.6%peryear,depending on assumed global GDP growth. Netting out the impact of sharp decline in 2009, trend growth averages +1.4% annually in the higher GDP case and +0.4% annually under a lower GDP variant. Common themes are the relative strength of nonͲOECD demand growth, notably from China, Asia,
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theMiddleEastandLatinAmerica,andthepredominanceofthetransportationandpetrochemicals sectors, which lead to a continued lightening of the demand barrel. When economic recovery materialises,strongpetrochemicalmarketswillsupportbuoyantethaneandnaphthagrowth,even thoughthereisariskofpetrochemicalcapacityoverhang,atleastthrough2012. Nonetheless, OECD demand falls on a sustained structural basis, as it has since 2006. Global oil intensity is expected to decline by 2.4% per year, slightly more quickly than the recent historical trend, as government policies stress energy efficiency and structural changes affecting the road transport, aviation and power generation sectors persist. Baseline changes and a weaker OECD prognosisresultinaglobaldemandprojectionfor2013of3.3mb/dbelowlastyear’slevelunderthe higherGDPscenario. Economicgrowthandefficiencyimprovementsareseenasthekeydriversofdemandtrendsinthe yearstocome,tendingtooutstrippriceeffects,partlysincenonͲOECDpricesubsidiesareexpected tobephasedoutonlygraduallyandalsosimplyreflectingtheobservationthatthepriceelasticityof demandhasdiminishedgreatlyasconsumptionbecomesconcentratedinpremiumendͲusesectors. This report tends to the view that significant demand destruction, as opposed to demand suppression,mayalreadyhaveoccurred,eveniffirmevidenceforthismustawaitthereͲemergence ofglobaleconomicgrowth. Supply The weaker demand outlook also has implications for the mediumͲterm supply profile, frequently overlooked in the eye of the economic storm as demand trends lower. The industry’s ability to expandcapacity,alreadyconstrainedafterseveralyearsofcreepingresourcenationalism,risingcosts, industrial bottlenecks and chronic project mb/d World Oil Supply Capacity Growth delays, is now further impeded with sharp 2.0 reductions in planned upstream spending. 1.5 The IEA’s report on the Impact of the 1.0 Financial and Economic Crisis on Global 0.5 Energy Investment for G8 Energy Ministers 0.0 highlights industryͲwide upstream capital -0.5 expenditurearound20%lowerin2009than -1.0 in 2008. In part, however, this relates to 2009 2010 2011 2012 2013 2014 lower costs, which may have fallen by OPEC Capacity Growth OPEC NGLs Growth Global Biofuels Growth Non-OPEC Growth (ex Biofuels) 10Ͳ15%. In theory, cost reductions and Total Net Change freedͲup drilling, fabrication and service capacityshouldultimatelyservethesectorwelltoexpandforthefuture.Butfornow,asproducers negotiate contract cost reductions and await global demand recovery, upstream project deferrals anddelayshaveintensified. Around2mb/dofnewcapacitymayhavebeendeferredindefinitelysincelastautumnandafurther 4mb/d faces delays of 18 months or more. Much of this deferred capacity had already been captured in our evolving monthly projections in the OMR, and much could be reactivated later. It nonethelessleavesaratheranaemicprofileforsupplygrowththrough2014afterashortͲtermsurge in2010.Totalcapacitygrowthisnow4.2mb/d,comparedwith5.5mb/dinourlastoutlook.
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Alltold,nonͲOPECsupplydeclinesby0.4mb/dnetbetween2008and2014,comparedwithsixyear growth of 1.5mb/d in our last projection. Downward revisions are focused on the FSU and North America, notably Canadian oil sands. That said, Canada, the US Gulf of Mexico, Brazil, biofuels and Caspian output show sustained growth through 2014. Under a lower GDP scenario, persistent spending curbs could reduce nonͲOPEC supply by a further 0.5mb/d, partly due to the impact on maturefielddecline. ProjectedOPECnetcrudecapacitygrowthamountstoamodest1.7mb/d,reachingtotalcapacityof 35.8mb/d in 2014. This is weaker than the net 3.2mb/d six year increase envisaged last year. Weaker demand, contract renegotiation, reduced cash flow, geopolitical turmoil and increased resource nationalism underpin this year’s more modest outlook. Saudi Arabia, the UAE, Algeria, Libya,IraqandAngolaallseecapacityexpansion,butthesearelargelyoffsetbydeclineelsewhere. Although also affected by project delays, OPEC NGL and condensate supply nonetheless rises by 2.6mb/dto7.3mb/d,with90%oftherisefromMiddleEastproducers. Crude Trade GlobalinterͲregionalcrudeoiltradeisexpectedtoriseby0.2mb/dbetween2008and2014,equating to 0.1% annual growth. However, using 2009 – when OPEC production cuts and falling demand dramatically reduced crude trade – as a baseline reveals a more robust picture. Crude trade from 2009Ͳ2014shouldriseby2.6mb/d,or1.5%annually,asglobaldemandrecoversandexportsfromthe Middle East and Africa increase. Chinese crude imports rise from 3.6mb/d in 2008 to 5.1mb/d in 2014,withOtherAsiaalsoseeingimportsriseby0.8mb/dto6.6mb/d.OECDimports,however,fall acrosstheboardasweakerdemandandmorecomplexnewrefiningcapacityinotherregionsdiverts crude from OECD markets. All told, lower prevailing global demand has reduced crude trade prospectsacrosstheoutlookwith2008Ͳ2013levelsaveraging2.3mb/dbelowDecemberestimates. Biofuels Despiteanexpectedhiatusin2009/2010,globalbiofuelsproductiongrowthisexpectedtorebound in the latter half of the projection period. Output is seen increasing from 1.5mb/d in 2008 to 2.2mb/d in 2014, while capacity could potentially attain over 3mb/d. As has been the case historically, biofuels are seen accounting for Global Biofuels Output around15%ofexpectedincrementalgasolineand mb/d 3.0 gasoil demand, providing something of a relief 2.8 valve from the effects of constrained nonͲOPEC 2.6 2.4 supply growth on the one hand, and tightening 2.2 middledistillateavailabilitiesontheother. 2.0 1.8 1.6 Since our previous forecast, falling oil prices, high 1.4 feedstock costs and the credit crisis have 1.2 underminedtheeconomicviabilityofasubstantial 2008 2009 2010 2011 2012 2013 2014 2009 MTOMR tranche of both existing and proposed biofuels * Based on forthcoming 2008 MTOMR World Energy Outlook capacity alike. Questions over land use, the fuel Policy Driven Scenario* 2009 policy database versus foodstuffs debate and environmental sustainability continue to hang over firstͲgeneration biofuel technology. More benign secondͲ generationtechnologyisseenmakingamodestcontributionbylateintheoutlookperiod,albeitto the tune of only some 60kb/d or so. Some European governments have backed off previously
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ambitious biofuel targets, while emission and blending limitations may potentially undermine attainmentofUSRenewableFuelStandardswithinthistimehorizon.Yetindustryconsolidationand short project lead times seem likely to allow more rapid worldwide growth to recur fairly quickly once economic recovery becomes entrenched. Brazil, the geographical mainstay of biofuels production,retainskeycompetitiveadvantageswhichshouldallowproductiontheretogrowbyalmost 360kb/d(some75%)by2014,accountingforover50%ofthetotalincreaseinworldbiofuelssupply. Refining and Product Supply Unsurprisingly,globalrefinerycrudethroughputshaveslumpedin2009inresponsetoweakeningoil demand. MarketͲresponsive regions,notably the US, Japan and Europe have seen utilisation rates scaledbackthemost.Lessintuitively,significantcapacityexpansionisexpectedtocontinueinthe next few years, with 7.6mb/d of new primary distillation capacity due online between 2008 and 2014. NonͲOECD Asia accounts for 50% of this new distillation capacity, and the OECD a further 20%. Reflecting an everͲlightening demand barrel, 6.5mb/d ofnewupgradingcapacityisalsoexpectedtobeadded, Crude Distillation Capacity alongside 7.9mb/d of capacity designed to reduce oil mb/d Additions product sulphur levels. However, the shortͲterm 2.0 outlook sees a global crude and condensate feedstock 1.5 slate which becomes lighter and sweeter, potentially 1.0 underminingupgradingeconomics. 0.5 Manynewrefiningprojectshavebeendeferredwith, surprisingly, some of these being strategic 0.0 2009 2010 2011 2012 2013 2014 investments planned for the Middle East. However, OECD China financingdifficultieshavebeenoffsetinpartbyeasing Other Asia Middle East Other Non-OECD contractor and equipment markets, leaving overall additions at relatively high levels. Even in the face of recovering demand growth after 2009 therefore, surplus capacity is likely to persist, potentially depressingmarginsandraisingtheprospectthatlessviablecapacity,notablywithinOECDcountries, will be deactivated, if not closed down altogether. These pressures are only exacerbated by mandatoryenvironmentalspendingrequirementsandthe,attimesconflicting,obligationtocurbthe sulphurcontentoffinishedoilproductswhilealsocontrollingrefineryCO2emissions. With our model matching OPEC crude supply to the difference between global demand and nonͲOPECsupply,OECDrefineryutilisationratestakethebiggesthitfromnowͲlowerdemand,with utilisation falling below 75% beyond 2010. NonͲOECD utilisation remains more stable, at close to 80%. The continued skew of demand growth towards diesel and jet kerosene makes these the distillate products most prone to future tightness, given the expected capacity and crude slate. EuropeandAfricacouldbothseemiddledistillateimportrequirementsrise,whileNorthAmerican export potential diminishes. Gasoline may tend towards surplus, with rising North American light productimportseasilyaccommodatedfromEuropeandLatinAmerica,whileAsianimportsrecede. However,thisscenarioimpliesanunsustainablytightresidualfueloilmarket,borneofconstrained throughputs,currentlyplannedupgradinginvestmentandaninitiallylightercrudeslate.Inreality, theensuingsqueezeonupgradingmarginscoulddeferupgradinginvestmentand/orboostutilisation ofhydroskimmingcapacity,albeitthelatterrisksexacerbatinglightdistillateoverhang.
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Price Formation From highs near $150/bbl last summer, crude prices fell to around $35/bbl in February 2009 and were trading around $70/bbl in June. Most analysts recognise that a constant ebb and flow of factorscombinestoinfluenceprices,makingitdifficulttoidentifyanyonedominantdriveratagiven point in time. However, the relative influence of oil market fundamentals on the one hand, and speculative financial flows into and out of futures markets on the other, continue to vie for prominenceamongthoseseekingtoexplainshortͲtermpriceshifts.Thisreportlargelyretainsthe views set out in previous editions, that changing upstream and downstream market fundamentals provide the clearest clues on likely price direction, particularly for the medium and longer term. Inventorylevels,upstreamsparecapacityandthebalancebetweenrefiningconfigurationandcrude slate all influence absolute and relative prices. Limited price elasticity can also magnify the price impact of relatively small changes in supply and demand. There is a clear need for broader and deeper data capture on market fundamentals if light is to be shed on currently opaque nonͲOECD stocklevelsanddemand. However, it is also clear after the recent rollerͲ $/bbl Crude Futures coasterrideinpricesthatmanyother,lesstangible Front Month Close 150 factors, including expectations for the shape of the 130 marketinthefuture,alsoplayakeyshortͲtermrole in influencing prices. These range from concerns 110 about‘peakoil’andtheadequacyofupstreamand 90 downstream investment, all the way to exchange 70 rate fluctuations, equity market shifts, perceptions 50 Source: Platts onglobaleconomicrecoveryandshortͲtermmoney 30 flows into and out of commodity futures markets. Jun 07 Dec 07 Jun 08 Dec 08 Jun 09 That said, recent analyses have been unable to NYMEX WTI ICE Brent proveadirectpriceͲmakingrolefornonͲcommercial operatorsonfuturesexchanges.Moreover,thereisariskthatsome,moreheavyͲhanded,legislative proposals might choke off liquidity in futures markets, something that risks exacerbating price volatilityratherthanlesseningit.However,currentmovesbylegislatorstoextendoversighttooverͲ theͲcounter(OTC)derivativesmarketsaimedatgeneratingmorevisibilityontheseparticipants’role inthemarket,addingtounderstandingofpriceformationandthuspotentiallylimitingvolatility,are welcome. In parallel with calls for more information on the physical market therefore, mandatory disclosureofdeeperandbroaderinformationontradestakingplaceonfuturesmarketsshouldhelp throwmorelightontheinfluencepapermarketshaveonprices.
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DEMAND Summary x
Global oil product demand is expected to grow by 0.6% or 540kb/d per year on average between2008and2014,from85.8mb/dto89.0mb/d.Thisisbasedontheeconomicoutlook posited by the International Monetary Fund in the April 2009 edition of its World Economic Outlook,whichseesglobaleconomic activitygraduallyreboundingtoalmost5%peryearfrom 2012 onwards. Under an alternative, ‘lower GDP’ scenario, whereby global GDP expands less rapidly,attainingarateofgrowthofroughly3%by2012(athirdlessthanunderthehigherGDP case), oil demand would contract by 0.2% (Ͳ140kb/d) per year on average to 84.9mb/d. This entailsadifferenceof4.1mb/dversusthehigherGDPcase.
Global Oil Demand (2008-2014) (millio n barrels per day)
1Q08 2Q08 3Q08 4Q08
2009
2010
2011
2012
2013
3.1
3.1
3.1
3.1
3.1
3.2
3.1
3.0
3.2
3.1
3.2
3.3
3.4
3.5
3.5
Americas
30.5
30.5
29.8
30.0
30.2
29.2
28.8
29.2
29.0
29.1
29.4
29.6
29.9
30.2
30.4
Asia/Pacific
26.6
25.6
24.9
25.0
25.5
25.4
24.6
24.0
24.6
24.7
25.0
25.5
25.9
26.3
26.7
Europe
15.9
15.5
16.0
15.9
15.8
15.4
14.7
15.3
15.3
15.2
15.1
15.0
15.0
14.9
14.7
FSU
4.2
4.1
4.3
4.2
4.2
3.9
3.9
4.1
4.0
4.0
4.1
4.2
4.4
4.6
4.7
Middle East
6.6
7.0
7.4
6.8
7.0
6.7
7.3
7.7
7.1
7.2
7.5
7.9
8.3
8.6
8.9
85.8 83.8 82.3 83.4 83.3 -0.3 -3.6 -4.0 -2.4 -1.9 -0.2 -3.1 -3.4 -2.1 -1.7 -0.39 -2.98 -3.36 -2.49 -3.83
83.2 -3.0 -2.6 -3.16
84.3 1.4 1.1 -3.08
85.6 1.5 1.3 -2.96
86.8 1.4 1.2 -3.07
87.9 1.3 1.1 -3.35
89.0 1.2 1.1
Africa
World Annual Chg (%) Annual Chg (mb/d) Changes from last MTOMR (mb/d)
x
86.9 1.0 0.9 0.05
85.8 85.4 85.0 0.9 -0.5 -2.5 0.8 -0.4 -2.2 0.00 -0.09 -1.50
2008 1Q09 2Q09 3Q09 4Q09
2014
Given the sharp oil demand fall, notably in 2009, the calculation of average annual growth ratescanleadtoverydifferentresultsdependingonthechosenbaseyear.Thedeepeconomic recession that has spread worldwide in the past year has taken a severe toll on oil demand, expectedtocontractin2009atratesnotseensincetheearly1980s.Thismarksabreakafter severalyearsofstrongoildemandgrowth(whichendedwiththeslightcontractionof2008)and thus distorts compounded growth rates. Taking 2009 as the base year, average yearly growth wouldbeovertwiceashigh(+1.4%or1.2mb/d)underthehigherGDPscenario. Demand Scenarios (millio n barrels per day)
2008
2009
2010
2011
2012
2013
2014
Avg. Yearly Grow th, 2008-2014 %
Higher GDP Global GDP (y-o-y chg) 3.1% -1.4% OECD 47.5 45.1 Non-OECD 38.3 38.1 World 85.8 83.2 Low er GDP Global GDP (y-o-y chg) 3.1% -1.4% OECD 47.5 45.1 Non-OECD 38.3 38.1 World 85.8 83.2 Low er vs. Higher Global GDP (% points) 0.00 0.00 OECD 0.00 0.00 Non-OECD 0.00 0.00 World 0.00 0.00
14
m b/d
Avg. Yearly Grow th, 2009-2014 %
m b/d
1.8% 4.2% 4.8% 4.8% 4.7% 45.0 44.9 44.7 44.6 44.4 39.4 40.7 42.0 43.3 44.6 84.3 85.6 86.8 87.9 89.0
3.2% -1.1% 2.6% 0.6%
-0.52 1.06 0.54
3.2% -0.3% 3.2% 1.4%
-0.14 1.30 1.16
1.1% 2.7% 3.0% 3.0% 2.9% 44.9 44.7 44.2 43.8 43.3 39.1 39.9 40.6 41.1 41.6 84.0 84.5 84.8 84.9 84.9
2.1% -1.5% 1.4% -0.2%
-0.70 0.55 -0.14
1.9% -0.8% 1.8% 0.4%
-0.35 0.69 0.34
-1.1 -0.4 -1.2 -0.8
-0.17 -0.51 -0.68
-1.3 -0.5 -1.4 -0.9
-0.21 -0.61 -0.81
-0.75 -0.03 -0.27 -0.30
-1.54 -0.24 -0.82 -1.06
-1.76 -0.50 -1.46 -1.96
-1.78 -0.78 -2.21 -2.99
-1.75 -1.04 -3.03 -4.07
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OildemandgrowthwillbedrivenbynonͲOECDcountries,whileoilconsumptionintheOECD willdeclineovertheforecastperiod.UnderthehigherGDPcase,nonͲOECDoilproductdemand increasesby2.6%onaverageperyearover2008Ͳ2014,from38.3mb/dto44.6mb/d,equivalent to+1.1mb/dperyear,withgrowthconcentratedinAsia,theMiddleEastandLatinAmerica.By contrast,OECDoilproductdemand decreasesannuallyby1.1%onaverage,from47.5mb/din 2009 to 44.4mb/d in 2014 (Ͳ520kb/d per year). Under the lower GDP scenario, nonͲOECD oil demand growth would almost halve to 1.4% per year, while OECD growth, at Ͳ1.5% per year, wouldbeaboutathirdlower.ThisdifferentsensitivitytoGDPgrowthlargelyreflectsdifferent developmentpatterns.Beingmoreenergyintensive,nonͲOECDcountrieswillcatchupfastwith theOECD.By2014globaloildemandwillbealmostevenlysplitbetweenmatureandemerging economies. It is important to note that this outlook envisages a gradual improvement in efficiencyinOECDandnonͲOECDcountriesalike,notablyinthetransportationsector.
OECD vs. non OECD Oil Demand
m b/d 50
OECD Non-OECD
45
40
35
30
25 1997
1999
2001
2003
2005
2007
2009
2011
2013
x
Transportation fuels will drive oil demand growth. This unifying theme – applicable to both OECDandnonͲOECDcountries–nonethelessobscuressomeregionaldifferences.IntheOECD, theaggregatedgrowthofmotorgasoline,jetfuel/keroseneanddieselafter2009willbemodest andinsufficienttooffsetthestructuraldeclineinbothunderboilerburningfuels(heatingoiland residual fuel oil) and industrial feedstocks (LPG, naphtha and ‘other products’). In nonͲOECD countries, the demand for transportation, boiler and industrial fuels will all rise at a relatively rapidpace.Yet,despitethesedifferences,distillates(jetfuel,kerosene,dieselandothergasoil) willlikelyremainthemainnonͲOECDgrowthdrivers,followedbyLPG,naphthaandgasoline.
World: Total Oil Product Demand by Type of Product, 2014
m b/d
Global Cumulative Oil Demand Growth by Product 2008-2014
4
12%
Gasoline LPG & Naphtha Other
3
Transportation Fuels
Distillates Fuel Oil Total
2
61% 1
Heating & Fuel Oil
(1)
27%
(2)
Other Products
(3) 2008
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Thecomparisonbetweenthecurrentprognosisandboththe2008EditionoftheMTOMRand its Refining and Product Supply Outlook Supplement (December 2008) presents significant differences.ComparedwithDecember’sSupplement,thecurrentglobaloildemandprojectionis 3.3mb/d lower by 2013,with the OECD bearing the brunt of the adjustment. The changes are related to the considerable volatility in oil Global Oil Demand: Difference vs. Previous prices and – more importantly – the MTOMR (December 2008) unwindingoftheglobaleconomicrecession. 2008 2009 2010 2011 2012 2013 kb/d In addition, there were baseline revisions pertaining to nonͲOECD countries following (500) (1,000) thesubmissionofnewdatafor2007. (1,500) (2,000) This outlook confronts several risks, which (2,500) couldsignificantlyaltertheexpectedpathof (3,000) global oil demand. These include: 1) the (3,500) timing, pace and strength of the expected OECD Non-OECD WORLD globaleconomicrecovery; 2)theevolutionof commodity prices, most notably oil; 3) the permanence or removal of administered price regimes in key nonͲOECD countries; 4) the prevalence of normal weather conditions, defined as a 10Ͳyear average of observed temperatures; 5) more rapidͲthanͲexpected developments in alternative sources of supply and energyefficiency;and6)furtherrevisionstobaselinedataresultingfromgreatertransparency.
Global Overview Globaloilproductdemandisexpectedtogrowby0.6%peryearonaveragebetween2008and2014, from 85.8mb/d to 89.0mb/d, representing an average volumetric increase of 540kb/d per year. The foundation of this projection is the economic outlook offered by the International Monetary FundinitslatestWorldEconomicOutlook(April2009),whichseesglobaleconomicactivitygradually rebounding to almost 5% per year by the end of the period, from Ͳ1.4% in 2009. The oil price assumption, meanwhile, is derived from forward price curves as of late April, which indicated a smoothrisetoroughly$61/bblinrealtermsby2014(around$72/bblinnominalterms). Such a recovery would imply a return to the status quo ante – i.e., the 2003Ͳ2007 period, when economicactivitywasnotonlystrongbutalsouniversallybuoyant,withglobaloildemandexpanding by 2.0% per year on average. However, the economic future is anything but certain. An extraordinaryconfluenceoffactorsledtothecurrentcrisis–loosemonetarypolicies,housingand financial bubbles, poor regulation and global current account imbalances – and, hence, the timing and profile of the potential recovery are subject to much debate. One school of thought assumes that the global economy will feature a pronounced ‘VͲshaped’ recovery by endͲ2009 if not before, and cites as evidence a recent string of soͲcalled ‘green shoots’ in several key countries – a slight rebound in industrial production in Japan, Germany and China and, in the US, strongerͲthanͲ expectedconsumerdemanddespitedismal1Q09GDPfigures,areboundinhousesalesandaslower paceofjobsdestruction,tonamejustafew. These ‘green shoots’, which are certainly welcome, may be interpreted as proof that the global recession has bottomed out, with the significant fiscal and monetary loosening in key economies workingtheirwayup.However,therecentresurgenceofeconomicactivitycouldalsosimplyreflect
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the rebuilding of depleted inventories Key Assumptions: GDP Growth & Oil Price $110 across several industries, making it 8% $100 arguablyprematuretopredictanimminent 6% $90 and strong economic rebound, not least 4% because the elimination of spare capacity, $80 2% the deleveraging of the private sector in $70 several highly indebted countries and the 0% $60 rebalancingofglobaldemandarestillatan -2% $50 early stage. As such, the recovery could -4% $40 2008 2009 2010 2011 2012 2013 2014 conceivably be more ‘LͲshaped’ (i.e., Real Crude Oil, 2008 $ (RHS) World: Real GDP shallow). Some economists suggest that OECD: Real GDP Non-OECD: Real GDP thisrecessioncouldsetthestageforlower potential growth in the medium term, since the foundations of the previous boom years have been demolished. If so, an alternative, lower GDP scenario, whereby global GDP would expand both less rapidlyandlessstronglytoroughly3%by2012andbeyond,cannotbediscarded.Ifitcametofruition, theprofileofoildemandwouldbeclearlyaffected,asdiscussedoverleaf. Average Global Demand Growth 1996-2002/2002-2008/2008-2014 thousand barrels per day
Europe
FSU
51
64
North America -28
317
91
-23
-183
Asia
Middle East
26
284
662
330 429
132 -91
193
Latin America 188
Africa 66
81
69
Avg Global Demand Growth (mb/d)
129 49
1996-2002 2002-2008 2008-2014
1.02 1.28 0.54
1.4% 1.6% 0.6%
Leaving aside the admittedly crucial question on the shape of economic recovery, the current recessionanditsaccompanyingbrutalfallinoildemandhasalsorenderedyearlycomparisonsand compoundedgrowthratessomewhatmisleading.Indeed,thecalculationofaverageannualgrowth rates can lead to very different oil demand appraisals depending on the chosen base year – more precisely,dependingonwhether2009isincluded,whenoildemandisexpectedtocontractatrates notseensincetheearly1980s.Taking2009insteadof2008asthebaseyear,averageyearlygrowth wouldbeovertwiceashigh(+1.4%or1.2mb/d)underthehigherGDPscenario.Althoughdemand comparisonsbetween2009and2014wouldarguablymakemoresensesincethatperiodisexpected to feature positive GDP growth rates under both the higher and the lower GDP scenarios, for the sakeofconsistencyinthisreportwetakethe2008Ͳ2014period.
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Mind the Gap: Global Demand Scenarios The jury is still out on whether the global economic recovery will be quick and strong, or slow and shallow. Since economic growth is arguably the most important variable affecting oil demand, any forecast is therefore bound to be significantly altered depending on the GDP outlook – all the more if it looks five years ahead, as is the case in this report. Attempting to address this uncertainty, we have modelled how sensitive oil demand would be under a ‘lower GDP’ scenario, which assumes that the expansion of global economic activity would be as much as a third lower than the IMF currently expects.
Scenario Rationale Lower GDP Case
Higher GDP Case •
The global economy rebounds quickly (from 2010) thanks to fiscal and monetary stimulus
•
The economic downturn is protracted – limited potential GDP growth for several years
•
Efficiency goals are actively pursued as prices rise – ‘accelerated’ efficiency improvements (tighter US CAFE standards, hybrid/electric vehicles, carbon cap-and-trade schemes, etc.)
•
Efficiency targets are less aggressively implemented as subdued oil prices remove economic incentives to develop new technologies – ‘normal’ efficiency improvements
•
Annual oil demand growth rebounds at +1.11.3 mb/d
•
Annual oil demand grows 0.8 mb/d range
within a 0.0-
Several caveats are necessary, though. It should be noted that our lower GDP scenario: • Is merely illustrative and does not imply any specific probability of occurrence; • Is based on a ceteris paribus approach (changing one variable while keeping all others constant): a. The iterations between GDP growth and the oil price (which would probably be lower under weaker economic activity) are ignored; and b. Medium‐term elasticities by country are assumed identical to those of the higher GDP case, although income and price elasticities would arguably be different in either case. Under the higher GDP case, after the 2009 hiatus, global oil product demand increases by 1.4% or 1.2 mb/d per year on average to 89.0 mb/d by 2014. By contrast, under the lower GDP scenario, oil demand would grow by only 0.4% or 340 kb/d per year on average between 2009 and 2014 to reach 84.9 mb/d. In other words, if economic growth were to be weaker, global oil demand would expand only a third as fast. This entails a large difference between the two cases: 4.1 mb/d by the end of the forecast period – all the more considerable as this is almost equivalent to the entire consumption of several big emerging countries. Higher vs. Lower GDP Scenarios
% Chg 6
m b/d 90
4
88
2
86
Higher GDP Low er GDP
84
Low er (2) 2008
18
Global Demand: GDP Sensitivity
Higher 82
2009
2010
2011
2012
2013
2014
2008
2009
2010
2011
2012
2013
2014
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Mind the Gap: Global Demand Scenarios OECD Demand: GDP Sensitivity
m b/d 48
Higher GDP
(continued) Non-OECD Demand: GDP Sensitivity
m b/d 45
Low er GDP
47
43
Higher GDP Low er GDP
46 41 45 39
44 43
37 2008
2009
2010
2011
2012
2013
2014
2008
2009
2010
2011
2012
2013
2014
OECD demand would contract almost three times as fast (Ͳ350kb/d versus Ͳ140kb/d per year on average), while nonͲOECD demand would grow half as fast (+690kb/d versus +1.3mb/d per year on average). This asymmetrical effect highlights the greater oil intensity of emerging economies – i.e., much higher income elasticity, coupled with stronger GDP growth – when compared with mature economies. In addition, most large nonͲOECD countries, notably in the Middle East, are effectively shieldedfromtherealpriceofoilbyvirtueofadministeredendͲuserpriceregimes(incountriessuchas VenezuelaorIran,forexample,gasolinecancostaslittleas$0.10/litre).ThisisnotthecaseinOECD countries,whicharegenerallymoreresponsivetooilpricefluctuations,albeitwithalag. The two largest oilͲconsuming countries, the United States and China, which also embody the OECD/nonͲOECD dichotomy, further illustrate this pattern. Whereas US demand would rebound to almost 19.0mb/d by 2014 under the higher GDP case (equivalent to +90kb/d per year on average relativeto2009),itwouldstagnateatabout18.6mb/d(+10kb/dperyear)bytheendoftheoutlook periodifGDPgrowthwereweaker.InChina,therespectivefigureswouldbe9.6mb/d(+360kb/dper year) and 8.5mb/d (+150kb/d per year) by 2014. In the case of the US, therefore, the difference betweenthebaseandthelowerGDPscenarioswouldbenegligible(Ͳ390kb/d)relativetototaldemand. Bycontrast,thedifferenceforChina(1.1mb/d)wouldbeequivalenttoasmuchas11.0%ofitscurrent (2009)demand. US50 Demand: GDP Sensitivity
m b/d 19.6
Higher GDP
19.4
China Demand: GDP Sensitivity
m b/d 10.0
Low er GDP
Higher GDP
Low er GDP
9.5
19.2
9.0
19.0 8.5
18.8
8.0
18.6 18.4
7.5 2008
2009
2010
2011
2012
2013
2014
2008
2009
2010
2011
2012
2013
2014
The reason is that the outlook for 2009 remains a tentative forecast at best, but we fully acknowledgethatcomparing2008with2014maygivethefalseimpressionthatoildemandgrowth is necessarily poised to remain extremely subdued in the medium term, which is certainly not the caseunderthehigherGDPtrend. Intermsofdrivers,theoveralloildemandpictureisbroadlyunchangedversuspreviouseditionsof the MTOMR. Geographically, oil demand will be driven by nonͲOECD countries, while oil consumption in the OECD is projected to decline over the outlook period. NonͲOECD oil product
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demand is expected to increase by 2.6% on average per year over 2008Ͳ2014, from 38.3mb/d to 44.6mb/d,equivalentto+1.1mb/dperyear,withgrowthconcentratedinAsia,theMiddleEastand Latin America. By contrast, OECD oil product demand is foreseen to decrease annually by 1.1% on average,from47.5mb/din2008to44.4mb/din2014,anaverageyearlydeclineofroughly520kb/d. This different sensitivity largely reflects much higher oil intensity in emerging countries, where petrochemical, industrial and power generation activities will continue to expand despite gradual, efficiencygains.Bycontrast,economicactivityintheOECDislikelytoshiftfurtherfromindustryto services. Electricity generation and heating needs will increasingly rely on natural gas or other sources,whilefuelefficiencyisexpectedtoincreasemarkedlyasnew,moreefficienttransportation technologiesemerge.Assuch,by2014globaloildemandwillbealmostevenlysplitbetweenOECD and nonͲOECD countries – a major change in little more than a decade, when nonͲOECD demand accountedforroughlyathirdoftotalglobaldemand. On a sectoral basis, transportation fuels will remain the main engine of oil demand growth. This unifying theme – applicable to both OECD and nonͲOECD countries – nonetheless obscures important disparities. In the OECD, the aggregated demand for motor gasoline, jet fuel/kerosene andgasoil/dieselwillfallslightly(Ͳ0.2%peryearonaveragein2008Ͳ2014,albeitgrowingpostͲ2009), while the structural decline in other product categories is expected to be larger – heating oil and residualshoulddeclineby6.3%peryear,whileLPG,naphthaand‘otherproducts’shouldfallby1.9% peryear.InnonͲOECDcountries,thedemandfortransportation,burningandindustrialfuelswillall rise at a relatively rapid pace (+3.3%, +1.0% and +2.6% per year, respectively). Yet, despite these differences,middledistillates(jetfuel,kerosene,dieselandothergasoil)willundoubtedlyremainthe mainnonͲOECDgrowthdrivers,asnotedinpreviousreports,followedbyLPGandnaphtha(largely usedaspetrochemicalfeedstocks)andgasoline. OECD Demand: Difference vs. Previous MTOMR (December 2008) kb/d -
2008
2009
2010
2011
2012
(500)
2013
kb/d 500
2008
2009
2010
2011
2012
2013
-
(1,000)
(500)
(1,500)
(1,000)
(2,000) (2,500) OECD, North Am erica OECD, Pacific
Non-OECD Demand: Difference vs. Previous MTOMR (December 2008)
OECD, Europe OECD
(1,500) Africa China (excl. Hong Kong) Non-OECD Europe Middle East
Latin Am erica Other Asia FSU Non-OECD
ThecomparisonbetweenthecurrentprognosisandboththeJuly2008EditionoftheMTOMRandits December2008RefiningandProductSupplyOutlookSupplementpresentssignificantdifferences.As noted, the effect of the extreme volatility in oil prices and the severity of the global economic recession – two unforeseen and major events – have weighed heavily on oil consumption, particularly in 2009. Compared with December’s Supplement – which published our last mediumͲ term oil demand assessment, covering the 2008Ͳ2013 period – the current global oil demand projectionis3.3mb/dlowerby2013.ItshouldberememberedthatinNovember2008,theIMFhad predictedthattheworldeconomywouldexpandby+3.6%peryearonaveragebetween2008and 2013,markedlymorethanunderitscurrentassessment(+2.9%onaverageoverthesameperiod). Moresignificantly,whereassixmonthsagotheFundexpectedtheglobaleconomytogrowby+2.2% in2009,itsmostrecentprognosisforeseesacontractionof1.4%.
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Notsurprisingly,therevisionsareconcentratedintheOECD,giventhattherecessionbeganwitha financial meltdown in the United States before extending to the rest of the world, and because matureeconomieswerehitbyasurgeininternationaloilpricesin1H08asthecrisisbegantounfold. As such, the 2013 projection for OECD demand is now 2.2mb/d lower versus the December prognosis,withthebulkoftheadjustmentconcentratedinthePacificandEurope,whichhavesofar beenthehardesthit–andwhichwillmostlikelytakelongertorecover.InnonͲOECDcountries,the revisions are lower (Ͳ1.1mb/d by 2013) by virtue of their lower sensitivity to oil prices given the prevalence of administered price regimes, and since their economies were expanding at a much higherpacethantheOECDwhentheglobalcrisiserupted.Still,theregionsthataremoredependent upon global trade and/or commodity exports – China, Latin America and the FSU – feature the largestrevisions.Bycontrast,thedemandforecastsforAfricaandtheMiddleEasthavebeenrevised up slightly on expectations of more buoyant economic growth than previously expected in the former and ambitious petrochemical expansion plans in the latter. It should be also noted that a smallpartofthenonͲOECDrevisionsareduetochangestothe2007baseline. This outlook, like any other, intrinsically confronts several risks, given the high complexity of the driversthatsustainoildemand.Each–oracombination–ofthefollowingfactorscouldsignificantly altertheexpectedpathofglobaloildemandinthemediumterm. x As argued earlier, there are questions regarding the timing, pace and strength of the expected globaleconomicrecovery,andthedebateontheseissuesisfarfromsettled. x Predicting the evolution of commodity prices, most notably oil, is a hazardous exercise, as evidenced by the extreme price volatility that has prevailed in recent months and years. As noted,thisdemandoutlookassumesanoilpricetrajectoryderivedfromforwardpricecurvesas oflateApril,wherebythepricereachesroughly$61/bblinrealtermsby2014(about$72/bblin nominalterms)–yetinearlyJunenominalpricessurgedtoaround$70/bbl. x We presume that administered price regimes in key nonͲOECD countries will move gradually towards freeͲmarket prices, as suggested by the recent example of China. However, a sudden crude oil price rise could conceivably either lead to the reinstatement of price controls and subsidiesincountriesthatwereotherwisefollowingChina’sprudentandgradualliberalisationor, perhapsevenlesslikely,astillmoreprecipitousdismantlingofsubsidieswerethefinancialcosts tobecometoogreat. x Weassumenormalweatherconditions,definedasa10Ͳyearaverageofobservedtemperatures. Nonetheless, a repeat of the string of unusually warm winters observed in the Northern Hemisphere in 2006Ͳ2008 – which weighed significantly on OECD demand over that period – cannot be entirely discounted, nor indeed exceptional hurricane activity or other unpredictable weatherphenomena. x We expect that alternative sources of supply (the gradual yet growing use of natural gas and biofuelsasasubstituteforseveralrefinedproducts,includinggasoline,diesel,heatingoilorfuel oil) will make further inroads, and that the recent gains in energy efficiency, notably in the transportation sector, will continue. However, both assumptions could be derailed by very lowprices. x Finally, despite clear advances regarding transparency, data uncertainties, notably in nonͲOECD countries,continuetoblurthedemandpicture,notablyinsomelargecountriesthatstillprovide insufficient or difficultͲtoͲinterpret figures. As transparency improves further, baseline data revisionscouldeventuallyalterthedemandpictureinsomecountriesandregions.
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OECD North America OilproductdemandinNorthAmericaisexpectedtofallby0.4%peryearonaveragebetween2008 and2014,from24.3mb/dto23.7mb/d.Thisislargelyunderpinnedbyariseintransportationfuels, notablyintheUS,whichmayaccountforaround81.5%ofregionaldemandin2014.Nonetheless, thecombinationofthesevereeconomicrecession,changingbehaviouralpatternsfirsttriggeredby thesharpoil pricerisein 1H08anda newUSadministrationintentonimprovingoverallefficiency andreducingcarbonemissionssuggeststhatareturntopasthighgrowthratesingasolinedemand– almosthalfofregionalconsumption–isunlikely,despiteanexpectedeconomicrecoverythatcould boostdiscretionarydrivingagain. m b/d 24.4
OECD North America: Oil Demand Growth by Product, 2008-2014, kb/d 200 100 (100) Gasoline Distillates LPG & Naphtha Fuel Oil Other Total (RHS)
(200) (300) (400) (500) 2008
2009
2010
2011
2012
2013
2014
OECD North America: GDP Sensitivity Higher GDP
400 200 (200) (400) (600) (800) (1,000) (1,200) (1,400)
Low er GDP
24.2 24.0 23.8 23.6 23.4 23.2 23.0 2008
2009
2010
2011
2012
2013
2014
The transportation sector is indeed poised to experience profound changes in the years ahead, as implied by the precarious state of North American car manufacturers. Short of a widespread adoption of dieselͲfuelled vehicles (a technology that has never really taken off in the region), the financialhealthoftheindustryislikelytodependuponfuturegenerationsofpassengercarsthatare bothsmallerandbasedonhybridorelectrictechnologies.Meanwhile,demandforotherproducts suchasnaphtha,heatingoilandresidualfueloilislikelytodeclineasotherregionstakethemantle of petrochemical production and as other, cleaner sources of energy such as natural gas are more broadlyadopted. OECD North America: Demand Trends, Main Refined Products Trends Post-2009
(mb/d)
Avg. Annual Growth, 2008-2014
0.2
-8.6%
Declining petrochemical activity in the US and Canada as other, more competitive petrochemical production areas emerge; growth expected in Mexico, but from a low base
11.0
+0.6%
Growth driven by all three countries, although at a much faster pace in Mexico, owing to rising living standards an expanding fleet; no wide-scale switch to diesel cars, but a rapid adoption of hybrid/electric vehicles, notably in the US
1.8
+0.6%
Air travel boosted by the economic recovery, particularly in Mexico’s growing market; offsetting efficiency gains in aircraft fleets and airlines operations
(including biodiesel)
5.0
+0.0%
Rebounding diesel demand, driven by economic activity and offsetting the continuing displacement of heating oil in favour of natural gas and electricity in the US and Canada
Fuel Oil
0.7
-8.5%
Declining use for power generation in all three countries, as fuel oil is substituted by natural gas or other sources both for price reasons and in a bid to curb carbon emissions
Product
Naphtha
Volume, 2014
Gasoline (including ethanol)
Jet Fuel/ Kerosene Gasoil
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OECD Europe OilproductdemandinEuropeisseendecliningby1.3%peryearonaverageovertheoutlookperiod, from 15.2mb/d in 2008 to 14.1mb/d in 2014. Demand will continue to be largely responsive to trends in its largest economies (France, Germany, Italy, Spain and the United Kingdom, accounting for 60.8% of total regional demand by 2014). Demand in these countries is already falling for structural reasons:lower economic growth when compared with other European countries, decliningpopulations(particularlyinItalyandGermany),the‘dieselisation’ofvehiclefleets,andthe substitutionofheatingoilandresidualfueloilbynaturalgasandrenewables.Risingmiddledistillate demand (diesel and jet fuel) should thus offset the steep fall in gasoline consumption, keeping overalltransportationfuelsdemand(overhalfoftotalconsumption)broadlyunchanged. m b/d 15.5
OECD Europe: Oil Demand Growth by Product 2008-2014, kb/d 200
-
150
(100)
100
(200)
50
(300)
-
OECD Europe: GDP Sensitivity Higher GDP Low er GDP
15.0
14.5
(400)
(50) (100) (150) (200) 2008
2009
Gasoline LPG & Naphtha Other 2010 2011 2012
(500)
14.0
Distillates (600) Fuel Oil Total (RHS) (700) 2013 2014
13.5 2008
2009
2010
2011
2012
2013
2014
There are several caveats to this outlook. First, the recession has wreaked havoc in industrial production and hence in demand for some fuels such as LPG and naphtha. We assume a gradual recovery of the petrochemical sector (particularly in Germany), but this could prove too optimistic. Second, the substitution of burning fuels (heating oil and residual fuel oil) is predicated on the continuingavailabilityofnaturalgas.However,Europehasalreadytwiceexperiencedtheinterruption ofgassuppliesfromRussiaasaresultofthelatter’sdisputewithUkraineoverpricingandrepayments, somethingthatisnotyetwhollyresolved.Moreover,itisunclearwhetherRussiawillbeabletomeet its future export commitments. Third, the penetration of biofuels is uncertain, with some countries backtrackingonmandatesandreducingtheirfinancialsupportfortheindustry.Thiscouldmeanthat moreoilcouldberequiredtosatisfythegrowthintransportationneedsthanisshownhere. OECD Europe: Demand Trends, Main Refined Products Trends Post-2009
(mb/d)
Avg. Annual Growth, 2008-2014
1.0
-1.4%
Petrochemical activity assumed to recover from the recession in ‘core’ countries (France, Germany, Italy, Spain and the United Kingdom) but then stagnating; moderate growth in several ‘peripheral’ (eastern) countries
1.8
-4.8%
Incentive-based scrapping of older gasoline-fuelled cars in favour of diesel vehicles in core countries; moderate growth in peripheral ones
1.4
+1.1%
Air travel boosted by the economic recovery, particularly in peripheral countries’ expanding markets; offsetting efficiency gains in aircraft fleets and airlines operations
(including biodiesel)
6.3
+0.0%
Diesel fleets expanding in peripheral, less saturated countries; gradual substitution of heating oil by natural gas and electricity
Fuel Oil
1.3
-3.9%
Declining use for power generation as the two largest consumers (Italy and Spain) further switch to other sources (natural gas, renewables and nuclear); rising bunker demand in the Netherlands and Belgium as global trade recovers
Product
Naphtha
Volume, 2014
Gasoline (including ethanol)
Jet Fuel/ Kerosene Gasoil
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The Demand Conundrum: From Suppression to Destruction Asoildemandplummetsonaglobalscaleonthebackoftheworsteconomicrecessioninoverhalfa century,anoldquestionhascomebacktohauntoilanalysts:whetherthislosswillbepermanentor temporary – i.e., whether demand has been ‘destroyed’ or merely ‘suppressed’. Naturally, this issue oftencentresontheUS,beingtheworld’slargestoilconsumingcountry–andalsoonethatuniquely provides a comprehensive array of oil data, thus allowing for detailed analyses of oil demand trends. Thisdebateisnotonlyofacademicinterest;inwhichdirectionoildemandevolveswillhaveprofound mediumͲandlongͲtermeconomicconsequences. Proponents of the ‘suppression’ view argue that US oil demand will eventually rebound to previous levels given the sharp fall in the oil price from its midͲ2008 peak. According to this thinking, the oil marketiscyclical:strongdemandpromptstheoilpricetorise,whichtheneventuallycurbsdemand; theweakerdemand,inturn,depressestheprice,fosteringanewroundofdemandgrowth. Atfirstglance,historicalevidencewouldlendsomecredencetothe‘suppression’view.However,the ‘destruction’ case may be more persuasive after examining the main drivers in three key areas of US demand: road transportation fuels (gasoline and onͲroad diesel), jet fuel and fuel oil, and then by presentingtheefficiencyassumptionsthatunderpinourglobaloildemandoutlook. 1.
