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IN THIS ISSUE WINTER 201601 Comment

02 A turbulent timeNancy Yamaguchi, Contributing Editor, reviewsthe effects of recent political turbulence on NorthAfrica’s oil and gas sector.

10 A maturing marketRasholeen Nakra, Frost & Sullivan, Canada, explainshow market developments have shaped the overallgrowth of the LNG industry.

16 Roundup, roundup: global pipelineprojectsOil and gas prices have fallen drastically in 2015.Due to an abundance of supply and reducedconsumption, global energy markets have had tofind more economical ways of transporting oil andgas and put an abundance of pipeline projects onhold. Dr. Hooman Peimani seeks to summarise themajor global pipeline projects and how they havebeen affected.

22 What’s up down under?David Bizley, Editor, Oilfield Technology , takes a lookat some of the challenges facing the Australian oiland gas industry.

26 Finding the right pathEkaterina Kalinenko and Luisa Sykes, Euro PetroleumConsultants, explain how the global petrochemicalindustry can adapt to the high level of uncertaintyand volatility in energy markets and still remaincompetitive.

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NEW FOR 2016Welcome to the rst edition of Energy Global magazine – abrand new, digital quarterly from Palladian Publications Ltd.Since 2009, www.energyglobal.com, has been bringingyou the latest news, views and expert comment fromthe global oil and gas industry. It is also the homeof our four industry leading publications coveringthe upstream ( Oilfield Technology ), midstream(World Pipelines and LNG Industry ), and downstream(Hydrocarbon Engineering ) sectors, as well as a specialindustry storage supplement ( Tanks and Terminals ).Our expertise in all of these fields has led to thecreation of this magazine – our first to cover the oil andgas industry in its entirety. Each issue will include aselection of our favourite articles from recent editionsof our sister publications, as well as some brand newcontent, prepared especially for Energy Global readers.At the end of each article, you’ll find full details ofwhere and when the piece was originally published.If you’d like to keep up-to-date with the latestdevelopments in a particular sector of the industry, we’dencourage you to sign up for a free trial subscription ofthat publication via www.EnergyGlobal.com/magazines/.We hope you enjoy this edition of Energy Global magazine. Keep an eye on your inbox for the next editionin the Spring. In the meantime, we’ll be breaking newsacross www.energyglobal.com, so please bookmarkus, follow us on Twitter (@EnergyGlobal), like us onFacebook (Facebook.com/EnergyGlobal) and join ourarray of groups on LinkedIn.


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22

Nancy Yamaguchi,Contributing Editor, reviews the effects of

recent political turbulence

on North Africa’s oil andgas sector.


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3

orth Africa, Tunisia in particular, is viewed as thebirthplace of the Arab Spring protests in 2011, a series ofprotests that spread across North Africa and theMiddle East, focusing largely on issues such as

unemployment, ination, high food prices, restrictions onfreedom of speech and corrupt leadership. A number of countrieschanged leadership entirely, while others launched a process of

change and concessions. While 2011 is used as a convenient datemarker, the issues were long standing. Protracted dissatisfaction inTunisia was galvanised by the self-immolation of a young,unemployed citizen who had been victimised by the authorities.This tragedy set off the Tunisian Revolution that toppledPresident Zine El Abidine Ben Ali, who had been in power for over

23 years before he had to ee the country. Before him, Tunisia’srst President, Habib Bourguiba, had been in ofce for over30 years. Most Tunisians had known only one or perhaps tworulers in their entire lives, and hoped that a change in leadershipwould change the country. In neighbouring Libya, MuammarGhadda had been in power since 1942. His presence had verymuch dominated the country, and in many ways made it a pariah

nation. In Egypt, President Hosni Mubarak had been in power since1981. He was unable to respond properly to the Arab Springprotests, and was forced to resign in 2011. The Egyptian Crisisfollowed. Algeria was the site of the 2010 – 2012 Algerian Protests,and although President Abdelaziz Bouteika was re-electedvirtually without opposition, unrest persists to this day.

Arial view of the Hoggar Mountains,Algeria, in the Sahara Desert.