TheDeterminantsofTransportationFuelsDemand
Transportationfuelsdemandisafunctionofthreemaincomponents:structure,activityandintensity. Theprincipalstructuralfactorsincludethenumberofvehiclesinuse(thefleet),theirtype(cars,trucks, buses and twoͲwheelers) and their respective energy sources (gasoline, diesel or another fuel). The activityisessentiallymeasuredbyvehiclemilestravelled(VMT),possiblythebestproxyoftransportation fuelsdemand.Finally,intensityisappraisedbythenotionofaveragemilespergallon(AMG),alsoknown asfueleconomy(orintensity),whichevaluatestheoverallenergyperformanceofthefleet. The relationship between transportation fuels demand structure and these three main factors can be expressedasfollows: TransportationFuelsDemand=(Fleet*VMT)/AMG Or,intermsofchange:
'Demand='Fleet+'VMTͲ'AMG This equation thus states that for demand growth to be positive, the expansion of the vehicle fleet and/or the rise in vehicle miles travelled must be higher than overall improvements in efficiency. As discussedbelow,thisrelationshipisempiricallysupportedbyavailabledata. The US vehicle fleet totalled an estimated 249 million units in 2008, with automobiles accounting for roughly 55% of the total, and trucks/buses (including SUVs) for 45%. The fleet’s increase has been directlyrelatedtoincomeandpopulationgrowth,withaveryhighcorrelation(R2equals0.99inboth casesoverthe1990Ͳ2008period).Meanwhile,vehiclemilestravelledcorrelatestronglytobothvehicle registrations (R2 = 0.98) and motor fuel consumption (R2 = 0.99). By implication, the correlation betweenGDPandmotorfuelconsumptionis,unsurprisingly,alsoquitesolid(R2=0.96). By contrast, the average fuel consumption per vehicle (AMG) has largely stagnated since the early 1990s. After increasing from 13.9 miles per gallon in 1985 to 16.2mpg in 1991, it is estimated at 17.1mpgin2008–only+5.2%in17years–andaboutathirdhigherthaninmostotherOECDcountries. Meanwhile,thecorrelationbetweeneitherVMTormotorfuelconsumption,ontheonehand,andreal gasolineprices,ontheother,isstatisticallyweakoverrelativelylongperiods.Althoughthemostrecent datasuggestthatVMTstallandevenfallwhenpricesexceed$2.00/gallon,thisisalsoarguablyrelated toanincomeeffect.
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The Demand Conundrum: From Suppression to Destruction Real GDP vs. Vehicle Registrations 1990-2008
250
(continued)
Real GDP vs. Motor Fuel Consumption, 1990-2008
Vehicle Registrations (million)
190 Motor Fuel Consumption (billion gallons)
240 230 220 210 200 190
180 170 160 150 140 R2 = 0.9625
R2 = 0.9912 180 7,000
8,000
9,000 10,000 11,000 Real GDP (2000 $, billion)
130 7,000
12,000
9,000 10,000 11,000 Real GDP (2000 $, billion)
12,000
Sources: US FHWA, BEA
Sources: US FHWA, BEA
Vehicle-Miles Travelled, Motor Fuel Consumption, Vehicle Registrations & Gallons per Vehicle
Vehicle-Miles Travelled vs. Real Gasoline Price 1995-2008 (base: January 2000) 340
160 150
Fuel Consum ption
140
Vehicle Fleet
Retail Gasoline Price (cents per gallons)
Vehicle-Miles Travelled
Gallons per Vehicle 130 120 110 100 90 1985
8,000
1988
1991
1994
Source: US FHWA (1987 = 100)
1997
2000
2003
R2 = 0.5504 290 240 190 140 90 2,300
2006
2,500 2,700 2,900 Vehicle-Miles Travelled (billion)
Sources: US FHWA, EIA, IEA
3,100
Thedataindicate,insum,thatsincetheearly1990sfueldemandgrowthhasdependedessentiallyon theexpansionofthevehiclefleet,giventhatfuelintensitybarelyimprovedoverthatperiod.Partofthe increase in VMT in the second half of the 1980s was attributable to improved fuel intensity (the correlation between VMT and AMG over 1985Ͳ 1991standsat0.95).Bycontrast,overthepast18 US: Motor Fuel Expenditures as % of Total Household Expenditures, All Quintiles years the growth in VMT has been almost 5.0% exclusively related to the increase in the vehicle fleet, until recently largely driven by SUVs and 4.5% 2 other ‘light trucks’ (with R for VMT versus AMG 4.0% fallingto0.63). 3.5%
The fleet’s growth was supported, in turn, by a 3.0% larger,richerpopulationwhoincreasinglychoseto 2.5% both purchase large cars and SUVs (given low 1984 1989 1994 1999 2004 retail fuel prices) and live outside big cities (the Source: US BLS suburbansprawl)withlimitedavailabilityofpublic transportation. This rendered gasoline demand relatively inelastic, even as retail prices began to gradually rise in 2002. And even then only a fraction of the population was truly affected by higher prices.Motorfuelsexpendituresbythesecond,thirdandfourthquintiles–thebulkofthepopulation– averaged roughly 5.5% of total household spending in 2007. This is lower than in most developed countries,wherepriceshavebeentraditionallymuchhigher.
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The Demand Conundrum: From Suppression to Destruction
(continued)
Undersuchcircumstances,apricerise(anexogenousfactor)hadtocoincidewithanincomeshock(an endogenous factor) for growth in VMT – and hence in gasoline demand – to stall and eventually contract. This is exactly what happened during 2007Ͳ2008: the acceleration of the oil price rise to doubleͲdigit,yearͲonͲyeargrowthrates,whichbeganlateintheyear,wasfollowedshortlybyominous signsofanimpendingeconomicslowdownamidworseningfinancialindicators.
Retail Gasoline Price (cents per gallons)
USdriverseventuallyreactedtothepricerisebycuttingleisuredriving,sharingnonͲdiscretionarydaily commutes, switching to smaller cars, using public transportation when available and even riding bicycles.However,asthefinancialandeconomiccrisishasbroadenedover recentmonths,massivejob losses in the US (and elsewhere) have further Vehicle-Miles Travelled vs. Real Gasoline Price reduced nonͲdiscretionary job commutes. Oct 2007- Sep 2008 (base: January 2000) Meanwhile,domesticcarmanufacturersspecialised 350 in gasͲguzzling light trucks are all facing serious 330 financialdistressassalescollapse.Thesubsequent 310 fall in gasoline prices has had a marginal effect in 290 reviving VMT and transportation fuels demand – average income per capita will arguably need to 270 recoverfirst. 250 R2 = 0.6778
Yet it is far from certain that transportation fuels 230 2,950 2,970 2,990 3,010 3,030 3,050 will rebound strongly as the economy improves, Vehicle-Miles Travelled (billion) given the recent federal policy moves to increase Sources: US FHWA, EIA, IEA fuelefficiency(USaveragefueleconomyshouldrise to35.5milespergallonby2015,whichimpliesslashingthefleet’scurrentfuelintensitybyalmosthalf). According to the equation stated above, if AMG rises, demand will fall, unless the fleet and/or VMT increaseevenmore. Admittedly,thefleetislikelytoexpandagainonceincomesbeginrising–butfuturesaleswillarguably begearedtowardsmoreefficientvehicles.Indeed,itseemsunlikelythatmotoristswhohavepurchased smaller cars will revert to gasͲguzzling vehicles, despite the numerous incentives offered by the automotiveindustry.Assuch,foroildemandtogrowstrongly,USmotoristswouldarguablyneedtodrive muchmorethaninrecentyearstocompensateforthegradualimprovementofthefleet’soverallefficiency. Thelikelihoodofthisdependsonwhetherrecentbehaviouralchangesregardingdiscretionarydriving, car sharing and public transportation usage become well entrenched. It will also depend on whether the anecdotal evidence that the suburban sprawl may be gradually losing its appeal is confirmed. If more Americans are indeedconsidering living closer to their place ofwork, given oftenͲlimited public transportationalternativesfurtheraway,thiswouldsignalanotherstructuraltrendandeventuallyentail evenlessdriving. The fleet’s gradual but inexorable efficiency improvement will also have a substantial impact. As a simplisticillustration,assumingthatallnewcarssoldfrom2011arehighlyefficientandassumingtypical new registration and scrapping rates, by 2014 some 15% of the fleet could comprise highly efficient vehicles.Thismightpotentiallyreducegasolinedemandby1.4mb/dfromcurrentlevels. Weremaindoubtfulthatalltheserecenttrendswillbefullyreversed,andthatUSmotoristswilldrive markedly more than in the recent past. We therefore assume that demand for transportation fuels, notablygasoline(accountingforjustunderhalfoftotalUSoildemand)willexpandatasubduedpace (+0.3%peryearonaveragebetween2008and2014),wellbelowtheratesobservedduringthe1990s and early 2000s (about +1.5Ͳ2.0% per year on average). This suggests that current gasoline consumptionlevelsmaywellbeseeninretrospectastheinflexionpoint–i.e.,thepeak–ofUSdemand.
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The Demand Conundrum: From Suppression To Destruction 2.
(continued)
JetFuel:LeanerOperations
USjetfueldemandhascontinuouslydecreasedsince2006,afterastrongrecoveryfromthesharpfall triggered by the 2001 terrorist attacks. Demand averaged 1.5mb/d in 2008, 5.9% lower than in the previous year and 9.0% or 150kb/d down versus its 2005 peak. It would be tempting to argue that risingoilpricesaretoblameforthisdecline.Afterall,thesurgeinjetfuelpricesthatbeganin2003 wreakedhavocintheUSairlineindustry,forcingseveralmajorcarriersintobankruptcyprotectionand pushing manysmall operators out of business altogether. The emergence of the current recession in 2008alsoarguablycontributedtolastyear’sevensteeperdeclineinjetfueldemand. Yet the industry was also obliged to restructure itself. Aside from taking painful financial and managerial measures (from hedging fuel prices to laying off staff), air carriers implemented several – long postponed – operational enhancements. In otherwords, the industry was forced to enhance its overallefficiency.Suchmeasuresinclude 1)optimisingpassengerandfreightloads; 2)flyingatslightly reducedspeeds; 3)redeployingaircrafttointernationalroutes; 4)tighteningrefuellingprocedures;and 5)improvingdomestictankering. Real GDP vs. Jet Fuel Demand Growth 1995-2008
% Chg 6% Other Kerosene Jet Fuel % Chg (Jet Fuel) 4%
kb/d 1,850
US50: Jet Fuel/Kerosene Demand
1,800 1,750
5.0% 4.5%
1,650
0%
1,600
-2%
1,550
GDP Growth
4.0% 2%
1,700
3.5% 3.0% 2.5% 2.0% 1.5%
1,500 1,450 1995
1997
1999
2001
2003
2005
2007
-4%
1.0%
-6%
0.5% -6%
R2 = 0.6524 -4%
-2%
0%
2%
Jet Fuel Dem and Grow th
4%
6%
Thefirstfourofthesemeasureshavehadadirectimpactondomesticjetfueldemand.Byoptimising passengerandfreightloads,carriersareabletoflymore passengersandcargoonfewerplanes,thus reducingthenumberofflights.Flyingatslightlyreducedspeedsmayincreaseairbornehoursbuthelps to save fuel. Redeploying aircraft to international routes enhances average fuel efficiency, as planes take off and land less often. By enhancing refuelling procedures, airline companies reduce aircraft overfilling.Finally,improvingdomestictankering,whichentailsmovingflightstolessexpensiveairports, doesnotnecessarilyreducefueldemandbutcontributestoreduceoveralloverheads. The graph overleaf – expressed as an index to facilitate comparisons – shows how passenger and freightloadsincreasedsharplyasjetfuelcostsbegantheirjourneyfromlessthan$1.0/galloninearly 2004 to a peak of $3.8/gallon in July 2008 (the last available data point corresponds to December 2008). Interestingly, although both the number of passengers and cargo tonnes rose continuously untilearly2008,jetfuelconsumption(asopposedtodemand,whichincludesstocking)initiallybeganto fall and then stagnate from late 2004, suggesting that the efficiency measures described above had startedtopayoff. Nonetheless,thereisalimitonhowmuchefficiencycanbeimproved:thepassengerloadfactorhas hoveredaround79%sincemidͲ2006.Regardingcargo,bycontrast,thereseemstobesomescopeforfurther improvement,asthefreightloadfactorhasaveragedroughly60%overthepasttwoͲandͲaͲhalfyears.
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The Demand Conundrum: From Suppression to Destruction US: Air Carrier Main Indicators December 2002 = 100
113
540
Passenger Load (12-m avg) 111
Freight Load (12-m avg)
109
Fuel Consum ption Fuel Cost (RHS)
(continued)
490 440 390
107
340
105
290 240
103
190 101 99 Dec-02 Dec-03 Source: US BTS
140 Dec-04
Dec-05
Dec-06
Dec-07
90 Dec-08
In sum, eventhough the current recession has led toplummeting flight demand, both for passengers (‘enplanement’)andcargo(‘freighttonneͲmiles’),theindustryhasarguablysucceededinimplementing structuralefficiencychangesthatwillcertainlyprevailastheeconomyrecovers,especiallyiffuelprices spikeagain.Efficiencyislikelytofurtherimproveinthemediumtermaslighter,moreefficientunits built with composite materials and featuring less gasͲguzzling engines replace older aircraft (this has alreadybeguntosomeextent).Lookingfurtherahead,theadventofviablesyntheticjetfuelandeven ‘biojet’willarguablyfurthercurbdemandforoilͲbasedjetfuel.Indeed,someexperimentalfuelshave alreadybeensuccessfullytested,bothbythemilitaryandprivatecarriers.
m illion 75
US: Air Carrier Passenger Enplanement
70
Y-o-Y Chg 25% 20%
m illion 720
US: Air Carrier Freight Tonne-Miles
Y-o-Y Chg 30%
670
20%
620
10%
570
0%
520
-10%
470
-20%
420
-30%
15% 65 60 55
10% 5% 0% -5%
50 45 08 07 06 05 04 03 02 cccccccDe De De De De De De Source: US BTS
3.
-10% -15%
08 07 06 05 04 03 02 cccccccDe De De De De De De Source: US BTS
TrendsinInterfuelSubstitution:FuelOilandThePowerSector
Since2006,averageUSfueloildemandhasfallensignificantlyrelativetothepreviousthreeͲyearperiod, whenithadactuallyrisenbacktolevelsseeninthelate1990s.Isthisananomaly,ordoesitsignalthe emergenceofanewtrend?Asseeninthesectoralgraphbelow,thedemandfallfrom2006onwards hasbeenlargelyrelatedtotheabruptreductionofpowergenerationshareinfueloildemand–from roughly45%onaveragein1998Ͳ2005toabout18%onaveragein2006Ͳ2008.Moreover,thissharehad beenshrinkingsince2004,suggestingthatthe2005surgeinoverallfueloildemandwasarguablydueto the devastation brought about by hurricanes Rita and Katrina. In the fall of that year, indeed, both hurricanesseverelydisruptednaturalgasproductionintheGulfofMexico,sendinggaspricestorecord highsandobligingutilitiesandindustriesintheareatorelyextensivelyonfueloil.
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The Demand Conundrum: From Suppression to Destruction US50: Fuel Oil Demand kb/d 950
Fuel Oil Dem and
(continued)
US50: Fuel Oil Demand by Sector
% Change
15%
100%
10%
900
80%
5%
850
0%
800
-5%
750
-10%
60% 40%
-15%
700
20%
-20%
650
-25%
600
-30%
1998 2000 Source: IEA
2002
2004
2006
0% 1998
2008
Source: IEA
2000 Pow er
2002
2004
Bunkers
2006
Industry
2008 Other
What accounts for fuel oil’s diminishing share in power generation? Available data from the US EIA indicatethat‘petroleumliquids’(mostlyfueloil)havebeengraduallydisplacedbynaturalgas.Indeed, the share of natural gas in terms of total power generation has continuously increased over the past decade (from 15% in 1998 to 21% in 2008), with the exception of a brief interruption in 2003, when domesticgaspricessurged.Bycontrast,theshareoffueloilinpowergenerationhasfallentolessthan 1%,comparedwithalmost3%in2004. US50: Fuel Oil vs. Natural Gas, Power Gen.
US50: Natural Gas Demand, Power Gen. bcf/d 20
Natural Gas Dem and
FO as % of Total Gen. 4%
NG as % of Total Gen. 29%
3%
25%
2%
21%
1%
17%
% Change 15%
19 10%
18 17
5%
16 0%
15 14
-5%
13 12 1998 2000 Source: US EIA
-10% 2002
2004
2006
2008
0% Jan-04 Jan-05 Source: US EIA
13% Jan-06
Jan-07
Jan-08
Admittedly,therecentstrengthofnaturalgasisduelargelytorelativeprices.Overthepastthreeyears, naturalgashascertainlybecomemuchmorecompetitivethanfueloil–andthecurrentoutlookisthat gas prices will remain depressed for the foreseeable future, given an ongoing supply glut. However, natural gas has another important advantage. Being a cleaner fuel, it is better suited to meet increasingly stringent environmental regulations, and as such has even slightly encroached upon coal use at the margin. Even though natural gas is essentially used as an intermediary load to meet peak electricity demand in summer (coalͲfired combinedͲcycle plants meet the country’s base load, accountingforabout52%oftotalgenerationcapacityinwinterandroughly45%insummer),inthepast twowinterstheshareofnaturalgashasnoticeablyrisenrelativetonormalseasonaltrends,whilethat ofcoalhasslightlyfallen. Doesthismeanthatfueloilispoisedtobecomeanincreasinglymarginalsourceforpowergeneration? Theanswerisprobably‘yes’,fortworeasons.First,asnoted,naturalgaspricesarelikelytoremainlow. Second, anecdotal evidence suggests that older, fuel oilͲfired plants are being decommissioned and replacedbyeithernaturalgasͲorlowͲsulphurgasoilͲfuelledunits.
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The Demand Conundrum: From Suppression to Destruction 4.
(continued)
CappingItAll:MTOMREfficiencyAssumptions
Thisdiscussionhashighlightedseveralimportantpointsthatargueinfavourofthe‘destruction’case. First,the‘suppression’viewarguablyoverplaystheeffectsofanoilpricedecline,notablywithregards to transportation fuels. As noted, the rebound in oil demand will be primarily driven by strong economicgrowth.Theincomeandpriceeffectsareinfactasymmetric:theirrisehasgreaterimpact upon demand than their decline. Second, the ‘suppression’ argument also overlooks efficiency improvementsintransportationandinterfuelsubstitutiontrendsinthepowersector,whicharelikelyto havedurableconsequencesonoildemandpatternsinthemediumtolongterm. In fact, on a per capitabasis, US oil demand has continuously fallen over the past two decades, from 32barrelspercapitain1978toalmost26barrelsin2007–a19%drop,despitetheincreaseinoverall oil demand. More broadly, this has occurred on a global basis, although there are clear regional differences(theMiddleEast,forexample,istheworld’smostinefficientareaintermsofoiluse,since energyisabundantandcheap). GDP & Oil Demand per Capita, 2008
Oil Intensity (1995 = 100)
Oil Demand per Capita (bbls)
18
100 OECD
Middle East
16
Non-OECD
95
14
90
12
OECD
10
85
Latin Am erica
8
80 FSU
6
Africa
4 2
Asia
75 Non-OECD Europe / World
70 65
-
5 10 15 20 25 30 GDP per Capita (US$1,000, 2000 PPP)
60
35
1995
1998
2001
2004
2007
2010
2013
In our demand outlook, we assume that efficiency gains in both OECD and nonͲOECD countries will continue – that is, global oil intensity will decline by 2.4% per year on average from 2009 to 2014 (comparedwithͲ2.1%from1996to2008).Theimprovementshouldbeslightlylesspronouncedin2010 –byvirtueoftheexpectedstrongreboundinoildemandrelativetothelowslikelytobereachedthis year,notablyintheOECD–butshouldacceleratethereafter. However,theseefficiencyassumptionscouldprovetootimid.Indeed,ratherthanponderingwhether demandwillbe‘destroyed’or‘suppressed’,amorepertinentquestionisarguablywhethertheongoing shift towards greater energy efficiency will be more pronounced than in the past. As much as we attempt to account for what, in our view, are discernible structural adjustments technological breakthroughsornewpolicyinitiativescouldbringforwardstillstrongerefficiencyimprovementseven morerapidlythanwecurrentlyexpect.Insuchcase,evenunderconditionsofstrongeconomicactivity, greaterefficiencyadvancescouldstillresultinloweroildemandgrowth.
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OECD Pacific Oil product demand in the Pacific is expected to decrease by 3.3% per year on average, from 8.0mb/din2008to6.6mb/din2014)–themostpronounceddeclineintheOECD.Demandinthe region has sharply fallen as the economic recession unwinds, and that has compounded structural declinetrends.TheembodimentofthesedevelopmentsisJapan,expectedtoaccountfor49.5%of regionaldemandin2014(versus59.1%in2008).Thecountry’sexportͲorientedeconomicmodelhas been severely hit by the fall in global trade; as in Germany, industrial production has plummeted, bringing down with it naphtha consumption – and begging the question whether petrochemical activitywillrecoverasmorecompetitiveproducersemergeelsewhere.Inaddition,Japanfacesan aging demographic trend, drives ever more efficient vehicles and increasingly uses electricity for heatingpurposes–allfactorsthatunderpinthecountry’sstructuraloildemanddecline. m b/d 8.5
OECD Pacific: Oil Demand Growth by Product 2008-2014, kb/d 100
-
50
OECD Pacific: GDP Sensitivity Higher GDP Low er GDP
8.0
(100)
-
(200)
(50)
(300)
(100)
(400)
(150)
(500) Gasoline LPG & Naphtha Other
(200) (250) 2008
2009
2010
2011
Distillates Fuel Oil Total (RHS)
2012
2013
2014
7.5 7.0 6.5
(600) (700)
6.0 2008
2009
2010
2011
2012
2013
2014
Moreover, the widespread nuclear power outages that helped support oil demand over the past coupleofyears(intheformofsurgingresidualfueloilconsumptionanddirectcrudeburninginorder togenerateelectricpower)areseeminglyreceding.Oneofthesevenreactorsofthegiant8.2ͲGW KashiwazakiͲKariwa nuclear plant, which had been shut down nearly two years ago following a devastating earthquake, is expected to resume operations over the next few months, possibly followedbyasecondreactorbytheendoftheyear. OECD Pacific: Demand Trends, Main Refined Products Trends Post-2009
(mb/d)
Avg. Annual Growth, 2008-2014
1.6
+0.1%
Growing strongly in Korea but declining rapidly in Japan as other, more competitive petrochemical producers emerge (the Middle East and China)
1.4
-1.6%
Declining in Japan given demographic, technological and behavioural changes; marginal or stagnant growth in Korea and Australia
0.4
-11.8%
Rapidly declining kerosene consumption (used for heating in Japan and Korea) given sustained switch to electricity, offsets recovery-driven jet fuel growth, notably in Korea and Australia
(including biodiesel)
1.5
-2.1%
Sharp structural heating oil decline, notably in Japan, offsetting growing diesel demand in all countries (Australia, Japan, Korea and New Zealand) as economic activity rebounds
Fuel Oil
0.5
-8.6%
Declining across the region, displaced by natural gas and other sources, notably nuclear in Japan as shut-in plants resume operations
Product
Naphtha
Volume, 2014
Gasoline (including ethanol)
Jet Fuel/ Kerosene Gasoil
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Meanwhile, oil demand in Korea (32.0% of regional demand in 2014 versus 26.8% in 2008) is expectedtodeclineslightly.Therelativelystrongdemandgrowthforeseeninnaphtha,gasolineand dieselwillnotbesufficienttooffsetthefallinkerosene(usedforheating,asinJapan),heatingoil andresidualfueloil.Moreover,theoveralldeclinecouldbelarger.Theoutlookfornaphtha(47.0% oftotaldemandin2014,comparedwith39.6%in2008)assumesthatthecountrywillsuccessfully fulfil its ambitious petrochemical expansion plans despite fierce competition from other regions, notablytheMiddleEast. Asia OilproductdemandinAsiaisexpectedtoexpandby2.3%peryearonaverage,from17.5mb/din 2008 to 20.1mb/d in 2014. Although some of the more exportͲdependent Asian countries have been battered by the global economic slump, the region as a whole is likely to post positive GDP growththisyear.Assuch,incomelevelsshouldriseagainstronglyovertheforecastperiod,notably in urban areas. This will feed further demand for greater mobility – exemplified by the rapid expansionofmotorbike,passengercar,truckandaircraftfleets–whichwillcontinuetobethemain driverofoilconsumptiongrowth.TheprevalenceofadministeredendͲuserpriceregimesinsome countries such as India and Indonesia may also provide demand support if oil prices were to spike again,notonlyfortransportationfuelsbutalsoforkerosene,whichisessentiallyusedbythepoor. Furthermore,risingcrudeoilpricescouldleadtoareimpositionofsubsidiesinChinaandelsewhere, despitearecent,gradualpriceliberalisation. Asia: Demand Trends, Main Refined Products Trends Post-2009
(mb/d)
Avg. Annual Growth, 2008-2014
1.8
+2.4%
Growing in Singapore, Chinese Taipei and China, which aims to becoming one of the world’s petrochemical powerhouses; declining in India as natural gas becomes the main feedstock for petrochemical production, notably fertilisers
3.6
+4.2%
Surging as vehicle fleets expand, given rising income per capita in urban areas, notably in China and India; increasing moderately in Indonesia, Chinese Taipei and Thailand
1.4
+1.7%
Growing jet fuel demand with rising air transportation and expanding aircraft fleets in China, India, Indonesia, Singapore, Thailand and Malaysia; subsidised kerosene to remain the fuel of the region’s poor, mainly in India and Indonesia
(including biodiesel)
6.6
+2.7%
Rebounding demand, driven by economic activity and gasoil’s multiple usages in China, India, Indonesia, Thailand, Malaysia, Pakistan, Philippines and Chinese Taipei; additional support may be provided by subsidies if prices rise
Fuel Oil
2.4
-0.2%
Rising moderately in China, as ‘teapot’ refineries consolidate, more strongly in coastal areas as global trade resumes and bunkers demand picks up; declining in the power generation sector because of natural gas substitution
Product
Naphtha
Volume, 2014
Gasoline (including ethanol)
Jet Fuel/ Kerosene Gasoil
Gasoilwillremaintheregion’smostusedproduct(33.1%oftotaldemandby2014),givenitsmultiple applications (transportation, agriculture and smallͲscale power generation). Should coal shortages reͲemergeinChina,gasoilcouldagainbeusedasakeysourceforpowergeneration.Gasolinewill come next (17.8% of total demand) on the back of surging vehicle fleets. India, in particular, is poisedtorecordtheregion’shighestpaceofgasolinedemandgrowth,helpedbythisyear’slaunch ofafirstlowͲcostpassengercar(theTataNano).Airtravelandtourismwillboostjetfueldemand acrosstheregion,whiletheresumptionofglobaltradeshouldsupportmarinebunkersdemand.The consolidation of China’s ‘teapot’ refining sector may tame fuel oil demand, although much will
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depend upon the government’s pricing and import policies on this product and on whether such restructuringfavoursthestateͲownedmajors.Finally,LPGandnaphthademandwillbesupported bypetrochemicalexpansionplans,notablyinChina. Asia: Oil Demand Growth by Product 2008-2014, kb/d 400 300 200 100 (100)
Gasoline LPG & Naphtha Other
(200) (300) 2008
2009
2010
2011
2012
700 600 500 400 300 200 100 Distillates Fuel Oil (100) Total (RHS) (200) 2013 2014
m b/d 20.5
Asia: GDP Sensitivity Higher GDP
Low er GDP
20.0 19.5 19.0 18.5 18.0 17.5 17.0 2008
2009
2010
2011
2012
2013
2014
Despiteamarkedeconomicslowdownasitsmanufacturingindustryfacesshrinkingexportmarkets, China should eventually recover and remain the region’s largest oil consumer, with 47.8% of total demand by 2014, for obvious demographic and income per capita reasons. India has so far withstoodtheworsteffectsoftheglobalrecessionandhasacomparablepopulation,butabouthalf asmuchincomepercapita.Assuch,itisexpectedtoconsumemuchlessoilthanChina,accounting for only 18.1% of regional demand. Indonesia, Singapore, Chinese Taipei and Thailand will follow moredistantly(with5Ͳ7%each). Middle East OilproductdemandintheMiddleEastisseengrowingbyanimpressive4.3%peryearonaverage over the projection period, from 7.0mb/d in 2008 to 8.9mb/d in 2014. The region has so far weathered the global economic slump and fall in oil prices much better than expected, although countriessuchasSaudiArabiaandtheUAEarelikelytofaceamildrecessionthisyear.Oildemand hascontinuedtorise,albeitsomewhatlessrapidly,astheconstructionindustryhasfacedthebrunt of economic slowdown. Yet the dynamics of oil demand growth are – and will remain – strong: sustained economic expansion (based on oil and gas, petrochemicals, heavy industry and construction),demographics(continuedurbanisationandayoungandgrowingpopulation)andfuel pricesthatarecurrently–andlikelytoremain–amongthelowestintheworld. Therefore, demand for all oil product categories is expected to remain resilient. Demand for transportation fuels (mainly gasoline and jet fuel) will continue to rise on the back of expanding vehicleandaircraftfleets(theGulf,inaddition,isbecomingoneoftheworld’smainairtravelhubs). Meanwhile, demand for LPG and naphtha is also poised to increase sharply to feed the region’s expandingpetrochemicalsector,withlocalproducersintentondisplacingrivalselsewhere,notably intheOECD.Demandforresidualfueloil(and,toalesserextent,gasoil)willalsosoarinorderto meetevergrowingpowerneedsgiventhelaggingdevelopmentofdomesticnaturalgasresources.
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Middle East: Oil Demand Growth by Product 2008-2014, kb/d
200
Gasoline LPG & Naphtha Other
160
Distillates Fuel Oil Total (RHS)
120
m b/d 9.0 580 530 480
8.5
Middle East: GDP Sensitivity Higher GDP Low er GDP
8.0
430 80
380
40
330
-
7.5 7.0
280 230
(40) 2008
2009
2010
2011
2012
2013
2014
6.5 2008
2009
2010
2011
2012
2013
2014
Saudi Arabia and Iran will continue to account for the lion’s share of regional demand by 2014 (38.4% and 25.4%, respectively). However, Iraq is poised to make a strong economic comeback as it recovers from the war; a relatively well‐educated population and a large industrial base, in addition to important oil and gas resources, will sustain growth there. Baseline revisions to Iraqi oil demand (2007) and a newly published economic forecast from the IMF (World Economic Outlook, April 2009) suggest that the country will be at par with the UAE, with each accounting for roughly 8% of the region’s total oil demand by 2014. Middle East: Demand Trends, Main Refined Products Trends Post-2009
(mb/d)
Avg. Annual Growth, 2008-2014
0.2
+5.8%
Surging as ambitious petrochemical projects are developed across the region, particularly in Saudi Arabia and Iran
1.8
+5.4%
Rising rapidly, spurred by expanding vehicle fleets on the back of rising income per capita, urbanisation and extremely low end-user prices, especially in the largest markets, Iran and Saudi Arabia, and to a lesser extent, Iraq and the UAE
0.6
+2.5%
Increasing as air traffic rises across the region, which is becoming a key global hub, with the largest markets being respectively Iran, the UAE, Iraq and Saudi Arabia
(including biodiesel)
2.2
+2.6%
Rebounding demand as rapid economic activity resumes, notably in the construction sector and, to a lesser extent, the power industry, with Iran and Saudi Arabia at the forefront
Fuel Oil
2.1
+4.2%
Growing to feed power plants as long as alternative sources (mainly domestic natural gas) remain prone to delays, notably in Iran, Saudi Arabia, the UAE, Iraq, Kuwait and Syria
Product
Naphtha
Volume, 2014
Gasoline (including ethanol)
Jet Fuel/ Kerosene Gasoil
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Petrochemicals: Feedstock Requirements for the Ethylene Market Theeconomicrecessionhassuppressedglobalethylenedemandsignificantly,compoundingabusinessͲ cycletroughfollowingmassivecapacityadditionsintheMiddleEastandAsia.Nonetheless,beforethe economicmalaiseunfolded,theethylenemarkethadbeengrowingatratessome50%higherthanGDP. Assuch,onceeconomicgrowthresumes,substantialdemandforpetrochemicalfeedstocksislikelyto reͲemerge.Between2008and2014,totalnaphthaandLPG(includingethane)demandisexpectedto growby0.4%and1.0%onaverage,respectively.Theethylenemarketisthusseenreboundingstrongly, expanding by 3.7% per year on average over the forecast period. It should be noted that this mediumͲterm outlook is based on capacity data from Chemical Markets Associates Inc. (CMAI), into whichwehaveincorporatedourownviewsregardingeconomicgrowth. 1.
EthyleneProductionCapacityTrends
Global ethylene production capacity is estimated at 129.7 million tonnes per year (mt/y) in 2008, with North America, Northeast Asia, the Middle East and WesternEuropeaccountingfor81%ofthetotal.In NorthAmerica(27%ofglobalcapacity),ethaneisthe main feedstock (56% of ethylene production), followed by naphtha (17%) and propane (15%). Northeast Asia (China, Hong Kong, Japan, South Korea, North Korea and Chinese Taipei) represent 22%oftheworld’sproductioncapacity,withnaphtha being the primary feedstock (88% of ethylene production). The Middle East, meanwhile, despite having added 7mt/y of production capacity from 2003 to 2008 (37% of total capacity additions), accountsforonly13%ofglobalcapacity.
2008 Share of Total Ethylene Capacity Africa 1%
Southeast Asia 6% South America 4%
Central Europe FSU 2% 3% West Europe 19%
Northeast Asia 22%
Indian Subcontinent 3%
Middle East 13%
North America 27%
Source: CMAI
MiddleEasternproductionisbasedmainlyonethanefromtheregion’ssubstantialnaturalgasreserves, with71%ofregionalethyleneproductioncomingfromethane,whilepropaneandnaphthaaccountfor 12%and15%,respectively.Finally,WesternEuroperepresents19%oftheworld’sethyleneproduction capacity,with71%ofproductioncomingfromnaphtha. Regarding feedstocks, naphtha accounts for 52% of globalethyleneproduction,followedbyethanewith 30%.Propane,butaneandgasoilarerelativelyminor sources of ethylene, representing 8%,4%and4% of ethyleneproduction,respectively.
mt 9 8 7 6 5 4 3 2 1 0
World Ethylene Production Capacity Net Additions
From 2003 to 2008, ethylene production capacity increasedby19.2mt/y,ofwhich38%isinNorthEast Asiaand37%intheMiddleEast.Between2008and 2014, global production capacity is expected to 2009 2010 2011 2012 2013 2014 increase by 35.7mt/y (including 2.4mt/y yet to be Source: CMAI announcedand1.3mt/yofshutͲins).However,CMAI expectsproductioncapacitytoberationalised(i.e.,temporarilyshutin)byupto9.7mt/y,basedmainly on demand lagging capacityand leading to effective netadditions of about 26mt/yby endͲ2014.The MiddleEast,inparticular,isexpectedtoraiseethyleneproductioncapacityby16.6mt/ybetween2008 and2014,representing45%oftheworld’sproductioncapacityadditions.Itisworthnoting,moreover, that69%ofexpectednewcapacityintheregionisscheduledtocomeonlinebetween2009and2011.
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Petrochemicals: Feedstock Requirements for the Ethylene Market
(continued)
Elsewhere, Northeast Asia will increase production capacity by 9.7mt/y, representing 26% of total capacity additions. Additions of 5.2mt/y in South East Asia will account for 14% of the global capacity increase.Bycontrast,closureof1.0mt/yofproductioncapacityandrationalisationofupto4.2mt/yshould occurinNorthAmerica,whileinWesternEuropecapacityrationalisationofupto2.0mt/yisexpected. 2008 - 14 Ethylene Capacity Additions West Europe Africa Central 0.4% 3.2% Europe 0.5% FSU 3.2% South America 3.8%
Southeast Asia 14.0% Northeast Asia 26.2%
North America 0.2%
2014 Ethylene Feedstock Share
GasOil 4%
Others 2%
Indian Subcontinent 3.3%
Ethane 33% Naphtha 48%
Middle East 45.0%
Source: CMAI
Source: CMAI,IEA
Butane 4%
Propane 8%
As a result of mainly ethaneͲbased capacity additions in the Middle East, ethane’s share of world ethylene production will increase to 33%, while naphtha’s is expected to fall to 48%. Nonetheless, naphtha will remain the main feedstock for ethylene production. By 2014, Northeast Asia’s ethylene production capacity will be the largest, reaching 23% of the world’s capacity, followed by the Middle Eastwith20%.Meanwhile,theshareinNorthAmericawillfallto21%and,inWesternEurope,to15%. 2.
EthyleneDemandTrends
Worldwideethylenedemandshrankby3.2%to111mt/yin2008,inlinewithslowingglobaleconomic growth.BasedonCMAIdataandourownanalysis,ethylenedemandisforecasttocontractby5.9%in 2009aseconomicgrowthisfurtheraffected.Afterwards,itshouldincreaseby6.0%annuallyonaverage – or about 1.5 times GDP growth – from 2010 to 2014, reaching 138mt/y by endͲ2014. Overall, world ethylene demand is expected to grow at a fairly strong Ethylene Demand rate of 3.7% per year from 2008 to 2014, posing mt significant feedstock growth requirements on the oil 160 refining and gas processing sectors. Under our 140 120 alternative,lowerGDPscenario,worldethylenedemand 100 wouldgrowat2.0%overtheforecastperiod.Intermsof 80 drivers, ethylene demand growth will be mainly 60 40 supported by polyethylene consumption, expected to 20 grow annually by 4.1% and representing 67% of 0 incremental ethylene demand over the period. Ethane willfeed45%ofincrementalethylenedemand,followed Source: CMAI,IEA bynaphtha(31%)andpropane(11%). By 2011, ethylene demand should reach 115.2mt/y under the base GDP scenario, surpassing the 114.6mt/yattainedin2007.However,asnotedearlier,productioncapacityshouldincreaseby17.2% from 2008 to 2011 (i.e. by 22.3mt/y), thus suppressing utilisation rates. A very significant excess in production capacity is expected to linger throughout the forecast period. Taking as a base level an operating rate of 90% (the 2003Ͳ2008 average) and defining excess production capacity as the differencebetweennameplatecapacityat90%andexpecteddemand,excessproductioncapacitycould reach22.3mt/yby2010,equivalentto15%oftotalproductioncapacity.
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Petrochemicals: Feedstock Requirements for the Ethylene Market
(continued)
EthyleneCapacityUtilisation Consequently, operating rates will be very low. Even considering CMAI’s suggested capacity rationalisations (7.5mt/y on average through 2014), operating rates will remain well below 90% until theendoftheperiod. Operating rates should fall to 78% in 2009, increase towards89%in2013andthendecreaseslightlyto88%in 2014 as 2.4mt/y of new capacity materialises. Overall, the average operating level over the forecast period is expectedtostandat83%,wellbelowrecenthistoricallevels.
2008-2014 Share of Incremental Ethylene Demand GasOil, 5%
Others, 2%
GivenpoorshortͲtermprospectsforethylenedemand,there Ethane, Naphtha, 45% iscertainlyroomforfurthercapacityrationalisation/closures 31% and project slippage/ cancellations (typical lead times for ethylene capacity are three to four years once final design and financing are completed). We assume that ethylene Butane, plantswillcontinuetorunaslongastheymakeaprofit,i.e. 5% Propane, as long as revenues cover variable production costs. 11% Source: CMAI,IEA EthyleneproductionbasedonNGLsisexpectedtoretainits cost advantage over ethylene production from naphtha and heavier feedstocks over the forecast period. Therefore,furtherrationalisation/closuresaremostlikelytooccurinEurope,NorthAmericaandAsia. mt 25
Excess Ethylene Production Capacity
Average Ethylene Plant Operating Rate 25%
%
20
20%
15
15%
10
10%
5
5%
0
0%
-5
-5%
100 95 90 85 80 75 70 65 60
Excess capacity (@ 90% op. rate) Excess capacity as a % of nameplate capacity
Source: CMAI,IEA
Source: CMAI,IEA
EventhoughtheMiddleEastwillremaintheregionwiththelowestproductioncosts,operatinglevels areexpectedtoremainsuppressed,asdelaysinthestartͲupofnewethylenederivativecapacityinIran are expected to continue while the rampͲup of new plants takes place. In North America, operating rates should average 81%, as rationalisation of up to 4.2mt/y of production capacity is likely to take place, mainly high production cost facilities. Merger and acquisition (M&A) activity in the region will likelyresultincapacityclosuresinordertoincreaseoperatingratesatmoreefficientplants,improving thereforetheirproductioncostposition. In Western Europe and Northeast Asia, operating rates are expected to average 78% and 92%, respectively,withcapacityrationalisationofupto2.0mt/yand2.8mt/yduetohighproductioncosts andincrementalcompetitionoflowͲcostmaterialcomingfromtheMiddleEast.Finally,SoutheastAsian operatingratesareexpectedtoaverage85%overtheforecastperiod.Closuresinthisregionaremore difficulttoachievesincesomecountries,suchasthePhilippines,VietnamandIndonesia,haveonlyone production facility each, which lowers the probability of shutͲins. Besides, several countries have inherentfeedstockcostadvantages,namelyethaneorrefinerygas,whichagainreducetheprobability ofclosure.
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Latin America OilproductdemandinLatinAmericaisexpectedtoriseby2.1%peryearonaveragebetween2008 and2014,from5.9mb/dto6.7mb/d.LiketheMiddleEast,theregionhasseeminglywithstoodthe worst effects of the global economic downturn, although its largest countries are expected to experiencethisyeareitheramildrecession(BrazilandArgentina)oramuchdeeperone(Venezuela) afterseveralyearsofverystronggrowth.Yettheregionislikelytoremainakeysourceofglobaloil demand growth as its largest economies rebound and are joined by the region’s secondͲtier economies(Colombia,Chile,PeruandEcuador).Thelatterhavealsoexpandedatarapidpaceover thepastdecade,althoughsome,suchasEcuador,havebeenhitbyfallingcommodityprices. m b/d 6.8
Latin America: Oil Demand Growth by Product 2008-2014, kb/d 150
300 250
100
200 50
6.6
Latin America: GDP Sensitivity Higher GDP Low er GDP
6.4
150 100
Gasoline LPG & Naphtha Other
(50)
Distillates Fuel Oil Total (RHS)
50
2008
2009
2010
2011
2012
2013
2014
6.0
(50)
(100)
6.2
5.8 2008
2009
2010
2011
2012
2013
2014
AsinothernonͲOECDareas,oildemandgrowthwillbemostlyconcentratedintransportationfuels. Meanwhile, demand for other product categories will be more countryͲspecific – for example naphtha in Brazil, which by far is the region’s largest petrochemical producer, or gasoil in Chile following decreasing gas imports from Argentina and delays in hydropower projects. In addition, naturalgasispoisedtomakefurtherinroadsintheenergymixincountriessuchasBrazilorPeru. Latin America: Demand Trends, Main Refined Products Trends Post-2009
(mb/d)
Avg. Annual Growth, 2008-2014
0.2
+2.1%
Growing petrochemical activity in Brazil, the largest regional economy, as well as in Argentina, Chile and Colombia (but all from a very small base, with Brazil accounting for 86% of regional naphtha demand)
1.8
+3.9%
Rising as vehicle fleets across the region expand, notably in the largest countries (Brazil, Venezuela, Argentina, Colombia, Chile and Ecuador, in that order); low end-user prices (in Venezuela and possibly Argentina providing further support
0.3
+2.1%
Spurred by increasing business and leisure air travel as income per capita rises, particularly in Brazil, Argentina, Chile, Venezuela, Colombia, Ecuador and Peru
(including biodiesel)
2.1
+1.4%
Fuel Oil
0.7
-0.2%
Product
Naphtha
Volume, 2014
Gasoline (including ethanol)
Jet Fuel/ Kerosene Gasoil
Rebounding demand, driven by economic activity (from freight transportation to power generation) in Brazil, Argentina, Venezuela, Chile, Colombia, Peru and Ecuador; additional support provided by subsidies Declining in most countries, replaced by natural gas or gasoil for power generation (both base and peak); only growing in countries with undeveloped or limited access to gas sources (such as Venezuela)
Heavily subsidised retail prices, notably in Venezuela and Argentina, will also contribute to fuel oil demandgrowth.Nonetheless,eventhoughsubsidiesinVenezuelaareunlikelytobedismantledfor politicalreasons,inArgentinathisislessclearͲcut,withthecurrentgovernmentincreasinglyunder pressure for what is perceived as extensive economic mismanagement. This report assumes that Argentina’sadministeredpriceregimewillbeeventuallybutgraduallydismantled,thuscurbingthe runawaygrowthintransportationfuelsdemandobservedinthepastfewyears.Assuch,amongthe region’s largest countries, both Brazil and Argentina are expected to feature oil demand growth
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D EMAND
commensuratewiththeireconomicexpansion,whileVenezuelawillpostveryhighoilconsumption growth(thecountry’sgasolinepricesareamongthelowestintheworld). Brazil will continue to dominate the region’s demand picture (41.6% of total demand by 2014), followedbyVenezuela(16.6%),Argentina(8.8%),Chile(5.2%)andColombia(4.5%).Itisinteresting to note that although Colombia’s economy is some 50% larger than Chile’s, the latter features greateroilintensity,reflectingitsmuchgreaterdependenceonburningfuelsforpowergeneration. Former Soviet Union OilproductdemandintheFormerSovietUniongrowsby2.1%peryearonaverage,from4.2mb/din 2008to4.7mb/din2014.Thisassumesthattheregion’seconomy–drivenbyRussia,followedmore distantlybyUkraineandKazakhstan–willreboundfromitscurrentlows.Russiahasbeenseverelyhit by the global downturn and the fall in commodity prices. The sharp contraction of the Russian economyhasweighedonregionaloildemand,whichisexpectedtoshrinksignificantlythisyear.Yet theregion’sprospectsremaingood,givenabundanthydrocarbonresourcesandlargeindustrialbase. m b/d 4.8
FSU: Oil Demand Growth by Product 2008-2014, kb/d 80 60 40 20 (20) (40) (60) (80) (100) (120)
Gasoline LPG & Naphtha Other 2008
2009
2010
2011
2012
Distillates Fuel Oil Total (RHS) 2013
2014
200
4.7
150
4.6
100
4.5
50
4.4
-
4.3
(50)
4.2
(100)
4.1
(150)
4.0
(200)
3.9
FSU: GDP Sensitivity Higher GDP Low er GDP
2008
2009
2010
2011
2012
2013
2014
Oildemandshouldthusrebound,spurredbytransportationneeds.Thisshouldbeparticularlymarkedin Russia–accountingfor71.3%ofregionaldemandby2014–whichisstillsettobecomeEurope’slargestcar market,despiteitscurrenteconomicwoes.Thecountrywilldominatedemandinallproductcategories, Former Soviet Union: Demand Trends, Main Refined Products Trends Post-2009
(mb/d)
Avg. Annual Growth, 2008-2014
0.3
+0.9%
Growing Russian petrochemical output (94% of regional naphtha demand), assuming it recovers from its current recession-driven slump
1.3
+2.2%
Growing as vehicle fleets expand on the back of strong economic expansion and rising income per capita, particularly in Russia, the largest regional (and soon European) car market
0.3
+0.5%
Rising air business and leisure air travel and expanding aircraft fleets in Russia and elsewhere
(including biodiesel)
1.1
+1.6%
Increasing as economic activity resumes; strong demand growth in Russia, Ukraine, Kazakhstan, Belarus and Azerbaijan
Fuel Oil
0.5
+3.8%
Rising in order to meet power generation needs in Russia and elsewhere, and also allowing to free natural gas volumes to support Russian exports
Product Naphtha
Volume, 2014
Gasoline (including ethanol)
Jet Fuel/ Kerosene Gasoil
withtherelativeexceptionofgasoildemand,whichisexpectedtorisestronglyinvirtuallyallcountries.Fuel oil demand is also expected to rise, given growing power generation requirements in countries such as Russia and Kazakhstan. Moreover, fuel oil use in Russia is likely to be actively encouraged despite its environmentaleffects,inordertofreeadditionalvolumesofnaturalgasandmeetexportcommitments.
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Summary •
The global oil supply outlook is revised downward sharply from our previous outlook due to project slippage in the wake of markedly lower oil demand, cash‐flow constraints and contract renegotiation. Oil production capacity is projected to rise by 4.0 mb/d by the end of the 2008‐14 outlook period compared with growth of 5.5 mb/d in our last outlook. From a revised base of 89.4 mb/d in 2008, total supply capacity, including non‐OPEC, biofuels, OPEC NGLs and OPEC crude, is expected to reach 93.4 mb/d in 2014. The bulk of the growth will come from OPEC crude capacity additions, augmented by increases in OPEC NGLs and global biofuels.
•
Non‐OPEC supply is hit hardest by the global recession and spending squeeze. Instead of 1.5 mb/d growth for 2007‐13, it is now projected to decline by 0.4 mb/d from 2008‐14. The largest downward revisions are in the Former Soviet Union (FSU) and in North America, the latter largely due to slippage in Canadian oil sands projects. Of a total 2 mb/d of capacity identified as being deferred or cancelled in recent months, a full 1.7 mb/d involve Canadian oil sands projects.
•
A Lower GDP Scenario highlights the risk of protracted lower upstream spending, as currently forecast for 2009, and perhaps beyond. Over and above upstream project slippage, which drives the bulk of the downward revisions, lower short‐term spending could accelerate decline at existing mature fields, potentially curbing another 0.5 mb/d of total non‐OPEC crude production capacity. But a cyclical decline in upstream costs has also been factored in and limits the extent of the downside sensitivity in our lower supply case. World Oil Supply Capacity Growth
mb/d
2.0 1.5 1.0 0.5 0.0 -0.5 -1.0 2009
2010
OPEC Capacity Growth Global Biofuels Growth Total Net Change
2011
2012
2013
2014
OPEC NGLs Growth Non-OPEC Growth (ex Biofuels)
•
OPEC crude production capacity growth in 2008‐14 is down 47% from our previous outlook, with projects either stalled, while members renegotiate development costs, or expansion plans slowed in response to the weaker outlook for oil demand and lower oil revenues. OPEC crude capacity is projected to rise 1.7 mb/d to 35.8 mb/d. Iraq remains the OPEC wild card given constitutional and security issues, and we maintain a cautious view on its supply capacity growth.
•
However, OPEC crude and gas liquid capacity combined is expected to rise by 4.3 mb/d, to 43.2 mb/d, over the 2008‐14 period due to a more than 50% jump in NGL, condensate and other non‐conventional supply. OPEC gas liquids are on track to increase by 2.6 mb/d, to 7.3 mb/d by 2014, with Middle East producers accounting for 90% of the increase. Gas liquids make up 17% of total OPEC supply by 2014 compared with 12% in 2008.
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Non-OPEC Supply Overview Whilethepastyear’splungeintofullͲblownglobaleconomicrecessionhasmademostheadlinesin terms of its impact on oil demand, its effect on nonͲOPEC supply is no less significant. Strikingly, comparedwithlastyear’senvisagedgrowthof1.5mb/dinthemediumterm,totalnonͲOPECsupply isnowprojectedtodeclineby0.4mb/dfrom2008to50.2mb/din2014.Spendingcurbsandproject deferralsunderpintherevision,withnosuggestionthatresourceconstraintshavebecomeabinding impedimenttoexpandingcapacityinthelongerterm.Thatsaid,thereremainconsiderableaboveͲ ground barriers which could continue to keep nonͲOPEC expansion prospects disappointing in an historicalcontext. This changed picture for nonͲOPEC supply stems partly from a lower baseline. Total nonͲOPEC supply in 2009 is now estimated to average 50.3mb/d, a decline of 300kb/d from 2008 and a full 1.3mb/dlowerthanwhenourfirst2009projectionwaspublishedinthe10July2008OMRandwas stillexpectedtogrow.ItisworthnotingthatsupplyoutagesaffectingtheUSGulfofMexico(GoM) andAzerbaijaninpartdrivethisbaselinerevision.Butalsofortheoutlookperiod,theimpactofthe recession,coupledwithlowerdemandexpectationsandofcourse,substantiallyloweroilprices,has prompted significant downward revisions to the nonͲOPEC supply outlook, ranging between 1Ͳ2mb/d per year for most years of the forecast compared with the December 2008 MTOMR Supplement(allMTOMRsupplycomparisonshereafterareinrelationtotheDecemberSupplement). Non-OPEC Oil Production Growth 1996-2002/2002-2008/2008-2014 thousand barrels per day
FSU 3301
2369
Europe 109 -136
-1904
-1432
North America -677 -45
Middle East / Africa
-533
172
Asia 248
-436
253
17
72
Latin America 668
345
847
OPEC NGL 1434 681
Biofuels
2599
1052
90
716
Angola and Ecuador included in OPEC throughout Indonesia included in Asia throughout Regional Totals exclude biofuel growth
Revisionsarenotuniformacrosstheperiodandtheoveralldeclineby2014masksassumedyearͲonͲ yeargrowthin2010and2011.Thisispartlyduetocompletionofaglutofprojectsthathavebeen delayedfrom2008/09;inotherwords,thisistheflipsideofthecointo2009’smuchweakerͲthanͲ expectedperformance.Butthereafter,from2012Ͳ14,nonͲOPECsupplyisexpectedtofalleachyear.
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Despitetheoveralldownwardrevision,growthby2014isstillseenfornaturalgasliquids(NGLs)and nonͲconventionaloilproduction(collectively+1.0mb/d),biofuels(+0.7mb/d)andrefineryprocessing gains(+0.1mb/d).TotalnonͲOPECcrudeoutputwilldeclineby2.1mb/dby2014.However,thisdoes notnecessarilyimply‘peak’productioninconventionalnonͲOPECcrudehasbeenreached.Thisreport assumes that ultimately, nonͲOPEC upstream investments will bear fruit and production will rise – providedthereisadequateaccesstoreservesandasustainedstreamofinvestmentcapital.Moreover, the distinction between conventional and nonͲconventional resources is itself becoming increasingly blurred–‘yesterday’snonͲconventionalproductionistoday’sbaseͲloadsupply’. mb/d 52.00
Total Non-OPEC Supply
51.75 51.50 51.25 51.00 50.75 50.50 50.25 50.00 2008 2009 2010 2011 2012 2013 2014 2009 MTOMR Dec 2008 MTOMR
mb/d 0.6 0.4 0.2 0.0 -0.2 -0.4 -0.6 -0.8 -1.0
Non-OPEC Supply - Yearly Change
2009 2010 2011 Crude Global Biofuels Total
2012 2013 2014 NGLs/Non-Conv Processing Gains
MostofthedownwardrevisionstoprojectednonͲOPECsupplyareduetoprojectslippage,deferral orevenoutrightcancellation,whileothercomponentsstemfromalowerbaselineandtechnicalor other issues at existing assets. However, this report will also put forward a scenario in which expected lower upstream spending in the short term (well documented by regular equity analyst spending reviews) leads to an acceleration of mature field decline rates, cutting the projection by around another 0.5mb/d – on top of the existing downward revision due to project slippage. In termsofchangeoverthe2008Ͳ14period,thisreportnowforeseesadeclineof0.4mb/d,compared with last year’s anticipated growth of 1.5mb/d. The lower GDP scenario with accelerated decline ratesimpliesdeclineby2014wouldbe0.9mb/d. What Has Changed Since Last Year? Recent years have seen decelerating nonͲOPEC supply growth, and in some instances outright decline,duetofieldmaturityinkeyareas,notablywithinsomeofthelargerOECDproducerssuchas theUK,Norway,MexicoandpartsoftheUS.Expectedgrowthinlastyear’sMTOMRalreadyreliedto alargeextentuponincrementalbiofuelsandnonͲconventionaloutput,aswellasNGLs.Butinthe past year, the impact of the economic downturn has been profound. Not only have demand prospects been severely curtailed, but refining economics have worsened and absolute crude oil price levels have fallen – all of which leads to investment being cut in the upstream, at least temporarily.Inaddition,oilcompanieshavelesscashtospend.Forsmallercompanies,thereare severeliquidityissuesandcreditismoredifficulttoobtain. Asaresult,withtheexceptionofthoseprojectsthatwerenearingcompletion,manynewupstream projects have been delayed where possible, sometimes indefinitely. Partly, this is deliberate – projectsthatcanbedeferredorslowedoftenhavebeen–butinpartitisalsoafeatureofpersistent bottlenecksfacingprojectsponsorsintermsofaccesstorawmaterials,labouranddrillingcapacity.
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TheJuly2008EditionoftheMTOMRfoundthat,onaverage,upstreamprojectswerebeingdelayed byaround12months–andthatwasclearlybeforetheeconomiccrisishit.Thatsaid,therearesome signsthatcyclicaltightnessintheabilitytoexpandcapacityisnoweasing.Giventime,thatmaylead toprojectscomingbackontothehorizonaftercontractcostshavebeennegotiateddown. mb/d 0.9 0.6 0.3 0.0 -0.3 -0.6 -0.9
Non-OPEC Supply - Change over 2008-14 Forecast Period
In addition, there were some major technical and weatherͲrelated outages in 2008 that have influencedthesupplybaseline.HurricanesGustavandIkeintheUSGulfofMexicoshutinasmuch as1.2mb/dforawhile–volumeswhichhavestillnotfullyrecoveredandshowupasadownward revision to 2008 and 2009, but contribute to ‘growth’ in 2010. Azerbaijan’s large offshore AzeriͲ ChiragͲGuneshli (ACG) complex, operated by a BPͲled consortium, suffered gas leaks and power problems,aswellastheshutͲdownofitskeyexportroute,theBakuͲTbilisiͲCeyhan(BTC)pipeline,at around the same time, leading this report to sharply curtail previously expected 2008 and 2009 growth(weexpectthesevolumestocomeonstreamagaineventuallyandoutputtorise,butmuch ofthisnowfeedsinto2010orlater). A New Picture Emerges ThenewpicturethatemergesisoneinwhichtotalnonͲOPECsupplydeclinesby0.4mb/dfrom2008 to50.2mb/din2014.Regionally,theonlyareatoshowpronouncedgrowthfrom2008to2014is Latin America, largely on the basis of rising Brazilian crude and fuel ethanol output, but also increasedsupplyfromColombiaandPeru.Theareawithbyfarthemostpronouncedcontractionin the same period is OECD Europe, where the North Sea faces steady and rapid decline from its generallyageingfields. But the regional breakdown masks substantial changes for specific countries or categories. Crude from Canadian oil sands now shows the largest nonͲOPEC increment from 2008Ͳ2014, growing by 790kb/d.Thisisfollowedbyglobalbiofuels,whichareexpectedtoincreaseby720kb/d.Nextare BrazilianandUSGulfofMexicocrudegrowth,with670kb/dand560kb/drespectively.TheCaspian statesAzerbaijanandKazakhstangrowoutputbyaround350kb/dand250kb/drespectively.Onthe declineside,Mexicancrudeleadsthepack(Ͳ750kb/d),followedbyRussia,theUKandNorway(allin the range of Ͳ0.6mb/d in the period to 2014). The single biggest shift in expected fortunes is probablyRussia,whichinlastyear’sMTOMRwasprojectedtoseeadeclineofonly50kb/d,albeitin the period 2008Ͳ13. Canada, Kazakhstan and others have also taken substantial hits in this year’s mediumͲterm outlook. None of this necessarily undermines longerͲterm growth prospects from thesesources,butacknowledgesthatnewoilfromherewilltakelongertobringtomarket.
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Downside Risks to Non-OPEC Supply Due to Lower Investment? Beyondupstreamprojectslippage–intentionalorotherwise–andoutrightprojectcancellation,bothof which are captured in our bottomͲup modelling approach, there remains the question of whether expectedlowerinvestmentwillalsocurboutputatexistingmaturefieldsintheshorterterm.Afeature in the OMR dated 10 April 2009 (Spending Cuts May Worsen Decline) measured the impact of a 20% acceleration in field decline rates in select mature basins (with total production of around 10mb/d), whichresultedinapotentialreductionof110kb/din2009,risingto250kb/din2010. mb/d 51.2 51.0 50.8 50.6 50.4 50.2 50.0 49.8 49.6 49.4
Non-OPEC Supply: 2 Scenarios 0
Potential Impact of Lower Spending 2009-14
-200 -400 -600 -800 High GDP Scenario Low GDP Scenario 2008 2009 2010 2011 2012 2013 2014
2009 2010 2011 2012 North America Europe Former USSR Other Asia Middle East Africa
2013 2014 Pacific Latin America
Ultimately,thatsensitivityexercisehasnotbeenincorporatedintoourbaselineforecast,asearly2009 data are still filtering through and as declining costs may also provide something of an offset. But another,closerlookatthisasaWhatIf?scenarioisnonethelessenlightening.ToaugmentourLower GDP Scenario for demand, this exercise assumes that lower upstream spending for 2009 (widely estimatedtobedownaround20%)willextendinto2010and2011,beforegraduallyincreasingagainin 2012.TheeffecthasbeenextendedtoapplytomaturefieldsinallnonͲOPECcountries,exceptingthe US Gulf of Mexico, China and Russia. The Gulf of Mexico profile is largely driven by new field developments while in China, continued crude oil import dependence and strong state support are expected to ensure that upstream activities remain relatively unaffected, despite the economic downturn. In the case of Russia, this report has in any case already hiked field decline rates in the baselineoutlook. Tomeasurepotentialdownside,a10Ͳ20%accelerationofdeclineratesfromalreadyassumedlevelshas been applied to all other mature fields. This results in lower total nonͲOPEC production of around Ͳ460kb/donaverageinthefiveͲyearperiod,withamaximumimpactofͲ620kb/din2012. Itshouldbeemphasisedthatwhilethesevolumesarenotinconsiderable,theyaredwarfedbyexisting downwardrevisionstotheprojectionduetoprojectslippageandbaselineoutputrevisions.Thismakes sense,asitisassumedthatspendingcutsfirstaffectprojectsstillonthedrawingboardorinplanning, whilecompanieswillattempttomaintainproductionvolumesandrevenueflowatexistingassets. Whatistheevidenceofthisdevelopmenttakingplace?Reporteddatafortheearlymonthsof2009are so far sparse, with newest available aggregated OECD figures from February at the time of writing. Whatisavailablesofarshowslittlesignofaccelerateddecline,butitisperhapstooearlytosay.Clearly, thisreporthasreviseddown2009nonͲOPECsupplyby1.3mb/dsincefirstpublishingaforecastinJuly 2008,butthisisduemoretootherfactors,notablyshutͲinsduetoHurricanesGustavandIke,problems inAzerbaijanandprojectslippage.Ontheotherhand,oildrillingrigcountsaredownsharply.Inthe US,thenumberofrigsdrillingforoilhashalvedsincethebeginningoftheyear.Globalrigcountshave fallenby30%inthesameperiod,tobelowtheirfiveͲyearrange.
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Downside Risks to Non-OPEC Supply Due to Lower Investment?
(continued)
Global Rig Count 4,000
kb/d 1.5
3,500
1.0
Non-OPEC Crude Supply: y-o-y chg Katrina/Rita
3,000
0.5
2,500 0.0 2,000 Source:BakerHughes
-0.5
1,500 Jan
Mar
May
2004-08 Range 2008
Jul
Sep
Nov
2004-08 Avg 2009
-1.0
1998/99 Asiancrisis
Gustav/Ike;nownewslump?
1Q95 1Q97 1Q99 1Q01 1Q03 1Q05 1Q07 1Q09
Historically,themostrelevantcomparableperiodisprobably1998/99,whenpricesfellsharplyasOPEC raisedproductionjustastheAsianeconomiccrisiswasunfolding.Atthesametime,nonͲOPECsupply was on a temporary downͲtrend, albeit recovering thereafter. There are also important potential offsets to any potential negative impact from lower spending in absolute terms. Firstly, there is the issueoffallingcosts.Asoutlinedbelow,thisisdifficulttomeasuresofar,butthereareclearindications that upstream development costs, including steel prices, rig rental, labour etc, are falling – down 9% from3Q08to1Q09,accordingtoIHS/CERA.Coupledwithotherfactors,suchascurrencydevaluation (e.g. the Russian rouble), this may mean that lower spending in absolute terms is partially offset. Nonetheless,curbedinvestmentduringthedowncycle,whileperfectlyrationalineconomicterms,does riskstoringupproblemsforsupplygrowthinthelongertermwhenmarketstightenonceagain.
Is Sluggish Non-OPEC Performance Irreversible? Thisreport’srevisionsresultinaslightdeclineinnonͲOPECoilproductionovertheoutlookperiod, whichmayleadsometoquestionwhetherthenonͲOPECsupplybasecanbemateriallyexpandedin future.TheIEAdoesnotbelievethatgeologicalresourceconstraintswillnecessarilyimpedefuture supplygrowth,butratherthatbarrierstoinvestmenthaveunderminedthepaceatwhichproduction canbeexpandedintheforecastperiodtomeetdemandgrowth. Thenaturalcounterparttothisisthathigherprices,reneweddemandgrowth,freeraccesstoreserves, moretransparentinvestmentconditions,andgreatercompanyspendingonexploration,trainingand newtechnologiesallholdthepotentialtoallowcapacitytoultimatelyexpandagaininfuture. Clearly,intermsofinvestmentintheupstream,muchdependsonthedevelopmentofoilpricesand thepaceofdemandrecovery.Atthetimeofwriting,benchmarkoilfutureswerearoundthe$70/bbl mark, hardly ‘low’ by any historical measure except in comparison with July 2008’s nearͲ$150/bbl high.Somehavecitedrecentpricelevelsasunconducivetonewfielddevelopment.Unfortunately, attemptstopinpointthetruemarginalcostofnewsuppliesarefraughtwithdifficulty.Sowhilethe last couple of years saw estimates of breakͲeven oil sands and ultraͲdeepwater costs of between $80Ͳ100/bbl, an easing in the cyclical (if not structural) pressures that earlier inflated overall costs has likely brought those levels down. Some analysts now envisage oil sands breakͲeven reaching below$50/bblagainby2010.
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New IEA Research Finds 2009 Upstream Spending Down 21% Regularupstreamspendingreviewsfoundearlierthisyearthat2009ExplorationandProduction(E&P) investmentwouldbesubstantiallylowerthanin2008.InareportpresentedattheG8EnergyMinisters’ Meeting in late May*, the IEA found that energy investment worldwide will plunge due to the global financialcrisisandrecession,whichhascurbeddemandforenergy,crimpedcreditavailabilityandseen oilpricestumblefrom2008’smidͲyearhighofalmost$150/bbl. Intheoilandgassectorspecifically,theIEApaperfoundthatglobalinvestmentbudgetsfor2009areoff 14%from2008andthatupstreaminvestmentbudgetsfor2009havebeencutbyaround21%fromayear earlier – a reduction of almost $100 billion. $ bn Global Upstream Capital BetweenOctober2008andendͲApril2009,over20 Ͳ20.6% Expenditure planned largeͲscale upstream oil and gas projects, 500 valued at a total of more than $170 billion and 400 involvingaround2mb/dofoilproductioncapacity (and 1bcf/d of gas capacity), were deferred 300 indefinitely or cancelled. A further 35 projects, 200 Ͳ36.7% involving4.2mb/dofoilcapacity(and2.3bcf/dof Ͳ7.5% gas),weredelayedbyatleast18months.Oilsands Ͳ0.1% 100 projects in Canada account for the bulk of the postponedoilcapacity. 0 Total NOCs
Supermajors
Other IOCs
Total
Thedropinupstreamspendingismostpronounced 2008 2009 in the regions with the highest development costs andwheretheindustryisdominatedbysmallplayersandsmallprojects.Forthesereasons,investmentin nonͲOPEC countries is expected to drop the most. In addition, cuts in spending on existing fields risk pushingupdeclinerates(seeDownsideRiskstoNonͲOPECSupplyDuetoLowerInvestment?). *TheImpactoftheFinancialandEconomicCrisisonGlobalEnergyInvestment:(http://www.iea.org/Textbase/Papers/2009/G8_investment_ExecSum.pdf)
Producer Costs (Jan 2004 = 100)
Index (2000=100)
IHS/CERA Upstream Capital Costs Index (UCCI) 240 Q3 2008:
150
300
140
260
130
220
120
180
160
110
140
140
100
220
230
200
Q1 2009:
180
210
Source:IHS/CERA
80
60
90
100 2000
100 Source:USBureauofLaborStatistics
120
2002
2004
2006
2008
2010
2004 2005 2006 2007 2008 2009 Machinery & Equipment Support Activities Drilling - RHS
Itisdifficulttopreciselyelaborateontheextentofcostreductionstodate.TheIHS/CERAUpstream CapitalCostsIndex(UCCI)measuresa9%fallin1Q09from3Q08andseesthisaslikelytofallfurther. Meanwhile, of three significant indicators published by the US Bureau of Labor Statistics (BLS), drillingandsupportactivities(effectivelywages)alsoshowadistinctdeclinesincereachingapeakin November last year, dipping by 12.5% and 8% respectively by April (costs for machinery and
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equipment so far remain more or less unchanged in the same period). Oil companies are widely reported to have been renegotiating service contracts, notably the super majors (BP said it was pushingfora40%reduction),furthercontributingtoprojectslippage.Anotherfactorsupportiveof more potential upstream investment is that a lengthy period of low(er) oil prices may ultimately bring changes to the fiscal, regulatory and general investment environment in many nonͲOPEC countries,notablyincountriesnowfacingthetwinchallengeoflowerpricesandfallingproduction. Conversely,weretheglobalrecessiontobeprotractedandwereoilpricestofallagainandremain low, investment too would likely fall further. Indeed, arguably below a threshold of $30Ͳ35/bbl, therewouldlikelybeshutͲinsathighͲcostmarginalwellssuchassmallͲscalestripperwellsintheUS (which nonetheless aggregate up to 1mb/d of total US output). At the time of writing, however, particularly since the recent recovery to around $70/bbl (from midͲFebruary’s low of around $35/bbl),thereisnoclearevidenceofthishappeningyet. Revisions to December 2008 Outlook and Regional Breakdown In terms of magnitude of downward revisions since the 2008 Edition of the MTOMR, the FSU and Canadianoilproductionhavewithoutdoubttakenthebiggesthits.Inbothcases,wehadassumed growthofaround1mb/doverthe2007Ͳ13period,whichcomparesto0.1mb/dand0.5mb/dinthe currentprojection.IntheFSU,crude productioninRussia,AzerbaijanandKazakhstanwasineach casehitbyprojectslippage,includingdelaystosomeofthemegaprojectssuchasKashagan,Vankor, SakhalinandACGexpansions.InCanada,slippageatoilsandsandbitumenͲrelatedprojectshascut theprojectionsubstantially.
mb/d
Non-OPEC Supply - Regional Change
kb/d
Selected Non-OPEC Supply Revisions
200
0.75 0.50
0
0.25
-200
0.00
-400
-0.25
-600 -800
-0.50
2009
-0.75 2009
2010
2011
2012
2013
Total OECD
Former USSR
China
Other Asia
Latin America
Other
2014
2010
Russia Global Biofuels Kazakhstan Brazil ex ethanol
2011
2012
2013
Canada Azerbaijan Mexico US ex ethanol
AtablewithdetailsofmajorprojectcapacityandrevisedstartͲupdatesislistedintheTablessection.
North America North America is one of the areas hardest hit by the impact of the global recession and a reͲevaluation of projects. Compared with assumed growth of 630kb/d for 2007Ͳ13 in last year’s MTOMR, this report now projects production will remain flat in the 2008Ͳ14 period, due to sharp downward revisions to US and Canadian production. In the US, it is a combination of lower fuel ethanol growth and a stronger contraction in onshore LowerͲ48 crude production, which has changedthepicture.Meanwhile,offshoreproductionintheGulfofMexicoisstillexpectedtogrow byaround550kb/d.TotalUSoilproductionisexpectedtogrow175kb/dto7.7mb/din2014.
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mb/d 16 14 12 10 8 6 4 2 0
North America Oil Production
mb/d 0.40
North America Supply - Annual Changes
0.20 0.00 -0.20 -0.40
2008 2009 2010 2011 2012 2013 2014 US - Total Crude US - NGL Canada - Conv Crude Canada - Oil Sands Mexico - Crude Other
2009 2010 2011 US - Total Crude Canada - Conv Crude Mexico - Crude
2012 2013 2014 US - NGL Canada - Oil Sands Other
Canadian Oil Sands – Down But Not Out OilfromCanadianoilsands–longseenasnonͲOPEC’sfallͲbackplanwhenother,matureassetsdecline – appears to be the sector hardest hit by the recession and the sharp fall in oil prices. Of a total of 2mb/dofoilproductioncapacityidentifiedbytheIEAasbeingdeferredorcancelledinrecentmonths, afull1.7mb/dinvolveCanadianoilsandsprojects.Asaresult,projectedtotaloilsandsoutputgrowth over the 2008Ͳ14 period has been slashed by 40% and output is now set to increase by 0.8mb/d comparedwiththelastreport’santicipatedincremental1.3mb/d.Whilethisisstillimpressivegrowth– indeedcomparableonlywithnonͲOPECincreasesinglobalbiofuels,BrazilianorUSGulfofMexicocrude –therevisionisnonethelesssubstantial.Butdespitethedownwardadjustment,oilsandsgrowthwill continuetooffsetanetdeclineinCanadianconventionalcrudeproductionof275kb/din2008Ͳ14. mb/d 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0
Canada Oil Production
2000 2002 2004 2006 2008 2010 2012 2014 Crude (w/o bitumen) NGLs Other Oil Sands Mined Oil Sands
kb/d
Canada Oil Supply Revisions 0
-50 -100 -150 -200 -250 -300 -350 2009 2010 Crude (w/o bitumen) Other Oil Sands
2011 2012 2013 NGLs Mined Oil Sands
CapitalandenergyͲintensivetoprocessandexport,theoilsandsdevelopmentshaveinvolvedsubstantiallargeͲ scaleexportinfrastructure,largelytosendvolumessouthtocomplexrefiningcapacityintheUS.Togetherwith ultraͲdeepwatercrude,theoilsandshavecometobeabyͲwordforthe‘marginalbarrel’ofnonͲOPECsupply Ͳwhichispreciselywhyexpansionprojectswerehitsohardwhenoilpricesfellsharply.However,thisreport remainscautiouslyoptimistic.Evenwithapotentialforsustainedlowerprices,andpossibleenvironmental considerations,theoilsandsbenefitfromthesheersizeoftheresourcebase(estimatedatover170billion barrelsofrecoverablereserves),thebenigninvestmentenvironmentandtheproximityofUSmarkets. Beyond a wider economic recovery, the key factor remains oil prices and correspondingly, the cost of developingnewoilsandsproduction.Crucially,costsarecomingdownandwereoilpricestoremainat current levels, investment will likely pick up again. The Canadian Association of Petroleum Producers (CAPP)andtheCanadianEnergyResearchInstitute(CERI),despitehavingbothreviseddowntheirgrowth forecastssincelastsummer,stillexpectoilsandsproductionat1.8Ͳ2.2mb/dandaround1.9Ͳ2.9mb/dby 2014 and 2015 respectively, similar to our own prognosis of total syncrude and bitumen production of 2mb/d by 2014. All told, the oil sands are instrumental in boosting total Canadian oil supply from 3.2mb/din2008to3.8mb/din2014.
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InMexico,thesteepdeclineseeninrecentyearsisexpectedtocontinue,albeitataslightlyslower pace.Comparedwithlastreport’sassumed900kb/ddeclineduring2007Ͳ13,wenowexpectadrop of740kb/dby2014to2.43mb/d.Essentially,wehaveassumedthatCantarell,Mexico’slargestoil fieldanduntilrecentlythemainstayofitscrudeproduction,willcontinuetoseestrongdeclineratesin therangeof25Ͳ30%.Meanwhile,wehavebroughtforwardtherampͲupofoutputintheChicontepec region, based on higherͲthanͲexpected recent production trends. Overall, despite higher expected upstreamspendingandattemptstochangelegislationwhichishopedwillattractoutsidecompaniesto contributetotheexpansionofMexicanultraͲdeepwateroilproduction,thereremainsalargequestion markoverwhetherthesteepdeclineofrecentyearscanbereversed. OECD Europe ThepictureforOECDEuropehasnotchangedmuchsincethe2008EditionoftheMTOMR–OECD Europeisstillexpectedtoshowthestrongestdeclineofanyregion.Itisprojectedtofall1.38mb/d or 30% by 2014, to 3.41mb/d. The UK and Norway will see total supply drop by 590kb/d and 560kb/d,to980kb/dand1.91mb/drespectively.FortheUK,thisisaslightlylessbleakpicturethan thatpaintedinthelastoutlook,withsomeadditionalfieldstartͲupsatthetailͲendoftheoutlook.In Norway,revisionswereminorsincethelastreport.Mostproducingareasareexpectedtocontinue theirsteepdecline,thoughwenowseegrowthof50kb/dintheHaltenbankenarea,comparedwith fallingoutputinthelastMTOMR.Elsewhere,crudeproductioninDenmarkwillfallby100kb/d,by 40kb/dinItaly,andby10kb/deachinFranceandGermany. mb/d 5.0
OECD Europe Oil Production
mb/d
OECD Europe Supply - Annual Changes
0.00 4.0
-0.10
3.0
-0.20
2.0
-0.30
1.0
-0.40
0.0
-0.50
2008 2009 2010 2011 2012 2013 2014 UK Norway Other Europe Crude Other Europe NGL Other Europe Non-Conv. Other
2009 2010 2011 2012 2013 2014 UK Norway Other Europe Crude Other Europe NGL Other Europe Non-Conv. Other
OECD Pacific AnexpectedsharperdeclineinAustralianoilproductionwidenstheoveralldropintheOECDPacific slightly.TotalOECDPacificproductionisnowexpectedtodeclineby100kb/dto550kb/dby2014. Australiaactuallyseesanincreaseto600kb/doutputin2010,asseveralsmallnewfieldsrampupto mb/d 0.8
OECD Pacific Oil Production
mb/d 0.08 0.06 0.04 0.02 0.00 -0.02 -0.04 -0.06 -0.08 -0.10
0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0 2008
2009
Australia
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2010
2011
2012
New Zealand
2013
2014
Other
2009 Australia
2010
2011
2012
New Zealand
2013
2014 Other
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peakcapacity,beforedecliningagaintoaround450kb/dby2014(onanetbasis,productiondeclines 90kb/din2008Ͳ14).NewZealandoutputseesasimilarpattern,risingto90kb/din2010duetonew offshorefields,butthendecliningagaintoaround50kb/dby2014. Former Soviet Union (FSU) TheFSUseesthesharpestdownwardrevisionsinthisreport’sprojection,partlyduetoitssizeable output. Adjustments were largely in Russia, but output in Azerbaijan and Kazakhstan was also reviseddownonprojectslippage.TotalFSUoilsupplyisexpectedtogrowby100kb/dto12.9mb/d in2014,comparedwithlastreport’sassumed950kb/dgrowthto13.7mb/din2007Ͳ13. Total oil production in Russia is now expected to decline by 550kb/d by 2014, compared with a 50kb/ddipasforeseeninthelastreport.MostmajorfieldstartͲupshavebeendelayed,duetoa stillͲrestrictive foreign investment climate and Russian oil companies facing high levels of debt. DelaystonewoilfieldprojectsincludePrirazlomnoye,Kuyumbinskoye,VladimirFilanovsky,Sakhalin increments ArkutunͲDaginskoy and Odoptu and the huge RosneftͲcontrolled Vankor field (which is nowduetostartproductioninthemiddleofthisyear). mb/d 0.50 0.40 0.30 0.20 0.10 0.00 -0.10 -0.20 -0.30 -0.40
FSU Supply - Annual Changes
mb/d 10.2
Russia Total Oil Production
10.0 9.8 9.6 9.4 9.2 9.0
2009 2010 2011 2012 Russia - Crude Russia - NGL
2013 2014 Azerbaijan
Kazakhstan
Other
Turkmenistan
8.8 2008 2009 2010 2011 2012 2013 2014
Russiahasbeenhitharderthanmostbytheeconomicrecessionandloweroilprices,andalackof investment plus a relatively mature base has seen total output decline in 2008 (a decline is also envisaged for 2009). Due to a lack of fully disaggregated fieldͲspecific production data, modelling Russia’s oil output depends on assumptions of startͲups and crucially, aggregated decline rates at existingassets.BesidestheaboveͲmentionedprojectslippage,thisreporthashikedRussiandecline ratesformaturefieldsontheassumptionthatinvestmentwillremainconstrained. The recent row between ExxonMobil and the Russian government concerning the further development of the huge Sakhalin 1 productionͲsharing agreement (PSA) in Russia’s Far East is instructive in this case. Disagreement over the project’s budget for 2008 and 2009 had led ExxonMobil to suspend plans for further development of the complex, including the Odoptu and ArkutunͲDaginskoy fields with a combined 300kb/d crude production capacity. Eventually the budgetwasagreedinAprilthisyear,butfieldstartͲupdatesforbothincrementsweredelayedbyat leastayear.Moreover,therowledtoallegationsfromsomequartersthattheRussiangovernment’s aim was ultimately to take on a larger share of the PSA, or even squeeze out Exxon – somewhat similartoSakhalin2,whereShellandJapan’sMitsuiandMitsubishiwereforcedtorelinquishpartsof theirshareinfavourofGazprominlate2006.
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FSU Exporters Branching Out FSUoilexportersplantoadd6.1mb/dofnewpipelinecapacityfeedingtheFarEast,Baltic,BlackSea andtheMediterraneanby2014.Projectednetgrowthofonly100kb/dofnewcrudeproductioninthe FSUcountriesinthisreport’stimehorizonof2008Ͳ2014mightsuggestthatsomepipelineswillremain unused.However,acloserlookuncoversdifferentincentivesbehindcertainpipelineprojects.Keyaims are arguably geographical diversification in a quest for new markets, the replacement of existing transport routes (pipeline, rail or waterway) as well as to accommodate future rising output. The 6.1mb/dofnewcapacityisnotentirelyincrementaltherefore.
F S U E x p o r t R o u t e s Primorsk
RUSSIA
BPS
ESPO Samara
BPS 2
Taishet D r u z h b a P i p e l in e C P C P i p e li n e
Atyrau
Novorossiysk Samsun B u r g a s -A l e xa n d r o u p o l i s P i p e li n e Ceyhan
B T C P i p e li n e
Skovorodino Daqing
K AZ AKHSTAN
Atasu
Kenkiyak K C T S K a z a k h s t a n - Ch i n a P i p e l in e
Kozmino
CHINA
Source:IEA
Russia is following a strategic path of geographical diversification to decrease the number of transit countriesandminimisetheriskofinterruptionsinexportflows.Atthesametime,itistryingtoredirect exports towards more lucrative markets. With production expected to decline by 550kb/d over the 2008Ͳ2014period,twoimportantprojectsofthestatepipelinemonopolyTransneft–theBalticPipeline System2 (BPSͲ2) and EastSiberianͲPacificOcean (ESPO)pipeline,could initially becompeting for oil. TheBPSͲ2wasproposedafteranothertariffdisputebetweenRussiaandBelarusin2007leftEuropean countries short of oil supplies during the peak winter period. It would bypass Belarus, and filling the initial0.6mb/dphaseofBPSͲ2withcrudeinthefirstquarterof2012couldresultinlowerflowsthrough thenorthernbranchoftheDruzhbapipelinetoEurope.However,withcrudefromWestSiberianfields potentially being diverted to the ESPO, it is unlikely that there will be enough crude to fill also the DruzhbaorbotharmsoftheBPS.Ultimately,newfieldsinEastSiberiaaretobetheprimarysourceof crude supply for the ESPO, the first stage of which, from Taishet to Skovorodino should be commissionedinDecember2009.TheoilwillbethentransportedbyrailtotheKozminoterminalon the Pacific coast until the second stage of the project is built, likely by 2014. A spur line from SkovorodinotoDaqing,ChinashouldbebuiltbyendͲ2010,withcrudedeliveriesstartingin2011. Azerbaijanhasalreadyinvestedheavilyinoilexportinfrastructure,liketheBakuͲSupsaandBakuͲTbilisiͲ Ceyhan(BTC)pipelines,totransportgrowingcrudeoutputtowesternmarkets.TheBTCwasrecently expandedtotakeupto1.2mb/dofoildirectlytotheMediterranean.Itisfilledprimarilywithcrude from the AzeriͲChiragͲGuneshli (ACG) offshore complex, but since October 2008 also transports small volumesofKazakhstaniTengizcrude.Azeriproductionisestimatedtogrowby360kb/dby2014and thereareplansforafurtherexpansionoftheBTCto1.6mb/dby2012.
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FSU Exporters Branching Out
(continued)
Kazakhstan is committed to the development of multiple oil export routes to meet future crude productiongrowthof270kb/dby2014aswellastoincreaseexportflexibility.TheKazakhstanͲChina oilpipeline,builtinthreestageswiththefinalmiddlesectionfromKenkiyaktoKumkoltobecompleted in2010,couldtakeupto400kb/dofcrudefurthereasttoChina.BoththeKazakhstanͲChinapipeline and ESPO offer direct pipeline routes to endͲuser markets and the expected growth of the Chinese economyvirtuallyguaranteesdemandforRussianandKazakhstanioil.However,theformidablelength of the pipelines coupled with challenging weather conditions in difficult terrain increase the cost of repairs,maintenanceandtransit. Additional pipeline projects, such as the new Kazakhstan Caspian Transport System (KCTS), and expansions of the AtyrauͲSamara and the Caspian Pipeline Consortium (CPC) pipelines, are being considered to accommodate strong production growth, notably from the Kashagan field, after 2014. TheKCTS,consistingofaplanned460kb/dpipelinefromEskenetoanoilterminalinKurykandatanker fleettotransporttheoilacrosstheCaspiantoBakuandthenprimarilytotheBTCpipeline,isexpected tobecomeoperationalin2014.TheCPCexpansiontodoubleitscurrentcapacityhadbeenlongblocked by disagreement between Russia, a key CPC shareholder, and other partners over issues concerning, amongotherthings,transitfeesandloanrepaymentterms.Theexpansionofthelineisnowscheduled inthreestagesandthepipeline’scapacityshouldreach1.4mb/dbymidͲ2014;howeverthedatecould slipifafinalinvestmentdecisionisdeferredbeyondmidͲ2010.
PlannedFSUPipelineProjects
Region
Project
From
To
Baltic FarEast FarEast FarEast FarEast BlackSea Caspian Mediterranean Mediterranean Mediterranean
BPSͲ2 ESPOͲ1stPhase ESPOͲ2ndPhase ESPOͲspur KazakhstanͲChina CPCexpansion KCTS BTCexpansion BurgasͲAlexandroupolis TransͲAnatolian
Unecha(RUS) UstͲLuga(RUS) Taishet(RUS) Skovorodino(RUS) Skovorodino(RUS) Kozmino(RUS) Skovorodino(RUS) Daqing(CHN) Atyrau(KAZ) Alashankou(CHN) Tengiz(KAZ) Novorossyisk(RUS) Eskene(KAZ) Baku(AZE) Baku(AZE) Ceyhan(TUR) Burgas(BUL) Alexandroupolis(GRE) Samsun(TUR) Ceyhan(TUR)
NewCapacity (mb/d) 0.60 0.60 1.00 0.30 0.40 0.67 0.46 0.40 0.70 1.00
EndͲ Year 2012 2009 2014 2010 2010 2013 2014 2012 2012 2012
Length (km) 900 2757 1943 1030 2163 1510 750 1769 287 555
Turkey’s Bosporus straits act as a natural chokepoint for Russian and Caspian crude oil accessing western markets. Daily oil flow through this narrow 30 km waterway is 3mb/d with about 5,500 oil tankersuptoSuezmaxsizetransitingbetweentheBlackSeaandtheMediterraneaneachyear.Winter weather conditions often cause delays and the Turkish authorities also frequently slow down tanker movementsduetoenvironmentalconcerns.Giventhelogisticalconstraints,severalprojectsbypassing theBosporusareunderconsiderationbutimplementationofmostofthemremainsuncertain.Turkey itself has proposed construction of the TransͲAnatolian Pipeline connecting Samsun on the Black Sea with Ceyhan on theMediterraneancoast. This couldbe laid in part of the same corridor as the BTC, though the line would not become operational before the proposed BurgasͲAlexandroupolis pipeline. This route, whose construction could start in 2010, is preferred by Russia and its initial throughput is slatedat0.7mb/dfrom2012. Diversificationandflexibilityofexportrouteshasbecomeacriticalissueforproducersandconsumers seekingsecure,uninterruptedsupplies.Kazakhstan’sandAzerbaijan’spipelineprojectsarenecessaryto absorb future production growth. However, in Russia there is the risk of shortͲterm excess capacity, giventhecurrentexpectationforRussiansupplycontractionin2008Ͳ2014,andthishastobebalanced againstincreasedsecurityofsupply.
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Suchactions,plusstillrelativelyhightaxationlevelsoncrudeproductionandexports,arelikelyfor nowtoimpedetheRussianoilindustryfromrampingupproductionanyfurther.Ontheotherhand, the Russian government is aware of these challenges and is mooting tax breaks for new oil fields, especially for East Siberian fields destined to fill the halfͲcompleted Eastern SiberiaͲPacific Ocean (ESPO)pipeline,duetobringRussiancrudetoNortheastAsia. TheproductionoutlookforAzerbaijanandKazakhstanhasbeentrimmed,butbotharestillexpected toshowstronggrowthof360kb/dand270kb/drespectivelytoreach1.27mb/dand1.68mb/dby 2014.BehindCanadianoilsands,globalbiofuels,BrazilianandUSGulfofMexicocrude,theCaspian countriesthusremaintwoofthemostimportantcontributorsofnewcrudeoilandgasliquids.In Azerbaijan, the ongoing problems at the ACG complex due to gas leaks and power issues, that emerged in autumn 2008, have delayed rampͲup of new incremental production. This report assumesthatallproblemswillhavebeenresolvedbyendͲ2009andthatproductionwillsteadilyrise thereafter. In Kazakhstan, another 100kb/d of capacity each should be added to the Tengiz and KarachaganakprojectsbyendͲ2010,followedbyafurtherexpansionofTengizin2011.Followinga renegotiatedoperatingagreementbetweentheconsortiumpartners,itisnowexpectedthatinitial production from the huge Kashagan field will commence in late 2013, after which the consortium wouldbefinedapenalty.Developmentsintheregionareofcourseinextricablylinkedtotheparallel developmentofdiversifiedexportroutes(seeFSUExporters:BranchingOut). China ProjectedoilproductiongrowthinChinahasbeenapproximatelyhalvedto125kb/d,asopposedto thelastreport’s235kb/d.ChinaisoneofthefewestablishednonͲOPECproducerstoseecontinued growth, though here too, project delays and decline rates, especially at the larger, onshore fields suchasDaqingandShengliarenotunsubstantial.Mostnetgrowthistocomefromnew,offshore fieldsinBohaiBay,whereChineseandothercompanieshavebeensuccessfulatbringingonstream key new fields. While currently around 680kb/d, total offshore production is expected to rise to around 980kb/d, or 25% of total Chinese oil output. It is these incremental volumes that are offsettingdeclineinmatureonshorefields,thoughevennewBohaiBayproductiondoesnotachieve this in the latter half of the outlook period. Total Chinese oil supply is forecast to increase by 125kb/dto3.92mb/dby2014. Other Asia TotalOtherAsiaoilproductionisnowexpectedtodipbyaslender55kb/dby2014,comparedwith thelastreport’sprojectionofa50kb/driseto2013.TheproductionoutlookinMalaysia,Indiaand Indonesia has each been revised down by around 50Ͳ60kb/d on project delays. Malaysia is now expectedtoseeitstotaloilproductiondeclineby70kb/dby2014andIndiabyaround10kb/d.In Indonesia, now included in nonͲOPEC, crude production is forecast to fall by 70kb/d, while NGL outputshouldrisebyalmostthesameamount,asmajorgasprojectscomeonstream.Meanwhile, Vietnam, with a slate of offshore projects in the pipeline, should see its total output rise around 70kb/dto2014.Thailandtoo,isexpectedtosee incremental outputofaround30kb/d.Regional expansionsincludesubstantialamountsofcondensateandNGL.