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4 Energy Global Winter 2016

Morocco alone seemed to respond quickly to protests andremain peaceful. The ruler, King Mohammed VI, is viewed as amoderate, and the constitutional reforms offered receivedenough public approval that the government remained in power.

For the rest of North Africa, however, the sociopoliticalsituation remains in ux, without universally approved leadership.There was widespread disappointment, with critics noting thatthe Arab Spring had moved into an Islamist Winter. This is having anegative impact on the energy sector, affecting both the state runenterprises and the private sector participants, when they areallowed. The North African countries have been criticised forhaving very poor governance of their resource industries. The lackof security and the risk of investing in many North African areas issuppressing activity, cutting into government revenue, which

Figure 1. Active oil and gas rigs in North Africa, monthly,2007 through August 2015. Source: Baker Hughes.

Figure 3. The rise and fall of North African crude exports tothe US. Source: EIA.

Figure 2. North Africa has lost its share of total Africancrude oil output. Source: BP.

suppresses growth and prosperity, and so on in a cycle. Theviolence in Libya has continued more or less nonstop, with at leasttwo rival governments contending for power while neither has theability to control the rise of jihadists and Islamic State (IS) members,some of whom have been linked to attacks in Tunisia and Egypt.

The tourism industry is expected to suffer, of course, and it isan important, non-energy, economic activity. This will re-emphasise

the importance of the energy sector in the overall economicpicture. Throughout 2015, the situation was further complicated bythe lack of OPEC unity and the drop of global oil prices, which cuteven more into government revenues. Algeria and Libya are two keyOPEC countries, and their oil production and oil revenues declined.This slump was felt throughout the region. This article discusses theups and downs of North Africa’s oil and gas industry, posing thequestion of whether the sociopolitical and market conditions mayameliorate the current industry stagnation. Is it a good time to stepback from energy investments in North Africa?

North African upstream sector: up anddownNorth Africa is the site of a major share of Africa’s oil and naturalgas reserves, and Algeria and Libya are members of OPEC. Yet theupstream sector has languished, and production has actually beenin decline. According to BP, Algerian oil reserves have been at at12.2 billion bbls for seven years from 2007 through 2014. Egyptianreserves were raised from 4.07 billion bbls in 2007 to 4.5 billion bblsin 2010, but they were hastily revised down and were listed at3.6 billion bbls in 2014. Tunisia’s reserves fell from 0.6 billion bbls in2007 to 0.43 billion bbls in 2014. Only Libya has added signicantlyto its reserves since 2007, raising its estimate from 43.66 billion bblsin 2007 to 48.36 billion bbls in 2014. Currently, there is no huge pushto invest in expanding the reserves base, which is alreadyconsiderable. It is not an absence of reserves as much as thepolitical situation that has carved away at oil output. In 1970, Libyawas the fourth largest crude producer in OPEC. In 2014, OPECreported that Libyan crude production averaged only 479 000 bpd,the lowest level of any OPEC member. Now, a number of keyoilelds are effectively shut in, transport infrastructure is damagedor blocked, and supposed security guards are on strike.

When global oil prices spiked in 2008, there was a surge in oildevelopment in many prospective areas around the globe. But asFigure 1 illustrates, much of the excitement bypassed North Africa,and activity declined during 2015. Figure 1 presents the BakerHughes data series on active oil and gas drilling rigs in Algeria, Libyaand Tunisia. The strength of global crude prices post-2008stimulated oil development, yet the price spike was also a factor inthe global economic slump that cut into demand. Following that,the civil war in Libya in 2011 paralysed its oil industry, with starklyvisible results. Even after Libyan wells came back into operation,2015 saw another downturn, partly in response to two moreattempted coup d’etats and the strife between the two rivalgovernments. In February 2014, there were a total of 71 active rigs inAlgeria, Libya and Tunisia, but this has since fallen to 54 active rigs inAugust 2015.

Figure 2 presents the long-term trend in North African crudeproduction according to BP. Libyan output shows massive swings upand down. In 1970, Libya was one of OPEC’s top producers, withcrude output of 3.357 million bpd. Output collapsed and remainedin the range of 1 – 1.2 million bpd from 1981 through 1989.Production climbed to approximately 1.8 million bpd by2006 – 2008. Then, the global recession hit, followed by the civilwar in 2011, which slashed production to 479 000 bpd in 2011.Production was restored to 1.509 million bpd in 2012, yet it


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plummeted again to 498 000 bpd in 2014. The InternationalEnergy Agency (IEA) believes that Libya’s sustainable near termproduction capacity is only 500 000 bpd, and production in July 2015 was estimated at 390 000 bpd. Libya’s resources remainenormous, but development is difcult in an environment wheresecurity cannot be guaranteed. In the future, it might also bepossible to develop Libya’s shale oil resources. The US Energy

Information Administration (EIA) has estimated Libya’s technicallyrecoverable shale oil resources at 26 billion bbls, placing itsreserves as the fth largest in the world following Russia, the US,China and Argentina. But this must be a distant future.

Algerian production grew impressively during the 1990s andreached nearly 2 million bpd by 2007, but output fell to1.525 million bpd in 2014. Two small elds came onstream inAugust 2015 to help stem the decline, the 20 000 bpd Bir Sebaaeld and the 12 000 bpd Bir Msana eld. New developments havecome about slowly because of multiple delays in oil and gasprojects. Government approval of projects has often come tooslowly, which has discouraged investors. Foreign investors havealso declared that the contract terms offered by the government

Figure 4. Ups and downs of North African LNG exports.Source: BP.

Figure 5. North African exports of pipeline natural gas.Source: BP.

Table 1. North African refinery configuration 2015 (1000 bpd)No. of refineries CDU VDU Coking FCC HDC Cat ref Alk Isom HDT Lube Asp

Algeria 5 497.4 14.5 0.0 6.0 0.0 90.2 0.0 0.0 83.3 3.3 5.2

Egypt 9 794.3 94.6 39.3 0.0 33.5 83.7 9.0 27.4 207.5 8.1 20.0

Libya 5 380.0 3.8 0.0 0.0 0.0 20.3 0.0 0.0 43.3 0.6 3.4

Morocco 2 154.7 27.5 0.0 5.0 0.0 26.5 0.0 0.0 52.6 2.1 1.9Tunisia 1 34.0 0.0 0.0 0.0 0.0 3.3 0.0 0.0 0.0 0.0 0.0

Total 22 1860.4 140.3 39.3 11.0 33.5 224.0 9.0 27.4 386.8 14.1 30.5

Source: Trans-Energy Research Associates, drawing on company data and Oil and Gas Journal

are not as favourable as they are able to nd in other prospectiveareas. There were three licensing rounds that attracted much lessinterest than the Algerian government had hoped. During thelicensing round in 2010, for example, only two blocks were awardedout of 10 on offer. The threat of violence is a huge deterrent. Forexample, the In Amenas natural gas complex was attacked bymilitant Islamists in January 2013. This complex is located near the

border with Libya. It is operated by the state oil and gas companySonatrach with BP and Statoil as foreign partners. BP and Statoilwithdrew their personnel and postponed their plans to expandoutput from the facility. Violence has continued, and theinternational community was outraged when a militant groupkidnapped and beheaded a French tourist in September 2014.

The government launched new contractual and scal terms in2013 in order to stimulate interest. The revisions to its hydrocarbonlaw included the basing of some taxes on prot rather thanrevenue, which allows project costs to be taken into account ratherthan just revenue. The government also provided tax incentives forthe development of shale oil and gas, other unconventionalreserves, certain small and offshore elds, and elds isolated

because of a lack of infrastructure. In the 2014 round of bidding, 17of 31 licenses on offer were for unconventional projects. Althoughonly four were awarded, this was viewed as a positive step.