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mb/d 4.0
Other Asia (ex China) Oil Production
mb/d
Other Asia (ex China) Supply Annual Changes
0.15 3.0
0.10 0.05
2.0
0.00 -0.05
1.0
-0.10 0.0
-0.15
2008 2009 2010 Indonesia-Crude Malaysia Vietnam
2011
2012 2013 India Thailand Other
2014
2009 2010 2011 Indonesia-Crude Malaysia Vietnam
2012 2013 India Thailand Other
2014
Latin America In Latin America, the picture is not much changed since the last MTOMR. The single largest contributor to growth remains Brazil, where crude production is expected to grow by 670kb/d to 2.48mb/d by 2014. This growth has been revised downward by around 70kb/d from the last projection,butstillremainsthesinglelargestsourceofincrementalconventionalcrudeoilsupplyin our outlook. Almost all of this growth in turn stems from offshore crude production in the deepwaterCamposandSantosbasins.New,muchͲfetedcrudefromthepreͲsaltlayersinadjacent but deeper waters,whererecent discoverieshaveproventheexistenceoflargereserves,willonly feedintothisforecastinthelatteryears.TheexceptionistheTupifield,whereapilotprojectisdue topumpsmallvolumesfromthissummer.Productionthereisexpectedtorisetoaround100kb/d fromtheendof2010andfrom2013,productionvolumeswillsteadilybeincreased.InBraziltoo, fuel ethanol production is expected to grow by 350kb/d by 2014, providing the secondͲlargest sourceofregionalgrowth. mb/d 6.0
Non-OPEC Latin America Oil Production
mb/d 0.40
5.0
Non-OPEC Latin America Supply Annual Changes
0.30
4.0
0.20
3.0 0.10
2.0
0.00
1.0 0.0 2008
-0.10 2009
2010
2011
2012
2013
2014
Brazil-Crude
Brazil-Alcohol
Argentina
Colombia
Peru
Other
2009 Brazil-Crude Colombia
2010
2011
2012
Brazil-Alcohol Peru
2013
2014
Argentina Other
Colombia remains one of the other important sources of incremental oil production, due to increasedoutputfromtheRubialesandCastillaheavycrudeoilfields.TotalColombianoilsupplyis projectedtogrowby120kb/dto710kb/dby2014.Peruisexpectedtoseeincrementalproduction of100kb/d,thusalmostdoublingitsoutputto230kb/dby2014.Incrementaloutputislargelyfrom Perenco’sBlock67intheAmazon.Argentinaisexpectedtoseeproductionremainrelativelyflatat around 750kb/d. Total Latin American oil production is forecast to increase by 1.2mb/d to 5.32mb/dby2014–byfarthestrongestregionalgrowth,withBrazilgenerating60%ofthisincrease.
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Middle East Due to downward revisions, notably to Syria, but also Oman and Bahrain, total nonͲOPEC Middle Easternsupplyisexpectedtofallby300kb/dto1.33mb/d,comparedwiththelastreport’sassumed 180kb/ddecline.InSyria,intheabsenceofsignificantnewfieldstartͲupsexpectedincomingyears, maturefielddeclineissettocausea175kb/dfallto225kb/dby2014.OilproductioninYemenis mb/d
Non-OPEC Middle East Oil Production
Non-OPEC Middle East Supply Annual Changes
mb/d
2.0
0.04 0.02
1.5
0.00 1.0
-0.02 -0.04
0.5
-0.06 0.0
-0.08
2008
2009
Oman Bahrain
2010
2011 Syria Jordan
2012
2013
2014
Yemen Other
2009 2010 Oman Bahrain
2011 2012 Syria Jordan
2013 2014 Yemen Other
projected to fall 60kb/d to 250kb/d. In Bahrain, oil output will fall 45kb/d to 145kb/d. The key Bahraini field, Awali, is expected to see capacity double to around 70kb/d due to an extensive EnhancedOilRecovery(EOR)project,butthiswillonlycomeonstreamin2015,thusfallingoutside our forecast period. The balance of Bahrain’s output derives from its 50% share in the Abu Safah fieldoffshoreSaudiArabia.Lastly,oilproductioninOmanisprojectedtodip20kb/dto710kb/dby 2014,asaraftofEORprojectsonlyjustoffsetdecliningoutputatmaturebaseloadfields. Africa Incontrasttogrowthof65kb/dassumedinthelastMTOMR,totalnonͲOPECAfricanproductionis now expected to decline by 140kb/d to 2.41mb/d by 2014. In Egypt, decline over the 2008Ͳ14 period has been widened by 110kb/d to 170kb/d, in other words shrinking to 480kb/d in 2014, from650kb/din2008.ProductionprospectsinCongowerereviseddowntoo,byaround50kb/d, and are now set to remain flat at 250kb/d over the forecast period. Oil production in Sudan was also revised down, by around 40kb/d, and is now projected to decline by 30kb/d to 450kb/d in 2014.Meanwhile,Ghanawillemergeasanewgrowthcentre,wherefirstoilfromtheJubileefieldis expected in 2010 and will ultimately rise to around 120kb/d after an expansion project, set to commencein2012.AgroupofnewfieldswillsignificantlyboostoilproductioninMauritania,now forecast to grow by 70kb/d to 85kb/d in 2014, despite disappointing performance so far from existing assets. Lastly, this outlook has added Uganda, ultimately set to become a small producer whenagroupoffieldsintheAlbertBasincomeonstream,startingin2011. mb/d 3.0
Non-OPEC Africa Oil Production
0.10
2.0
0.05
1.5
0.00
1.0
-0.05
0.5
-0.10 -0.15
0.0 2008 2009 Egypt Congo Ghana
Non-OPEC Africa Supply - Annual Changes
0.15
2.5
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2010
2011
2012 2013 2014 Sudan Equatorial Guinea Other
2009 Egypt Congo Ghana
2010
2011
2012 2013 2014 Sudan Equatorial Guinea Other
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The Evolution of Crude Oil Production by Quality The global feedstock available to refiners is getting lighter and sweeter, in large part due to rising capacityofcondensateproduction,latestsupplyqualityprojectionsfortheyears2008Ͳ2014show.The outlookisbasedexclusivelyoncrudeoilandgascondensate. Weprojectatrendoflightercrudeoilsuntil2012withaweightedaverageAPIrisingfrom33°to33.6°, stabilisingthereuntil2014.WhileAPIgravitywillriseinallregionsfrom2008to2012,itwillfallslightly formostregionsfrom2012to2014.Africa’sprojectedcrudemixgetslighterthroughouttheperiod, partlyduetotheAkpocondensatefieldinNigeria.Crudesfromallproducingregions,excepttheFSU, arelighterinthisyear’sprojectionscomparedwithlastyear’soutlooks,notablyinNorthAmerica. API, degrees
Global Crude Quality 2008-2014
Sulphur (%) 1.25
33.8 33.6 33.4 33.2 33.0 32.8 32.6 32.4 32.2
1.20 1.15 1.10 1.05 1.00
API, degrees
Sulphur (%)
(excluding condensate)
1.25
33.8 33.6 33.4 33.2 33.0 32.8 32.6 32.4 32.2
2008 2009 2010 2011 2012 2013 2014 API
Global Crude Quality 2008-2014
1.20 1.15 1.10 1.05 1.00 2008 2009 2010 2011 2012 2013 2014 API Sulphur (RHS)
Sulphur (RHS)
Until2011crudesuppliesshouldsweetenfromanaveragesulphurcontentof1.16%in2008to1.06%,a trendsharedbypracticallyallregions,butmostmarkedlyintheMiddleEastandFSU.Averagesulphur content then rises to 1.11%, a trend that also was evident in last year’s projections. The strongest driversforsourercrudefrom2012areNorthAmericaandtheMiddleEast,whilesweetercrudesfrom AfricaandFSUpartlyoffsetthetrend. Middle East production ‘sweetens’ in the first part of the period due to rising condensate production andincreasedcapacityoflightandextralightcrudes.NearͲtermgainslargelyreflectnewSaudioutput oflightcrudefromKhurais,NuayimandShaybahfieldsasproductionbuildsupthisyearandnextaswell asacutbackinheavier,sourergradesduetolowerOPECtargets.Thistrendthenshiftsasnewheavy andsouroilproductionfromtheManifafieldisbroughtonstreamtowardstheendoftheperiod. Newer Russian supplies tend to be both lighter and sweeter than traditional baseload Urals, and are augmentedbyrisinglightandsweetKazakhstanandAzerbaijanvolumes.Bycontrast,Albertabitumen with an API of 11° and a sulphur content of 4.50% drives heavy/sour North American supplies with increasing volumes throughout the period. Increased sweet Canadian synthetic crude volumes more thanoffsettheeffectonsulphurcontent. Current Gravity & Sulphur 1
Light
40.0
Changes in Quality 2008-2014 2
1.20 Middle East
Africa
Lighter
Middle East 35.0
API
API
0.80 AsiaPacific
FSU
Africa
Europe
30.0
North America
AsiaPacific
Latin America
Heavy
0.00
25.0
Latin America
-0.40
Europe
0.00 2.0 Sour 1.5 1.0 0.5 Sweet0.0 Sulphur % 1 Symbols proportionate in size to regional production. 2 Hollow symbol denotes crude + condensate production in decline.
56
FSU
World 0.40
World
North America -0.04 -0.08 Sulphur %
-0.12
-0.16
Sweeter
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OPEC Crude Oil Capacity Outlook Theeconomiccrisisandvolatileoilpriceswingsofthepastyearhavecombinedtoderailthetimeline forproductionexpansionplansinsomekeyOPECmembers,withcapacitygrowthnowenvisagedat a much slower pace than projected a year ago. However, while the rise and subsequent fall in oil prices is largely behind the postponement or cancellation of some highͲcost nonͲOPEC production projects,thereasonsforOPEC’sdelaysareasvariedasthegroup’sdiversemembership. Project delays in the 2008Ͳ14 period reflect an array of issues, including strategic reviews of investment plans in response to sharply weaker oil demand, renegotiations of highͲcost contracts withoilservicefirms,reducedcashflowsduetobothlowerpricesandoutputtargets,geopolitical turmoilandresourcenationalisminsomememberstates. OPEC producers are expected to increase crude capacity by a net 1.7mb/d between 2008Ͳ14, to 35.8mb/d. This represents a downward revision of 1.5mb/d compared with last year’s sixͲyear outlook for OPEC capacity growth of 3.2mb/d. MTOMR production capacity projections for each countryarebasedonnewprojectstartͲupsnetofdeclineatexistingfields.Declineratesrangefrom 1%Ͳ5% per year for onshore fields in the Middle East to as much as 15%Ͳ20% at mature offshore deepwaterprojectsinWestAfrica.ThenetdeclinerateforOPECisassumedtoaverage3%annually. Steady downward revisions to oil demand projections Expected Increments in OPEC Capacity overthepastninemonthshavepromptedanumberof mb/d 1.2 countries to review investment decisions taken during 0.9 the dizzying surge in oil prices through midͲ2008. An 0.6 estimated22projectshavebeenstalledsincelate2008 0.3 asbothproducingcountriesandIOCsarerenegotiating 0.0 -0.3 contract terms with oil service companies, contractors -0.6 andothersuppliersinanefforttocapturesignificantly 2009 2010 2011 2012 2013 2014 lower costs. Renegotiation of some contracts has Saudi Arabia Iraq Iran Other MEG Nigeria Angola reportedly led to a drop in project costs ranging from Other OPEC Total OPEC 20% to as much as 50%. Saudi Arabia reportedly managedtoreducesomeprojectcostsby25%whiletheUAEmayhaveloweredcostsbyasmuchas 50%forsomeenhancedoilrecoveryprojects. Afurthereasingintheoilservicesmarkettightnessthatearlierinflatedcostsinthesectortorecord levels—for everything from contract management services, rig rates and manpower—is expected, withmanycompanieswaitingonthesidelinesuntilcostsdropfurther.Thatsaid,projectsawaiting finalsanctionthathavebeendelayedduetocontractrenegotiationsallareexpectedtoeventually moveforwardundernewterms,albeitmanyhavenowhadstartͲuppostponeduntilafterthe2014 endͲpointofouroutlook,bywhichtimedemandshouldhaverecoveredfromitscurrentweakness. The increasing trend towards resource nationalism among some OPEC countries over the past few years is having a marked impact on crude capacity expansion plans for the outlook period. The upward oil price trend from 2004 to midͲ2008, and expectations that capacity constraints would make oil ever more costly, empowered several OPEC members such as Algeria, Ecuador, Iran and LibyatoalterproductionͲsharingcontractsinan efforttocapturemoreoftherevenuestream.In the case of Venezuela oil assets have been nationalised. As a result, sharply lower production profiles emerged for some countries in the medium term, with Ecuador, Iran and Venezuela now collectivelyenvisagedpostinga1.0mb/ddropinproductioncapacityby2014
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Significant Gains for Middle East OPEC Producers Whileattheforefrontofcontractrenegotiationattheendoflastyear,SaudiArabiaisstillontrack to increase the country’s production capacity by a gross 1.55mb/d in 2009. Saudi Aramco will registerthelargestsingleincrementalcapacityincreaseinhistorythisyearwiththestartͲupofthe massive 1.2mb/d Khurais development in June 2009. The 250kb/d Shaybah expansion and the smaller 100kb/d Nuayyim project were also brought on stream in June and combined, the three projectsaredesignedtoraisetheKingdom’stotalinstalledcapacityto12.5mb/d. However,givenweaknearͲtermdemand,itisunlikelythatSaudiAramcowillmaintainimmediately operablecapacityatsuchelevatedlevels,andwehaveassumedoperationsatsomefieldscouldbe shutͲin for rehabilitation or extensive maintenance work during this weaker demand period. As a result,anet1.23mb/dincreaseincapacity,to12mb/dby2014,isprojected.Thatsaid,weassume thatSaudiArabiacouldsurgeto12.5mb/dbyendͲ2009iftheneedarose. Only the 900kb/d Manifa development appears to have been substantially delayed, from 2012 to 2013Ͳ14, with construction, engineering and other service contracts for the heavy oil project currentlybeingrenegotiatedinabidtocapturefallingdevelopmentcosts. TheUAEisexpectedtopostthesecondͲlargestcapacityincreaseafterSaudiArabia,upby330kb/d to3.1mb/d.Earlierplanstoexpandcrudecapacityfromcurrentlevelsof2.7mb/dto3.5mb/dby 2012havebeendeferredto2018.AbuDhabihasrenegotiatedanumberofcontractsinaneffortto reducecostsand,asaresult,announcedmorethan$4billionworthofprojectsin2009.Thecountry has five key projects in the pipeline. The majority of the projects will increase capacity utilising relativelyexpensiveEORtechniquesforthefirsttimeatsomeoftheUAE’smatureonshorefields. TheexpansionoftheoffshoreUpperZakumfield,oneofthelargestoilfieldsintheworld,isslatedto increasecurrentoutputofaround500kb/dto750kb/dbutonlyabout150kb/disexpectedtobe onlineduringtheforecastperiodduetothefield’sformidabletechnologicalchallenges.TheUpper Zakumproject,ajointventurebetweenstateͲownedAdnocandExxonMobilinkedin2006,hasbeen delayeduntillate2013/early2014. Estimated Average Sustainable Crude Production Capacity (million barrels per day)
Increment 2008
2009
2010
2011
2012
2013
2014
08 - 14
Algeria
1.42
1.38
1.42
1.50
1.58
1.67
1.74
0.32
Angola
1.92
2.06
2.12
2.06
2.08
2.11
2.13
0.21
Ecuador
0.50
0.49
0.48
0.45
0.43
0.41
0.39
(0.11)
Iran
3.97
3.98
3.95
3.84
3.72
3.62
3.48
(0.49)
Kuwait
2.63
2.62
2.59
2.55
2.52
2.64
2.69
0.06
Libya
1.78
1.77
1.76
1.78
1.79
1.94
2.04
0.27
Nigeria
2.48
2.60
2.50
2.43
2.36
2.39
2.46
(0.02)
Qatar
0.88
0.93
1.00
1.03
1.01
0.99
0.97
0.09
10.74
11.22
12.16
12.04
11.83
11.86
11.97
1.23
UAE
2.74
2.72
2.71
2.71
2.84
3.01
3.06
0.33
Venezuela
2.62
2.51
2.42
2.33
2.25
2.22
2.20
(0.42)
31.68
32.28
33.10
32.73
32.41
32.85
33.14
1.46
2.47
2.43
2.35
2.23
2.43
2.63
2.70
0.23
34.15
34.71
35.46
34.96
34.84
35.48
35.84
1.69
0.46
0.56
0.75
-0.50
-0.12
0.65
0.36
Saudi Arabia
OPEC-11 Iraq Total OPEC Increment
Reachingthecountry’sproductioncapacitytargetof3.5mb/dwillrequireconsiderableinvestment andtechnologicalexpertisegiventheEmirates’maturefieldsandchallenginggeologicalbasins.Abu Dhabi’s crude capacity targets have also been delayed by the reluctance of the country’s four
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Western joint venture partners to commit substantial investment flows while the fate of their historicconcessionsremainuncertain.TheagreementswithShell,ExxonMobil,BPandTotalforthe onshoreconcessionsareduetoexpirein2014andwithBP,TotalandJapanOilDevelopmentCoin 2018.AbuDhabiformallyopenedtalkswithWesterncompaniesearlierthisyear. QataralsoplanstofocusonEORprojectsduringtheoutlookperiod,withincrementalproductionat thealͲShaheenfieldsexpectedtopushcapacityover1mb/dby2010beforeedginglowerstartingin 2013. By 2012 the country’s crude oil production capacity is forecast to be eclipsed by the rapid expansionofNGLsandcondensateoutput(seeOPECGasLiquidsSupply). LongͲstanding internal political disagreements between Kuwait’s parliament and the ruling family overthefutureroleofIOCinvolvementinthecountry’soilindustryarehavingaseriousimpacton themediumͲtermoilproductionoutlook.Kuwaitiproductioncapacityisexpectedtorisebyamodest 60kb/d, to 2.69mb/d by 2014. An escalation in Incremental OPEC Capacity, 2008-2014 parliamentary nationalistic rhetoric against IOC +1.69 mb/d involvementinthecountryinrecentyearshasbasically UAE closedthebookonProjectKuwaitfornow.However, 0.33 Saudi Arabia Algeria 0.32 1.23 theimpactofrecentchangesinParliamentremainsto be seen and may alter this view. The project aims to Others bring in foreign partners to expand production at the -0.89 Libya 0.27 northern oil fields to 900kb/d, which would allow the Iraq Angola 0.23 0.21 country to reduce its dependence on its Greater Burgan fields. Put forward more than a dozen years ago, there is still no investment model for Project Kuwait and the divisive debate among government officialscontinues.BothChevronandBPsignificantlyreducedtheirstaffinthecountryearlierthis yearfollowingtheexpiryoftechnicalcontractswithKuwaitOilCo.andthecurrentpoorprospects forfutureparticipationinthecountry’soilsector.Governmentplanstoraisecapacityto3.5mb/d steadilyrecededfrom2010to2015,andmostrecentlyhavebeenpostponeduntil2020. TheGCͲ24projectatthenorthernSabriyafieldhasbeenscaledbackfrom160kb/dto115kb/dand delayed until 2013 at the earliest. Ongoing water injection treatment work at the Burgan fields shouldhelpoffsetdeclineselsewhere,withoutputexpectedtoincreasebyafurther100kb/d,from 1.6mb/d to 1.7mb/d by 2014. However, in addition to the stalled Project Kuwait, ExxonMobil’s LowerFarsheavyoilprojecthasbeendelayedbeyond2014. Iran’s challenging political and commercial operating environment, coupled with sharply lower oil revenues,continuestounderminethecountry’sambitiousproductionexpansionplans.Iraniancrudeoil capacity is now expected to decline by a significant 490kb/d, from 3.98mb/d to 3.48mb/d over the forecastperiod.Alreadyplaguedbypersistentdelaysandcancellationsofplannedprojects,IOCinterestin developing projects in the country has cooled along with the downturn in the outlook for oil demand. Forecastcapacityisnowaround100kb/dbelowthatofayearago,largelyduetothestalledplansforthe 110kb/dDarkhovinIIIfieldandthe100kb/dAzadeganIIproject.Withinvestmentbywesterncompanies waningandhamperedbyUSsanctions,Iranianstateoilcompanyofficialshavebeenaggressivelypursuing other,oftenNOC,jointventurepartnersinAsiaandSouthAmericaforthestalledprojects.Chinahasinked adealforthesecondphaseoftheAzadegandevelopmentbutplannedexpansionofexistingcapacityby the2013targetlooksunlikely.TheAzadeganfieldrestsinthemiddleofanoldlandminefieldandworkto cleartheareawillbetimeͲconsumingandcostly.Newcapacityadditionsoverthe2008Ͳ14periodarea net470kb/dbuttheescalatingdeclineratesatolderonshorefieldsmorethanoffsetsthegains.
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Political and Security Problems Temper Iraq’s Capacity Outlook Iraq has put forward an ambitious fourͲpronged strategy to reverse declining production in the country’smainsouthernproducingregionfortheneartermandtorebuilditsbeleagueredoilindustry for the longer term. Despite tremendous international interest for the country’s oil development projects, official plans to increase production by 3.5mb/d to reach 6mb/d by 2017 appear over optimistic given the many political and security risks that continue to challenge the government and industry.Constitutionalissuesregardingthelegalityofcontractawards,ongoingsecurityconcernsand complexjurisdictionproblemsmakeitdifficult,ifnotalmostimpossible,todevelopaforecastofIraq’s productionprofileforthemediumtermwithahighdegreeofconfidence. Asaresult,wehavetakenaveryconservativeviewoffutureIraqiproductioncapacityforthe2008Ͳ14 forecast period. Over the near term, the unexpected accelerating decline in the country’s southern capacity will have a negative effect on total capacityduring2010Ͳ11, slipping to as low as 2.23mb/d. While our view contrasts with more optimistic oil ministry reports, some officials at the State Oil MarketingOrganisation(SOMO)fearanevenmore mb/d Iraqi Production Capacity Profile direnearͲtermoutlook,seeingproductionslipping 4.0 below 2.1mb/d due to an accelerating deterioration in pipeline and other oil field 3.0 infrastructure as well as a lack of skilled manpower. However, efforts to reverse the 2.0 declinewithaggressivedrillingplansfollowingthe recent award of new contracts to oil service 1.0 companies are expected to produce tangible 0.0 results later in the forecast period, with capacity 2008 2009 2010 2011 2012 2013 2014 expectedtosteadilyriseto2.7mb/dby2014. MTOMR 2008 Forecast
MTOMR 2009 Forecast
As a first step to urgently address the decline in Potential Capacity the southern fields, the oil ministry has crafted a fastͲtrack programme of drilling and upgrading projectsby local or Iraqi joint venture companies that aimstorampupproductionby300Ͳ500kb/datahalfadozendifferentfieldsoverthenext18months. Manybelievetheseprojecttimelinesmaybeoverlyambitiousgivenpracticaloperatingandlogistical problems. A shortage of skilled workers as well as difficulty in securing equipment needed for the upgradesislikelytoresultinprojectslippagebyatleastsixmonths. Inadditiontothecountry’sprogrammeoffastͲtrackeddrillingprojects,currentexpansionplansinvolve awardingoneͲofftechnicalservicecontractstoaccelerateupgradingordevelopmentofindividualfields. Lastly, the country launched its first formal licensing round in October, 2008 and a second one is plannedforendͲ2009.Combined,thecurrentplansputforwardaredesignedtoadd1.5mb/dby2013 and2.0mb/dby2017. However, contracts for individual field developments and for the latest licensing rounds have been slowedbyendlesspoliticaltinkeringandchangestocommercialterms.Whiletherehasbeenanopen biddingprocessandmoretransparencythistimeunlikethecontroversialtechnicalserviceagreements (TSAs)andtheengineering,procurementandconstruction(EPC)contractsthatwereofferedinthefirst half of 2008 and then withdrawn companies still face considerable political and commercial risks withouttheproperconstitutionallegalframeworkinplace. Indeed,theKurdishRegionalGovernment(KRG)hasawardedmorethan20explorationandproduction concessioncontractsandserviceagreements,andsomemodestadditionalcapacityisalreadyinplace. But the legality of these contracts is being hotly debated. Moreover, while first exports of new production from the Tawke and Taq Taq fields from the Kurdish region were inaugurated on 1 June 2009,anumberofproblematicissuesremaintoberesolved.
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Political and Security Problems Temper Iraq’s Capacity Outlook
(continued)
BaghdadagreedtoallowtheexportstobeblendedwithKirkukandshippedviatheCeyhanpipelineto theTurkishMediterraneanportprovidedSOMOhandledthemarketingofthecrude.SOMOwilldeposit the revenue from the sales into a federal account but the contentious issue over revenue splitting remains.OilMinisterShahristaniiscurrentlyrefusingtoallowrevenuescollectedfromthesaleofthe new TawkeͲ and Taq TaqͲblended crude to be disbursed since he considers the productionͲsharing contractssignedbythecompanieswiththeKRGtobeillegal. Combinedoutputfromthetwonewcrudestreamscouldpotentiallyadd100kb/dthisyearbutexport plans could be derailed if the payment issue is not resolved soon, and without access to the Ceyhan pipeline, production would need to be limited to volumes that could be sold by truck. However, a satisfactoryresolutionbetweenBaghdadandtheKRGcouldtranslateintoanadditional400Ͳ500kb/dof capacityforthecountry’sproductionprofilewithinourmediumͲtermoutlook. Parliamentary elections now scheduled for January 2010 may provide more clarity and a more stable investmentclimate.Ifpoliticianscanagreeearlynextyearonanewhydrocarbonlaw,whichhasbeenin limbo since it was put forward in October 2008, Iraqi capacity may well reach higher levels than projected in our current outlook, around 3.5mb/d. But with the cost of building capacity to 6mb/d estimatedatanywherefrom$50Ͳ60billion,companiesarelikelytotreadcarefullyonfirminvestment decisionsatleastuntiltheelectionshaveruntheircourse.
OPEC’s African Producers Struggle to Meet Targets Thedropinpricesfromahighof$147/bbllastJulytoalowof$35/bblinFeb2009hasalsodrained some bloated central government budgets and limited funds for state oil companies. Chronically cashͲstrapped Nigeria is struggling to meet its financial commitments to projects, though its joint venture partners have stepped in to provide loans for the state oil company’s share. However, a sharpescalationinattacksonthecountry’soilinfrastructurebymilitantsinthevolatileNigerDelta region and renewed efforts by the government to combat the insurgency have led to an even sharper reduction in output levels this past year. Current production offline due to civil unrest has beenaveraging700Ͳ800kb/din2009,withRoyalDutchShellespeciallyhardhit. Giventheworseningviolence,IOCsappeartobetreadingcautiouslywithinvestmentplans.Nigeria’s lowerOPECproductiontargetlevelalsoappearstobeconstrainingIOCinvestmentdecisionsforthe relatively more expensive offshore projects. As a result, we have taken a more cautious view of Nigeriancrudeoilproductioncapacityovertheforecastperiod,withcapacityexpectedtodeclineby a marginal 15kb/d, to 2.46mb/d by 2014. This excludes some 500kb/d of longͲterm shutͲin capacity.Thestaticcapacitypicturelargelyreflectsdelaysinagreeingtimeframesforexpansionof some of Nigeria’s ultraͲdeepwater field developments.The 120kb/d Bosi development and the 180kb/d Usan project are now running three years behind original planned targets, with startͲup now pencilled in for 2012 and 2013, respectively. There is another 700kb/d in projects on the drawing board but they have not been included in the outlook given uncertainty on investment decisionsandthedevelopmenttimeline. Algeria’s move to sharply alter productionͲsharing contract (PSC) terms and increase the state’s share of the projects via implementation of stricter terms, when prices started their upward trajectoryin2004,hasledtoexcessivegovernmentbureaucraticdelays,complexrenegotiationsand
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ultimatelystalledproductionplans.Thetoughertermsandgreaterroleforthegovernmentinthe operating and valuation process also discouraged foreign investors from bidding in the country’s latestexplorationlicensingroundinDecember2008,thefirstonesincetheoverhaulofthecountry’s investment terms.Onlyninebidsweresubmittedfor16licensesonofferandcontractseventually awardedtojustfourcompanies.ThelackofinterestinthelatestE&Proundandtheprospectofa lowercapacityarelikelybehindAlgeria’sdecisiontoeasecontracttermsthisyear.Algerianplansto increasecapacityviaEORprojectshavebeenonthedrawingboardformorethan8Ͳ10years,with thelongdelaystoexpansionplansstartingtohaveamarkedimpactoncapacitylevels,downfrom 1.42mb/din2008to1.38mb/din2009. However,anumberofcontractsforEORprojectshavebeensignedsincethebeginningoftheyear whichshouldhelpspurarecoveryinproductioncapacityinthemediumterm.Inaddition,despite lowerrevenueprojections,AlgeriaraiseditsfiveͲyearbudgetforcapitalexpendituresfortheoiland gassectortoarecord$63billionforthe2008Ͳ12governmentforecastperiod.Thatisupfromlast year’sforecastbudgetof$45billionforthe2007Ͳ11periodandjust$33.2billionfor2006Ͳ10.Unlike mostotherstateoilcompanyplans,Algeriaalsoincludesprojectedinvestmentbyforeignpartnersin its official budgets. State Sonatrach is expected to finance 75% of the current budget with IOCs providingtheremaining25%. As a result of increased expenditures, we have revised our outlook for Algeria, with capacity now seenrisingby320kb/d,to1.74mb/doverthe2008Ͳ14period,comparedwithlastyear’sprojected declineof60kb/dto1.39mb/d.RedevelopmentplansforHassiMessoud,thecountry’soldestand largestfield,aremovingforwardwithcapacityexpectedtobeincreasedfromacurrent400kb/dto 600kb/d.OtherprojectsinthepipelineincludetheRhourdeelͲBaguelexpansion. Libyan government plans to raise production capacity to 3mb/d by 2012 have now been revised down to 2.3mb/d by 2013 but even this lower target looks optimistic. Our latest projectionsees Libyancapacityreachingjust1.94mb/dby2013andjustover2mb/dby2014.Despiteexpectations thatLibya’soilsectorwouldseeaninfluxofforeigninvestmentandincreasedproductioncapacity following the lifting of US sanctions in 2004, projects have been stalled by excessive bureaucratic delays and ever more changes in contract terms in the wake of resurgent resource nationalism. Capacityisexpectedtorisebyanet270kb/dovertheforecastperiod,withincreasesfromtheWaha EORprojectandNafooraexpansioneachaccountingforaboutoneͲthirdofthegrowth. Angola’scrudeoilproductioncapacityisexpectedtoincreaseanet210kb/d,to2.13mb/doverthe fiveͲyearperiod.Newfielddevelopmentsareestimatedatover1.0mb/dfortheperiodbutvolumes are offset as older deepwater projects mature beyond 50% recovery and production declines escalate.Someofthelargerdevelopmentsinclude: ŀ ŀ ŀ ŀ ŀ
Tombua/Landana(Block14)at100kb/d Pazflor(PerpetiaͲAcaciaͲZiniaͲHortensiaͲBlock17)at200kb/d KizombaD(Block15)at125kb/d PSVM(Plutao/Saturno/Venus/MarteͲBlock31)at130kb/d SEPAJ(Palas/Astraea/Juno/Ceres/HebesͲBlock31)at110kb/d
The country’s production potential is markedly higher but OPEC quota constraints coupled with relatively higher development costs for its ultraͲdeep water offshore projects have meant IOC investmentdecisionshavebeenputonholdgiventheuncertaindemandoutlook.
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Nationalism Undermines Outlook for OPEC’s Latin American Members The resurgence in resource nationalism has had the largest impact on our outlook for production capacityinVenezuelaandEcuador,expectedtodeclinebyacombined530kb/dby2014.Inthepast few years it has been extremely difficult to develop a robust production capacity forecast for Venezuelagiventheacutelackofavailabledataandincreasinglycloudyinvestmentoutlookdueto the ongoing nationalisation of oil industry assets. Because of these issues we have previously retaineda‘currentcapacityextendedforward’approachuntilaclearerpictureemerged.Venezuela has recently released some unaudited data on the country’s oil exports, aiming to augment thirdͲ party estimates of production levels. Not only does considerable uncertainty over baseline productionpersist,butsotooforfuturedevelopmentsintheoilsectorandinvestmentplans. Itisincreasinglyapparentthattheglobaleconomicdownturnislikelytohaveadetrimentalimpact on Venezuela’s oil sector so this year we have attempted to estimate a more specific production capacityprofile.Inresponsetoloweroilrevenuesandthecontinuedneedtofundthegovernment’s social welfare programmes, Caracas slashed the budget for state oil company PDVSA by 65% this year, to US$6.1billion versus $17 billion in 2008. As a result, we have amended our outlook to reflect the acute shortage of investment capital for PDVSA, with capacity expected to decline by 420kb/d,from2.62mb/din2008to2.2mb/din2014. Inadditiontotheinvestmentshortfallsaffectingcapacity,developmenttimelinesforprojectsinthe Orinoco belt have yet to be finalised or dates that have been announced appear overly ambitious, withmostofthenewheavyoilcapacityannouncedsofarnotexpectedwithinourforecastperiod. Thecountry’snationalisationofthemajorityofoilservicecontractorsin1H09isalsolikelytohavea detrimentalimpactonoilfielddeclineratesintheneartermasmanyoftherigssitidle. The outlook for Ecuador has been clouded by the government’s severe shortage of investment capital for projects and its inability to attract foreign partners given stricter operating terms. Companieshaveslashedexpendituresoroptedtowithdrawaltogetherratherthanacceptpunitive contractchangesandthereareanumberoflawsuitspending.Inaddition,stateͲownedPetroecuador halved its capital spending budget to under $1billion for 2009. As a result, Ecuador’s capacity is expectedtodeclineby110kb/d,to390kb/din2014. OPEC Gas Liquids Supply In contrast to the anaemic crude capacity profile, OPEC NGL and condensate capacity is expected to increasebyabout60%overthe2008Ͳ14period.Totalcondensate,NGLandnonͲconventionaloutput capacity is projected to rise by 2.62mb/d, to 7.32mb/d, NGL, Condensate & Non-Conventional with Middle East producers providing virtually all of the mb/d as % of Total OPEC Supply 18% growth.ThegasliquidscomponentinOPEC’stotalsupply 50 45 profile is seen rising from 12% in 2008 to 17% by 2014. 40 35 16% OPEC NGLs as classified here include condensates, gas 30 liquids (including ethane), gasͲtoͲliquids (GTLs) and other 25 20 14% 15 nonͲconventionaloutput. 10 5 0 12% Expansion of gas liquids capacity is moving apace, not 2008 2009 2010 2011 2012 2013 2014 OPEC NGL, condensates & non-conventional least because of the acute need to boost natural gas OPEC Crude output for reinjection at aging oil fields. A shortage of % NGL and condensate
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gassuppliesneededtomeetdomesticdemandfromthepowersector,atdesalinationplantsandfor industrialusehasalsoensuredthatrobustcapacityexpansionstaysontrack.Theseextravolumesof gas liquids from OPEC, condensates in particular, play a significant role in shaping the expected refineryfeedstockslateandupgradingeconomicsthrough2014. OPECMiddleEastproducersaccountforthelion’sshareofthegrowthincapacity,upby2.36mb/d to 5.52mb/d by 2014. Nigeria also sees robust growth, with output more than doubling over the forecastperiod. Qatargasliquidsoutputisforecasttomorethandoubleovertheperiod,upbyaround750kb/d,to 1.3mb/d by 2014. Major increments are expected from Qatargas Train 4 at 160kb/d and from RasGasTrain6at155kb/d.IncrementalvolumesofcondensateandNGLfromtheDolphinproject arealsoexpectedfollowingthestartͲupofthefifthtraininmidͲ2009.Dolphincapacityisexpectedto increasefromanaverage75kb/din2008topeaklevelsof145kb/din2009. Saudi Arabia’s capacity is expected to expand by 39% over the outlook period, to 1.98mb/d. IncreasedcapacityissplitbetweennonͲassociatedandassociatedgasprojects.StartͲupofthenonͲ associated Hawiyah NGL Recovery Project has been delayed from 2008 to 2009, with output expectedto reach its peak 300kb/d capacity around 2011. The Khursaniyah gas processing facilities were delayed from last year and full nameͲplate NGL capacity of 290kb/d is not expected to be operationaluntilendͲ2009. Iran’s condensate and NGL capacity is forecast to mb/d OPEC NGL and Condensate Production reach 1mb/d by 2014, an increase of about 8 7 550kb/dover2008.DevelopmentofIran’smassive 6 SouthParsprojecthasbeenfraughtwithdelaysand 5 costlyoverrunsbutfinalcompletionofPhases6Ͳ10 4 3 is expected to add around 285kb/d by endͲ2009 2 while Phase 12 is likely to increase capacity by a 1 further170kb/dby2013.However,furtherproject 0 2008 2009 2010 2011 2012 2013 2014 expansions beyond this time frame remain uncertain.TotalhasnowpulledoutofthePhase11 Other OPEC UAE Algeria Iran Qatar Saudi Arabia development due to the unattractive contract terms.StatoilHydrohasalsooptednottogoforwardwiththeAnarandevelopment,inpartdueto the costly overruns experienced during the company’s development of Phases 6Ͳ8. The project timeline suffered from significant work delays by Iranian subcontractors as well as difficulty in obtainingpipelineandotherneededmaterialasaresultofUSsanctions. TheUAEisslatedtorampupNGLoutputby60%,toaround850kb/dby2014.StartͲupofthedelayed 270kb/dHabshanOGD3processingfacilitiesthisyearwillaccountfor85%ofthe320kb/dincrease. Nigeria NGL and condensate is expected to increase by 230kb/d, to 450kb/d by 2014. StartͲup of theTotalͲoperatedAkpogas/condensateprojectinApril,2009willprovide175kb/doftheincrease.
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C RUDE T RADE
CRUDE TRADE Summary x
GlobalinterͲregionalcrudeoiltradeisexpectedtoriseby0.2mb/dbetween2008and2014, equating to 0.1% annual growth. However, using 2009 as a baseline – when OPEC production cutsandfallingdemanddramaticallyreducecrudetrade–revealsamorerobustpicture.Crude tradefrom2009Ͳ2014shouldriseby2.6mb/d,or1.5%annually,asglobaldemandrecoversand exportsfromtheMiddleEastandAfricaincrease.Nonetheless,weakerglobaldemandprospects have reduced crude trade across the outlook versus December’s report, with average global annualtradefrom2008Ͳ2013adjusteddownby2.3mb/d.
x
TheMiddleEastwillremainthekeycrudeexportingregioninthemediumterm,withexports moving from 16.8mb/d in 2008 to 15.0mb/d in 2009 and then to 16.6mb/d in 2014. Africa showsthestrongestexportgrowthduringtheforecastperiod,however,movingfrom7.8mb/d in 2008 to 7.5mb/d in 2009 and reaching 9.2mb/d in 2014. FSU and Latin American export levels,bycontrast,shouldfallby190kb/dand175kb/d,respectively,between2008and2014.
x
China’s crude imports rise from 3.6mb/d in 2008 to 5.1mb/d in 2014 as refinery demand increaseswithnewcapacityadditions.ImportsintoothernonͲOECDAsiancountriesshouldrise from5.8mb/din2008to6.6mb/din2014.Whilea2009decreaseinimportlevelsduetoOPEC production cuts somewhat distorts the trajectory, OECD imports look to fall across the board. OECD Europe and Pacific absolute import levels from 2008Ͳ2013 also absorb large downward revisionsof1.1mb/dand375kb/d,respectively,versusDecember’sprojection.
Overview A reassessment of mediumͲterm oil balances has reduced global demand growth in the forecast period,which,inturn,hasreducedglobalcrudetradevolumesby2.3mb/dfrom2008Ͳ2013versus December’soutlook(thisexerciseisbasedentirelyuponthehigherͲGDPdemandprojection).Crude trade is still expected to slightly expand during 2008Ͳ2014 as global demand recovers and the requirement for OPEC crude gradually increases from 2011 onwards. However, the growth trajectory depends strongly on the baseline year used in the analysis. Sticking with this MTOMR’s convention of comparing 2008 to 2014, global crude trade rises only 0.2mb/d over the forecast period.Yet,startingfrom2009,whenvolumeshavebeenseverelycurtailedduetoOPECproduction cutsandplummetingdemand,steadygrowthleaves2014trade2.6mb/dhigherthanthebaseyear. mb/d
Inter-Regional Crude Exports: Yearly Change
1.8
1.8
0.9
0.9
0.0
0.0
-0.9
-0.9
-1.8
-1.8
-2.7
-2.7 2008 2009 2010 2011 2012 2013 2014
China OECD EUR
J UNE 2009
Africa Mid East
Other Asia Latin Am
OECD PAC FSU
Inter-Regional Crude Imports: Yearly Change
mb/d
2008 2009 2010 2011 2012 2013 2014 China OECD EUR
Africa OECD NAM
Other Asia Latin Am
OECD PAC Other Eur
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Middle East crude volumes continue to play a crucial role in export dynamics, but absolute levels looktodeclineslightlyfrom16.8mb/din2008to16.6mb/din2014.MostMiddleEastincremental exports will continue heading to Asia as China expects to receive 595kb/d more from 2008Ͳ2014, andOtherAsiashouldincreaseitstakeby455kb/d.However,theseincreasesareoffsetbydeclining volumesintotheOECDastheregionabsorbstheimpactfromreducedglobaldemand.While2009 totalMiddleEasternexportsareseenonly0.4mb/dlowerthanDecember’sforecast,the2010Ͳ2013 period averages almost 2.5mb/d less. Most of those reduced volumes stem from downward revisions of barrels heading to Other Asia where 2009 exports are 0.8mb/d below December’s forecast and the 2010Ͳ2013 period averages 1.4mb/d less. The OECD Pacific also sees reduced volumes from the Middle East versus December, with 2009 levels revised down by 350kb/d and 2010Ͳ2013downbyalmost500kb/d. Middle East Export Growth 2008-14
To
ME-China AFR-OECD NAM FSU-China AFR-OECD EUR ME-Other Asia AFR-Other Asia AFR-China ME-OECD NAM FSU-OECD EUR ME-OECD PAC
China Oth Asia Africa FSU Latin Am Oth Europe OECD Eur OECD Nam OECD Pac mb/d
Inter-Regional Export Growth 2008-2014
-1.2
-0.8
-0.4
0.0
0.4
0.8
mb/d
-1.2 -0.8 -0.4 0.0
0.4
0.8
Africa displays the strongest growth of any export region, though it too sees some lower absolute volumesrelativetoDecember’soutlook.OverallAfricanexportsshouldmovefrom7.8mb/din2008 to 7.5mb/d in 2009 to 9.2mb/d in 2014. OECD EuropeandNorthAmericaabsorbthelargestshares Africa Export Growth 2008-14 ofnewsupplies,followedbyOtherAsia.Downward OECD Nam revisions to African export levels occur in the early OECD Eur Oth Asia part of the forecast, as 2009Ͳ2011 sees 570kb/d China lowervolumesand2012Ͳ2013seesupwardrevisions Mideast of 330kb/d versus December’s projection. FSU Downward revisions are concentrated in exports to OECD Pac OECDEuropeandNorthAmerica,wherefrom2009Ͳ Oth Eur 2013 supplies average about 0.3mb/d less for both Latin Am regions.Upwardrevisionsapplytovolumesheading mb/d -0.2 to Other Asia, which are 600kb/d higher in 2009Ͳ 0.0 0.2 0.4 0.6 2013thaninDecember’sreport. FSUexportsareexpectedtofall,movingfrom6.6mb/din2008to6.4mb/din2014.Yet,absolute volumes have been revised down through the period, 400kb/d lower from 2009Ͳ2013 versus December, as production expectations have fallen. Most all of the downward revisions apply to volumes heading to OECD Europe, which takes 655kb/d less in 2009Ͳ2013 versus December’s forecast.However,FSUexportstoChinawillstillgrowby500kb/din2008Ͳ2014,supportedinpart byincreasedpipelineexports(seeFSUExportersBranchingOut).
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C RUDE T RADE
Ontheimportsside,ChinaandOtherAsiacontinuetoabsorbthegreatestamountsofcrudesupplies fromincrementaltrade.China’simportsshouldrisefrom3.6mb/din2008to3.7mb/din2009and reach5.1mb/din2014.OtherAsianimportsshoulddecreasefrom5.8mb/din2008to5.6mb/din 2009,beforereboundingto6.6mb/din2014. Crude Exports in 2014 and Growth in 2008-14 for Key Trade Routes* (million barrels per day) * Excludes Intra-Regional Trade
OECD Europe OECD North America
4.2 (-0.9)
(+0.5)
4.5
1.5
(-1.0)
(-0.1)
2.5
OECD Pacific
1.2 (+0.5)
2.9
China
(+0.5)
2.2 Other Asia
1.5
1.5
(+0.6)
(+0.2)
(-0.2)
4.8 2.9
(+0.5)
(-0.4)
Red number in brackets denotes growth in period 2008-14
ForChina,importsfromAngolaandRussiaactasthegreatestsourcesofgrowthfrom2009Ͳ2011.In thelatterhalfoftheforecastperiod,however,importsfromtheMiddleEastandNigeriaplayalarger role.StrategicstockbuildingcouldaddtoChina’srisingimports.ForOtherAsia,mostincremental imports come from Nigeria and the Middle East. The largest single source of growth, however, shouldcomefromQataricondensate. IntheOECD,bothEuropeanandNorthAmericanabsoluteimportvolumesfallfrom2008Ͳ2014,but rise(by75kb/dand315kb/d,respectively)from2009Ͳ2014.OECDPacificimports,bycontrast,fall throughouttheperiod,andin2014stand1.2mb/dlowerthanin2008.Sourcesofimportgrowthfor Europe and North America stem from Azerbaijan and North and West Africa exports. Most OECD Pacific declines are due to reduced demand overall and a subsequent lower intake of Middle East crudes.