Despite the government’s interest, however, development ofshale resources is not to be expected in the near future. TheUS EIA estimates Algeria’s technically recoverable shale oilreserves at 5.7 billion bbls. The EIA’s assessment places Algeria’stechnically recoverable shale gas reserves at an incredible707 trillion ft3, the third largest in the world following China andArgentina. The US is fourth on the list, with shale gas reserveslisted at 665 trillion ft 3. However, much of the Algerian resourcebase is located inland in the deeper desert areas, where the waterresources needed for hydraulic fracturing operations are in shortsupply. Farmers and ranchers in the area immediately expressedconcern over potential competition for water supplies. There islittle existing infrastructure to support new development. Thegovernment mistakenly assumed that there would not be anypublic opposition to shale oil and gas development, and wasunprepared for the protests that broke out.

Tunisia is a small producer, with a production capacity of53 000 bpd in 2014, according to BP. Tunisian production is alsodeclining, having fallen from a peak of 97 000 bpd in 2007.

Egyptian output rose to a peak of 941 000 bpd in 1993 beforeentering a state of decline, falling below 700 000 bpd by 2005.There was a resurgence in output thereafter, and a high degree ofoptimism because of increased output from the Western Desertand the success of enhanced oil recovery (EOR) application inmature elds, but output has stagnated since then. Indeed, crudeexports might have fallen even lower if certain foreign producershad not been permitted to maintain exports as a means ofrepaying debt.


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7Winter 2016 Energy Global

In total, North Africa’s position as an oil exporter has waned. AsFigure 2 illustrates, the region accounted for over 80% of Africa’stotal oil exports before 1970. This share has declined since then, withthe decline hastening during the most recent decade. In 2014, NorthAfrica’s share of total African crude exports had fallen below 34%.Internal unrest and lack of investment are chiey to blame, butcompetition has also grown from a hitherto unexpected source:

North America. North African crudes are characterised by theirquality, typically light in gravity and low in sulfur. The past decadebrought the US as an unexpected entrant to this market. Theadvances in hydraulic fracturing caused a ‘shale boom’ in the US, andthe new supplies of light tight oils (LTO) have largely supplantedAfrican crudes. Figure 3 displays the sharp rise and fall in NorthAfrican crude exports to the US between 2000 and 1H15. NorthAfrican crude exports to the US, led by Algeria and Libya, surpassed500 000 bpd in 2006, but they collapsed to 200 000 bpd in 2012,and had all but vanished by 2014.

Natural gas exports: also up and down Just as political turmoil and market uncertainty has affected oil

output, North African LNG exports have risen and fallen. Egypthoped to expand its natural gas production and exports via LNG. Therst LNG plant was the Spanish Egyptian Gas Company (Segas) plantat Damietta, which came onstream in 2004. Egypt built two LNGplants, and exports quickly climbed to 14.97 billion m 3 in 2006. AsFigure 4 shows, however, exports began to fall after 2008, and theyare now nonexistent. There simply has not been enough natural gasto supply the plants, as local demand has grown and development ofnew oil and gas elds has stalled.

Libya inaugurated LNG exports to Spain, but as the gure shows,the exports were relatively small, in the range of 0.5 – 0.8 billion m 3/yuntil civil war and unrest eliminated exports entirely.

Algeria is the chief LNG exporter in North Africa, and in fact itwas the rst LNG exporter in the world. It has two LNG plants, atArzew and Skikda, with an expansion completed at Arzew in 2014,known as the GL3Z train. Enhancements are also underway at Skikdathat will increase output. As shown in Figure 4, LNG exports hadbeen declining steadily from 25.75 billion m3 in 2004 to 14.9 billion m3 in 2013, before recovering to 17.3 billion m3 in 2014, according to BP.This is still well below historic export levels. North African producersare also watching the US because of plans to build LNG exportterminals in the US Gulf Coast, which would provide an avenue forexporting US shale gas.

Exports of natural gas via pipeline have also languished (Figure 5),as reported by BP. Algeria is the chief exporter, delivering largevolumes of pipeline gas to Italy and Spain, with lesser volumes toPortugal and other European countries, plus volumes to neighbouringMorocco and Tunisia. Exports fell from 37.5 billion m3 in 2008 to23.49 billion m3 in 2014. Egyptian exports of pipeline gas havevanished, but formerly went to Israel, Jordan, Lebanon and Syria.Libya’s natural gas exports to Italy were disrupted by the civil war,falling from 9.87 billion m3 in 2008 to 2.34 billion m3 in 2011. Theyhave risen since then, but not to their prior levels, reaching6.47 billion m3 in 2012 and subsiding to 5.23 billion m3 in 2013 and5.97 billion m3 in 2014.