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BIOFUELS Summary x
Biofuels production growth will slow in 2009, but subsequently rebounds in the mediumͲterm,withoutputincreasingfrom1.45mb/din2008to2.16mb/din2014.Although 0.7mb/dgrowthduring2008Ͳ2014exceedsthe0.6mb/dgrowthfrom2008Ͳ2013positedinthe 2008MTOMREdition,thesupplypatternchangeswithweaker2009Ͳ2010outputandstronger latteryearcomparisons.
x
DownwardnearͲtermrevisionstoNorthAmerica,EuropeandAsia,onweakeconomics,reduce 2009Ͳ2010globalannualoutputby125kb/dversuslastyear’sreport.Yet,stronggrowthinLatin America and mandateͲdriven expansion in the OECD put 2012Ͳ2013 global annual output 140kb/dhigher.TheUSandBrazilremainthelargestproducers,accountingfor80%ofgrowth.
x
Downside risks remain as economic crisis threatens further plant closures and capacity expansions.Governmentsupportformeetingconsumptiongoalsremains,butiscounteredby persistentenvironmentalandfeedstockconcernsassociatedwithfirstͲgenerationbiofuels.And secondͲgeneration technologies should not scale up considerably by 2014. As such, our production estimates undershoot those implied by government policy goals. However, more completetarget/mandatecompliancewouldlendsignificantupsidetotheprojection.
x
With 120kb/d annual output growth from 2008Ͳ2014, biofuels partly offset nonͲOPEC conventionalsupplydeclines.By2014ethanolandbiodieselshoulddisplace5.4%and1.2%of globalgasolineandgasoildemand,respectively,onanenergycontentbasis.
x
Small secondͲgeneration biofuel quantities should enter the market, particularly as US mandatesrequireacellulosicethanolrampupby2014.Still,weassessglobalsecondͲgeneration capacityat60kb/dorlessinthelatterforecastyears,withoverhalffrombiomassͲtoͲliquidsand theremainderfromcellulosicethanol.
Medium-Term Growth, Despite Many Uncertainties Logically, the prognosis for liquid biofuels supply should have worsened since the MTOMR 2008 Edition.EvenwhilerecordͲhighoilpricessupportedarobustexpansionofproductionandcapacityin 2008,industryprofitabilitysufferedandissuesrelatedtoenvironmentalsustainabilityandfoodprice inflationbeganundermininggovernmentsupportforsomefirstͲgenerationbiofuelsfromfoodcrops. mb/d 2.4
kb/d 600
Global Biofuels Supply
2.0
400
1.6
200 0
1.2
-200
0.8
-400
0.4
-600
0.0 2008
2009
2010
OECD EUR Biodiesel Other Ethanol US Ethanol
68
Non-OPEC Supply Growth 2009-2014
2011
2012
2013
Other Biodiesel Brazil Ethanol
2014
2009
2010 2011 2012 2013 Non-OPEC (excl. Biofuels) Global Biofuels Total Non-OPEC
2014
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B IOFUELS
In 2009, many producers remain only on the cusp of profitability, as oil prices have dropped and accesstocredithasdriedup.Althoughfeedstockpriceshavefallen,theyhaveremainedstickieron the way down, cutting into producer margins. Bankruptcies, plant closures and overcapacities characterise the operating environment, particularly in the OECD. And longerͲterm environmental andfoodcompetitionquestionsremain. World Biofuels Production Forecast (thousand barrels per day)
2008
2009
2010
2011
2012
2013
OECD North America
665
711
797
835
872
872
872
United States
647
688
774
810
842
842
842
OECD Europe
202
179
204
237
248
248
248
OECD Pacific
6
5
8
12
14
14
14
Total OECD
873
895
1,009
1,084
1,135
1,135
1,135 11
FSU
1
2
3
5
11
11
Non-OECD Europe
4
4
4
4
5
5
5
China
32
25
30
34
45
48
48
Other Asia
30
32
41
66
80
82
82
Latin America
505
565
629
676
743
809
880
Brazil
485
546
605
649
708
773
844
Middle East
0
0
0
0
0
0
0
Africa
2
2
2
2
4
4
4
574
630
709
788
888
959
1,030
1,447
1,526
1,718
1,871
2,023
2,094
2,164
Total Non-OECD Total World
2014
Yet,biofuelsgrowthwillstillconstituteareliefvalveforoilmarkets,andparticularlyforgasolineand gasoil. From 2003Ͳ2008, biofuels growth met about 16% of global incremental gasoline and gasoil demand.From2008Ͳ2014,withgasolineandgasoildemandgrowing3.5mb/dcollectively,biofuels shouldagain meet15%ofthisnewconsumption, with Global Biofuels Output ethanol accounting for the lion’s share. Tightening mb/d 3.0 product specifications, particularly for diesel, heating 2.8 2.6 oilandbunkerfuel,provideademandnicheinaworld 2.4 where fuel desulphurisation heading down the barrel 2.2 2.0 becomes an increasingly costly and technically difficult 1.8 process.Whilepoormarginsandbankruptciesremain 1.6 1.4 nascent features of the biofuels industry, market 1.2 consolidationandassetpurchasesbyentitieswithmore 2008 2009 2010 2011 2012 2013 2014 robust finances suggests some transition to more 2009 MTOMR * Based on forthcoming 2008 MTOMR World Energy Outlook sustainable production in the future. And lowerͲcost Policy Driven Scenario* 2009 policy database producerswillcontinuetogrowstrongly. Ultimately, blending mandates provide a floor for growth, especially with poor economics and overcapacity disrupting nearͲterm expansions. Notably, the fulfilment of government mandates/targetsgloballysuggestssignificantproductionupside,asgraphicallydepictedinthePolicy Driven Scenario above. Yet, our 2008Ͳ2014 production growth outlook sees only 715kb/d of new biofuelsoutput,with80%fromLatinAmericaandtheUS(ethanolandbiodieseldataareavailablein Tables4and4Aonpages114and115).Althoughthisgrowthexceedsthe600kb/dgrowthfrom2008Ͳ 2013 posited in last year’s report, the production pattern changes considerably with this year’s projectionfeaturingweaker2009Ͳ2010outputandstrongerlatteryearcomparisons.
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This forecast still tempers later year expansion as land availability and infrastructure remain roadblocksandsecondͲgenerationvolumesremainsmall.Moreover,carfleetswithouthighflexͲfuel vehiclepenetrationandthecorrespondinginfrastructuretostoreanddispensehighethanolblends throughservicestationsfaceenginelimitsonethanolblending.Thoughgovernmentpoliciesprovide afloor,theyalsocloudfutureprospects.Lukewarmsupportamongsome,increasedenvironmental scrutinyandprotectionisttradebarriers,whichinhibitrebalancingtolowercostproducers,expose incompatibilities with ambitious usage targets. MediumͲterm realisable supply increases will struggle to meet all the aspirations for biofuels to improve their cleanliness versus fossil fuels, becomemorecostefficientandremainhomegrownatthesametime. Key Revisions to the Supply Outlook An upward revision to 2008 supply of 95kb/d provides a higher 1.45mb/d baseline to guide the forecast,butnearͲtermfalteringeconomicshavedramaticallychangedthegrowthpatternfromlast year. We see 2009 production growing to 1.53mb/d and 2010 at 1.72mb/d, both below levels predictedlastyearasutilisationrateshavefallenandprojectshavebeencancelledand/ordeferred.
World Biofuels Production - Changes to Forecast from July 2008 (thousand barrels per day)
2008
2009
2010
2011
2012
OECD North America
69
-55
-1
36
73
73
United States
75
-53
2
39
70
70 -31
OECD Europe
-24
-98
-75
-42
-31
OECD Pacific
-11
-15
-15
-11
-8
-8
Total OECD
35
-167
-91
-17
34
34
FSU
-2
-7
-7
-5
2
2
Non-OECD Europe
1
-1
-1
0
0
0
-19
-49
-51
-46
-35
-32
China
2013
Other Asia
-39
-53
-47
-23
-9
-7
Latin America
124
119
130
131
148
158
Brazil
156
120
127
140
139
147
Middle East
0
0
0
0
0
0
Africa
-5
-8
-11
-11
-9
-9
Total Non-OECD
60
0
13
47
96
112
Total World
95
-167
-78
30
131
146
Upwardrevisionsforthe2008baselinestemsalmostentirelyfromhigherͲthanͲexpectedethanoloutput intheUSandBrazil.Incontrast,thecontinuedintegrationofbetterandmorecomprehensivedatafrom OECD countries and a fewnonͲOECD ones has driven many of our downward revisions, particularly in OECDEuropeandAsia.ButweseepostͲ2011productionhigherthaninourprojectionslastyear.Brazil outputincreasesinthelaterforecastyearsshouldhelpworldbiofuelssupplyreach2.16mb/dby2014. Our forwardͲlooking revisions stem from reappraising our capacityͲdriven model, with over 2,000 biofuels production plants, and expectations of production economics. Given their small and fragmentednaturecomparedwithoilrefineries,biofuelsplantsremaindifficulttotrack.Andalthough the credit crisis has increased the time needed to bring plants online, smaller overall capital requirementsandshorterconstructionleadtimesmeanbiofuelscapacitycanrespondmorequicklyto changingmarketconditions.Assuch,whileweconservativelyscrutiniseourfutureplantassumptions, wecontinuetoerronthesideofallowingpotentialavailablecapacitytogrowfasterthanproduction.
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Theimplicationisthatpotentialavailablecapacitycouldreach3.0mb/dby2014,upfrom2.1mb/d in 2008. Yet, this 2014 figure is 230kb/d lower than last year’s 2013 estimate and we still limit capacityinmostregions,exceptBrazil,after2012,givenindustryuncertainties. Economic Crisis Increases Production Challenges Biofuelsproducershavesufferedwiththeadventofthecreditcrisisandfallingoilprices.Threesets of economic challenges confront producers now and in the future:feedstock prices, risk managementoffeedstockcostsandrevenuestreamsandavailabilityoffinancing. Jan Ethanol Feedstock vs Gasoline Prices 08=100 175
Jan Biodiesel Feedstock vs Diesel Prices 08=100 160
150
140
125
120
100
100
75
80
50
60
Source:Platts,Reuters
25
Source:Platts,Reuters
40
Jan 08
May 08
Sep 08
Intercont Exch Sugar
Jan 09
May 09
Jan 08
Chicago Corn
May 08
Sep 08
SE Asia Palm Oil
NY Harbor RBOB
Jan 09
May 09
NW Eur Rapeseed Oil
NW Europe ULSD
Feedstock Prices: Falling oil prices since last summer have not met with a corresponding fall in agricultural feedstock prices, degrading biofuels competitiveness versus fossil fuels and pressuring margins. Although a recent gasoline price rise has made ethanol blending more attractive, sticky corn and sugar prices have in some cases kept margins below levels needed to cover the costs of capital (in the US) and induced some switching from ethanol to sugar production (in Brazil’s case). Biodieselcrushspreads–thespreadbetweenthebiodieselpriceandfeedstockoilpriceͲhavealso sufferedinEuropeandSoutheastAsia,promptingutilisationcutsandidlingofplants. Forecasting agricultural fundamentals and prices is beyond the scope of this report. It should be noted, though, that the US Department of Agriculture’s longͲterm projections see corn prices remainingathistoricallyhighlevelsasethanolproductionincreases.AndarecentUSCongressional Budget Office report puts ethanol breakͲeven profitability at a gasolineͲtoͲcorn price ratio of 0.9, which has rarely been exceeded over time. Feedstock prices will likely remain a constraint on biofuelsexpansion.Moreover,increasedcommoditypricevolatilitybroughtaboutbytheeconomic crisisandotherfactors–suchasweather–castuncertaintyoverrevenuestreamsandexpansions. US Ethanol Margin vs Production
$/galJan-06
Jan-07
Jan-08
3.25 2.75 2.25 1.75 1.25 0.75 0.25 -0.25 Jan-06
Jan-07
Source:Reuters/CBOT
J UNE 2009
Jan-08
Jan-09 k b/d 675 625 575 525 475 425 375 325 275
Jan-09
Corn Ethanol Margin Production
$/t
Biodiesel Crush Spreads 30-day moving average
300 250 200 150 100 50 0 -50 -100 -150 Nov 07
Source:Reuters Mar 08
Jul 08
NW Europe Rapeseed
Nov 08 Mar 09 SE Asia Palm
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Biofuels Expansions May Hinge on Industry Consolidation The credit crisis and poor production margins have sown seeds of destruction for some biofuels producers,buthavecreatedopportunitiesfordeeperͲpocketedentitiestoenhancetheirownbusiness modelsbybuyingcheapassets.Recently,oilrefinersValeroandSunocohaveintegratedbiofuelsinto their downstream operations by acquiring plants from bankrupt US ethanol producers VeraSun and NortheastBiofuels,respectively.Someindependentbiofuelsproducerswhohaveweatheredthecrisis have also purchased distressed assets. And companies such as ADM and Cargill continue to have biofuels production integrated with their agricultural output. Together the oil and agricultural integrationmodelsnowaccountforalmost20%ofUSethanolcapacity.Suchconsolidationmaymarka moresustainableindustrymodelinthefuturewiththerealisationofgreatereconomiesofscale. However,itisstilltooearlytogaugethedegreetowhichrefinersandbiofuelsproductionwillultimately benefit. Valero acquired its ethanol capacity at 61c/gal and Sunoco looks to pay $8.5m for a 100mgal/yr plant. These payments are significantly less than the costs of new US ethanol builds in 2008,whichrangedfrom$1.30Ͳ2.40c/gal.Forrefiners,integratingbiofuelsproductionislikelyaimedat capturing a growing portion of the longerͲterm transportation fuel value chain as the US Renewable FuelsStandard(RFS)increases.Forthebiofuelsindustry,runningthisnewcapacitywilllikelycontinue to depress already weak ethanol margins,putting smaller players more at risk and generating further upheaval. Though, in the US, as the RFS begins to increase by more than our production forecast, strongerethanolmarginsmayreͲemergewiththe2010USsummergasolineseason. Inthemediumterm,thedegreetowhichbiofuelscapacitywillbescoopedupand/orexpandedbystronger playersremainsuncertain.Refinersmaybecontenttohavejustonefootinbiofuelsproductionnow,with an eye to increasing their involvement as production technologies mature or longerͲterm mandates look increasinglylikelytohold.NesteOil’splannedbiomassͲtoͲliquidsplants(about16kb/deach)inSingapore andRotterdam(duetostart upin2010and2011,respectively)illustratethepotentialsupplygainsfrom refinersexploitingmoreadvancedproductiontechnologies.Anddespitedifficultfinancingconditions,some largerbiofuelsindependentshavecarriedonwithambitiousexpansionplans.Abengoa,forexample,still lookstobringEurope’slargestethanolplant(480ml/y)onlineinRotterdamby1H10.
RiskManagementofFeedstockCostsandRevenueStreams:Duringthe2008runupincommodity prices, biofuels producers often failed to manage their risk exposure or badly timed entering into hedging instruments. A steep pullback in prices subsequently left some with bad hedges and the need to post margin calls and purchase feedstocks at bn$ Biofuel Plant Global Asset Financing higherthanmarketprices.Lossesonhedgesandcorn 6 Source: New price bets crimped cash flows to untenable levels for 5 Energy Finance some producers, notably US ethanol maker VeraSun. 4 Goingforward,commoditypricevolatilitywillremaina 3 risktoproducers.Yet,creditandcashflowconstraints 2 brought about by the crisis have reduced hedging 1 abilitiesforsome,particularlythesmallerproducers. 0
Availability of Financing: Credit constraints have also undermined the industry’s ability to finance capacity expansionsandnewprojects.ManyproducersaresaddledwithdebtsandstruggletocoverdayͲtoͲ day operating costs while investors have soured to the industry’s prospects. According to one industrysource,worldwideassetfinancingofbioͲrefineries–nowalmostthesolesourceofphysical biofuelsinvestment–plungedfromaround$5.7billionin3Q07toabout$1billionin1Q09.
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In Brazil, producers have accelerated their sugarcane crush and have produced over 60% more ethanol in the early part of 2009 versus the same period in 2008 to generate nearͲterm cash to compensate for financing shortfalls. And sugarcane industry association Unica has announced that onlyhalfofexpectednewBrazilianmillsmaycomeonlinethisyear.SimilarproblemsexistinEurope andtheUS.Still,thepotentialformarketconditionstorapidlychangeandcreditconditionstothaw overthemediumtermmeansthatadditionstocapacityshouldnotdryup.Moreover,opportunistic asset purchases by companies with deeper pockets may signal a more sustainable model of future supplyexpansion(seeBiofuelsExpansionsMayHingeonIndustryConsolidation). Outlooks and Policies Differ Across Regions US and the Americas While US ethanol margins have languished due to rising corn prices, production has advanced rapidly,supportedbyfavourableblendingeconomics,whichincludesa45Ͳcentblenders’taxcredit and the RFS, which mandates gasoline pool inclusion of 685kb/d of conventional ethanol in 2009, rising to 980kb/d in 2015. Recent proposed RFS implementation by the US Environmental Protection Agency (EPA) would reaffirm these targets and those for ‘Advanced Biofuels’, which includebiodieselandcellulosicethanol(thoughthebiodieselmandateforthisyear,combinedwith thatfor2010,wouldturnintoarequirementmetovertwoyears). US Renewable Fuel Standard (RFS): Mandated Biofuel Volumes (thousand barrels per day) Conventional biofuels of which ethanol Advanced biofuels
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
587
685
783
822
861
900
939
978
978
978
978
978
978
978
2022 978
587
685
783
822
861
900
939
978
978
978
978
978
978
978
978
0
39
62
88
130
179
245
359
473
587
718
848
978
1,174
1,370
of which cellulosic ethanol
0
0
7
16
33
65
114
196
277
359
457
554
685
881
1,044
of which biodiesel
0
33
42
52
65
65
65
65
65
65
65
65
65
65
65
of which other advanced biofuel
0
7
13
20
33
49
65
98
130
163
196
228
228
228
261
587
724
845
910
992
1,080
1,184
1,337
1,451
1,566
1,696
1,826
1,957
2,153
2,348
TOTAL RFS
However,theRFSalsosubjectsbiofuelstomeetingmandatorygreenhousegasemissionsreductions, comparedwithpetroleumfuels,measuredoverthecourseoftheirlifecycletoincludeeffectsfrom production,transportation,blendingandlandusechanges.RecentEPAanalysissuggestssomecornͲ based ethanol production would not meet a 20% emission reduction standard, though the criteria would apply to plants commencing construction after December 19, 2007 and natural gasͲfired plantsbuiltin2008Ͳ2009wouldgenerallycomply.Moreover,theEPAisstillseekingcommentson raising the federal certification of ethanolͲblended gasoline from 10% to 15%, which would overcome the ‘blending wall’ to ethanol absorption beyond 10%, by volume, of the gasoline pool. Based on our gasoline demand outlook, meeting RFS ethanol requirements – conventional and advanced–wouldtesttheblendingwallinthe2011Ͳ2012period. WhilethisreportdoesnotforecastUSrulemaking,itdoestakeacautiousviewondomesticsupply expansion based on these uncertainties, weak production economics and potential new capacity. Though we have potential capacity climbing to more than 930kb/d by 2012, we see US ethanol productiononlyreaching800kb/d,whichimpliesundershootingtheRFSforconventionalbiofuelsusage. Moreover, we see potential US cellulosic capacity at only 20kb/d by 2012, again below mandated use. Favourablechangestoproductioneconomics,technologyorgovernmentsupportimplysignificantupsideto ourprojectioninlinewiththeRFS,butfornowweretainacaponUSproductiongrowthbeyond2012.
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All of this suggests a growing scope for imports, particularly from Brazil, which continues to enjoy competitive advantages in terms of production costs, infrastructure and sustainability compared with other first‐generation biofuels. Higher than expected growth raised our 2008 baseline for ethanol production there by 100 kb/d versus last year’s projection. While capacity expansion delays and higher sugar prices may continue to undermine near‐term growth, the higher baseline and better medium‐term growth prospects put Brazil’s production 155 kb/d higher Americas Ethanol Trade for 2013 versus last year’s forecast. We have also kb/d 150 factored in higher biodiesel expectations for both Brazil and Argentina, which by 2013 should produce a combined 100 40 kb/d more than envisaged in last year’s outlook. 50 Of course, downside factors still persist. Notably, the US continues to maintain a 54 c/gal (about 14 c/l) 0 import tariff against Brazilian ethanol. In addition, Brazil’s Jan-07 Jul-07 Jan-08 Jul-08 Jan-09 own export infrastructure – storage, terminals and US Imports from Brazil/Caribbean Basin pipelines – must continue expanding to allow for greater Brazil Total Exports offtake opportunities outside the domestic market. Europe OECD Europe continues to represent the largest downward revisions in our forecast. While poor production economics persist, an increasing mélange of government policy may undermine the attainment of ambitious long‐term usage goals. The EU maintains a target of 5.75% renewable fuels, by energy content, in the transport pool by 2010 and a 10% renewable fuels mandate for 2020. Yet, the roadmap to achieve these goals has fragmented, both in terms of targets and fuel quality standards. Germany, accounting for 1/3 of Europe’s production, has (as of mid‐June) still not confirmed its 2009 usage requirement with the upper and lower houses of parliament differing over a proposal to reduce the biofuels quota from 6.25% to EU & Member State Biofuel Targets 5.25%. The government has already reduced exemptions As % of Transport Fuel Demand* on excise taxes for biodiesel. The UK and the EU-27 Netherlands have scaled back medium‐term targets. France Moreover, the European Commission recently assessed Germany Italy that the EU is likely to miss its 2010 target, with a 4% Netherlds. biofuels share looking more realistic than 5.75%. Spain
UK We have revised down our baseline 2008 OECD Europe % production by 25 kb/d, mostly due to lower than 0 2 4 6 8 * On energy content basis except UK expected ethanol volumes. Declining production in 2008 2010 where targets are volume based 2009 and growth the following year back to only 2008 levels leaves the 2011‐2014 outlook trending 30‐40 kb/d lower than last year’s. Based on our estimates of future European gasoline and diesel demand, our production estimate would satisfy only a 3% share of 2010 transport demand, implying significant scope for imports.
Yet, imports also face barriers. In March, the EU imposed duties on B99 biodiesel (pure biodiesel with a small quantity of diesel) from the US to stem the perceived unfair advantage garnered by imports stopping to add a small amount of diesel to earn a tax credit (so called ‘splash and dash’). As of early June, EU member states seemed to support extending the tariffs for up to five years. While the measures may have curbed about 25 kb/d of supplies coming from the US, they are
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unlikelytoboostnearͲtermEuropeanproductioncorrespondingly,giventheavailabilityoflower cost imports from Latin America and Southeast Asia. But impending proposals for biofuels to generategreenhousegassavingsof35%relativetopetroleummayeventuallyputimportstreams based on soybean oil or palm oil at risk. The European Commission is due in 2010 to put forth legislation which includes indirect landͲuse change impacts on biofuels emissions savings. Until then,marketaccessuncertaintiesremainforbothforeignanddomesticproducers. Asia-Pacific UncertaintiesregardingmarketaccessforSoutheastAsianexports,weakmarginsandlowerbaseline production numbers have precipitated downward revisions in most Asian countries. With better historicaldatafromChina,Asia’slargestproducer,wehavereviseddown2008productionthereby 20kb/d.Despitepotentialbiofuelscapacityof120kb/d(2/3ofthisinethanol)by2014andanethanol consumption target of 44kb/d for 2010, we have kept production levels moderate, reaching only 50kb/dby2014,givenChinesegovernmentpolicytolimitbiofuelsderivedfromfoodsources. IndonesiaandMalaysiahavecontinuedsupportfortheirbiofuelsindustries,adoptingmandateslast autumnwhichgraduallyincreasethrough2010.Theformer,however,hasthusfardelayedsettinga biodieselpriceformula,whichisnecessarytoallocatesubsidiestoproducers.Thailandhasrolledout ambitious targets for its ethanol industry. And Singapore biodiesel production should get a boost withthestartͲupofNeste’sbiomassͲtoͲliquidsplantbytheendof2010.Butgovernmentsupportfor ethanolinIndiahasallbutevaporated,withthepresentEͲ5mandatelookingshaky.WeseeOther Asia production growing by 50kb/d during 2008Ͳ2014, but a downwardͲrevised 2008 base and slowernearͲtermgrowthleaveour2013productionestimateslightlylowerthanlastyear’sforecast. Biofuels Continue to Provide a Relief Valve for Oil Markets While biofuels production remains a small part of oil product demand, its share should rise in the nextfiveyears.Ouroutlookshowsthatonanenergycontentbasisethanolshoulddisplace5.4%of gasolineandbiodieselshouldaccountfor1.2%ofgasoildemandin2014,whichishigherthanlast year’sendofperiodestimates.Still,whenlooking atgasolineandgasoildemandgrowthoverthe nextfiveyears,biofuelsaccountfor14.9%oftheincrementonanenergycontentbasis.Stripping outgasoildemandforheatingandpowergenerationuseimpliesthatbiofuelsshouldaccountforan evenhigherpercentagewithrespecttotransportationdemandgrowthintheforecastperiod. With annual growth of 120kb/d during 2008Ͳ2014, biofuels should contribute significantly to an otherwise sluggish outlook for nonͲOPEC supply in this outlook. The amount of crude oil that biofuels displace remains higher given that production of 1 barrel of gasoline may require 2 crude barrelsinahighlycomplexrefineryandmoreinasimplerplant.AssumingontheonehandaUSGC cracking refinery gasoline yield of 47.0% and, on the other, a NW Europe hydroskimming gasoline yieldof14.7%,annualethanolgrowthof70kb/d(afteradjustingforenergycontent)coulddisplace anything from 150kb/d to 475kb/d of crude for the 2008Ͳ2014 period. With most new ethanol comingfromtheUSandBrazil,thelowerendoftherangeseemsmorelikely. Still,asnonͲOPECsupplycontinuestostruggle,biofuelscanpotentiallyactasasignificantsupplybooster inoilmarkets.Theultimateextentofthatrolewilldependpartiallyonthedegreetowhichoilmarkets retighten,butalsoonthedegreetowhichgovernmentsjuggleenvironmentalconcerns,demandside incentivesandtheneedfortheindustrytorebalanceitselftowardsthelowestcostproducers.
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I NTERNATIONAL E NERGY A GENCY Ͳ M EDIUM ͲT ERM O IL M ARKET R EPORT Ͳ 2009 E DITION
REFINING AND PRODUCT SUPPLY Summary x
x
Globalrefinerycrudedistillationcapacityisprojectedtoincreaseby7.6mb/dduringtheperiod 2008 to 2014. China accounts for 32% of the total increase, with Other Asia accounting for another 22%. The OECD contributes a further 22% of the increase, driven largely by North America. In contrast to previous years, the Middle East contributes around 10% of the global increase,halfitspreviousshare,asseveralprojectshaveslippedbeyondthisreport’stimeframe. Refineries will also expand their upgrading capacity, thereby raising light product yields and loweringfueloilyields.Upgradingunitadditions,includingbothstandͲaloneunitsandcapacity atnewrefineries,areprojectedtoreach6.5mb/dby2014.Similarly,hydrotreatingcapacityis expectedtoincreaseby7.9mb/d,asrefineriesinvesttomeettightersulphurspecifications.
mb/d 2.0
Crude Distillation Capacity Additions
Crude Distillation Capacity Additions Other NonOECD
OECD
1.5 Middle East
1.0 0.5 0.0 2009 2010 2011 OECD Other Asia Other Non-OECD
x
x
x
76
2012 2013 2014 China Middle East
China
Other Asia
Lower global demand for oil has dramatically reduced refinery throughput levels in 2009. Utilisation rates have fallen in those areas where refineries are operated by commercially sensitiveowners;notablytheUS,JapanandEurope.Thisreductioninthroughputshascreated anoverhangofexcessrefiningcapacitythatwillpersistthroughoutmuchofthenextfiveyears andwilllikelyweighonrefinerymargins.Severalregionsfacetheveryrealthreatofsignificant reductionsinrefinerycapacityasthemarketseekstoredresscurrentimbalances. Refineries, particularly in Europe and the US, face ongoing investment requirements from tighter product specifications and environmental regulations. This will continue to absorb a significantproportionofplanned capitalexpenditureforlittlefinancialbenefit,atatime when cashflowisunderpressurefromtheweakermarginenvironment. Product supply balances point to the reͲemergence of tight middle distillate markets by 2011, despitecurrenthealthystocklevels,asglobaldemandgrowthresumesitslongͲtermtrend.Fuel oilmarketsareyetagainexpectedtoseesubstantialtightening,assupplypotentialislimitedby ongoing upgrading capacity additions and lower supplies of heavy/sour crude from OPEC. Anotherconstraintistheshifttoalightercrudeslatefromrisingcondensatesuppliesfromthe MiddleEast.Gasoline/naphthamarketsareexpectedtoseeareturntosurplusbytheendofthe MTOMRperiodastheaforementionedcondensatesuppliesboostlightdistillateproduction.
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Refinery Investment Overview Global refinery crude distillation capacity will increase by 7.6 mb/d by 2014. Non‐OECD Asia accounts for over 50% of the growth as a significant number of new refineries are expected to be constructed in the region, largely by India and China. China alone accounts for some 2.4 mb/d, almost one third, of the total increase. The OECD regions contribute a further 22% of the increase, driven largely by North America, as a few refineries in the US prepare for rising supplies of Canadian oil sands output. In contrast to previous years, the Middle East is seen contributing only 9% of the global increase, half its share in previous reports, as several large‐scale projects look to have slipped beyond this report’s timeframe. Increases to capacity in Africa, the FSU, non‐OECD Europe and OECD Pacific are more muted, reflecting a variety of factors. These include regional demand patterns and challenges in securing investment for projects that lack sound commercial justification. However, Latin America projections have been significantly revised up this year, following the award of engineering, procurement and construction (EPC) contracts for the 200 kb/d Abreu‐e‐Lima refinery in Northeastern Brazil. Brazil’s 150 kb/d Comperj Petrochemical refinery is now included in our estimates for 2014, but we continue to exclude Petrobras’ proposed 600 kb/d and 300 kb/d Premium I and II refineries as they are not expected to be completed before 2015. Global capacity growth averages 1.3 mb/d per year over the outlook period. Growth is particularly strong in 2009 at 1.8 mb/d, as several large new refineries in India and China, come on stream. A few of these were previously expected to start in 2008. Compared with last year’s projections there has been a significant degree of slippage across the board, the causes of which are discussed below in Refinery Investment: A Victim of the Global Recession?. Perhaps the most notable change to projections concerns the Middle East where several of the refineries previously included in our estimates have been delayed or cancelled. Despite the temptation to merely push completion dates back by 12‐18 months, we see the problems at some of them, notably the Al Zour project in Kuwait, as structural rather than temporary. kb/d
Crude Distillation Forecast Revisions
800
mb/d 6.0
Possible vs. Actual Capacity Additions Actual
Possible
400
4.0
0 -400
2.0
-800 2009 OECD
2010
2011
China
2012
2013
Other Asia
0.0 2009
2010
2011
2012
2013
2014
Refining margins have come under considerable pressure from weaker demand and cuts to crude supply made by OPEC countries. Furthermore, the loss of significant volumes of heavy/sour Middle Eastern crude and the tighter fuel oil markets highlighted in previous reports have combined to undermine upgrading spreads. The collapse in domestic diesel demand has forced US refiners to increase exports to Latin America and Europe, further pressuring the respective regional margin environments. As has been witnessed in the US gasoline market, incremental imports tend to depress marginal domestic crude runs. This suggests that European and possibly OECD Pacific refiners face a more challenging outlook in the near term as, for example, US diesel exports depress European runs. Middle East
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Global Product Balances Despitethedramaticreductionsindemandprojectionspresentedinthisreport,manyofthethemes highlighted in the December 2008 MTOMR Supplement remain unchanged. Partly this reflects the methodologyandassumptionsthatunderpinthisanalysis.Butitisalsothecasethatovertheentire MTOMR period the bias towards middle distillates as a source of growth remains. So too does the expectationthatfueloilmarketswillcontinuetotighten,despitethenowweakerdemandprojection. Undoubtedly, the assumption that OPEC continues to restrict incremental supplies of heavy/sour crudetobalancethemarketalsohasanimpactonprojections.Thenetchangeintheglobalcrude slate’s average API and sulphur suggests that residue supplies will tighten in years to come. Furthermore,ourassumptionthatrefineriescontinuetoaddnewupgradingcapacityandmaximise utilisationofexistingcapacityalsorestrictsthesupplyoffueloil.Thequestionthenbecomes:how will light and middle distillate markets attain a balance if refineries are unable to obtain sufficient feedstocktosustainthenecessaryutilisationofupgradingunits?
mb/d
API, degrees
Global Cumulative Oil Demand Growth by Product 2008-2014
4 Gasoline
Distillates
LPG & Naphtha
Fuel Oil
Other
Total
Global Crude Quality 2008-2014
Sulphur (%)
33.8
3
1.20
33.6
1.15
2
33.4
1
1.10
-
33.2
(1)
33.0
(2)
32.8
(3)
1.05 1.00 2008 2009 2010 2011 2012 2013 2014
2008
2009
2010
2011
2012
2013
2014
API
Sulphur (RHS)
Ofcoursethehugeimpliedfueloildeficitshownbelowcannotoccur.Therefore,suchascenariocan alsobeinterpretedastheemergenceofexcessupgradingcapacity,relativetotheavailablefeedstock. Consequently, it is likely that fuel oil to light product price spreads would remove the incentive to upgrade fuel oil, pressuring upgrading margins, and narrowing lightͲheavy crude differentials. This wouldreducedemandforfueloilasafeedstockbyrefineries,therebypartiallyredressingthemarket imbalance.Theimplicationsforthesupplyoflightandmiddledistillatessuggesttighterbalancesthan presentedhere.Realistically,sparehydroskimmingcapacityandheavy/sourcrudesuppliessuggesta fueloildeficitiseasilyremedied,albeitwithknockͲoneffectsforotherproductmarkets.
mb/d 0.5
Global Potential Product Balances 2008-2014
0.0 -0.5 -1.0 -1.5 -2.0 2008
2009
2010
Naphtha/Gasoline
78
2011
2012
Gasoil/Kerosene
2013
2014
Fuel Oil
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AnothercontributingfactortotightfueloilmarketsistheriseinNGLvolumes,highlightedelsewhere inthisreport.Totheextentthatthesesuppliesmeetdemandfrompetrochemicalproducers,they lower the call on exͲrefinery feedstocks such as naphtha and LPG. However, incremental NGL volumesalsorestricttheavailabilityofcrudetorefineries,asagrowingproportionofdemandismet outside the remit of crude/refined products. Higher crude supplies than those needed to balance aggregatedemandandtheexistenceofasignificantdegreeofsparerefiningcapacitysuggeststhat fueloilmarkettightnessneednotnecessarilyemerge.However,inthisreportweintendtoconsider ascenariowherecrudesuppliesarebalancedagainstdemand,toexamineareasofrelativetightness andoversupply. As already noted the most significant change in product balances occurs in the fuel oil market. Despitetheweakerdemandprojectionpresentedinthisreport,theimpactofOPECsupplycutsand the continued investment in upgrading capacity to severely curtail fuel oil supplies. The projected shiftoftheMiddleEast,fromitshistoricroleasanexportertoasignificantimporteroffueloil,drives muchofthischange.Similarly,theexpectedreductioninexportsfromtheFSUalsocontributesto the global tightening of fuel oil markets. Asian markets are also projected to increasingly rely on importstomeettheirprojecteddemandrequirements,notablyasmorecomplexrefiningcapacityis addedintheregionandtheshifttoalightercrudeslatebotheroderegionalproduction.Elsewhere, falling demand in OECD North America partially reduces the regional import requirement, while European imports increase on the back of lower domestic production and the assumption that refineryfeedstockuseincreases. ProductSupplyBalancesͲFuelOil PotentialEvolutioninRegionalBalance2008/2014 Thousandbarrelsperday
FSU 1117
NorthAmerica
Ͳ609
Europe
743
Ͳ330 Ͳ225
Ͳ464
MiddleEast Asia Ͳ17
Ͳ668 Ͳ768
Africa LatinAmerica 344
131
Ͳ1224
133
132
World Ͳ26
Ͳ1679
Despitecurrentoversupplyinmiddledistillatemarkets,theresumptionofstrongdemandgrowthis expected to outstrip refinery supply potential from 2011 onwards. In common with previous projections,thelongͲtermincreaseinmiddledistillateusageintransportationremainsasignificant contributortoprojectedtighteningofdistillatemarkets.
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Recently,thedramaticslowdownindieseldemandinAsia,mostnotablyChina,coupledwithaglobal shifttowardsmoredistillateproduction,hascontributedtotheoverͲsuppliedmarketconditionsin early 2009. Nonetheless, as the global economy recovers so too will diesel and jet fuel demand. Europe remains the largest importer of middle distillates. A more cautious European refinery throughputprojection(discussedoverleaf)raisesimportrequirementsbyaround50%toinexcessof 2mb/d. Similarly, North American distillate exports are now projected to shrink, due to lower refinery throughput projections. While it is evident that both regions have ample spare refining capacitytoproducemoredistillates,itisunclearwhethertheycaneffectivelycompeteforthecrude necessary to meet this potential. The dramatic decrease in OECD Pacific demand, compared with previousprojectionspushestheregiontobecomethebiggestnetexporterofkeroseneandgasoil, whileChinaandOtherAsiaremainbroadlybalanced. ProductSupplyBalancesͲGasoil/Kerosene PotentialEvolutioninRegionalBalance2008/2014 Thousandbarrelsperday
FSU 982
802
NorthAmerica
Europe
276 80
Ͳ1499
MiddleEast Ͳ2259
509
542
Asia 928
Africa
439
LatinAmerica Ͳ324 Ͳ206
Ͳ586
Ͳ308
World
Ͳ3 Ͳ622
Lightdistillatebalancesareexpectedtotendtosurplusbytheendoftheprojectionperiod,despitea nearͲterm tightening. Our assumption of lower North American crude runs raises the need for importstobalancetheregion,asdoestherisingethanolmandateintheUS.Muchofthegrowthin gasoline imports is driven by robust Mexican import growth, while US imports are expected to increase marginally. Higher European exports are driven by the pronounced slowdown ingasoline demandovertheperiodandthecollapseinnaphthademandintheregioninrecentmonths. Elsewhere,risingsuppliesofethanolfromLatinAmericaareassumedtoincreasetheregionallight distillatesurplus,muchofwhichisassumedtobeutilisedintheUS.MiddleEasternnaphthaexports areexpectedtoremainstrongonthebackofincreasedsuppliesfromcondensatesplitters.Butthe stronggrowthinregionalgasolinedemandwilllimittheincreaseinnetexports.Africansuppliesof naphtha, mainly from North African states is expected to increase, so too are the import requirementsofseveralWestAfricanstates,notablyNigeria,aslimitedrefinerysuppliesandsurging demandaremetbyEuropeanandAsianexportrefineries.
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ProductSupplyBalancesͲGasoline/Naphtha PotentialEvolutioninRegionalBalance2008/2014 Thousandbarrelsperday
FSU NorthAmerica
905
Ͳ 1166
154
Europe
155
1095
Ͳ 1549
MiddleEast 496
385
Asia
Ͳ678
Africa
LatinAmerica 433
Ͳ427
137
543
55
World 280
257
Regional Refinery Utilisation
Thedeclineinglobaldemandhasusheredinaperiodofmarkedlylowerrefineryutilisation.Notonly are regional utilisation rates now lower than previously assumed, the addition of 7.6mb/d of distillation capacity more than exceeds the projected demand growth over the period 2009Ͳ2014. Thissuggeststhataverageutilisationrateswillremainweakinsomeregionsthroughto2014.Asin the December 2008 MTOMR Supplement, we assume that more complex refineries sustain higher averageutilisationratesthanlesscomplexrefineries.Wealsoassumethatregionswhererefineries are operated by less commercially sensitive companies, such as NOCs or state refining companies, are less likely to adjust throughputs to reflect economic realities. Consequently, our bottomͲup assessmentofregionalcrudeprocessingsuggeststhatOECDregionswillbearthebruntofthelower throughputs. Europe and the Pacific are assumed to be particularly hardͲhit with smaller, less complexrefineriesshoulderingalargepartofthelowerruns,alongwithrefinerieswhichareheavily dependent on gasoline exports to balance output against local demand requirements. Rising NGL volumesalsofurtherpressurethroughputlevelsasthissourceofsupplylargelybypassesrefineries. 90%
RefineryUtilisationRates OECD
85%
NonͲOECD
80% 75% 70% 1Q2006
1Q2008
1Q2010
1Q2012
1Q2014
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Global Crude Throughput: Refiners ‘Play The Game’ Refinery throughput levels have plummeted in response to the collapse in oil demand in recent months. Perhapsunsurprisingly,utilisationrateshavefallenintheregionsthatcontainagreaterproportionofrefining assetsoperatedoncommerciallines,e.g.byindependentrefiners.Thisisbecausetheymustrelyontheir own actions to offset unfavourable economic conditions. This stands in stark contrast to regions where nationaloilcompanies(NOCs)arethepredominantoperators.Herecruderunshave,inmanycases,only decreasedmarginally,ifatall. Thelogicalconsequenceofthisreductioninthroughputshasbeenthecreationofasignificantoverhangof excess crude distillation and upgrading capacity. Furthermore, this report’s estimate of 7.6mb/d of new crudedistillationcapacityexceedsthe2008Ͳ2014projecteddemandgrowth,underthehighgrowthscenario. Hence,itseemslikelythatglobaloperatingrateswillweakenfurtheroverthecomingfiveyears.Thelower GDPscenariowould,barringfurtherprojectcancellations,resultinsignificantlyweakerdemandandhence evenlowerrefineryutilisationratesby2014thancurrentlywitnessedin2009. Theprojectedreductioninutilisationratesislikelytoforcerefineriesthatlackscale,haveahighexposureto product trade, or are uncompetitive in term of costs, to temporarily shutdown and potentially face permanent closure. However, given high exit costs, e.g., site remediation, such capacity is likely to face temporaryratherthanpermanentclosure. The recent performance of US refiners suggests that calls from several players for the industry to show ‘restraint’ by not increasing crude runs to unsustainable levels have been noted. Monthly US Energy InformationAdministration(EIA)datasuggestthatthroughputsatcatalyticcrackingunitshavealsobeencut back,implyingthatrefinershavesoughttominimisegasolineproduction. Without such restraint, the US would arguably be a net exporter of gasoline at this time rather than continuing to be the world’s biggest importer. Gasoline imports from Europe, the Middle East and Asia continuetoarrive,placingpressureongasolinecracksanddepressingnotonlyEastCoastrefinerycruderuns, but also interͲregional movements of gasoline. It would appear, therefore, that distillateͲfocused regions haveheldthecompetitiveadvantageoverUSrefinersgiventhestructuralstrengthinmiddledistillatecracks comparedwithgasolineinrecentyears.Butwiththerecentcollapseinmiddledistillatecracks,thereremains thepossibilitythatitisUSrefinerswhofacearelativelymorebenignoutlookinthecomingquartersandthat European and Asian refiners will shoulder a greater proportion of the anticipated run cuts in the next 12Ͳ18months. TheprojectionscontainedinthisreportexpectrelativelyweakOECDdemandtoweighheavilyonallthree regions,whiletheAtlanticBasingasolinetradeisexpectedtohamperUScruderuns.Furthermore,marginal importsofgasolineanddistillatefromtheFSUandAsiawillundermineEuropeancruderuns.
OECD North America NorthAmericancrudedistillationcapacitygrowthin2008Ͳ2014isbroadlyunchangedfromlastyear’s report at 1.2mb/d. However, this masks significant slippage at several key projects as capital expenditure (capex) plans have been slashed. The regulatory outlook in the US has tightened significantly with the new Obama administration, with capͲandͲtrade carbon pricing looking an increasinglylikelyprospectinthecomingyears. The collapse in US demand has significantly affected independent refiners’ investment plans. Integrated oil companies have also responded to the pressure on nearͲterm cash flow and the implicationsoflowerdemand.Motivahassloweditsplansfora325kb/dexpansionofthePortArthur, Texas refinery, while Marathon has deferred the heavy crude processing upgrade at its Detroit,
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Michiganrefinery,bothbyatleast12Ͳ18months.Consequently,itisnowexpectedthattheseprojects willcommencein2012and2013respectively.Similarly,theexpectedcompletiondateforBP’sWhiting refineryupgradetohandleagreaterproportionofheavyCanadiancrudehasslippedto2012.These three projects account for over 350kb/d of new crude distillation capacity alone and a significant proportionoftheregion’stotalupgradingcapacityaddition. Some projects appear to have been relatively unaffected by the economic slowdown. Marathon’s 180kb/dexpansionoftheGaryville,Louisianarefineryappearsontrackforcompletioninearly2010, whileTotal’sexpansionofthe230kb/dPortArthurrefineryappearsonscheduleforcompletionin 2011. Conversely, the BP/Husky Toledo heavy crude processing upgrade and expansion has been removedfromtheprojection,followingareviewoftheassociatedCanadianoilssandsproject. Projected Canadian capacity increase is limited to the expansion of the 100kb/d Saskatchewan refinery by Consumer’s Cooperative Refineries Ltd. Although there is only limited visibility on the project,itappearsontrackandweretaina2012completiondate.Mexicancapacityexpansionplans centre around the muchͲdelayed Minatitlan refinery, which we retain on a midͲ2010 completion date, based on comments from senior PEMEX officials. Further additions are now not expected before 2013/2014 when upgrades at the Tula Hidalgo, Salamanca, and Cardereyta refineries are complete. We continue to discount the prospects for a newͲbuild 300kb/d refinery within our projections.WhileitremainsobviousthatsuchaplantisneededifMexicowishestoreduceimports, therationaleforspending$9Ͳ12billionwhenexcessrefiningcapacityintheUScouldbeacquiredfor afractionofthecostappearsquestionable.
mb/d 1.0
North America Utilisation Rates
North American Capacity Additions 90% 85%
0.5 80% 75% 0.0 2009
2010
2011
2012
2013
2014
Crude Addition Desulphurisation Upgrading
70% 1Q2006 1Q2008 1Q2010 1Q2012 1Q2014
NorthAmericanrefineryutilisationisexpectedtodeclineslightlyfromthelowlevelsseentoday,as the recovery in demand is met by rising imports and ethanol supplies, rather than a rebound in domesticcapacityutilisation.Theincreaseinregionalrefiningcapacityimpliesthatcruderunswill recoversomewhatfromtoday’slowlevels,butweassumethatsmaller,lesscompetitiverefineries are likely to remain under pressure. Similarly the narrowing of upgrading spreads is also likely to depressregionalactivitylevels. Despite recent weakness, regional gasoline demand should recover its 2007 level by 2014, on the back of rising Mexican, if broadly static US demand. However, we expect a rising portion of this demand rebound will be met by ethanol and gasoline imports, limiting the call on refiners to raise runs.Therecentcollapseinjetfueldemandisexpectedtolargelyremovetheneedtoimportjetfuel during 2009. Net imports are expected to resume by 2011, on the back of the expected strong recoveryinjetfueldemand.