The OPEC members: Algeria and LibyaNorth Africa is a signicant centre of oil and gas activity, largely byvirtue of its two OPEC members, Algeria and Libya. But just as OPEChas lost market share and lost some ability to inuence prices, Libyaand Algeria have lost ground, arguably to a greater degree than thatexperienced by the other OPEC members. Following the Arab Springuprisings, there were hopes for market-based reforms that would

revivify the energy industries and promote economic growth. Butfor many, the initial surge of hope and activity was blunted bycontinual setbacks. It became clear that large scale reforms wouldtake time, patience, national unity and money. The supplies ofthese things are never abundant, even in the best of times, andthe recent years have been far from the best of times. NorthAfrica therefore remains in a state of ux. There are manyopportunities, but there is at best a highly unpredictable ability tocapitalise on these opportunities, and at worst a greatlydeteriorated ability.

By far the greatest hindrance to energy sector success is thepolitical situation. Governments are not perceived as stable,representative, and able to enforce rule of law. This makes itdifcult to raise capital, reducing the potential for successful

Figure 7. Algeria has become a net importer of gasoline.Source: OPEC.

Figure 8. Algeria has become a net importer of diesel.Source: OPEC.

Figure 6. North Africa subsidised diesel prices relative to UKprices. Source: The World Bank.


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development, which then runs in a destructive cycle. Libya inparticular remains divided, and its civil war is continuing to have adrastic impact on the energy industry. The internationallyrecognised government elected in 2014, also known as the TobrukGovernment, has set up its centre in the east and controls the vitalRas Lanuf renery and oil port. But the self-named 'Libya Dawn'organisation holds itself as the legitimate government in Tripoli inthe west. There are at least two other coalitions seeking power,plus assorted militias and local groups who may throw support toother coalitions depending on the issues. The United Nationscontinues to negotiate for a resolution to the conict but, in themeantime, a number of key oilelds and terminals have ceased tooperate. Some have been damaged or sabotaged. Others have had

Figure 10. Libya has become a diesel importer. Source: OPEC,supplemented by Trans-Energy Research Associates.

Figure 11. Decline on North African refined product exportsto the US. Source: EIA.

Figure 9. Libya has become a significant importer ofgasoline. Source: OPEC, supplemented by Trans-Energy ResearchAssociates.

operations blocked by the guards supposed to provide security,some of whom have gone on strike, and others of whom haverefused to let tankers load at the Ras Lanuf terminal.

Although OPEC members often lend mutual support, andvarious services are provided by the OPEC Secretariat, OPEC itselfis experiencing an erosion of inuence as oil prices have tumbled.When Saudi Arabia announced in late 2014 that it would not work

to defend prices, the spot price for Brent crude fell fromUS$87.43/bbl in October 2014 to US$47.76/bbl on average in January 2015. Prices recovered to the US$55 – 64/bbl range fromFebruary to July 2015, but average prices in August dropped toUS$46.58/bbl. Without OPEC unity and a desire to rein inproduction and support prices, there is little reason to believethat prices will rise.

The refining sector

Refinery capacity and utilisationTable 1 presents North Africa’s renery capacity by country andunit type. While each North African country maintains a rening

industry, the reneries are for the most part lacking in conversioncapability and in the ability to produce a full slate of desulfurisednished product consistent with Euro 5 or US quality standards.Morocco and Tunisia have the smallest industries. Egypt, with acrude capacity of 794 300 bpd, has the largest industry. Egypt’sMiddle East Oil Renery at Alexandria is a sophisticated facilitywith a hydrocracker and a coker for fuel oil destruction, pluscatalytic reforming and isomerisation for octane production. Butthis renery is a standout in the region, where most renerieshave hydro skimming congurations. Algeria’s industry has a crudecapacity of 497 400 bpd, including 335 000 bpd at the region’slargest renery, located at Skikda. This renery has run as much as350 000 bpd. Libya’s nameplate crude capacity is 380 000 bpd.