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mb/d
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North America Naphtha and Gasoline Balance
11.5
North America Gasoil and Kerosene Balance
mb/d 7.4 7.2 7.0 6.8 6.6 6.4 6.2
11.0 10.5 10.0 9.5 9.0 1Q06 1Q08 1Q10 Forecast Supply Demand
1Q12 1Q14 Reported Supply
1Q06
1Q08
1Q10
Forecast Supply Demand
1Q12
1Q14
Reported Supply
Similarly,netexportsofdiesel,whichhavesurgedinrecentmonths,areexpectedtocontractduring in the 2011Ͳ2014 period, as the resumption of robust demand growth erodes the current surplus. North America is projected to remain a net importer of residual fuel oil, despite the continued declineindemandwhichwillcreateagrowingsurplusofcrackedmaterial.However,ourassumption of continued use ofsignificant volumes of imported straightͲrun fuel oil inupgrading units suggest that,overall,theregionwillendtheperiodasmallernetimporterthancurrently. Refinery Investment: A Victim of the Global Recession? Althoughprojected refinery capacity growth may appear to have stayed relatively stable in aggregate terms,numerousprojectshavesuffereddelaysandindeedsomehavebeencancelled.However,much of the growth projected in recent years is driven by strategic rather than purely economic reasons. Consequently, one would expect many of these projects to be relatively unaffected by the economic downturn. In reality, a surprising number of these strategic projects have fallen victim to the deteriorationinfuturereturnsinrecentmonths. Severalstrategicreasonsforrefineryinvestmenthavebeencited.Firstly,resourceholderswhoseekto capture an additional share of the valueͲadded chain by becoming vertically integrated with downstream operations. Secondly, state oil companies seeking to meet domestic product supply requirements.Andlastly,somecountrieshavesoughttocreateanexportͲorientedmerchantrefining industry,mostnotablyIndia.Whileitistemptingtouniversallylabeltheseprojectsashavingsuffered at the hands of the global recession, in reality a multitude of factors lie behind the revised project timingsnowenvisaged. Undoubtedly, the dramatic decline in global demand and much reduced growth prospects has meant thatseveralprojectshavebeendelayedorcancelled.Globaldemandisnotexpectedtorecovertoits 2007leveluntil2012,evenunderthehigherofourGDPscenarios.InthelowerGDPgrowthscenario demandfailstoreachthe2007levelwithinthisreport’stimeframe.Despitethisdropindemand,the interveningperiodpotentiallyseessome6mb/dofnewrefiningcapacityenterservice.Theprospectof significantly higher excess refining capacity has reduced many project sponsors’ expectations of potentialreturns,giventhelikelihoodofsignificantpressureonmarginsinthecomingyears. Someprojectshavefailedtosecurefundingastroubleddebtmarketshavebeenclosedtoallbutthemost creditͲworthy corporations. Even those sponsors with solid balance sheets have paid substantial premiumstohistoricalnormstosecurefundsinrecentmonths,suggestingthathighercostsofcapitalwill threatenprojectswithlessrobustreturns.Hence,whenmeasuredagainstahighercostofcapital,many downstreamprojectsmayfailtoaddsufficientvalueforshareholdersandbedeferredorcancelled.
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Refinery Investment: A Victim of the Global Recession?
(continued)
Thedropinoilpriceshasalsounderminedmanyprojects’sponsorscashgenerationability.Numerous companieshavecutcapexplansastheyseektomaintainadegreeofcashneutralityintheseuncertain times. Both IOCs and NOCs alike have benefited from the bull market in oil prices in recent years, leavingthem,withstrongbalancesheetsorhealthypublicfinances.Withcashflowdownbymorethan 50%,thedeferralofexpenditureshasbecomeamuchmoreattractiveoption. Visible examples of this include Valero, the largest US independent refiner, whichhas cut 2009capex fromanoriginalguidanceof$4.5billiontojust$2.5billion,comparedwith$3.8billionin2008.Evenso, ValeroseesnonͲdiscretionarycapexataround$1.8billion,ifitistomeetenvironmentalregulationsand stayinbusiness,suggestingthatdiscretionaryspendingis75%beloworiginalexpectations. One positive impact of the economic downturn is easing tightness in engineering, procurement and construction markets, as demand for contractor services has wilted in recent quarters. Every project sponsornotirrevocablytiedtoexistingcostsforaproject(andquiteafewwhoare)willwanttocapture the benefit of these lower prices. Projects are being delayed or retendered in order to capture the possibility of lower costs and therefore higher returns. Delays of 6Ͳ12 months are emerging as companiesawaitlowerbidswhichfactorin,notonlythedeclineinsteelandconcretecosts,butalso lowercostsforfoundry,engineeringandprojectmanagementservices.Someindustrycommentators see refinery construction costs having already fallen to 2006 levels, with the prospect of further reductionstofollow.So,whileitistemptingtouniversallylabelprojectsashavingsufferedatthehands oftheglobalrecession,inrealitythebindingconstraintisnolongercontractormarkettightnessbuta lackofability,orwillingness,tofinanceprojectsasaggressivelyaspreviously.
OECD Europe European investment has been dramatically reduced since last year’s report. The impact of the economic slowdown on demand, the prospect of lower capital costs in the future and uncertainty overfuturecarbonpricinghaveallcontributedtolowerinvestmentprojections.Theprospectofa significantnumberofrefineryclosureshasincreasedrecently,withrisingdistillateimports,weaker gasoil cracks and increased competition for gasoline supplies to export markets, (e.g., the US) pressuringEuropeanmargins.Upwardsof2mb/dofrefiningcapacityinEuropemaybevulnerable toprolongedorpermanentclosureasitiseitheruncompetitiveinsize(below60kb/d)orcomplexity (theabilitytoupgraderesidualfueloilintolightandmiddledistillates)orboth. Investment plans retain a Mediterranean bias with projects in Italy, Greece, and the Iberian Peninsula dominating capacity growth. However, in common with other regions, the aggregate total now incorporates significant slippage compared with previous estimates. Notably, Repsol’s 110kb/d expansionofits SpanishCartagena refinery nowlooks likely to becompleted in2013, 18months later thanpreviouslyestimated,astheshortͲtermcashflowconstraintsandfallingcapitalcostsdelayprogress. NorthwestEuropeanrefineriesareexpectedtoaddlittlenewcapacitybeyonddieselhydrotreatingunits, followingthecancellationof,ordelayto,upgradingprojectsatPreem’sBrofjorden,Neste’sNaantaliand ConocoPhillips’ Wilhelmshaven refineries. Eastern European capacity increases will centre on the expansionofLotosGdanskrefineryandMOLgroup’sinvestmentintheDuna,Sisak,andRijekarefineries.
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mb/d 0.4
OECD Europe Utilisation Rates
OECD Europe Capacity Additions 90% 85% 80%
0.2
75% 70% 0 2009
2010
Upgrading
2011
2012
2013
2014
Desulphurisation Crude Addition
65% 1Q2006 1Q2008 1Q2010 1Q2012 1Q2014
European refineries face several structural issues that are assumed to limit throughputs in the coming years. Firstly, declining European demand has been exacerbated by the recent economic downturn, pressuring regional crude runs. Furthermore, a significant and increasing proportion of gasolineproductionmustbeexportedinanincreasinglycompetitivemarket,tocompensateforthe longͲterm decline in regional demand. Lastly, Europe’s bias towards middle distillates, which are currently oversupplied, is also likely to pressure product cracks and therefore margins, suggesting that refiners will struggle to raise runs in the short term. As highlighted above, a significant proportion of the region’s refining capacity is insufficiently complex or large, or both, and may struggletocompetewithnewcomplexexportrefineries,e.g.thenew580kb/dJamnagarexpansion, whichisbiggerthan12OECDEuropeancountries’totalcapacity. mb/d 5.0
7.9
4.5
7.4
4.0
6.9
3.5
6.4
3.0
5.9
2.5
5.4 1Q06
1Q08
1Q10
Forecast Supply Demand
1Q12
OECD Europe Gasoil and Kerosene Balance
mb/d
OECD Europe Naphtha and Gasoline Balance
1Q14
Reported Supply
1Q06
1Q08
Forecast Supply Demand
1Q10
1Q12
1Q14
Reported Supply
Fallingthroughputassumptionsreduceregionalgasolinesupplies,buttheregionshouldremainanet exporter, thanks to the collapse in naphtha demand and ongoing declines in gasoline. The lower throughputsalsocutintoregionalmiddledistillatesupplieswiththeresultthatnetimportsofboth dieselandkeroseneareexpectedtoincreaseinexcessof2mb/dby2014,whengasoilfeedstocksfor hydrotreatingaretakenintoaccount.Europeremainsanetimporteroffueloil,assumingongoing imports of Russian atmospheric residue for upgrading. Were economics to no longer support upgradingfueloilintolightormiddle distillates,thentheregioncouldbebroadlybalancedby the endoftheprojectionperiod.
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Joined-Up Thinking Refiners, notably in Europe and the US, but also elsewhere, have faced the challenge of reducing the environmental impact of their operations for many years. Tighter regulations aimed at cutting lead, sulphur, or benzene in gasoline, and sulphur in diesel/gasoil have driven much of the investment for more than a decade. Arguably, refiners have benefitted from higher margins than would otherwise havebeenachieved,asthetighterspecificationsraisedproductioncostsandlimitedexportrefineries’ abilitytocompete,withoutsimilarinvestmentinnewequipment,whichhasnotalwaysbeenasrapidly forthcoming. However, some recent changes to product markets have been less than favourable for refiners. The combination of mandatory biofuel blending targets, higher fuel efficiency in vehicles, and the introduction of carbon pricing has effectively cut demand, most notably for gasoline, and left some refinersstrugglingtosurvive.Thisimpacthasbeenexacerbatedbytheglobaleconomicrecession. To remove sulphur from light and middle distillates requires heat, pressure, and invariably hydrogen, theproductionofwhichisinexorablylinkedtoincreasedCO2emissions.AsoffͲroaddieselandheating oilmovetowardssulphurͲfreespecifications,refinerswillneedtoinvestinadditionaldesulphurisation capacity. This will necessitate significantly higher use of energy to produce fuels that meet the tighterstandards. InadditiontofuelͲspecificimprovements,refineriesthemselveshavebeenforcedtoreduceemissions ofparticulateͲmatterandsulphurandnitrogenoxides.Thisisalaudableandarguablynecessarystepto cut the environmental impact of refineries. So too is the reduction of CO2 emissions by large energy users,includingrefineries.However,recentlegislativeinitiatives,inbothEuropeandmorerecentlythe US, present refiners with several difficult choices. The strategic decision faced by refiners essentially boils down to this:should they continue to invest significant amounts in nonͲremunerative environmental improvements, look to sell refineries that require significant investment, effectively crystallisingtheimpairedvalueoftheassets,orcloseplantswherefuturereturnsnolongerjustifythe levelofcapex necessarytomeettighterenvironmentalregulations?Thedifficultyofthesechoicesis exacerbatedwhereuncertaintyoverfuturecarbonpricingleavesthemvulnerabletooperationalcarbon leakageandatasignificantdisadvantagetorefineriesinotherregions.Aweakermarginenvironment also compounds the difficulty of these choices as it undermines the cash flow to finance additionalinvestment. Regulatorsseekingacombinationofenergysecurity,sustainabledevelopmentandcompetitivenessrun the risk of failing to achieve all three if future capex requirements and additional costs from carbon pricingsignificantlyunderminerefineryprofitability.LowerCO2 andSOx/NOxemissionsareachievable. Butperhapsthequestionthattheyshouldbeaskingthemselvesisthis:aretheseloweremissionsgoing tobeattheexpenseoflowerdomesticcruderunsandrisingproductimports,ratherthantheresultof continuedinvestmentbyrefineriesinenhancedefficiencyandemissionsreductions?
OECD Pacific Although current projections suggest that South Korea will drive much of the regional capacity increaseoverthenextfiveyears,thebiggerissuefacingtheregionisthatoflikelycapacityclosures, notably in Japan, but possibly also in Australia. The structural decline in Japanese demand has acceleratedinrecentquarters,onthebackoftheeconomicdownturn.This,combinedwithashiftin China’srolefromaproductimportertoexporter,hasmeantthatuncompetitiveplantsintheOECD Pacificregionhavebeenforcedtocutrunsinresponsetomoredifficultregionaltradepatternsand weakermargins.
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Nevertheless investment by SK Corp., Hyundai Oilbank, and GSͲCaltex at their respective Inchon, Yosu,andDaesanrefineriesshouldboostcomplexityandlightproductyieldsduringthe2012Ͳ2013 period. Elsewhere, there is little sign of investment beyond that needed to meet tighter product specifications,withtheexceptionofthe35kb/dexpansionofNewZealand’sMarsdenPointrefinery andselectiveinvestmentinupgradingcapacityatahandfulofJapaneserefineries.
mb/d 0.2
OECD Pacific Utilisation Rates
OECD Pacific Capacity Additions 90% 85% 80%
0.1
75% 70% 65%
0.0 2009
2010
Upgrading
2011
2012
Desulphurisation
2013
2014
60%
Crude Addition
1Q2006 1Q2008 1Q2010 1Q2012 1Q2014
IncommonwithotherOECDregions,thePacificisexpectedtoseeregionalcruderunsremainunder pressure from a combination of weak demand, uncompetitive assets, and tighter environmental legislation. Contracting OECD Pacific demand is the largest contributory factor to our assumption that regional utilisation remains depressed through to 2014. It appears almost inevitable that refinersintheregion,notablyinJapan,butalsopossiblyAustralia,willneedtoclosecapacitythatis not competitive against newͲbuild export refineries elsewhere in Asia. Indeed despite lower throughputs assumed in this report, the significantly lower regional jet fuel/kerosene demand estimates published herein, would suggest we may not have been conservative enough on crude throughputassumptions. mb/d
OECD Pacific Naphtha and Gasolline Balance
mb/d
3.5
OECD Pacific Gasoil and Kerosene Balance
3.5 3.0
3.0
2.5 2.5 2.0 2.0
1.5 1Q06
1Q08
1Q10
Forecast Supply Demand
1Q12
1Q14
Reported Supply
1Q06 1Q08 1Q10 Forecast Supply Demand
1Q12 1Q14 Reported Supply
Theregionisexpectedtoremainanetimporterofnaphthadespitetherecentdemandcontraction from petrochemical producers, in addition to the structural decline in gasoline demand, driven by Japan.Despitelowerthroughputsregionalexportsofmiddledistillate,notablykerosene,aresetto increaserapidlyoverthe projection period. Thedegree towhichotherregionscanbetteruse the crude to meet domestic needs and/or export markets, might suggest that crude runs will be even lowerthanthescenariopresentedhere.Fueloilproductionisexpectedtodeclineonthebackofthe lowercruderunsandstartͲupofupgradingcapacityinKorea,butthePacificisexpectedtoremain broadlyinbalanceasdemandalmosthalvesfrom2008levelsby2014.
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China China remains the key driving force in global capacity additions with 2.4mb/d of new distillation capacityby2014.Althoughitshouldbenotedthathavenotassumedanycapacityimpactfromthe closure of teapot refineries in this estimate. The recent government stimulus package aimed at expanding refinery and petrochemical capacity offers the prospect of even greater additions if the planscometofruition,butfornowweretainarelativelycautiousoutlook. TheneartermseesaseriesofprojectscomingonͲstream,includingtherecentlycompleted240kb/d CNOOC Huizhou refinery and the 160kb/d expansion to the Sinopec/Saudi Aramco/ExxonMobil Fujianrefinery.Laterin2009afurther200kb/dwillbeaddedbyexpansionsatCNPC’sFushunand Dushanzi refineries. The shift to increase exports in the face of faltering domestic demand could raisethepressureonsmaller,lesscompetitive,refineriesintheAsiaPacificregion. China Capacity Additions
mb/d 2.0
China Refinery Utilisation Rates
90%
1.5
85%
1.0 80%
0.5 75%
0.0 2009
2010
Upgrading
2011
2012
Desulphurisation
2013
2014
70%
Crude Addition
1Q2006 1Q2008 1Q2010 1Q2012 1Q2014
Chineserefineryutilisationratesareassumedtoreverttoaround83%by2013,whichisweakerthan the 2008 peak of nearly 90%, but above the 1Q09 level of 80%. The assumed utilisation pegs productionoflightandmiddledistillatesatclosetoparitywithdomesticdemandprojections,thus continuing a policy of Chinese refiners meeting domestic needs. Such an assumption may not be borne out over time, as Chinese refinery activity appears to be more exportͲorientated in recent months.However,areinstatementofVAToncrudeimportsandproductexportsmaydampensuch activity.Nonetheless,therapidgrowthincapacity,alignedwithutilisationratesofaround83%will increasetotalproductsuppliedbyaround1.5mb/dthroughto2014. mb/d
China Naphtha and Gasoline Balance
3.3 3.0 2.8 2.5 2.3 2.0 1.8
mb/d
China Gasoil and Kerosene Balance
4.0 3.5 3.0 2.5
1Q06
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1Q12 1Q14 Reported Supply
1Q06
1Q08
1Q10
Forecast Supply Demand
1Q12
1Q14
Reported Supply
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FromalongerͲtermperspectivethetemporaryslowdowninlightdistillatedemandinrecentmonths islikelytomeanthatgasolineexportswillcontinueinthecomingquarters,followingthestartͲupof twolargeͲscalerefineries.Gasolineexportscouldfeasiblycontinuethroughuntil2012/3,although towards the end of the MTOMR period it is easy to envisage that regional runs will be raised to minimisetheneedforlightdistillateimports.Amorepronouncedsurplusappearslikelyinmiddle distillates during 2009Ͳ2011, as the marked slowdown in apparent diesel demand reverses China’s 2008netimports.TheconcurrentreductioninChinesejetfuelimportsintheshorttermalsoaddsto the overall increase in net middle distillate exports. Obviously higher utilisation rates than those assumedherewouldmaintainanetexportposition,butwouldrequirelowerrunselsewheretokeep crude markets balanced. China is expected to remain a net importer of fuel oil over the outlook period, although once again we would stress that our projections may be systematically underestimatingfueloilproductioninChina. Other Asia OtherAsiacontributessignificantlytotheglobaladditionofcrudedistillationcapacityoverthenext five years, with a total of 1.6mb/d likely. With the recent completion of the Jamnagar refinery expansion in India, and Vietnam’s 130kb/d Dung Quat, more than one third of the regional incrementisintheprocessofreachingfulloperatingrates.Subsequentgrowthincapacityislargely concentratedinIndia,withexpansionsatseveralrefineries,includingEssar’s110kb/dexpansionin late2010andIOC’sPanipat60kb/dincrease. ThisreportincludesIndia’s180kb/dBathindarefinery,developedbyHPCLͲMittalEnergy,whichwe hadpreviouslyexcluded.Progresstodatewouldsuggestthatthisprojectwillbecompletedinlate 2012,butwehavecautiouslyassumedastartͲdateofearly2013.BharatOmanRefineries’120kb/d Binaprojectisretainedforcompletioninearly2011. mb/d 2.5
Other Asia Utilisation Rates
Other Asia Capacity Additions 90%
2.0
85%
1.5
80%
1.0
75%
0.5 70% 0.0 2009
2010
Upgrading
2011
2012
Desulphurisation
2013
65%
2014
Crude Addition
1Q2006 1Q2008 1Q2010 1Q2012 1Q2014
RefineryutilisationinOtherAsiafallsinearly2009,partlyduetoevidenceofweakerrunsinsomeAsian countries,butalsoduetoourassumptionthatthestartͲupofcomplexnewrefiningcapacity,e.g.the 580kb/d Jamnagar expansion in India, cannibalises crude throughput from other refineries in the region. As refiners compete for crude we assume that the least competitive of the region’s hydroskimmingrefinerscutrunsindeferencetomorecomplexcapacityadditions.Hencetheoverall utilisation level falls by a proportionate amount. Nevertheless, the region’s strong capacity growth implies that supplies of light and middle distillate will rise. Furthermore, we also assume that less complex refiners will process an increasingly light crude slate, as a large part of the gas condensate projectedtobeexportedfromtheMiddleEastisassumedtoendupintheregion.
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mb/d
Other Asia Naphtha and Gasoline Balance
Other Asia Gasoil and Kerosene Balance
mb/d
2.8
4.40
2.5
4.20
R EFININGAND P RODUCT S UPPLY
4.00
2.3
3.80 2.0
3.60 3.40
1.8 1Q06
1Q08
1Q10
Forecast Supply Demand
1Q06
1Q12 Reported Supply
1Q08
Forecast Supply Demand
1Q10
1Q12 Reported Supply
The addition of exportͲorientated capacity in India raises the prospect of sustained gasoline and naphtha exports from the region over the medium term, as regional supplies outstrip projected demand growth. Conversely, heavy dependence on kerosene and gasoil to meet transportation needsisexpectedtokeeptheregionslightlyshortofrequirements,withjetsuppliesfromtheMiddle East likely to meet any shortfall. Fuel oil production, although not shown here, falls substantially from2009onwards,asthecombinedimpactofcomplexcapacityadditionsandincreasingvolumes ofcondensatereducerefinerysupplies. Middle East MiddleEasterncapacitygrowthhasbeensignificantlyreducedfrombothlastsummer’sestimateand theDecember2008update.Thecombinationofloweroilpricesandlowerdemandhashitprojects in the region particularly hard. Kuwait’s projects have suffered from domestic political infighting, somethingthathasafflictedtheupstreamforafargreatertimespan. Many of the projects previously mooted as being strategic have fallen prey to economic considerations.Notably,severaloftheSaudiprojectshavestalledattheprospectoflowercapital costs, as projects are deferred and retendered. LongͲrunning commercial negotiations between ConocoPhillipsandSaudiAramcocontinuetodragon,suggestingourcautiousapproachontheirJV Yanbuprojectwaswarranted,andwecontinuetoexcludeit. The December MTOMR Supplement update saw the removal of Kuwait’s 615kb/d Al Zour project and Total/Saudi Aramco’s 400kb/d Jubail refinery from our projections, following protracted uncertainty over likely completion dates. At the time of writing, these projects are not included within our revised and extended projections and we now also expect that Qatar’s 250kb/d Al Shaheen refinery and Saudi Aramco’s 400kb/d Ras Tanura expansion will not be complete before
mb/d 0.5
Middle East Utilisation Rates
Middle East Capacity Additions 90%
0.4 85%
0.3 80%
0.2 0.1
75%
0.0 2009
2010
Upgrading
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2012
Desulphurisation
2013
2014
Crude Addition
70% 1Q2006 1Q2008 1Q2010 1Q2012 1Q2014
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2015. These are thus also removed from our estimates. This leaves the region with only minimal additions from the ongoing Iranian capacity expansions at existing refineries and upgrading investmenttomeettighterfuelqualitystandardsinSaudiArabia. Furthermore, reports of the cancellation of contracts at Iran’s Persian Gulf Star Refinery at Bandar Abbaswouldsuggestthatthisprojectwillnotnowbecompletedwithinthe2014period.Wehave, therefore,removedthiscondensatesplittercapacityfromourestimates.Consistentwithprevious years we exclude the proposed Iranian heavy oil refineries, which notionally total 1.2mb/d. In commonwithlastyear,wediscountthecompletionofIPIC’s200kb/dFujairahrefineryandADNOC’s 420kb/d Ruwais expansion by 2015 due to lack of visible progress. Furthermore, despite reports that frontͲend engineering and design (FEED) contracts for several Iraqi grassroots refineries were awarded, we await more concrete progress on a number of fronts before we will include these projectsinourestimates.However,therehabilitationofexistingplantsmayofferenhancedproduct supplypotentialintheinterim,andtheadditionofseveralmicrorefineries(10Ͳ20kb/d)seemsmuch morelikelyinthecomingquarters. Burgeoningregionaldemand,especiallyforgasolineandfueloilsuggestrefineryutilisationwillrise significantlyinthecomingyears.Muchofthiscomesfromcondensatesplittingcapacitybeingmore fully utilised and debottlenecking investments in Iran and elsewhere allowing higher runs. Structural exports of naphtha are expected to continue unabated, while robust gasoline demand growth in countriessuchasIranandSaudiArabia,combinedwithourmorecautiousinvestmentoutlook,suggests thatimportsofgasolinecouldsurgeintheyearsahead,leavingtheregionamarginalnetexporterof lightdistillatesby2014.Jetfuelexportsareexpectedtoremainstableataroundcurrentlevels.Gasoil exportsareprojectedtofallinthecomingyears,asstrongregionalgrowth,thankstosubsidisedprices andtheassumptionofastrongreboundinregionaleconomicactivity,cutstheregionalsurplus.
Middle East Naphtha and Gasoline Balance
mb/d 2.2 2.0 1.8 1.6 1.4 1.2 1Q06
1Q08
1Q10
Forecast Supply Demand
1Q12
1Q14
Reported Supply
Middle East Fuel Oil Balance
mb/d 2.4 2.2 2.0 1.8 1.6 1.4 1.2 1Q06
1Q08
1Q10
Forecast Supply Demand
1Q12
1Q14
Reported Supply
The regional fuel oil balance is perhaps the most intriguing. The exclusion of Kuwait’s 615kb/d AlͲZour refinery deprives the region of a major source of fuel oil. We also assume that NOCs will exporttheheaviercrudegradestocomplexrefineriesinotherregions,givenprojectedtightnessin residual fuel oil markets and that less complex Middle East refineries will run an increasing proportionofcondensates.Consequently,theregionalbalancepotentiallymovesfromnetexports in2006/2007tonetimportsin2010.ThisscenarioisbynomeansassuredasNOCscanchoosetorun incrementalheavy/sourcrudethoughhydroskimmingcapacity.Thisisespeciallytrueassomeofthe power generators have stringent quality specifications that necessitate domestic crude grades to be usedtoproducethefueloilusedinpowergeneration.Alternatively,itispossiblethatanincreased levelofdirectcrudeburningwillemergeintheregiontooffsetthetighterregionalfueloilmarket.
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Africa Muchofthe talksurroundingnewAfricanrefiningprojectscontinuestobejustthat Ͳtalk.Ofthe potential 2.4mb/d of refining projects, the majority of which are grassroots refineries, only some 260kb/dofnewcrudedistillationisincludedinthisyear’sprojection.Algeriacontributesthelargest addition incrude distillation capacity, with a total of 180kb/d split between the Skikda and Arzew refineries. The single largest addition comes from the 100kb/d Skikda condensate splitter, which wasoriginallydueonstreaminearly2009,butseemsmorelikelytostartupattheendofthisyear, or possibly early 2010. In contrast, the lack of a FEED contract for the proposed 300kb/d Tiaret refinerypreventsusfromincludingthisprojectwithinourprojections. Afurther80kb/dofcrudedistillationcapacityadditionselsewhereinAfricaareaccountedforbythe 60kb/dTemarefineryexpansioninGhanain2011and20kb/daspartoftheMohammediarefinery upgrade project in Morocco. Mohammedia’s expansion includes the addition of a visbreaker and hydrocracker, significantly boosting middle distillate output. Lastly, we have pushed back Egypt’s Mostorod refinery upgrading project to 2013, following delays in securing funding, but given the underlying GDP assumption contained in this report, we see this project as realistically being completedwithinthenextfourͲandͲaͲhalfyears.SlowprogresstodateatprojectsinSouthAfrica, Libya,Angola,Mozambiqueandelsewhere,precludeusfromincorporatingincrementalcapacitiesin ourprojections,buttheawardofFEED/EPCcontractswouldincreasethelikelihoodofsuchamove.
mb/d 0.2
Africa Refinery Utilisation Rates
Africa Capacity Additions 90% 85%
0.1
80% 75%
0.0 2009
2010
Upgrading
2011
2012
Desulphurisation
2013
2014
70%
Crude Addition
1Q2006 1Q2008 1Q2010 1Q2012 1Q2014
Averageregionalutilisationhasbeenraisedtoaround80%followingstrongerthanexpectedcrude throughputs in recent quarters. Consequently, North African refineries are expected to sustain higher levels of naphtha exports than previously expected, despite gasoline demand growth in countriessuchasNigeria,beingstrongerthananticipated.Theregionisexpectedtoremainanet importerof gasoil,despitetheadditionalupgrading capacityhighlightedabove,asdemandgrowth outstripssupplyincreases. mb/d
Africa Naphtha and Gasoline Balance
0.9
mb/d 1.7
Africa Gasoil and Kerosene Balance
1.5
0.8
1.3 0.7
1.1 0.9
0.6 1Q06
1Q08
Forecast Supply OMR Demand
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1Q06
1Q08 Forecast Supply OMR Demand
1Q10
1Q12 Reported Supply
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Former Soviet Union With the exception of the 60kb/d Novopolotsk refinery expansion in Belarus in 2012, Russia accountsfortheentire340kb/dincreaseinFSUrefiningcapacity.Centraltothisprojectionisthe expectationthatRosneft’s140kb/dexpansiontotheTuapserefineryisonscheduleforcompletion in 2012 and that despite reports of its cancellation, the 140kb/d Tatneft refinery at Nizhnekamsk alsocomesonstreamatthebeginningof2012.However,wecontinuetoexcludeRosneft’s400kb/d Nakhodkarefineryascompletionbefore2015seemsunlikelyatthisjuncture. UpgradingadditionsfeatureheavilyintheFSUcapacityplans,witharound300kb/dofgasolineproducing units expected to be added over the MTOMR projection period and a further 250kb/d of distillate focusedunits.FurtherinvestmentsarelikelyifRussiamovesforwardwithplanstoreformexporttaxes, whichcurrentlyunderminetheincentivetoupgradefueloilintolightandmiddledistillates. mb/d FSU Refinery Utilisation Rates FSU Capacity Additions
1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0
85% 80% 75% 70%
2009
2010
Upgrading
2011
2012
Desulphurisation
2013
65%
2014
Crude Addition
1Q2006 1Q2008 1Q2010 1Q2012 1Q2014
FSU refinery utilisation rates are assumed to stay around current levels, with the Russian tax incentivestorefinedomesticcruderatherthanexportremaininginplace.Theimpactofinvestment in upgrading capacity is seen clearly in the rising supply of light distillates and declining fuel oil production.TheregionisprojectedtoremainanetͲexporteroflightandmiddledistillates,aswellas fueloil.Expansionofregionalupgradingcapacitywillalterthebalanceofexportstowardsahigher proportionofmiddledistillate,whilesimultaneouslycurbingvolumesoffueloilexports. FSU Gasoil and Kerosene Balance
mb/d
mb/d
2.5
2.0
2.0
1.5
FSU Fuel Oil Balance
1.0 1.5
0.5 1.0
0.0 1Q06
1Q08
Forecast Supply Demand
94
1Q10
1Q12 Reported Supply
1Q06 1Q08 1Q10 Forecast Supply Demand
1Q12 Reported Supply
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Latin America Latin American capacity projections are revised up from last year’s report with the inclusion of Petrobras’200kb/dAbreuͲeͲLimaand150kb/dComperjprojectsforcompletionin2013and2014 respectively.Alltold,theregionisnowexpectedtosee500kb/dofnewcrudedistillationcapacity. Thisisstillwellbelowthereportedpotentialforsome2.5mb/dfromnewrefineries.Theeconomic downturnhaspressuredplansbyseveralCentralAmericanstatesandVenezuelaforaseriesofboth domestic and international refineries. However, these were not included in previous projections, due to their lack of progress. The prospect of rising Brazilian crude production in the longer term from preͲsalt discoveries and Petrobras’ stated aim of matching downstream growth to upstream production, suggest that further expansion of the refining and petrochemical sector is likely. However,additionalprojectssuchasthe600kb/dand300kb/dPremiumIandIIrefineriesarenot seenasbeingwithinthisreport’stimeframe. mb/d Latin America Capacity Additions
Latin America Utilisation Rates
0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0
90% 85% 80% 75%
2009
2010
Upgrading
2011
2012
Desulphurisation
2013
70%
2014
Crude Addition
1Q2006 1Q2008 1Q2010 1Q2012 1Q2014
Utilisation rates are assumed to trend lower in the short term, but thereafter resume throughput ratesatabove80%ofnameplatecapacity.Thelackofamaterialincreaseinrefiningcapacity,ahead of the two Brazilian projects in 2013 and 2014 suggest that, despite rising volumes of ethanol supplies,LatinAmericangasolinemarketsmayyetrequireimportstomeetincrementaldemand,due to subsidised prices in Venezuela and Argentina. Middle distillate markets, notably gasoil, will continuetorequireseasonalimportsasdemandgrowthhereagainoutstripssupplypotential.Fuel oil exports are expected to fall as declining refinery output, following startͲup of upgrading units, erodesregionalsupplies. Latin America Naphtha and Gasoline Balance
mb/d 2.3
mb/d 2.6
2.1
2.4
1.9
2.2
1.7
2.0
1.5
1.8
1.3
Latin America Gasoil and Kerosene Balance
1.6 1Q06
1Q08
1Q10
Forecast Supply OMR Demand
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1Q14
Reported Supply
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1Q08
Forecast Supply OMR Demand
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PRICE FORMATION Overview In the 2008 Edition of the MTOMR, it was argued that price levels are set primarily by oil market fundamentals,whileacknowledgingtheimportanceofamyriadofotherfactorswithvaryingdegrees of influence over time. Perceptions about future (as opposed to prompt) supply and demand, geopoliticalrisks,exchangeratevariationsandshiftsinfinancialflowscanthereforeacttoaugment basicpricesignalsderivingfrompromptmarketfundamentals.Somecommentatorshaveexpressed viewsbroadlyinagreementwiththisposition,whileothersarguethatpricesdivergedfromthelevels warrantedbyfundamentalssincefinancialplayersbroughtlargesumsofmoneyintotheoilmarket. Theaimofthissectionistwofold:first,toprovideabriefoverviewofthecurrentstateofarguments on oil price formation; second, with the benefit of recently released data, to revisit some of the fundamentalfactorsexaminedinthe2008EditionoftheMTOMR. Oneyearon,datacaptureandcoverageunfortunatelyremainincompleteforboththephysicaland financial markets. As prices have started to climb again from earlyͲ2009 lows, it is all the more important to ensure greater disclosure to allow price changes to be better understood. Identifying andexaminingtoday’sprice driversis essentialto informviews onthefutureshapeofthemarket andtoguideinvestmentdecisionsaccordingly. The Speculation Versus Fundamentals Debate Persists OilpricesreachedrecordhighlevelslastJuly,bothinnominalandrealterms,withthebenchmark WesternTexasIntermediate(WTI)futurescontractpricetopping$147/bbl.Oilpricesrosesteadily from early 2004 but the 18Ͳmonth period beginning January 2007 saw prices surge by more than 150%.SucharemarkablerunͲupinoilpricessparkedadebateoverwhetherornotoilpricesmight be driven by factors that are inherently unrelated to oil supply and demand fundamentals. Argumentswereputforwardthat‘speculators’,ratherthanoilmarketfundamentals,werethemain culpritforthehighoilpriceandbetterregulationtocurbspeculationwasneededtobringdownthe pricelevel.ThePriceFormationsectioninourlastMTOMRattemptedtoassessthevalidityofsuch arguments. But the situation has subsequently changed dramatically; oil prices had collapsed by more than 75% by year end, from north of $140/bbl to the mid $30s before rallying to $70/bbl in early June, again seemingly often defying oil market fundamentals on their own. In short, the ‘speculation’ argument has been just as pronounced during the downͲcycle and recent uptick as it was when oil prices were breaking record highs. The IEA has continued to monitor market developments both on fundamental and nonͲfundamentals factors and reiterate our opinion that pricerisesorfallstendtobemultifaceted,ratherthandrivenbyasinglecause. $/bbl
Crude Futures Front Month Close
150
110
110
90
90
70
70
50 Source: Platts
30 Jun 07
96
Benchmark Crude Prices
130
130
50
$/bbl 150
Dec 07 Jun 08 NYMEX WTI
Source: Platts
30 Jun 07 Dec 08 Jun 09 ICE Brent
Dec 07 Jun 08 WTI Cushing Dubai
Dec 08 Jun 09 Dated Brent
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Speculators – Who Are They? SoͲcalled speculators have frequently been blamed for causing distortions in commodity markets, while,simultaneously,theyareconsideredapivotalconstituentofawellͲfunctioning,liquidmarket thatfacilitatespricediscovery.Althoughstudiesaboundseekingtoanswerthequestionofwhether ornotspeculatorsplayamajorpartinoilpriceformation,nodefinitiveorcompellingconclusionhas beenreached. Thenatureofspeculatorsandthewaytheyenterandinteractwiththemarketwereexaminedlast year. Yet, speculation, in practice, is very hard to detect in the market place and the precise classificationofspeculatorsmayindeedbeanunachievabletask.Abroaddefinitionofspeculators wouldbethosemarketparticipantswhohavenointerestinoilasaphysicalcommodity,whilesome may distinguish (mostly) longͲonly, longͲterm investors and index funds from active speculators engaging in both short and long deals, adjusting and unwinding their positions sometimes instantaneously. According to the US Commodities and Futures Trade Commission (CFTC), participantsinexchangeͲtradedcommoditymarketsareclassifiedintotwocategories–commercials, who are considered to be primarily hedging risk and nonͲcommercials, who could be called speculators. While the CFTC aims to classify participants according to the nature of their trading, practicalconstraintspreventitfromcapturingindepththepreciseessenceofeachentity’sdealings, especially those of swap dealers, who ‘swap’ derivative contracts tailored to customer needs and hedge the associated risks on the futures exchange. Notably, a substantial portion of passive investorsarenowknowntogaindesiredexposurestocommoditiesthroughswapdealers. Alsoimportanttonoteisthatspeculativeactivityisnotconfinedtothosewithnonaturalinterestin oilasaphysicalcommodity.Tradersatoilcompanies,refinersorindustrialconsumersmayengage intradesandtakepositionswhichcouldbefullyspeculativeinnature,basedontheirownviewsof themarket.Arefinercouldbuy,forinstance,athreeͲmonthfuturescontractbasedonabeliefthat thespotpriceinthreemonthstimewillbehigherthanthecurrentthreeͲmonthfuturespriceplus theinterestcostofthedownpayment(margin)forthefuturescontract.This,strictlyspeaking,isa formofspeculationasthepurchaseofthefuturescontractisnotpurelyforthehedgingofaprice risk. Understanding what different observers mean by speculators is therefore important when analysingvariousargumentsonthesubject.Generally,whencommentatorsrefertospeculators,the kindsofmarketparticipantstheyhaveinmindconsistofindexfundsandpassiveinvestorsaswellas moreapparentspeculativeplayerssuchashedgefundsandtraders‘betting’(i.e.takingrisk)onrising or falling prices. A stark difference exists, however, between ‘passive’ and ‘active’ investors. The formerallocateacertainamountofcapitalfromtheirportfoliostocommoditymarkets,basedona historicalcorrelationofreturnsoncommoditieswiththoseofotherassetclassessuchasbondsand equities. This type of investor, therefore, sometimes takes positions which are at odds with what immediate fundamentals suugest. Active investors, on the other hand, tend to act on percieved fundamentals, reading signals from various economic indicators as well as oil market data. In this section,werefertospeculatorsasbeingthosewhodonotintrinsicallyhavephysicalpricerisksbut takeonrisksbyenteringtheoilmarket. The ‘Speculation View’ The ‘speculation view’ of oil price formation holds that a growing participation in the oil futures market of nonͲcommercial, especially financial, players can push the price above the level that should result from purely fundamental factors – speculation causes prices to ‘overshoot’ or
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‘undershoot’.Mostproponentsofthisviewcitethetrendofagrowingamountofmoneyplacedin and out of commodities, oil in particular, by passive investors – index funds, pension funds and universityendowments–aswellasmoreactivetypesofinvestorslikehedgefunds,whichseemsto havecoincidedwithpricemovements.Commodities,indeed,havebecomeawellͲrecognisedasset classwithininvestmentportfoliosoffinancialinstitutionsasameanstodiversifyinherentriskssuch asinflation,dollardepreciation(forUSinvestors)orequitymarketweakness.Althoughthereisno officiallyreporteddataonthe totalamountofmoneyinvested incommodityindicesanddifferent institutionsapplydifferentmethodologiestoderiveanestimate,thecumulativeamountinvestedby various funds in commodity indices is said to have quadrupled from around $75 billion in January 2006toalmost$300billionlastJuly,withcrudefuturestakingalargeportionofthatamount.Asfar as the oil market is concerned, LCM Commodities, for instance, estimates that Asset Under Management(AUM)tiedtocrudefutureswascloseto$125billionwhenoilpricesreachedhistorical record levels last July, of which some $40 billion was additional inflows since January 2006. The trendandthedirectionofcapitalflows,unsurprisingly,reversedinthelatterhalfof2008withAUM fallingbelow$20billion,withatotaloutflowofalmost$50billionoverthesameperiod. Intermsofthenumberofcontractstraded,nonͲcommercials–mostlyfinancials–arealsosaidto outweigh commercial or physical players, buying or selling far more paper barrels than physical playersdo.However,alookatnetpositionsofnonͲcommercialentities,asreportedbytheCFTCon aweeklybasis,doesnotrevealanysoundcorrelationwithprices. NYMEX WTI Futures Mth1 '000 $/bbl Contracts Non-Commercials' Net Position 150 160 120 140 90 120 60 100 30 80 0 60 -30 Source: CFTC, Platts 40 -60 20 Dec 06 Jun 07 Dec 07 Jun 08 Dec 08 Jun 09
Funds' Asset Under Management (AUM) tied to Crude Futures
Source:LCMResearch
No n-co mmercials' net po sitio n NYM EX WTI M th1
Althoughsomefinancialinstitutionsactivelyengageinphysicaltradingofoilbycontrollingstorage facilities,theconventionalpathforfinancialsorspeculatorstoentertheoilmarketisthroughfutures contractswhichdonotresultinphysicaldelivery.Optionsandotherderivativesintheoilmarket, insofar as it resembles equity markets, can influence physical spot prices of underlying assets through, for example, a phenomenon known as ‘stockͲpinning’. A case of stockͲpinning can be observedwhenwritersofinitiallyͲoutͲofͲtheͲmoneycalloptionsbuytheunderlyingassetastheprice of the asset moves closer and closer to the strike price of the options. This can lead to herding amongagroupoffinancialplayersinthemarket,creatingaselfͲfulfillingprophecyuntilthepricehits the strike price. The oil market, however, is inherently different from equity markets in that it is finite,andthemechanicsofhowfuturesandderivativemarketswithoutphysicaldeliveryaffectthe spotpriceofphysicaloilneedcarefulexamination. When themarketisincontango (forwardpricelevelsareabovepromptprices),futurespricescan haveadirectimpactonspotpricesthroughcashͲandͲcarry,orstoragearbitrage,whichwouldfavour stockbuilds.Similarly,ifthespotpriceispulledupbyspeculation,basiceconomicconceptstellus
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that excess supply needs to be absorbed into storage, or be taken out of the market through hoardingonthepartofsuppliers.Indeed,anypriceabove(orbelow)theequilibriumwarrantedby supplyanddemand,ifcausedbyspeculation,mustbeexplainedbyanactofhoardingintheformof inventory builds or withholding production. It was suggested in the last MTOMR that there was no evience of exceptional stockbuild in the runͲup in prices. It is instructive to revisit some of the key fundamentalpricedriverswhichwerehighlightedlastyear,includingstocks,toseeifthisremainstrue. Oil Market Fundamentals Revisited Stock Levels Stocks are built up for a variety of reasons. To understand the mechanism through which stocks build, it is helpful to draw a distinction between intentional inventories and unintentional stockͲ build. The latter may be caused by excess supply, shrinking demand or both. The former is more complicatedasitcouldinvolve,interalia,mandatorystockholding,plannedmaintenance,seasonal considerationsandspeculationaboutfutureprices.TheMTOMR2008Editionusedasimplemodel ofsupplyanddemandcurvestoillustratehowanartificiallyͲelevatedpriceshouldbesupportedby inventorybuildͲup(orhoardingonthesuppliers’part),ifsuchapricelevelistobesustained. Recent data confirm the earlier finding that OECD stocks, although increasing from May onwards, werenotexceptionallyhighintherunͲupto$147/bbl.TheOECDisofcourseonlyaround50%ofthe global market in consumption terms and there is a lack of data with regards to nonͲOCED stock levels.TheOMR,nevertheless,seekstocapturechangesinnonͲOECDstocksinthemiscellaneousͲ toͲbalanceelementofitsfundamentalsestimates.Apositive‘miscellaneousͲtoͲbalance’couldimply a degree of nonͲOECD stockbuilds, but also potentially overstated supply, understated demand or somecombinationofthethree.ThelatestOMRdatafortheAprilͲJune2008perioddoimplysome inventory builds in nonͲOECD regions – 0.6mb/d, or 1.6% of nonͲOECD demand. In addition, recentlyͲreleased, albeit partial, data on Chinese oil inventories reveal that there were moderate stockbuildspreceedingtheOlympicGames. mbbl 2,750
OECD Stocks & Prices
130
2,700
110
2,650
90
2,600
70
2,550 2,500
$/bbl 150
50 Source: IEA, Platts
30
Jan 07 Jul 07 Jan 08 Jul 08 Jan 09 OECD Stocks
NYMEX WTI Front Month
mb/d 0.8 0.6 0.4 0.2 0.0 -0.2 -0.4 -0.6 -0.8 -1.0
'Miscellaneous to Balance'
1Q2007 3Q2007 1Q2008 3Q2008 1Q2009
Global crude inventories started to accumulate in the second quarter 2008, with the pace of build pickingupafterAugustasdemandandpricesbegantoslide.However,highlevelsofstockbuildsdo notnecessarilyresultfromspeculationperse.Rather,whendemandiscurbed,itiscommontosee inventoriesbuildupasbottlenecksariseattheexistinglevelofproductionandrefineryruns.Indeed, thisiswhatseemstohavehappenedafterAugust 2008asglobaldemandforcrudeoildiminished sharply. Another noticeable phenomenon during the same period was that the market entered heavycontangoandthereemergedclearopportunitiesforarbitrageurstobuyspotandsellforward.
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Onlandstoragefacilitieswerequicklyfilledandmanyidlevesselswerecharteredforfloatingstorage withoutapredefineddestination.Manyanalyststhereforesuggestedthattherewasaclearcaseof ‘speculation’, keeping the oil price higher than the levels warranted by the weak fundamentals. Strictlyspeaking,however,itisarguablewhethertheterm,speculation,includesanactofarbitrage, which by definition is riskͲfree, while speculation must, again by definition, entail a degree of risk takingandmakingbetsonthefuturedirectionofoilprices.
Arbitrage – Cashing in on a Contango Arbitrage is a common trading strategy in options and derivatives markets where prices for various optionsorderivativesonthesameunderlyingassetaremisaligned.Storagearbitrageintheoilmarket isoneofthemostobvious,straightforwardtradingtechniqueswhicharbitrageursusewhenthemarket isincontangotogainprofitswithouttakingonpricerisks.Earlierthisyear,thecontangoforaNYMEX WTIthreeͲmonthforwardcontractreachedaround$10/bbl;oilwasavailableonspotat$40/bbl,while, threemonthslater,thesamegradeofoilwasworth$50/bbl. $/bbl
NYMEX WTI Front Month Spreads
2.0
Backw ardation
0.0
$/bbl 1.5 0.5
-2.0
ICE Brent Front Month Spreads Backw ardation
-0.5 Contango
-4.0
-1.5
-6.0
-2.5
-8.0
-3.5 Source: Platts
-10.0 Mar 08 Jun 08 Sep 08 Dec 08 Mar 09 Jun 09 WTI M1-M2 WTI M2-M3
Contango Source: Platts
-4.5 Mar 08 Jun 08 Sep 08 Dec 08 Mar 09 Jun 09 Brent M1-M2
Brent M2-M3
Aslongascreditconditionspermit,anarbitrageurwouldexploitthiswidespreadandbuy1,000bblof crudeoilatthespotpriceandsella3Ͳmonthfuturesat$50/bbl.Thearbitrageurhastopay$40,000for theoilbought,andarefundable$3,000asamargin totheexchangeforthefuturescontract,aswellas SellingPrice $50,000 $40,000 $40/bblx1000bbl CostofOil storageandinsurancecosts.Assumingtheinterest Interest* $582 $46572x5.0%x3/12 rate of 5.0% p.a., the storage cost of $1.5/bbl per $4,500 Storage 1000bblx$1.5/bblx3months month, and the insurance premium of 0.5% on Insurance $825 $50,000x110%x0.5%x3months 110% of the cargo value, this arbitrage strategy TotalCost $45,907 (*includesinterestonmarginat16.43%,butignores yieldsmorethan$4,000ofprofit,regardlessofwhat Profit $4,093 interestonstorageandinsurancecharges) thespotpricemaybeinthreemonthstime.
Spare Capacity Spare supply capacity serves as an important indicator of market tightness because it shows how muchsupplycantheoreticallyincreasewithinashorttimehorizon,facedwithgrowingdemandora supplydisruptionelsewhere.Justastheincreaseinfinancialflowsinto(andtheoutflowsfrom)the oilmarketcoincidedwiththepricerise(andfall),thetightnessimpliedbyOPECsparecapacitycan alsoprovideaplausibleaccountofhowthefundamentalshavechangedandprovideaclueastowhy oilwaspricedsohighinthefirsthalfof2008,fellsome75%inthefollowingsixmonthsandisnow hoveringaround$70/bbl.
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Global Oil Balance
m b/d 88
$/bbl
87 86 85 84 83 1Q06
3Q06
1Q07
Supply
3Q07
1Q08
3Q08
Dem and
1Q09
P RICE F ORMATION
OPEC Effective Spare Capacity m b/d & Price Movements
140 120 100 80 60 40 20 Source: 0 2006
7 6 5 4 3 2 1 0
IEA, Platt s
2007
2008
2009
OPEC 'Effective' Spare Capacity Dated Brent
OPEC effective spare capacity was stable at around 2.5 mb/d between January 2007 and April 2008 but the following months witnessed it fall sharply from 2.3 mb/d in April to 1.5 mb/d in July as production increased. During the latter period, the oil price climbed by about $35/bbl to reach the historical high of $147/bbl. In stark contrast to the pre‐$147/bbl period, OPEC spare capacity has since continuously risen – it has more than quardrupled by April 2009, due largely to OPEC’s decision to curtail production amid the global economic downturn and steadily weaker demand. A look at how OPEC spare capacity evolved over the last 12 months helps to consolidate the fundamentals view that the tight market balance encouraged the run‐up in prices, while the economic downturn and demand collapse help explain the sharp fall. Coupled with low price elasticity of both supply and demand, limited spare capacity tends to focus the ability to control production to meet OPEC’s price or inventory objectives in the hands of a few suppliers with the capacity to adjust production. Inelastic Supply and Demand The price elasticity of demand and supply for oil, at least in the short run, is very low. On the supply side, developing oil fields for commercial operation is inherently a long‐term business, often taking five to 10 years to develop and produce oil from a new project. Price volatility and uncertainty about future demand levels can also lead producers to take a cautious approach to investment in new capacity, both upstream and downstream, limiting the supply side response to demand shifts and exaggerating the degree of price movements necessary to choke off demand. Additionally, shortages of specialised labour, equipment and service capacity, rising costs, project slippage and tightening fiscal and access terms all played a role in slowing supply expansion despite rising prices. Sharply higher upstream spending during 2000 to 2008, therefore, did not result in a proportional increase in supply capacity. Some factors that limit the responsiveness of demand to price changes are more subtle and sometimes policy‐driven. A large portion of oil demand, especially in advanced economies, stems from fuel use in the transport sector but modal shifts (away from cars to trains, for example) seem to occur very slowly. The problem is compounded by the fact that a pass‐through of increased crude oil prices is often distorted (due to taxation) or prevented (due to government subsidies), further delaying or weakening the demand response. For example, retail diesel prices in China were regulated and kept artificially low despite rising demand prior to the Olympic Games, when the crude price rose to $147/bbl. When the global economy was in a buoyant state with key emerging economies such as China and India experiencing a rapid expansion, rising prices were arguably inevitable on the back of supply tightness and various factors stopping cost feed‐through from the wellhead to the end‐user. That said, some advanced economies where the cost pass‐through was more apparent (the US, for example) did indeed see oil demand weaken sharply due to high prices.
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Demandexpansion isillustratedby arightwardshiftininthedemand curves(DtoD').Inbothcases, quantitydemanded(andsupplied) increasedby3%(fromQtoQ'),yet thepriceincreasesfromPtoP' differconsiderably,dependingon theslopeofthesupplycurveͲ i.e. thepriceelasticityofsupply.
Elasticity Matters* Low elasticity on both the demand and the supply side is a clear recipe for high volatility of marketͲclearing prices. One common critiquebyproponentsofthespeculationperspectiveisthat,duringa pricejumpofover55%,recordedinsevenmonthsfromJanuaryto July2008,therewasonlyaslightincreaseinrefinerycrudedemand, estimated around 1%. It is, indeed, striking that one percentage pointdemandgrowthcouldcausea55%riseinprices.Yet,thehighly inelasticshapeofthesupplycurvecouldeasilywarranta55%price hike with just a 1% expansion in demand. One can back out an impliedpriceelasticityofcrudeoilsupplybasedonthegivenchanges in demand and price; a 1% demand expansion and a 55% price increaseimplyapriceelasticityofcrudeoilsupplyof0.0227.So,for thepricetomove10%,demandneedonlyfluctuatebyalittleover 0.02% – a figure not wholly out of line with oil supply elasticity estimatesfrompreviousstudies,of0.02to0.05. Furthermore, the low price elasticity of supply can also help to explainthesharpfallintheoilpriceoverthefourmonthsfollowing the peak of $147/bbl last July. Critics of the fundamentals view argued earlier this year that the 75% price drop by the end of December2008couldnothavebeendrivensolelybyfundamentals andinsteadattributedittoanoutflowofmoneyfromcommodities byindexfunds,whichproponentsofthespeculationviewestimate amountedtosome$70billion,citingthatgasolinedemandoverthe sameperiodonlyfellby5%. Takingthe5%declineingasolinedemandasaproxyforthecrude oil demand change in that period, it is possible to calculate how muchthepriceshouldchangegiventhepriceelasticityofsupply of0.02.Thecalculationshowsthatthe75%fallwasinfactsmaller than the low elasticity would warrant; a 5% demand contraction wouldimplya90%dropinthepricetoclearthemarket.
Price D
D'
S
P'
P
Q
Price D
Q'
Quantity
D' S
P' P
Q
Q'
Quantity
Stockbuildsor supplywithdrawal.
Price
S'
S
P'
Sinceinitialproductdemandfallsareusuallyabsorbedintoinventories andtheimpactoncrudedemandisoftenlagged,theextentofcrudeoil demand contraction was most likely smaller than 5%, which would bringthechangeinpricenecessitatedtoclearthemarketclosertothe actualpricedropof75%.
P
Similarlyonthedemandside,lowpriceelasticityimpliessmallcuts in supply would warrant a large increase in the price to clear the market.Simultaneously,ifthepriceiselevatedoutofthemarket equilibrium, requiring inventory builds or hoarding, the actual amountthatneedstoexitthemarketmaybeverysmall.Common claimsthatlastsummer’soilpricesof$140/bblweresome30Ͳ40% above the level warranted by market fundamentals would imply thatsome3Ͳ4%ofglobaloilsupply,or2.6Ͳ3.5mb/d,wascurtailed throughstockbuildsorkeptintheground,assumingthattheprice elasticityofdemandisͲ0.1%.Thisclearlywasnotthecase.
Price
D Q' Q
Quantity
Stockbuildsor supplywithdrawal.
S'2
S
P'
P
D2 Q'2
Q
Quantity
* Some demand and supply numbers here are based on papers from leading proponents of the speculation view and are not necessarilyinlinewithIEAestimates.Theseinclude‘The2008CommoditiesBubble’(MichaelW.MastersandAdamK.White).
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The ‘Peak Oil’ Thesis, Geopolitics and Access to Oil Arguably,perceptionsaboutoilsupplyinyearstocome,canalsomateriallyaffectfuturespricesand, byarbitrage,sometimesspotprices.Acriticaldimensiontoconsiderinthisregardisthatthebulkof oilsupplyandreservesareconcentratedinareasandcountriesthatpresentadegreeofgeopolitical uncertainty.Uncertaintyisakeyingredientofmarketvolatility;variousissues–threatsofstrikes, terroristattacks,warandpoliticalinstabilityingeneral–inanumberofkeyproducingcountriessuch asNigeria,Iraq,IranandVenezuelahavesparkedfearsaboutstablefuturesuppliesandlikelyledto higherlevelsofstockpilingthanmightotherwisehavetakenplace,resultinginanupswinginprices. EquallyimportanthasbeenadecliningtrendinoilproductioninsomeofthekeynonͲOPECcountries suchastheUS,theUKandMexico.Althoughthepeakoilthesisinitselfismuchcontested,notleast inregardtothepessimisticviewonglobalresourcesitpresupposes,anditsdirectimpactontheoil price is probably minimal, an anaemic outlook for nonͲOPEC supply growth probably strengthens expectationofhighpricelevelsinthefuture.Theperceptionthatmoreandmoreproductioncapacity and reserves are expected to become consolidated in the hands of a few national oil companies, givingincreasedcontroltoproducersattheexpenseofimportingcountries,onlyreinforcesthistrend. Since oil is a limited natural resource, some studies have sought to apply the Hotelling rule of increasingmarginalcostofproductionattherateequaltotherateofinterestovertime.Thetheory basicallyholdsthat,withexhaustibleresources,producersfaceatradeͲoffbetweensellingaunitof oiltodayandhoardingthesameunituntilsomefuturedate.Asaunitsoldisaunitlostfromthe reserve,ifproducedandsoldtoday,thereturnforthesalemustbegreaterthanthepresentvalueof theexpectedreturnfromafuturesale.Hence,thereisaperceivedlongͲtermfuturescarcity,whichis saidtoaddadegreeofpremiumtofutureprices.Similarly,KeynesextendedtheconceptofUserCost to illustrate the mechanics of how present and future production decisions interact for exhaustible resources.Anyexpectedupside,netofinterest,bywithholdingsupplyisthereforeconsideredpartof the marginal cost for making decisions on present production. There is scant evidence that the oil price takes the path that the theory suggests, however. It also does not take into account that technologicaldevelopmentscanandhaveinfluencedperceptionsonthesizeofthereservebase. A Mismatch: Crude Availability, Refining Capacity and Required Product Mix Priortotherecentperiodofhighoilprices,therehadarguablybeenyearsofunderͲinvestmentnot just upstream but also the downstream end of the value chain – refining capacity, in particular – constrainingtheindustry’sabilitytomeetafastͲgrowingdemandformiddledistillatesthatemerged over the last five years. A tight availability of light sweet crude, most notably from Nigeria, and recentlyͲintroducedmandatesonlowͲsulphurfuelstandardsinOECDeconomiesleadingtogreater interest by refiners to run light sweet crude during 2007 and first half 2008 are a clear case of a tighteningsupplyanddemandbalanceforthatsegmentofthecrudemarket. Refineryyieldsareafunctionofrefinerycomplexityandcrudeinput.Thus,asurgeindemandfor middle distillates, or any other refined products can only be met by changing configuration of refinery or the type of feedstock or some combination of both. Making changes to refinery configuration or upgrading refining capacity entails capital investment with long lead times, while change of feedstock is an operational, shortͲterm decision. It is not surprising, therefore, that refinersturnedtolightsweetcrudetoboostmiddledistillatesyields.FrequentclaimsbyOPECthat therewereadequateoilsuppliesresteduponthefactthatsomeOPECheavycrudeswerestruggling to find a market even when benchmark prices kept breaking record highs. In order to assess the validityofthecrudeͲtypeargument,relevantdemandandsupplydataneedtobeexamined.
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Intermsofdemandformotorgasoline,dieselandjetfuel,theIEA’sdemanddatasince2006forboth OECDandnonOECDcountriesshowthatdemandforthosethreeproductsrosefrom47.9mb/din 2006to49.9mb/din2008–i.e.a4%or2mb/dincrease.Althoughthesupplyanddemandbalance wasrathertightin2007,therewasnoclearevidenceofshortageinoverallcrudesupplyin2006and 2008. But changes in required product specifications affected the type and amount of crude that refinerscouldprocess,effectivelytighteningfundamentalsforthesegrades. To illustrate this, consider there is currently 500kb/d of demand for motor gasoline and the maximumsulphurcontentallowedis20ppm.Arefinerrunsamixofcrudes,namelylightcrudeA with0.3%sulphurandheavycrudeBwith2.0%sulphurtoproduce,amongotherproducts,gasoline which meets the required specifications. If the governing regulations change so that gasoline can only contain 10 ppm of sulphur, even though the absolute level of demand for gasoline in the countrydoesnotchange,whatwilltherefinerdo?Therefinerasagoingconcerncaneitherinstalla scrubber to desulphurise the product, or change the crude feedstock, running more lowͲsulphur crude, which naturally yields products with lower sulphur content. Hence, changes in required productqualitycantightenthebalanceforonetypeofcrude,looseningitforanother.Inshort,the distillate market was supplyͲconstrained, rather than facing a demand squeeze; North Sea crude supply,forexample,wasdownby10.5%inJuly2008,comparedwiththeJanuary2007level,while Nigeriancrudeproductionalsodeclinedby10.6%inthesameperiod,despiterisingprices.ReadilyͲ available heavy sour crudes were neither a practical nor economically viable substitute for light sweet crudes due to alreadyͲstretched refining capacity and the narrow price discount offered by manyproducersfortheirheavy/sourgrades. The Dollar Effect How does the value of US dollar affect oil prices? One clear impact is that with oil prices denominatedintheUSdollar,theexchangerateforthedollarchangesoilpricesinothercurrencies. Aweakerdollarmeans,forexample,lowerpricesinEuros,whichshouldinturntranslateintohigher Oil demand in the euro zone which, all other things being equal, would tighten the global supply/demandbalance.Anothereffectisnotdirectlyrelatedtooilmarketfundamentals.Investors oftenbuycommoditiesfuturescontractsasahedgeagainstinflation.InflationintheUSwouldimply aweakerdollar,soinflationarytrendsorfearsofinflationencouragebuyingoffuturesbyfinancial investors. As the dollar is the world’s most widely adpoted reserve currency, perceptions or anticipation of inflation and dollar depreciation can prompt holders of USͲbased assets to seek exposuretoothertypesofassetsnormallyshieldedfromtheimpactofinflationintheUS. Dated Brent in Different Currencies Jun 06 = 100 225 200 175 150 125 100 75 50 25
$/bbl
WTI & Value of US$ (against EUR) EUR/US$ 0.60
150 125
0.65
100
0.70
75
0.75
50 Source: Platts
Jun 06
25 Jun 07
US$
Jun 08 EURO
Jun 09 Yen
0.80 Source: Platts
Jun 07
Dec 07
0.85 Jun 08
WTI (US$)
Dec 08
Jun 09
EUR/US$
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The CFTC and the IMF Find Little Evidence for the Speculation View Onewayofassessingtheroleofspeculatorsinpriceformationistoapplyastatisticaltestingmodelto the data on trading activities of different types of traders. Statistical analysis allows for an objective judgmentonthesignificanceofchangesinindependentvariableorvariablesinpredicting(not‘driving’) howthedependentvariablemightbehave.TheCFTChascarriedoutaseriesofsuchanalyses,thelatest ofwhichwasreleasedinDecember2008wherethecommissionranarecursivecoͲintegration*analysis using the extensive data it collects on daily trading activities on NYMEX. Although the methodology, includingclassificationcriteriafortraders,isnotwithoutitscriticsandshortcomings,–nodataonOTC trading activities were included, for example, – it is the most comprehensive attempt to date that quantifiestheeffectofspeculationonpriceformation. The CFTC’s December report examined market participants’ activities in greater detail and identified threenonͲcommercial‘subͲcategories’as‘themostactive’players,whichtogetheraccountedforabout 90%ofthetotalnonͲcommercialopeninterestbetween2000and2008.Thesewere‘FloorBrokersand Traders’, ‘Hedge Funds’ and ‘NonͲRegistered Participants’ (NRP) with the third being predominantly financialtradersinnature. Althoughcommodityswaptradersarestillclassifiedunderthe‘commercial’category,thereportsingled outthesignificantmarketposition(morethan30%ofthemarket)thatthisparticulargroupoftraders maintained through ‘the direct and indirect influx of commodity index money in futures markets’ (CFTC,2008). The study focused on ascertaining whether or not spot (frontͲmonth) contract prices and longerͲ maturity(1Ͳ2years)futurescontractpricesexhibitcoͲintegrationandifsotowhatdegree.CFTCdata confirmthebasictrendsfrom2000toJuly2008–atriplingoffuturesopeninterest(to1.5million),a quintupling of futuresͲequivalentͲoptions positions (to 3 million) and an increasing share of nonͲ commercials involved in ‘spread’ trading (from 27% to 40% of all open positions), with the notional amount in the oil market reaching $405 billion at the price of $140/bbl last July and the growth acceleratingfrommidͲ2003onwards. The explanatory powers of crude oil market fundamentals, namely the strength of world demand for industrial commodities and capacity constraints affecting crude oil production, as well as the level of open positions of specific kinds of traders are tested statistically, with market activity and exogenous liquidityshocksheldequal.Withoutdelvingtoodeeplyintothetechnicalpartofthemodellingexercise, thefinalconclusiondidnotestablishapriceͲmakingroleofthenonͲcommercialsintheoilmarket,even thoughitdidfindthatmarketactivitiesofhedgefundsandotherfinancialinstitutionsaswellasswap dealershelptoexplainthecoͲintegrationofspotandfuturesprices.Simultaneously,however,market fundamentals were also shown to be strong indicators of price coͲintegration. It provides, therefore, onlyinconclusiveevidencetosuggestthatspeculativeactivitieshadcausedthespotpricetoclimbupto thelevelitdidlastsummer.TheInternationalMonetaryFund,initsWorldEconomicOutlook,published October2008alsoadheredtothefundamentalsviewafteritsstatisticalanalysisrevealednoapparent systematic connection between ‘financialisation’ of commodities – financial flows into commodity markets–andpricevolatilityorfluctuations. *CoͲintegrationimplies,putsimply,thatthereisacorrelationbetweenvariablestested–inthecaseoftheCFTC’sDecember paper,betweenlongerͲdatedmaturityfuturesandfrontͲmonthcontractprices.
Thevalueofthecurrencycanthereforebeaverystrongdriverofoilpricelevels.Theoilpricemay rise by 25%, but that does not automatically mean that the price of oil has gone up by 25% everywhere. The Euro or Yen value of crude oil, for instance, could move differently to the dollar value,dependingontherelativestrengthofthecurrencyinquestion.TherealpricesofoilintheUS,
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EuropeandJapanmovedlargelyhandͲinͲhanduntilthelastquarterof2007,buttheythenbeganto divergewiththeUSrealpricesometimesmorethan15%higherthanthatofEurope.Asthedollar gained strength over the single currency, the discrepancy between US and European real prices quicklydiminished.Morerecently,astrongyenpusheddowntherealpriceofoilinJapansignificantly lowerthanUSandEuropeanprices.Moreover,theeconomicsofproducingoilindifferentregionscan fluctuatedependingontheleveloflocalanddollarͲdenominatedcostsinthelongertimeframe. Other Considerations Other Commodities Oilisonecommoditywheretherehasbeenamassiveinfluxofcapitalandapricesurgeconcurrently. Examining other commodities with or without futures markets may provide further clues as to whetherfinancialforcescandrivecommodityprices.Criticsof thespeculationview frequently cite commodity markets without a wellͲfunctioning futures market and point out that equivalent price increasesinthesecommoditiescannothavebeendrivenbyflowsofspeculativemoneymadepossible by the facets of a futures and derivatives market. Iron ore and some rare metals, which are not traded on the London Metal Exchange (LME), are examples of those commodities without futures marketwhichhaveexperiencedsharprisesintheirpricesoverthepasttwotothreeyears.Further,in agriculturalcropmarketswhichhaveafuturesmarketwithalongerhistorythanoil,thisdebateover theroleofspeculatorshaspersistedsincetheinceptionofafuturesexchangealmostacenturyago. However, even though speculators have frequently been condemned for price rises, studies have found no conclusive evidence that speculation drives agricultural commodity prices and have stressed a more important role played by speculation – providing liquidity and facilitating price discovery. Comparative analysis with other commodities, however, needs handling with caution because minerals like iron ore have completely different market dynamics from oil, with the benchmarkpricebeingsetannuallyandalmost70%ofglobalseabornetradedominatedbythetop three mining companies. Agricultural crops, meanwhile, are more prone to seasonal fluctuations thanoil,andoilispart,albeitsmall,ofproductioncosts.Still,thisapproachreaffirmsthatpricescan fluctuatewidely,regardlessofthepresenceandparticipationoffinancialforcesinthemarket. How Does the Spot Market Work? Thefundamentalsviewexaminedsofarisreallytwofold.First,itdistinguishesfuturesfromspot,or put differently, nonͲphysical from physical, contracts. Even if speculation did drive the price in a futuresmarket,sotheargumentruns,itwouldnotforcethespotpriceforphysicaldeliveryoffthe equilibriumdeterminedbyphysicalmarketfundamentals.Second,astheCFTCstudyshows,thereis no statistically significant relationship between positionͲtaking by speculative or nonͲcommercial playersandthefuturesprice,letalonethespotpriceforphysicaldelivery(thoughtheiractivitiesdid help explain coͲintegration between spot and futures prices). Hence, those who argue that the oil priceisdrivenoratleastheavilyaffectedbyalevelofspeculationarefacedwithatwoͲsteprefutation exercise,onetoshowthatfuturespricesaredetermined,toacertaindegree,byspeculationandthen toidentifyaconnectionbetweenthefuturespriceandthespotpriceforphysicaldelivery. Thespeculationview–thatthemassiveinflowoffundsintheoilmarketdrovetheoilprice–hasnot fullyrespondedtothepivotalquestionabouttherelationshipbetweenthefuturespriceandthespot price,otherthanclaimingthatmarketparticipantsoftenseefuturespricesasareferencepointfor pricingaspotcargo.ThisiscertainlynotselfͲexplanatoryand,indeed,itmayjustbethatthespot priceisgivingindicationstofuturestraderswhothendecidewhetherornottotakepositionsata
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givenfuturesprice.Tobetterdealwiththeissueoflinkagebetweenthefuturespriceandthespot price,itisusefultoconsiderthewaybusinessfunctions,i.e.howOTCbuyingandsellingofphysical crudeoilworks,whichisonedimensionseeminglymissingfromthisdebate. The fundamentals school of thought holds that futures markets merely reflect demand and supply for futures contracts, which generally do not result in physical delivery of crude oil. Hence, when financial investors or speculators put buy orders in futures market, it does not in itself mean the demandforcrudeoilhasincreased.Whilethecorrespondingfuturepriceislikelytoincreaseasa resultofthebuyorders,priceformationforspotcrudeoilforphysicaldeliveryremainsafunctionof physicalsupplyanddemand,i.e.thefundamentals.Theoretically,thisargumentappearssound,but when one looks closely at the predominant process of price formation, or negotiations between sellersandbuyers,isolatingspotpricesfromfuturespricesstartstolookratherproblematic. The most common trading practice or pricing mechanism in physical markets worldwide takes the formofpremiumsover,ordiscountsagainst,acertainbenchmark.Negotiationsforthesecontracts (ofphysicalsupply)usuallytakeplacemorethanonemonthpriortotheactualdeliveryofthecrude, butthepricesarehardlyeverfixedinabsoluteterms.UsingWTIasanexample–theworld’smost widelyͲused benchmark crude – a buyer agreeing to buy crude oil next month at the closing WTI priceforthatmonthminusxdollarswouldbeaoneͲlinerecapofatypicalfixture.Whatnumberthe x takes is a product of negotiations and relative bargaining powers of the seller and the buyer involved,whichwouldbebasedonfundamentalfactors.Moreimportantly,however,oncethexis fixed,theabsolutepriceoftheoilcantakeanyvalueandthisisamomentwherebothsupplyand demandcurvesbecomecompletelyinelastic–whatdeterminesthepricethenisthefuturesmarket andthebenchmarkpricethatdoesnotresultinphysicaldeliveryofcrudeoil. ASchematicIllustrationoftheShortͲTermDemandandSupplyCurves Therange"P"indicatesthatprice"level" issetbyfundamentals,butverticalshapeofdemandandsupplycurveswithinthe rangeensuresthatotherforcesmaydictatedailyclearingprices.
Price
Price D
S
D P
P
D
S
S
Price Level
Changesin fundamenals
Price Level
D D
S Q
Quantity
S
S D Q
Quantity
Thereareoften‘options’inmanyOTCcontractsforphysicaloil,whichbuyerscanoftenchooseto exerciseorwaveinaccordancewiththepriceandthestrengthofdemandfortheirownproducts;a fixed quantity only holds within a certain range of price levels. Furthermore, completely inelastic, verticaldemandandsupplycurveswouldonlyholdintheveryshortterm,perhapsforafewmonths. Overtimedemandandsupply,howeverinelastic,shouldadjustanditishardtoenvisageascenario inwhichfinancialandspeculativeforcesalonecansustainanelevatedordampenedpriceawayfrom thelevelswarrantedbyfundamentals.
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Itis,however,plausiblethat,foraslongasdemandandsupplyhavemultiplemarketclearingprices, buying and selling of futures and spot contracts by players of a nonͲcommercial nature drive the settlementpricewithinthatrange.A$16.37/bblor15.7%jumpinthepriceoffrontͲmonthcontracts –thebiggestoneͲdaygainindollartermssince1984–recordedon22September2008,hasfrequently beencitedasevidenceofhowmuchfinancialplayers,orspeculators,canaffectthepricewithsome proclaimingthatfundamentalscouldnotpossiblychangeinjustonedaytowarrantapriceincreaseof thatmagnitude.So,itisconceivablethatfinancialplayersandspeculatorscananddoaffecttheprice intheveryshortterm.Undersuchcircumstances,thefactthatoilissoldanddeliveredatagivenprice does not necessarily mean that the fundamentals would generate the same clearing price in the absenceofspeculationandfinancialplayersinthemarket.Thatsaid,itisquestionablewhetherone canappropriatelyclaimthattheoilpriceistherefore‘driven’byspeculationandbyhowmuch.Rather, ithasmoretodowiththepricingmechanisminthemarket,whichitselfreflectstherelativebargaining powersofsellersandbuyers,whichinturnwillbeheavilyinfluencedbyfundamentalfactors. Policing Speculators The International Organisation of Securities Commissions (IOSCO) set up a Task Force on Commodity Futures Markets in September 2008, following a surge in commodity prices and exploding volatility, whichraisedconcernthatspeculativeactivitybynonͲphysicalplayersunderpinnedthepricemove.The IOSCOTaskForce,coͲchairedbytheCFTCandtheUK’sFinancialServicesAuthority,publishedareport inMarch2009,whichprovidesareviewofstudiesdonebytheIMF,theEuropeanCommission,theUK Treasury and the CFTC, and entails a set of recommendations to governments to allocate more resourcestoenhancingtransparency,andmonitoringofcommodityfuturesandderivativestradingand marketsingeneral.TheTaskForcemakesawelcomecallformoreinformation,whichwouldimprove visibility in ascertaining the roles of various types of market participants, thereby enabling a deeper understandingoftheimpactofspeculatorsinpriceformation. IntheUS,thenewadministrationappearskeentointroducemeasurestonotonlyincreaseoversighton futuresexchangesbutalsotoregulateoverͲtheͲcountertradingofcommodityfuturesandderivatives, which are currently not subject to regulatory oversight. During his campaign for the US Presidency, Barack Obama advocated tougher regulation and increasing government oversight of US and internationalenergymarkets,accusingspeculatorsofdrivingenergypriceshigherandmakingprofitsat the expense of consumers. Since Obama has been sworn in as President, a new bill, The Derivatives MarketsTransparencyandAccountabilityAct,wasintroducedbytheUSHouseAgricultureCommitteein February, aimed at, among other things bringing overͲtheͲcounter (OTC) derivative deals under governmentscrutiny.HavingpassedcommitteeinFebruary,thebillhasstalledattheHousefloor.Inthe meantime,theObamaAdministrationproposedlegislationtoregulateallOTCderivativesbybestowingon theCFTCortheSecuritiesandExchangeCommission(SEC)thepowertoinvestigatebooksandrecordsof all OTC derivative trading as well as establishing a central, regulated clearing system for standardised derivativecontracts,whicharebelievedtoconstitutethebulkofOTCtrading.Thelegislation,ifenacted, would amend the Commodity Exchange Act, and nullify the controversial Commodity Futures ModernizationActof2000,which,arguably,createdthesoͲcalled‘Enronloophole’infuturesmarkets. ThesenewinitiativesfollowthemeltdownintheUSfinancialsystem,buttheinitialimpetusoriginates from last year’s runͲup in commodity prices and wideͲspread calls for tighter controls on speculative trading in futures markets. In addition to enhancing transparency by requiring recordͲkeeping and reportingbyentitiesinvolvedinderivativestrading,thecreationofaclearinghousewouldensurethat morecapitalwouldhavetobesetasideorincreasedmarginswouldberequiredfortradingderivative contracts. While it would certainly increase the cost of engaging in these trades through futures marketsandpossiblycurtailspeculativeactivity,thepreciseimpactonpricelevelsremainsunclear.
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Conclusion A multitude of factors are at play in oil price formation, although the fundamentals still seem to provideareasonablyplausibleaccountoffirstthejumpand,toalesserextent,thesubsequentfallof the oil price. Speculation, though its longͲterm impact on the price is neither quantifiable nor conceptually proven, does appear to have an impact on the spot market in the very short term, particularlyonadayͲtoͲdaybasis.Informationaboutmarketfundamentalsisinterpretedbyvarious marketparticipantsandformsanoverallexpectation,whichisfedintothespotmarketmostswiftly byspeculators.Indexfundsandotherpassiveinvestorsmayaddpressuretothemarketfromthe buy side, leading to claims that future prices are inflated beyond the level warranted by fundamentals,butnohardevidenceispresent;thefactthatthey‘rollover’theirpositions–sellwhat wasboughtandusetheproceedstobuyfurtherforward–onaregularbasismeansthatthesame degreeofsellͲsidepressureoriginatesfromthesefunds,unlesstheyputadditionalmoneyintooil. Further,eveniftheydopushfuturespricesup,themechanicswherebyhigherfuturepricesleadto higher spot prices are unclear, except where supply and demand for physical oil is also affected through stockpiling or hoarding behaviour. Perhaps a quote from Daniel Yergin, Chairman of CambridgeEnergyReserchAssociates,inhistestimonybeforeJointEconomicCommitteeoftheUS Congresoffersaconcisesummaryonhowweshouldmakesenseoftheoilpricefluctuationsseenin thelastfewyears:history‘demonstratesthatchangesofthisscaleandsignificanceresultnotfroma singlecause,butratherfromaconfluenceoffactors’,acknowledgingthatspeculationmayplayone role among many in influencing oil prices. Moves which result in greater tranparency in both physical and financial markets are to be welcomed. Legislators, however, need to be aware that searching for a single ‘smoking gun’ may be fruitless, and should bear in mind that any future legislationneedstoavoidtheriskofdestroyingmarketliquidityandpricediscovery,somethingthat couldexacerbatemarketvolatilityratherthanremoveit.
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Table 1 WORLD OIL SUPPLY AND DEMAND (million barrels per day)
TABLES
1Q08 2Q08 3Q08 4Q08 2008
1Q09 2Q09 3Q09 4Q09 2009
2010 2011 2012 2013 2014
North America
24.8 24.5 23.7 24.0 24.3
23.6 22.9 23.2 23.1 23.2
23.3 23.4 23.6 23.7 23.7
Europe
15.2 14.9 15.4 15.3 15.2
14.8 14.1 14.7 14.7 14.6
14.4 14.4 14.3 14.2 14.1
OECD DEMAND
8.9
Pacific Total OECD
7.8
7.5
7.9
8.0
48.9 47.2 46.6 47.3 47.5
8.1
7.1
6.9
7.4
7.3
46.5 44.0 44.8 45.1 45.1
7.2
7.1
6.9
6.7
6.6
45.0 44.9 44.7 44.6 44.4
NON-OECD DEMAND FSU
4.2
4.1
4.3
4.2
4.2
3.9
3.9
4.1
4.0
4.0
4.1
4.2
4.4
4.6
4.7
Europe
0.7
0.7
0.6
0.7
0.7
0.6
0.6
0.6
0.6
0.6
0.6
0.6
0.7
0.7
0.7
China
7.9
8.0
8.1
7.6
7.9
7.6
8.0
7.9
7.8
7.8
8.2
8.5
8.9
9.3
9.6
Other Asia
9.8
9.8
9.3
9.4
9.6
9.7
9.6
9.3
9.4
9.5
9.7
9.9 10.1 10.3 10.5
Latin America
5.7
6.0
6.0
5.9
5.9
5.7
5.9
6.0
5.9
5.9
6.0
6.2
6.4
6.5
6.7
Middle East
6.6
7.0
7.4
6.8
7.0
6.7
7.3
7.7
7.1
7.2
7.5
7.9
8.3
8.6
8.9
Africa
3.1
3.1
3.1
3.1
3.1
3.2
3.1
3.0
3.2
3.1
3.2
3.3
3.4
3.5
3.5
Total Non-OECD
38.0 38.5 38.8 37.7 38.3
37.4 38.4 38.6 38.2 38.1
39.4 40.7 42.0 43.3 44.6
1
86.9 85.8 85.4 85.0 85.8
83.8 82.3 83.4 83.3 83.2
84.3 85.6 86.8 87.9 89.0
14.2 14.1 13.6 13.9 13.9
14.2 13.7 13.7 13.9 13.9
14.0 14.3 14.2 14.1 13.9
Total Demand
OECD SUPPLY North America Europe
4.9
4.8
4.6
4.8
4.8
4.8
4.2
4.1
4.3
4.3
4.1
3.8
3.7
3.5
3.4
Pacific
0.6
0.7
0.7
0.7
0.6
0.7
0.6
0.7
0.7
0.7
0.7
0.7
0.7
0.6
0.5
Total OECD
19.7 19.5 18.8 19.4 19.4
19.6 18.6 18.5 19.0 18.9
18.8 18.8 18.6 18.3 17.9
12.8 12.9 12.7 12.7 12.8
12.8 12.9 12.6 12.5 12.7
12.8 12.8 12.7 12.7 12.9
NON-OECD SUPPLY FSU Europe
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
0.1
China
3.8
3.8
3.8
3.8
3.8
3.7
3.9
3.9
3.9
3.8
3.9
4.0
3.9
3.9
3.9
Other Asia
3.7
3.6
3.6
3.7
3.7
3.7
3.7
3.7
3.7
3.7
3.8
3.8
3.7
3.7
3.6
Latin America
4.1
4.1
4.2
4.2
4.1
4.3
4.3
4.4
4.4
4.4
4.6
4.8
4.9
5.1
5.3
Middle East
1.6
1.6
1.6
1.6
1.6
1.6
1.6
1.5
1.5
1.5
1.5
1.5
1.4
1.4
1.3
Africa Total Non-OECD
2.6 2.6 2.6 2.5 2.6 28.7 28.7 28.6 28.6 28.6
2.5 2.5 2.5 2.5 2.5 28.8 29.0 28.7 28.6 28.8
2.5 2.5 2.5 2.5 2.4 29.2 29.6 29.3 29.3 29.5
Processing Gains2
2.2
2.2
2.3
2.3
2.2
2.3
2.3
2.3
2.3
2.3
2.2
2.2
2.3
2.3
2.3
Other Biofuels3
0.3
0.4
0.4
0.4
0.4
0.3
0.3
0.4
0.4
0.3
0.4
0.5
0.5
0.6
0.6
Total Non-OPEC4
50.9 50.8 50.0 50.7 50.6
51.0 50.2 49.9 50.3 50.3
Total OPEC
31.5 31.4 31.5 30.5 31.2 4.6 4.6 4.7 4.9 4.7 36.2 36.0 36.2 35.4 36.0
28.4 4.9 33.3
Total Supply
87.1 86.8 86.3 86.1 86.6
84.3
50.6 51.1 50.7 50.4 50.2
OPEC Crude5 OPEC NGLs
5.1
5.4
5.5
5.2
6.1
6.6
6.9
7.1
7.3
Memo items: Call on OPEC crude + Stock ch.6
31.4 30.3 30.6 29.4 30.4
28.0 27.1 28.1 27.5 27.7
27.7 27.9 29.2 30.4 31.5
1 Measured as deliveries from refineries and primary stocks, comprises inland deliveries, international marine bunkers, refinery fuel, crude for direct burning, oil from non-conventional sources and other sources of supply. 2 Net volumetric gains and losses in the refining process (excludes net gain/loss in China and non-OECD Europe) and marine transportation losses. 3 Biofuels from sources outside Brazil and US. 4 Non-OPEC supplies include crude oil, condensates, NGL and non-conventional sources of supply such as synthetic crude, ethanol and MTBE. 5 As of the March 2006 OMR, Venezuelan Orinoco heavy crude production is included within Venezuelan crude estimates. Orimulsion fuel remains within the OPEC NGL & non-conventional category, but Orimulsion production reportedly ceased from January 2007. 6 Equals the arithmetic difference between total demand minus total non-OPEC supply minus OPEC NGLs.
110
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T ABLES
Table 1A WORLD OIL SUPPLY AND DEMAND: CHANGES FROM LAST MTOMR (million barrels per day) 1Q08 2Q08 3Q08 4Q08 2008
1Q09 2Q09 3Q09 4Q09 2009
2010 2011 2012 2013 2014
OECD DEMAND North America
0.0
0.0
-0.4
0.0
-0.1
-0.4
-1.0
-0.7
-0.8
-0.7
-0.5
-0.5
-0.4
-0.3
Europe
0.0
0.0
0.0
-0.2
0.0
-0.2
-0.6
-0.4
-0.6
-0.4
-0.6
-0.6
-0.7
-0.8
Pacific
0.0
0.0
0.0
-0.7
-0.2
-0.7
-0.6
-0.6
-1.2
-0.8
-0.9
-0.9
-1.0
-1.1
Total OECD
0.0
0.0
-0.4
-0.9
-0.3
-1.3
-2.2
-1.7
-2.5
-1.9
-2.0
-2.0
-2.1
-2.2
NON-OECD DEMAND FSU Europe
0.1
-0.1
-0.1
-0.2
-0.1
-0.3
-0.3
-0.4
-0.4
-0.4
-0.3
-0.3
-0.2
-0.2
-0.2
-0.1
-0.1
-0.1
-0.1
-0.2
-0.2
-0.1
-0.1
-0.2
-0.1
-0.1
-0.1
-0.1
China
0.0
0.0
0.0
-0.3
0.0
-0.6
-0.3
-0.3
-0.4
-0.4
-0.4
-0.3
-0.3
-0.4
Other Asia
0.2
0.0
0.2
0.0
0.1
0.0
-0.2
0.0
-0.2
-0.1
-0.1
-0.1
-0.1
-0.1 -0.3
0.0
0.1
0.1
0.0
0.0
-0.2
-0.2
-0.1
-0.2
-0.2
-0.2
-0.2
-0.3
-0.1
0.0
0.1
0.0
0.0
-0.3
0.0
0.1
0.0
0.0
0.0
0.1
0.1
0.0
Africa
0.0
0.0
0.1
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.1
0.1
0.1
Total Non-OECD
0.0
0.0
0.3
-0.6
-0.1
-1.7
-1.1
-0.8
-1.3
-1.2
-1.1
-1.0
-1.0
-1.1
Total Demand
0.1
0.0
-0.1
-1.5
-0.4
-3.0
-3.4
-2.5
-3.8
-3.2
-3.1
-3.0
-3.1
-3.3
North America
0.0
0.0
-0.1
-0.4
-0.1
-0.4
-0.4
-0.3
-0.4
-0.4
-0.5
-0.3
-0.5
-0.7
Europe
0.0
0.0
0.1
0.2
0.1
0.2
0.0
0.0
0.1
0.1
0.1
0.1
0.2
0.1
Pacific
0.0
0.0
0.0
-0.1
0.0
-0.2
-0.2
-0.1
-0.1
-0.1
-0.1
0.0
0.1
0.1
Total OECD
0.0
0.0
-0.1
-0.3
-0.1
-0.4
-0.6
-0.4
-0.4
-0.4
-0.4
-0.2
-0.2
-0.5
FSU
0.0
0.0
0.1
-0.2
0.0
-0.3
-0.2
-0.4
-0.4
-0.3
-0.4
-0.5
-0.8
-1.0
Europe
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
China
0.0
0.0
0.0
-0.1
0.0
-0.2
0.0
0.0
0.0
-0.1
0.0
0.1
0.0
-0.1
Other Asia
0.0
0.0
0.0
-0.1
0.0
-0.1
-0.1
-0.1
-0.1
-0.1
-0.1
-0.1
-0.1
0.0
Latin America
0.1
0.1
0.2
0.0
0.1
0.1
0.1
0.1
0.1
0.1
0.2
0.2
0.1
0.1
Middle East
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.1
-0.1
Africa Total Non-OECD
0.1 0.2
0.1 0.2
0.1 0.2
0.0 -0.3
0.1 0.1
0.0 -0.5
0.1 -0.3
0.1 -0.3
0.1 -0.4
0.1 -0.4
0.0 -0.3
0.1 -0.3
0.0 -0.7
0.0 -1.1 0.0
Latin America Middle East
OECD SUPPLY
NON-OECD SUPPLY
Processing Gains Other Biofuels Total Non-OPEC OPEC NGLs
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
-0.1
-0.1
0.0
-0.1
-0.1
-0.2
-0.2
-0.2
-0.2
-0.2
-0.1
0.0
0.0
0.0
0.2
0.1
0.0
-0.8
-0.1
-1.2
-1.1
-0.9
-1.1
-1.1
-0.8
-0.5
-0.9
-1.6
-0.1
-0.1
-0.2
-0.3
-0.2
-0.5
-0.6
-0.4
-0.4
-0.4
-0.1
0.2
0.2
0.2
0.0
0.0
0.1
Memo items: Call on OPEC crude + Stock ch.