Unsurprisingly, the turmoil that is affecting the upstreamsector is also affecting the downstream sector, and very littlehas been done to build and upgrade reneries in the region,despite many ambitious plans. The capacity already in place isseverely underutilised. According to BP, renery utilisation ratesfor Africa as a whole have been weak – below 80% utilisationsince the year 2000, and below 70% since 2011. BP reportedAfrican renery utilisation at a sickly 63% in 2014. It isunderstandably difcult to gain support for renery investmentprogrammes in such an environment. In the Middle East, Europe,the Mediterranean, Asia, and across the Pacic Ocean, there isalready spare renery capacity of a sort that can produce Euroand US standard fuels.

Pricing and the gasoline and diesel balanceLike many countries with state run energy industries, the NorthAfrican countries subsidise domestic fuel prices. Figure 6compares the trend in diesel prices at the pump in the ve NorthAfrican countries with the pump price in the UK between 2000and 2014, as tracked by the World Bank. In 2014, the average dieselprice at the pump in the UK was US$1.99/litre. In Morocco, whichis a net importer of product, the price was US$1.11/litre. Tunisia,which also has a small rening industry and is a net importer,priced its diesel at just US$0.68/litre. In the three main reningcountries, prices grow successively lower: US$0.25/litre in Egypt,US$0.16/litre in Algeria, and a mere US$0.10/l in Libya in 2012, thelast year for which data was available. There are many countriesthat subsidise domestic prices to please citizens and to helpcontain ination, but nearly all of them must contend eventuallywith an inefcient rening system.


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Conclusion: a time for recovery?North Africa’s oil and gas industry is essential to overall economichealth, and oil and gas revenues are the mainstay of governmentsnow challenged to bring order and prosperity to their citizens. Butplans to expand oil and gas activities upstream and downstreamare experiencing setbacks. Exploration and development activitieshave slowed, though the resource base is large and there appearsto be signicant potential for shale oil and gas development. Therecan be no ‘shale revolution’ in the midst of sociopoliticalrevolution. There is also less incentive to go prospecting forunconventional oil and gas when global prices have fallen. Themoney could be better spent restoring and improving output fromexisting areas by repairing infrastructure and improving security.Similarly, there is little incentive to invest in rening when there isunderutilised rening capacity of greater technological capability inmore advantageous locations.

North Africa is changing from within, while the rest of theworld changes around it. Oil prices had been weakening as globaldemand growth slowed and as other sources of supply expanded,including the new shale oil and gas supplies in the US, whichdramatically reduced US import requirements. OPEC was notwilling or able to defend prices, and they are now at a low ebb. Inthis regard at least, Algeria and Libya have aided the OPECmembership by reducing supply. In the longer term, both countriesneed to revive production and exports. For the time being,however, North Africa’s oil and gas industry may be in a restingcycle, slowly restoring itself rather than moving to grow. In today’smarket, this may be the wiser course.

This article was originally published in the December 2015 issue ofHydrocarbon Engineering . Register for your free copy of the magazine here:http://www.energyglobal.com/signin/?mgz=hydrocarbon-engineering

Figure 7 presents the trend in Algeria’s gasoline production versusthe trend in demand from 1996 through 2014, as reported by OPEC.For the decade from 1996 through 2005, Algeria was a slight netexporter of gasoline, with output in the range of 41 000 – 55 000 bpdand demand in the range of 40 000 – 47 000 bpd. Demand began togrow more rapidly after 2008, however, and it reached 87 000 bpd in2014. Renery output, in contrast, dropped during the Algerian

Revolution, falling to approximately 50 000 bpd in 2011 – 2013 beforerising to 63 000 bpd in 2014, still below the level of demand.