J UNE 2009
-0.4
-0.1
-1.3
-1.7
-1.1
-2.4
-1.7
-2.2
-2.6
-2.4
-2.0
111
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I NTERNATIONAL E NERGY A GENCY Ͳ M EDIUM ͲT ERM O IL M ARKET R EPORT Ͳ 2009 E DITION
Table 2 SUMMARY OF GLOBAL OIL DEMAND 1Q08
2Q08
3Q08
4Q08
2008
1Q09
2Q09
3Q09
4Q09
2009
2010
2011
2012
2013
2014
Demand (mb/d) North America
24.84
24.52
23.73
24.05
24.28
23.57
22.87
23.19
23.05
23.17
23.33
23.45
23.56
23.66
23.74
Europe
15.22
14.89
15.37
15.28
15.19
14.80
14.05
14.71
14.71
14.57
14.43
14.39
14.29
14.18
14.05
Pacific
8.87
7.82
7.50
7.93
8.03
8.08
7.05
6.88
7.35
7.34
7.20
7.07
6.87
6.71
6.58
48.92
47.24
46.59
47.27
47.50
46.45
43.97
44.79
45.12
45.08
44.97
44.90
44.73
44.56
44.37
FSU
4.18
4.07
4.26
4.18
4.17
3.94
3.90
4.06
4.04
3.99
4.10
4.23
4.39
4.55
4.72
Europe
0.67
0.65
0.63
0.66
0.65
0.63
0.62
0.61
0.63
0.62
0.64
0.65
0.67
0.68
0.70
China
7.88
7.98
8.09
7.62
7.89
7.60
7.96
7.85
7.85
7.82
8.17
8.55
8.92
9.27
9.60
Other Asia
9.85
9.77
9.31
9.40
9.58
9.71
9.58
9.27
9.45
9.50
9.66
9.85
10.06
10.27
10.48
Latin America
5.70
5.95
6.03
5.90
5.90
5.66
5.91
6.02
5.95
5.88
6.04
6.19
6.35
6.51
6.67
Middle East
6.59
7.00
7.43
6.82
6.96
6.68
7.26
7.70
7.11
7.19
7.53
7.92
8.26
8.61
8.94
Africa
3.13
3.12
3.07
3.12
3.11
3.15
3.14
3.05
3.18
3.13
3.21
3.29
3.38
3.45
3.53
Total Non-OECD
37.99
38.54
38.82
37.70
38.26
37.36
38.37
38.57
38.19
38.13
39.36
40.69
42.03
43.35
44.62
World
86.91
85.78
85.41
84.96
85.76
83.82
82.34
83.36
83.31
83.21
84.33
85.59
86.76
87.90
88.99
19.99 7.80 5.41 2.33 2.10 2.37 2.37 3.19
19.76 7.65 4.59 2.09 2.16 2.25 2.46 3.12
18.91 7.91 4.30 2.07 2.11 2.34 2.53 2.92
19.32 7.99 4.67 2.12 2.04 2.31 2.51 3.09
19.50 7.84 4.74 2.15 2.10 2.32 2.47 3.08
18.84 7.77 4.65 2.32 2.01 2.34 2.33 3.32
18.26 7.17 3.86 2.06 2.04 2.22 2.45 3.20
18.52 7.58 3.74 2.02 2.01 2.31 2.51 2.99
18.40 7.58 4.11 2.10 2.00 2.28 2.49 3.15
18.50 7.52 4.09 2.13 2.01 2.29 2.45 3.16
18.63 7.41 3.94 2.12 2.02 2.30 2.51 3.25
18.73 7.37 3.79 2.12 2.04 2.30 2.57 3.35
18.83 7.30 3.58 2.11 2.06 2.30 2.63 3.44
18.91 7.22 3.40 2.11 2.07 2.29 2.70 3.54
18.97 7.13 3.26 2.10 2.09 2.29 2.77 3.64
-3.5 -0.2 -0.7 -2.0 4.8 -0.6 2.9 2.6 5.9 9.1 5.4 4.7 0.9
-7.1 -0.3 -5.0 -4.6 3.0 -8.3 7.2 0.3 4.6 12.5 4.0 5.0 -0.5
-5.6 -2.3 -9.0 -5.2 -1.0 -5.9 0.0 -2.0 2.1 7.6 1.6 1.0 -2.5
-4.9 -0.7 -3.8 -3.4 2.2 -3.7 4.3 1.2 4.5 8.7 3.5 3.8 -0.3
-5.1 -2.8 -8.9 -5.1 -5.8 -5.4 -3.5 -1.5 -0.7 1.4 0.8 -1.6 -3.6
-6.7 -5.7 -9.8 -6.9 -3.9 -5.8 -0.2 -2.0 -0.7 3.7 0.5 -0.4 -4.0
-2.2 -4.3 -8.2 -3.9 -4.6 -3.5 -2.9 -0.5 -0.1 3.7 -0.8 -0.7 -2.4
-4.1 -3.7 -7.3 -4.5 -3.4 -4.7 3.0 0.5 0.7 4.3 1.8 1.3 -1.9
-4.6 -4.1 -8.6 -5.1 -4.4 -4.8 -0.9 -0.9 -0.2 3.3 0.6 -0.4 -3.0
0.7 -0.9 -1.8 -0.2 2.9 2.4 4.5 1.7 2.7 4.8 2.7 3.2 1.4
0.5 -0.3 -1.9 -0.1 3.1 1.9 4.6 1.9 2.5 5.1 2.5 3.4 1.5
0.5 -0.6 -2.8 -0.4 3.7 2.6 4.4 2.1 2.6 4.4 2.5 3.3 1.4
0.4 -0.8 -2.3 -0.4 3.7 2.4 3.9 2.1 2.5 4.1 2.3 3.1 1.3
0.3 -0.9 -2.0 -0.4 3.6 2.0 3.5 2.0 2.5 3.8 2.1 2.9 1.2
-0.88 -0.03 -0.05 -0.96 0.19 0.00 0.23 0.24 0.33 0.58 0.16 1.72 0.76
-1.82 -0.05 -0.39 -2.26 0.12 -0.06 0.54 0.03 0.26 0.83 0.12 1.85 -0.41
-1.44 -0.36 -0.78 -2.59 -0.04 -0.04 0.00 -0.19 0.12 0.48 0.05 0.38 -2.20
-1.25 -0.10 -0.32 -1.67 0.09 -0.03 0.32 0.12 0.25 0.55 0.11 1.42 -0.25
-1.26 -0.42 -0.79 -2.47 -0.24 -0.04 -0.27 -0.14 -0.04 0.09 0.02 -0.63 -3.10
-1.65 -0.84 -0.77 -3.26 -0.16 -0.04 -0.01 -0.19 -0.04 0.26 0.02 -0.17 -3.44
-0.53 -0.65 -0.61 -1.80 -0.19 -0.02 -0.23 -0.05 -0.01 0.27 -0.02 -0.25 -2.06
-0.99 -0.57 -0.58 -2.15 -0.14 -0.03 0.23 0.05 0.04 0.29 0.05 0.50 -1.65
-1.11 -0.62 -0.69 -2.42 -0.18 -0.03 -0.07 -0.08 -0.01 0.23 0.02 -0.14 -2.56
0.16 -0.13 -0.14 -0.11 0.12 0.02 0.35 0.16 0.16 0.35 0.08 1.24 1.13
0.12 -0.05 -0.13 -0.07 0.13 0.01 0.37 0.19 0.15 0.39 0.08 1.32 1.26
0.11 -0.09 -0.20 -0.18 0.16 0.02 0.38 0.21 0.16 0.35 0.08 1.35 1.17
0.10 -0.11 -0.16 -0.17 0.16 0.02 0.35 0.21 0.16 0.34 0.08 1.32 1.15
0.07 -0.13 -0.13 -0.19 0.17 0.01 0.33 0.20 0.16 0.33 0.07 1.27 1.08
-0.42 -0.21 -0.65 -1.29 -0.29 -0.19 -0.64 0.00 -0.21 -0.33 -0.03 -1.69 -2.98
-1.04 -0.57 -0.61 -2.22 -0.31 -0.16 -0.28 -0.17 -0.18 0.00 -0.04 -1.14 -3.36
-0.69 -0.37 -0.60 -1.66 -0.39 -0.11 -0.30 -0.02 -0.13 0.11 0.01 -0.83 -2.49
-0.78 -0.55 -1.17 -2.51 -0.41 -0.15 -0.43 -0.18 -0.19 0.03 0.01 -1.32 -3.83
-0.73 -0.43 -0.76 -1.92 -0.35 -0.15 -0.41 -0.09 -0.18 -0.05 -0.01 -1.24 -3.16
-0.55 -0.56 -0.88 -1.99 -0.31 -0.15 -0.37 -0.10 -0.20 0.00 0.03 -1.09 -3.08
-0.46 -0.60 -0.93 -1.99 -0.28 -0.15 -0.34 -0.10 -0.24 0.08 0.06 -0.97 -2.96
-0.38 -0.68 -1.04 -2.10 -0.24 -0.14 -0.34 -0.12 -0.29 0.07 0.09 -0.97 -3.07
-0.33 -0.78 -1.14 -2.25 -0.21 -0.14 -0.40 -0.15 -0.34 0.04 0.10 -1.10 -3.35
-3.35
-2.40
-2.33
-2.78
0.09
0.11
-0.11
-0.28
Total OECD
of which: US50 Euro4 Japan Korea Mexico Canada Brazil India
Annual Change (% per annum) North America -3.3 Europe 0.2 Pacific -0.5 Total OECD -1.7 FSU 2.3 Europe 0.2 China 7.1 Other Asia 4.1 Latin America 5.4 Middle East 5.2 Africa 3.1 Total Non-OECD 4.7 World 1.0 Annual Change (mb/d) North America -0.84 Europe 0.04 Pacific -0.04 Total OECD -0.85 FSU 0.09 Europe 0.00 China 0.52 Other Asia 0.39 Latin America 0.29 Middle East 0.32 Africa 0.09 Total Non-OECD 1.72 World 0.87
Revisions to Oil Demand from Last Medium Term Report (mb/d) North America 0.00 0.00 -0.40 -0.01 -0.10 Europe 0.02 0.01 0.03 -0.20 -0.04 Pacific 0.00 0.00 -0.02 -0.69 -0.18 Total OECD 0.02 0.01 -0.39 -0.91 -0.32 FSU 0.07 -0.06 -0.11 -0.16 -0.07 Europe -0.15 -0.11 -0.07 -0.11 -0.11 China 0.03 0.03 0.03 -0.27 -0.05 Other Asia 0.20 0.05 0.15 -0.05 0.09 Latin America 0.03 0.07 0.08 -0.03 0.04 Middle East -0.13 0.04 0.15 0.03 0.02 Africa -0.01 -0.02 0.07 -0.01 0.01 Total Non-OECD 0.03 -0.01 0.30 -0.60 -0.07 World 0.05 0.00 -0.09 -1.50 -0.39
Revisions to Oil Demand Growth from Last Medium Term Report (mb/d) World 0.22 0.11 -0.16 -1.52 -0.34 -3.03
112
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T ABLES
Table 3 WORLD OIL PRODUCTION (million barrels per day) 1Q08
2Q08 3Q08 4Q08
2008
1Q09 2Q09 3Q09 4Q09
2009
2010
2011
2012
2013
2014
5.21
6.07
6.62
6.90
7.09
7.32
OPEC Total NGLs
1
4.62
4.65
4.73
4.88
4.72
4.89
5.05
5.36
5.54
NON-OPEC2 OECD
14.19 14.07 13.60 13.85 13.93 7.65 7.78 7.23 7.45 7.53 3.28 3.17 3.12 3.09 3.16 3.26 3.12 3.26 3.31 3.24
North America United States Mexico Canada
14.18 13.74 13.70 13.93 13.89 7.81 7.80 7.67 7.73 7.75 3.04 2.98 2.89 2.85 2.94 3.33 2.97 3.13 3.35 3.20
14.01 14.28 7.94 8.18 2.77 2.67 3.30 3.43
14.25 14.11 13.91 8.12 7.95 7.70 2.55 2.48 2.43 3.58 3.68 3.78
Europe UK Norway Others
4.91 1.64 2.52 0.76
4.81 1.64 2.41 0.76
4.55 1.41 2.38 0.76
4.84 1.57 2.54 0.72
4.78 1.56 2.46 0.75
4.75 1.57 2.49 0.70
4.21 1.38 2.13 0.70
4.10 1.27 2.13 0.69
4.33 1.40 2.25 0.68
4.35 1.41 2.25 0.69
4.05 1.26 2.13 0.66
3.83 1.15 2.06 0.62
3.65 1.07 2.01 0.57
3.52 1.00 1.98 0.54
3.40 0.98 1.91 0.52
Pacific Australia Others
0.60 0.49 0.11
0.65 0.55 0.10
0.66 0.57 0.09
0.68 0.60 0.08
0.65 0.55 0.10
0.65 0.57 0.09
0.65 0.55 0.10
0.68 0.57 0.12
0.71 0.58 0.13
0.67 0.56 0.11
0.74 0.61 0.13
0.72 0.60 0.12
0.72 0.60 0.12
0.63 0.53 0.10
0.55 0.46 0.09
Total OECD
19.70 19.52 18.82 19.37 19.35
19.59 18.60 18.48 18.97 18.91
18.80 18.84
18.62 18.26 17.85
12.82 12.86 12.66 12.70 12.76 10.00 9.96 10.02 10.02 10.00 2.82 2.91 2.64 2.68 2.76
12.82 12.89 12.57 12.50 12.69 10.00 9.97 9.82 9.65 9.86 2.82 2.92 2.75 2.85 2.84
12.75 12.82 9.54 9.37 3.21 3.44
12.68 12.69 12.87 9.22 9.31 9.46 3.47 3.38 3.41
NON-OECD Former USSR Russia Others Asia China Malaysia India Indonesia Others
7.46 3.76 0.77 0.81 1.03 1.09
7.44 3.82 0.74 0.80 1.03 1.06
7.43 3.79 0.77 0.80 1.03 1.04
7.47 3.80 0.74 0.82 1.03 1.07
7.45 3.79 0.76 0.81 1.03 1.07
7.38 3.72 0.74 0.77 1.05 1.10
7.52 3.87 0.75 0.77 1.03 1.10
7.58 3.89 0.74 0.78 1.05 1.11
7.58 3.89 0.73 0.80 1.05 1.11
7.52 3.84 0.74 0.78 1.04 1.11
7.69 3.92 0.72 0.85 1.09 1.11
7.79 4.00 0.68 0.89 1.12 1.11
7.65 3.91 0.66 0.86 1.08 1.15
7.58 3.90 0.67 0.83 1.05 1.13
7.52 3.92 0.69 0.80 1.02 1.10
Europe
0.13
0.12
0.12
0.12
0.12
0.12
0.11
0.11
0.11
0.11
0.10
0.09
0.08
0.07
0.07
Latin America Brazil Argentina Colombia Others
4.05 2.32 0.75 0.57 0.41
4.07 2.37 0.71 0.58 0.41
4.18 2.40 0.76 0.60 0.42
4.19 2.38 0.74 0.61 0.46
4.12 2.37 0.74 0.59 0.43
4.34 2.52 0.75 0.61 0.46
4.34 2.51 0.75 0.62 0.46
4.40 2.57 0.75 0.62 0.46
4.41 2.59 0.74 0.62 0.46
4.37 2.55 0.75 0.62 0.46
4.65 2.82 0.75 0.62 0.46
4.83 2.98 0.76 0.64 0.45
4.90 3.04 0.76 0.66 0.44
5.07 3.17 0.76 0.69 0.45
5.32 3.37 0.76 0.71 0.48
Middle East Oman Syria Yemen Others
1.64 0.73 0.41 0.31 0.19
1.62 0.72 0.40 0.31 0.19
1.62 0.73 0.40 0.30 0.19
1.60 0.73 0.39 0.30 0.19
1.62 0.73 0.40 0.31 0.19
1.58 0.72 0.38 0.28 0.19
1.56 0.72 0.37 0.27 0.19
1.54 0.72 0.36 0.26 0.19
1.52 0.72 0.36 0.26 0.19
1.55 0.72 0.37 0.27 0.19
1.51 0.73 0.33 0.26 0.18
1.50 0.75 0.30 0.28 0.17
1.44 0.73 0.27 0.28 0.16
1.38 0.72 0.25 0.26 0.15
1.33 0.71 0.22 0.25 0.15
Africa Egypt Equatorial Guinea Sudan Others
2.56 0.65 0.37 0.50 1.04
2.56 0.65 0.36 0.49 1.06
2.55 0.65 0.34 0.47 1.09
2.53 0.65 0.33 0.44 1.11
2.55 0.65 0.35 0.48 1.07
2.53 0.65 0.32 0.46 1.10
2.53 0.64 0.31 0.48 1.10
2.55 0.63 0.30 0.49 1.12
2.53 0.62 0.29 0.49 1.12
2.53 0.63 0.31 0.48 1.11
2.49 0.60 0.27 0.50 1.11
2.54 0.57 0.30 0.48 1.19
2.51 0.54 0.33 0.47 1.18
2.50 0.51 0.33 0.48 1.18
2.41 0.48 0.32 0.45 1.16
28.67 28.67 28.56 28.61 28.63
Total Non-OECD Processing Gains Other Biofuels
3
4
TOTAL NON-OPEC
2.22 0.34
2.22 0.37
2.25 0.41
2.29 0.41
2.24 0.38
50.93 50.79 50.04 50.67 50.60
28.77 28.95 28.73 28.65 28.77 2.29 0.33
2.29 0.33
2.29 0.36
2.29 0.37
2.29 0.35
50.96 50.17 49.85 50.27 50.31
29.19 29.57 2.20 0.41
2.23 0.48
50.59 51.11
29.28 29.31 29.52 2.26 0.55
2.29 0.55
2.30 0.55
50.70 50.40 50.22
1 Includes condensates reported by OPEC countries, oil from non-conventional sources, e.g. Venezuelan Orimulsion (but not Orinoco extra-heavy oil), and non-oil inputs to Saudi Arabian MTBE. Orimulsion production reportedly ceased from January 2007. 2 Comprises crude oil, condensates, NGLs and oil from non-conventional sources. 3 Net volumetric gains and losses in refining (excludes net gain/loss China and non-OECD Europe) and marine transportation losses. 4 Comprises Fuel Ethanol and Biodiesel supply from outside Brazil and US.
J UNE 2009
113
T ABLES
I NTERNATIONAL E NERGY A GENCY Ͳ M EDIUM ͲT ERM O IL M ARKET R EPORT Ͳ 2009 E DITION
Table 4 WORLD ETHANOL PRODUCTION (thousand barrels pper day) ( y)
OECD North America United States Canada OECD Europe Austria Belgium Germany France Italy Netherlands Poland Spain UK OECD Pacific Australia
Total OECD FSU Non-OECD Europe China Other Asia India Indonesia Malaysia Philippines Singapore Thailand Latin America Brazil Colombia Middle East Africa
Total Non-OECD Total World
114
2008
2009
2010
2011
2012
2013
2014
617 601 15 60 2 2 14 18 1 5 4 5 1 2 2 679 1 0 26 11 4 1 0 0 0 5 474 467 5 0 2 513 1,192
677 655 19 48 1 2 14 16 2 2 2 4 0 3 2 728 1 0 20 12 3 1 0 2 1 5 532 526 4 0 2 567 1,295
754 731 20 53 1 2 14 16 3 1 3 5 2 4 4 811 2 0 22 16 3 2 0 2 1 8 589 581 5 0 2 631 1,442
787 764 21 68 2 3 14 20 4 3 4 6 4 5 5 861 2 0 26 27 4 4 0 3 1 14 632 624 5 0 2 689 1,549
823 794 26 69 2 3 14 20 4 3 4 6 4 7 7 899 8 1 37 35 4 6 0 6 1 17 692 683 6 0 2 775 1,674
823 794 26 69 2 3 14 20 4 3 4 6 4 7 7 899 8 1 40 35 4 6 0 6 1 17 757 747 6 0 2 843 1,742
823 794 26 69 2 3 14 20 4 3 4 6 4 7 7 899 8 1 40 35 4 6 0 6 1 17 827 818 6 0 2 914 1,812
J UNE 2009
I NTERNATIONAL E NERGY A GENCY Ͳ M EDIUM ͲT ERM O IL M ARKET R EPORT Ͳ 2009 E DITION
T ABLES
Table 4A WORLD BIODIESEL PRODUCTION (thousand barrels pper day) ( y)
OECD North America United States Canada OECD Europe Austria Belgium Germany France Italy Netherlands Poland Spain UK OECD Pacific Australia
Total OECD FSU Non-OECD Europe China Other Asia India Indonesia Malaysia Philippines Singapore Thailand Latin America Brazil Colombia Middle East Africa
Total Non-OECD Total World
J UNE 2009
2008
2009
2010
2011
2012
2013
2014
48 46 2 143 4 4 54 34 14 6 4 6 3 4 1 194 1 4 6 19 0 5 4 1 1 8 31 19 2 0 0 61 255
34 33 1 131 4 4 43 38 12 5 2 9 4 3 1 168 1 4 5 20 2 6 4 2 1 6 33 20 1 0 0 63 231
44 43 1 151 4 4 47 38 13 5 3 21 5 3 2 198 1 4 8 25 2 7 4 2 5 6 40 23 2 0 0 78 276
48 47 2 169 4 4 49 43 16 11 4 23 6 6 4 223 3 4 9 39 3 7 6 2 15 6 45 26 2 0 0 99 322
49 48 2 180 4 4 49 44 16 19 4 24 7 7 4 236 3 4 9 45 4 7 6 2 16 10 51 26 3 0 1 113 349
49 48 2 180 4 4 49 44 16 19 4 24 7 7 4 236 3 4 9 47 4 7 6 2 16 12 52 26 3 0 1 116 352
49 48 2 180 4 4 49 44 16 19 4 24 7 7 4 236 3 4 9 47 4 7 6 2 16 12 52 26 3 0 1 116 352
115
T ABLES
I NTERNATIONAL E NERGY A GENCY Ͳ M EDIUM ͲT ERM O IL M ARKET R EPORT Ͳ 2009 E DITION
Table 5 WORLD REFINERY CAPACITY ADDITIONS (thousand barrels per day)
2009
2010
2011
2012
2013
2014
Total
Crude Distillation Additions and Expansions OECD North America 85 410 OECD Europe 20 165 OECD Pacific 34 35
115 104
445
165 110
15
1,235 399 69 340 50 2,416 1,630 513 658 262
1
340
FSU Non-OECD Europe China Other Asia Latin America Middle East Africa
OECD North America OECD Europe OECD Pacific FSU Non-OECD Europe China Other Asia Latin America Middle East Africa Total World
200 270 220 81
1,836
1,252
1,310
1,463
1,046
665
7,572
145 108
221 58
85 65
79
250 65 132 361
258 148 113
107 15 513 540
289 145 73 79 76 240 220 59 111 8
120 50 20 94 20
90 198 215 135 57
171
1,248 589 318 626 91 1,418 1,069 557 420 130
767
1,300
1,112
1,214
521
6,466
311 75
386 -1 55 54 38 198 178 171 201 80
195 30 66 211
195 76
60 20
96 40 120 171
164 180 269 256
315
1,622 292 221 500 42 1,723 1,393 988 1,058 100
1,360
930
1,140
435
610 851
Total World
Upgrading Capacity Additions
240 115 30 211 82
450
216 20
360 124 38 20 100
50 556 270 25 130 60
200
2
285 61 63
80 45 1,553
200
3
Desulphurisation Capacity Additions OECD North America 475 OECD Europe 92 OECD Pacific 100 FSU 170 Non-OECD Europe China Other Asia Latin America Middle East Africa Total World
547 828 164 195 20 2,590
65 3 403 167 223 235 1,483
40
7,938
1 Comprises new refinery projects or expansions to existing facilities including condensate splitter additions. Assumes zero capacity creep. 2 Comprises gross capacity additions to coking, hydrocracking, residue hydrocracking, visbreaking, FCC or RFCC capacity. 3 Comprises additions to hydrotreating and hydrodesulphurisation capacity.
116
J UNE 2009
I NTERNATIONAL E NERGY A GENCY Ͳ M EDIUM ͲT ERM O IL M ARKET R EPORT Ͳ 2009 E DITION
T ABLES
Table 5A WORLD REFINERY CAPACITY ADDITIONS: Changes from Last MTOMR (thousand barrels per day)
2009
2010
Crude Distillation Additions and Expansions 5 OECD North America OECD Europe OECD Pacific FSU Non-OECD Europe China Other Asia Latin America Middle East Africa Total World
-136 -36 -140 -116 -128
2011
2012
2013
-415 16
400
65 110
2014
Total
55 -10 -36
140
166 -100
-70 -159 20 20 100
516 50 25 70 -60
40 95 30 -326 70
270 100 -569
370 128 175 -639 10
-173
-401
202
449
-24
53
-15 35
-74 -114 -25
185 -166 132 91
178 108 113
15 55 -30 -89
-26 -80 -148 30
-366 -137 -122 -61 42 240 -56 59 -25 8
-135 -57
198 140 -90 57
-91 -274 98 30 31 244 -96 140 -250 8
-437
-418
20
704
-160
115 1 -42 -50 -1 -41 -15 -30 53
-340 -96 3
75 11 66 66
75 76
8 198 -63 101 -5 -40
-68 -70 80 -301
-60 180 146 -46
-100 -19 27 16 7 89 -20 45 -299 -40
-10
-234
-141
371
Upgrading Capacity Additions OECD North America OECD Europe OECD Pacific FSU Non-OECD Europe China Other Asia Latin America Middle East Africa Total World
-29
Desulphurisation Capacity Additions OECD North America -25 -11 OECD Europe OECD Pacific FSU Non-OECD Europe China Other Asia Latin America Middle East Africa Total World
J UNE 2009
60 -52 -253
-280
30 -60
-294
117
118 30
20 180
P EM EX - Salina Cruz/Salamanca
P EM EX - Tula Hidalgo
Co no co P hillips - Wo o d River
B P - Whiting
M aratho n - Garyville
Co no co P hillips/EnCana - B o rger
M o tiva - P o rt A rthur
To tal - P o rt A rthur
Valero - P o rt A rthur
M exico
M exico
USA
USA
USA
USA
USA
USA
USA
upgrading/hydro treating
2012 Sino chem - Quanzho u Sino pec - M ao ming Sino pec - Tianjin Sino pec/KP C - Nansha Sino pec/Saudi A ramco /Exxo nmo bil - Fujian
China China China China China
SP C. - Singapo re P etro Vietnam - Dung Quat
Vietnam
30
2010
ENA P - B arrancabermeja P etro ecuado r - Esmeraldas P etro ecuado r - La Libertad P etro ecuado r - Shushufindi P etro jam Ltd. - Kingsto n Repso l-YP F - La P ampilla Lima
Co lo mbia Ecuado r Ecuado r Ecuado r Jamaica P eru
Iran
INA - Rijeka
P etro brazi SA - P lo iesti
B elneftekhim - No vo po lo tsk
Slavneft- M o zyr
A lliance Co . - Khabaro vsk
Cro atia
Ro mania
B elarus
Russia
Africa
2009
1 Crude distillatio n capacity is detailed. If the pro ject is primarily an expansio n o f upgrading o r hydro treating capacity, this will be no ted.
110
M o ro cco
CNP C -Fushun
A lgeria
China
2009
2012
2010
Ghana 80
140
Hydro cracker
UA E
CNP C - Dushanzi
Tatneft - Nizhnekamsk
Russia
2012
UA E
Saudi A rabia
China
Surgutneftegaz - kirishi
Russia
140
2011
2009
Saudi A rabia
Egypt
Ro sneft - Tuapse
Russia
FCC Hydro cracker
2011
2010
China
Luko il - Nizhny No vgo ro d
Ro sneft - Ko mso mo lsk
Russia
Russia
Hydro treater Hydro cracker
Saudi A rabia
ORL - Haifa
SA M IR - M o hammedia
Tema Oil Refining Co . - Tema
Citadel - M o sto ro d
Naftec SP A - Skikda
ENOC. - Jebel A li
A DNOC. - Ruwais
SA M REF - Yanbu
Saudi A ramco - Rabigh
SA SREF - A l Jubail
Qatar P etro leum - Ras Laffan
Israel Qatar
2012
FSU
B elarus
60
NIOC. - Tabriz
2011
2011 Iran
50
hydro cracker
NIOC. - Tehran
NIOC. - B andar A bbas
2012
NIOC. - Isfahan
Hydro cracker
Iran
2013 Iran
SK Co rp. - Incheo n
So uth Ko rea
Hydro cracker
Europe
So uth Ko rea
2012
2010
P ETROB RA S - vario us
B razil
NIOC. - A rak
Hyundai - Daesan
GS-Caltex - Yo su
So uth Ko rea
RFCC
Hydro treater
2013
2010
2013
P ETROB RA S - Co mperj
B razil
NIOC. - A badan
Repso l YP F SA - P uerto llano
To tal - Killingho lme
Spain
UK
75 110
2011 2012
P ETROB RA S - A breu-e-Lima
B razil
Iran
Repso l YP F SA - Cartagena M urcia
Spain
2011 2010
Iran
CEP SA - Huelva
Spain
upgrading capacity
2011 2010
M iddle East
Galp Energia - Sines
P o rtugal
upgrading capacity
90
Hydro cracker
Hydro cracker
60
upgrading capacity
2009
2010
2009
OECD P acific
Lo to s - Gdansk
Galp Energia - P o rto
Italy
P o land
Eni - Sannazzaro
Eni - Taranto
Italy
P o rtugal
Hellenic P etro leum SA - Elefsina
M o to r Oil Hellas - A ghil Theo do ri
Greece
Greece
Hydro treater
Hydro treater
Hydro cracker
Latin America
B o sico r - Karachi
Singapo re
Greece
P akistan
To tal - Leuna
Hellenic P etro leum SA - A spro pyrgo s
Germany
Reliance P etro leum Ltd. - Jamnagar
India
B ayerno il - Ingo lstadt
Germany
2009
ONGC. - M angalo re
Hydro treater
B P CL - Ko chi
Indian Oil Co . Ltd. - P anipat
India India
HM EL - B athinda
India India
HP CL. - M umbai
India
To tal - Do nges
B harat Oman Co . Ltd. - B ina Essar Oil - Vadinar
India India
Asia
CNP C - Jinxi CNOOC - Huizho u
China China
France
2012
2011
2012
2013
2010
2011
2013
2013
2013
2009
2009
2010
P ro je c t
OECD Europe
90
upgrading capacity
325
50
100
upgrading/hydro treating
upgrading/hydro treating
upgrading/hydro treating
P EM EX - Cadereyta
P EM EX - Cuidad M adero
M exico
160
M exico
CCRL - Regina
P EM EX - M inatitlan
Canada
M exico
CNP C - Weihai
2009
China
30
C o unt ry
P etro Canada - Edmo nto n
S t a rt Y e a r
Canada
C a pa c it y ( k bd) 1 CNP C - Qinzho u
P ro je c t China
C o unt ry
OECD North America
115
580
60
40
60
180
48
110
120
160
250
150
240
100
240
200
200
200
hydro cracker
60
hydro cracker
100
Hydro treater
Hydro cracker
Hydro treater
RFCC
Hydro treater
146
60
100
Hydro treater
80
Hydro treater
80
FCC
Hydro treater
FCC
Hydro treater
Hydro treater
Hydro treater
50
Hydro treater
150
200
130
Hydro treater
C a pa c it y ( k bd) 1
2009
2011
2013
2010
2010
2011
2013
2009
2009
2009
2011
2012
2010
2013
2011
2012
2011
2010
2013
2013
2011
2012
2014
2011-13
2014
2013
2009
2009
2012
2009
2013
2010
2009
2013
2010
2011
2011
2009
2014
2010
2012
2010
2009
2014
2013
2011
S t a rt Y e a r
T ABLES I NTERNATIONAL E NERGY A GENCY Ͳ M EDIUM ͲT ERM O IL M ARKET R EPORT Ͳ 2009 E DITION
Table 6 SELECTED REFINERY PROJECT LIST
J UNE 2009
J UNE 2009
Country
OECDEurope
Denmark Denmark Netherlands Norway Norway Norway Norway Norway Norway Norway Norway
Project
Adda Boje Schoonebeek Alvheim Dagny Froyredevelopment Goliat HeimdalOst Morvin Rev Skarv
BlindFaith BlindFaithexpansion Caesar Chinook&Cascade Clipper Droshky GreatWhiteetc Kaskida Liberty Louisianamisc Marlinexpansion Mirage Neptune Nikaitchuk Oooguruk Orion Perdido Phoenix(formerTyphoon) PointThomson Puma Shenzi Tahiti Texasmisc ThunderHawk ThunderHorse TubularBells Borealis CarmonCreek1 ChristinaLakeexpansion ColdLake FortHills1 Horizon1 Horizon2/3 Jackfish1 Jackfish2 JoslynNorth Kearl1 Leismerbitumenproduction LongLake1 LongLake2 NorthAmethyst NorthernLights PrimroseEastexpansion Scotfordphase2 Scotfordphase3 Surmont1 Surmont2 Syncrudestage3 Tucker Voyageur Chicontepec
OECDNorthAmerica
USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA USA Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Canada Mexico
80
10 5 5 90 5 35 50 10 20
2010 2011 2010 2008 2008 2012 2013 2008 2010 2009 2011
2008 2009 2011 2010 2009 2010 2009 2011 2011 2010 2009 2008 2008 2010 2008 2008 2010 2008 2014 2013 2009 2009 2010 2009 2008 2013 2014 2012 2010 2008 2012 2009 2011 2007 2012 2014 2012 2011 2009 2013 2011 2010 2009 2010 2013 2007 2012 2012 2009 2013 2008
Africa Cameroon Congo Congo Gabon Gabon Ghana Ghana Mauritania Mauritania Uganda
2009 2009 2012 2010 2008 2009 2008 2008 2010 2010
China 23 10 300 100 50 100 60 20 20 20
MiddleEast Oman Oman Oman Oman Oman Yemen Yemen
China China China China China China China China China China
Bozhong28Ǧ2S Changqingincrement JidongNanpu Jinzhou25Ǧ1 PenglaiǦ2 PenglaiǦ3 ShanxiInnerMongolia Shenhua1Ǧ1 Shenhua1Ǧ2 Shenhua1Ǧ3
LatinAmerica 2013 2014 2008 2009 2009 2013 2009 2013 2008 2009 2012 2008 2008 2009 2009 2009 2009 2014 2009 2013 2013 2008 2010 2009 2014 2010 2011 2014
Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Brazil Colombia Colombia Peru Peru
15 150 60 35 27 60 50 150 140 300 100 100 85 120 150 380 150 120 40 70 100 240 80 116 150 100 125 260
Shtokman ArkutunǦDaginskoye Kamennoye Kechimovskoye Kharyagaexpansion Kuyumbinskoye Lunskoye Odoptu PiltunAstokhskoyeincrement Priobskoye Prirazlomnoye Salym Talakanskoye Uvatexpansion UzhnoǦKhylchuyuskoye Vankor Verkhnechonskoye VladimirFilanovsky YuriKorchagin YurubchenoǦTokhomskye Chirag&Azeriexpansions Guneshlideepwater Guneshlideepwaterexpansion Karachaganakexpansion(phase3) Kashaganphase1 Tengizexp1 Tengizexp2 Tengizexp3
Country
FSU
Asia India India India Indonesia Indonesia Indonesia Indonesia Indonesia Indonesia Indonesia Indonesia Malaysia Malaysia PapuaNewGuinea Philippines Philippines Vietnam Vietnam Vietnam Vietnam Vietnam Vietnam Vietnam
Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Russia Azerbaijan Azerbaijan Azerbaijan Kazakhstan Kazakhstan Kazakhstan Kazakhstan Kazakhstan
StartYear 2009 2008 2008 2009 2008 2008 2010 2008 2008 2009 2008 2013 2008 2008 2009 2008 2011 2012 2011 2010 2009 2008 2009 2009
Project TyrihansN Vilje Volve Yme Brodgar/Callanish(BritSats) Chestnut Cheviot(formerEmerald) CurlewC Ettrick Grouse(KittiwaketieǦback) Jura Kessog Perth Starling WestDon(Donsatellite) Angel Crux Gorgongas Kipper&Turrum Pyrenees Skua&Montara Vincent Kupe Maari
Country Norway Norway Norway Norway UK UK UK UK UK UK UK UK UK UK UK Australia Australia Australia Australia Australia Australia Australia NewZealand NewZealand 65 25 50 40 25 10 30 7 30 10 30 25 15 3 25 50 30 20 20 90 45 80 10 35
(kbd)
StartYear
(kbd)
45 15 40 80 12 45 100 140 40 100 40 20 50 60 20 55 100 30 10 40 100 125 100 45 210 40 50 50 120 20 140 100 120 35 60 100 100 100 60 60 150 100 40 100 100 25 75 50 30 200 200
Peak Capacity
7
Peak Capacity Project
Dissoni M'boundiexpansion Moho Olowi Onal Jubileephase1 Jubileephase2 Tevet Tiof AlbertBasinPhase1
Daleelexpansion HarweelandotherPDOEOR MukhzainaEOR NimrǦKarim WestBukha Block43Nabrajah BlockS1AnNagyah
Albacoreexpansion BCǦ10ǦShellParquedasConchas BCǦ20ǦPapaTerra Cachalote Chinook/PeregrinoǦStatoilHydro Espadartemodule3 FradeǦChevron Jabuti Jubarte2PǦ57 MarlimLestePǦ53 MarlimSul2ǦPǦ51 MarlimSul3ǦPǦ56 Pinauna RoncadorPǦ55 Siri/Badejotest Tupipilot Castillaexpansion Rubialesexpansion Block67Amazon Camiseaincrements
Aishwariya Bhagyama Mangala Aster BanyuUrip(Cepu) BukitTua Gendalo/Gehem NorthBelut NorthDuristeamflood NorthDuristeamfloodphases2&3 UjungPangkah BungaPakma Gumusut PortMoresbyLNG Calauit Galoc BungaPakma CaNguVang HaiSuDen/HaiSuTrang PhuongDong SongDoc SuTuTrang SuTuVang
15 35 90 20 10 45 90 20 50 5
15 40 100 15 10 14 20
25 100 180 100 100 100 80 100 180 180 150 100 25 150 15 100 100 80 100 30
75 50 50 20 160 20 25 25 34 45 15 17.5 150 30 12 17 17.5 20 35 20 25 70 100
(kbd)
Peak Capacity
2011 2010 2008 2009 2009 2010 2012 2010 2011 2011
2012 2010 2013 2012 2009 2008 2009
2010 2009 2013 2012 2010 2013 2009 2009 2011 2008 2008 2011 2009 2012 2008 2010 2011 2013 2013 2009
2010 2011 2009 2010 2009 2010 2013 2010 2008 2012 2009 2008 2012 2010 2011 2008 2008 2008 2011 2008 2008 2012 2008
StartYear
I NTERNATIONAL E NERGY A GENCY Ͳ M EDIUM ͲT ERM O IL M ARKET R EPORT Ͳ 2009 E DITION T ABLES
Table 7 SELECTED NONǦOPEC UPSTREAM PROJECT STARTǦUPS
119
120 Country W. Qurna
Project
8 50
Bir Seba (Blocks 433a/416b)
IAN/EOR
Menzel Ledjmet East (MLE Block 405b)
Takouazet
El Merk
Mafumeira (Block 0)
Algeria
Algeria
Algeria
Algeria
Algeria
Angola
115 125
PAZFLOR (Block 17) Kizomba D‐‐Satellites (Block 15)
Negage (Block 14)
SE PAJ (Block 31)
CLOV (Block 17)
Angola
Angola
Angola
Angola
Yadavaran I
Abuzar EOR
Tawke
Taq Taq
Majnoon
Luhais
S. Rumaila
Iran
Iran
Iraq
Iraq
Iraq
Iraq
Iraq
South Pars
Jufeyr II
Iran
Foroozan
Iran
Iran
Aghajari Darkhovin II
Jufeyr I
Iran Iran
Iran
Gindungo, Canela, Gengibre (Block 32)
Pungarayacu field‐‐Phase 1
Angola
Ecuador
Angola
275
50
80
60
90
30
85
10
35
80
15
30 60
30
110
50
125
200
150
100
Tombua‐Landana (Block 14)
PSVM (Block 31)
Angola
Angola
35
135
30
36
2012
2012
2012
2012
2009
2009
2013
Lower Zakum expansion Upper Zakum expansion
UAE UAE UAE
75
Umm Shaif expansion ADCO Onshore ‐‐ASAB, Shah & Sahil EOR
UAE
900
Manifa
Saudi Arabia
150
25
65
40
1200
100
250
Khurais (incl Abu Jifan & Mazalij)
Nuayyim PNZ
Shaybah 2
Saudi Arabia Saudi Arabia
2011 2012
250
Saudi Arabia
AFK Ph 2 (Abu Hadriya; Fadhili; Khursaniyah)
Saudi Arabia
35
200 100
150
180
120
160
60
150
50
50
35
50
90
90
120
40
65
70
50
Saudi Arabia
Al Rayyan
2010
Egina Al Shaheen increments
Qatar
Bonga SW/Aparo
Nigeria Nigeria Qatar
Usan
2010
Gbaran/Ubie Bosi
Nigeria Nigeria
Ofon 2 expansion
Nigeria
Nigeria
Zuetina expansion
Verenex Ghadames Basin Area 47 Nafoora expansion
NC186 expansion
Libya Libya Libya
Gialo Expansion (Waha EOR)
Libya
Libya
Sabriya GC‐24 Amal
Kuwait
Burgan water treatment
Libya
Kuwait
PNZ
Nassiriyah
Iraq Kuwait
Nahr bin Umar
Iraq
Iraq
2009 2009
2012
2014
2013
2013
2012
2012
2012
2012
2010
2009
2012
2013
2012
2012
2011
2010
2010
2014
2013
2012
2012
2014
2013
2009
2009
2009
2009
2010
2014 2010
2014
2013
2012
2011
2010
2013
2013
2012
2012
2012
2010
2013
2013
2013
2013
2013
2012
Start Year Country
Project
UAE
UAE
Saudi Arabia
Saudi Arabia
Saudi Arabia
Saudi Arabia
Saudi Arabia
Qatar
Qatar
Qatar
Qatar
Qatar Qatar
Qatar
Qatar
Nigeria
Nigeria
Libya
Kuwait
Iran
Iran
Iran
Iran
Iran
Iran
Iran
Algeria
Algeria
Algeria
Asab 2 NGL
OGD 3 Habshan expansion
Manifa
Khurais
Hawiyah
Khursaniyah (NGL)
Khursaniyah (condensate)
Al Khaleej 2
Pearl GTL ‐ 2
Oryx GTL
Pearl GTL ‐ 1
RasGas Train 6 (condensate) Qatargas 6‐7 (condensate)
RasGas Train 6 (NGL)
Qatargas Train 4 (condensate)
Escravos GTL
Akpo
NC‐98
Sabriyah & Umm Niqa II
Kharg NGL
Pars 12 (NGL)
Pars 12 (condensate & LPG)
Pars 9‐10 (NGL)
Pars 9‐10 (condensate & LPG)
Pars 6‐8 (NGL)
Pars 6‐8 (condensate & LPG)
Gassi Touil (NGL)
El Merk (NGL)
El Merk (condensate)
MLE (Block 405)
Algeria
Algeria
200
Rhourde El Baguel expansion
Hassi Messoud EOR
Algeria
125
(kbd)
Start Year
(kbd)
NGL & Condensate Projects
Project
Crude Oil Projects
Country
Peak Capacity
Peak Capacity
71
270
50
70
300
210
80
40
70
65
70
110 140
45
160
35
175
60
115
50
50
120
34
80
50
80
10
30
55
24
(kbd)
Peak Capacity
2010
2009
2014
2009
2009
2009
2009
2009
2014
2012
2011
2009 2010
2009
2009
2012
2009
2013
2012
2013
2013
2013
2009
2009
2009
2009
2014
2012
2012
2012
Start Year
T ABLES I NTERNATIONAL E NERGY A GENCY ‐ M EDIUM ‐T ERM O IL M ARKET R EPORT ‐ 2009 E DITION
Table 8 SELECTED OPEC UPSTREAM PROJECT START‐UPS
J UNE 2009
NATURAL GAS MARKET REVIEW
2009 Order from our website:
www.iea.org/books or e-mail:
[email protected]
The global economic crisis has not spared the gas sector. Over the past year, we have moved from a tight supply and demand balance with extremely high gas prices to an easing one with plummeting gas prices. Since the last quarter of 2008, demand has been declining dramatically, essentially because of the global recession. Yet significant new volumes of liquefied natural gas will come on stream within the next few years, and the United States’ unconventional gas production has risen rapidly, with global consequences. It remains to be seen how these demand and supply pressures will play out, particularly in the pivotal power sector, in both OECD and non-OECD countries. Meanwhile, the security of gas supplies has once again become a critical issue, in particular in Europe after it experienced its worst supply disruption during the Russian-Ukraine crisis in January 2009. Moreover, the current market climate of weakening demand, lower prices and regulatory uncertainties added to the tough financial environment are likely to jeopardise investments, in particular in capital-intensive projects, further undermining long-term energy security in the most fundamental way when economies recover. The Natural Gas Market Review 2009 looks at these and other major developments and challenges in the different parts of the gas value chain in a selection of IEA countries – the United States, Canada, Spain, Norway, the Netherlands, and Turkey – as well as in non-IEA member countries in the Middle East, North Africa, Southeast Asia, and China.
I N T E R N AT I O N A L
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