Algeria is facing a similar problem with its diesel balance, asFigure 8 shows. In 1996, diesel demand was 61 200 bpd, while dieseloutput was more than twice demand at 127 400 bpd. But dieselproduction remained attish over the next 10 years while demandrose steadily. From 2007 through 2010, diesel demand and dieseloutput were roughly equal, but diesel output dropped fromapproximately 181 000 bpd in 2010 to 126 000 bpd in 2012. Productionrecovered to 190 000 bpd in 2014, but demand of 211 700 bpdremained above output.

Libya’s gasoline and diesel balances have been signicantly morevolatile. Figure 9 compares Libyan gasoline production with demand

from 1996 through 2014. Gasoline production was reported as slightlyabove demand from 1996 through 2001, at approximately46 000 – 48 000 bpd. Demand was in the range of39 000 – 43 000 bpd. According to OPEC data, Libyan gasoline outputfell to 17 000 bpd in 2004 and has remained in the range of15 000 – 19 000 bpd since then. Demand rose to nearly 76 000 bpd in2010 before the 2011 civil war caused it to fall to 63 000 bpd. Demandhas risen since then, however, and was reported at 89 100 bpd in 2014.Libya has become a major importer of gasoline.

Libya has also become a net importer of diesel (Figure 10). From1996 through 2004, Libya was a diesel exporter. Supply and demandthen moved roughly into balance until 2008, when demand began topull ahead of production. The Libyan Civil War of 2011 caused acollapse of both demand and production, with demand falling from115 500 bpd in 2010 to 70 200 bpd in 2012 and output falling from96 400 bpd in 2010 to 46 200 bpd in 2012. Demand recovered to98 000 bpd in 2013 and 96 400 bpd in 2014, but production hascontinued to decline, averaging 37 900 bpd in 2014.

Structure and quality of product exportsIn addition to being underutilised in terms of its nameplate crudecapacity, the North African rening industry lacks sufcientupgrading capacity. Renery output is not the ideal match fordomestic markets, nor for making successful inroads into exportrening. North African rened product exports to the US, forexample, dropped from a peak of 326 000 bpd in 2006 to109 000 bpd during 1H15. Figure 11 displays this trend. Algeria is by farthe main product exporter, with a brief resumption in exports fromLibya during the 2005 – 2010 period, and occasional cargoes fromEgypt, Morocco and Tunisia.

Very little of the product exported is nished gasoline, aviationfuels and diesel, however. North African output largely cannot meetthe specications for transport fuels. As Figure 12 illustrates, one ofthe chief exported products is actually a product class known as‘unnished oils’, which are used mainly as feedstock for cat crackingunits. Figure 13 provides a more detailed picture of Algeria’s productexports to the US broken out by product type. Not only have productexport volumes shrunk in recent years, the current composition ismainly unnished oils. The other product classes shown arepetrochemical feedstocks, liqueed petroleum gas (LPG,) fuel oil andgasoline blending components. The vanishingly small ‘other’ categoryincludes the high quality specication products such as gasoline,aviation fuels and diesel, plus all other products.

Figure 12. The principal North African product export tothe US: unfinished oils. Source: EIA.

Figure 13. Algerian refined product exports to the US bytype. Source: EIA.


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maturing market Rasholeen Nakra, Frost & Sullivan, Canada , explainshow market developments have shaped the overall

growth of the LNG industry.

A


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The oil and gas industry is volatile and newtechnology and market developments play a big rolein shaping this industry. The LNG industry is anexample, where market developments have boosted

the growth of LNG. Strong economic growth in the Asia-Pacic region has stimulated high gas demand. This, coupledwith domestic reserves available, generates the need for

international gas trade. The key regions contributing to thisdemand are Japan, China and India.

The Fukushima disaster in 2011 led to a shutdown of50 nuclear power plants in Japan. Nuclear energy accountedfor 30% of the country’s total electricity production, and theshutdown of nuclear plants triggered steep gas requirementsfor power generation. In 2014, approximately 70% of gas wasconsumed by the power sector.

In China and India, along with the economic growth, theswitch to cleaner fuels is one of the drivers for high gasdemand. Europe’s reliance on LNG has increased in the past

two years as it diversies its gas supply source, other thanRussia’s piped gas imports. Figure 1 shows the steady increasein the percentage of LNG trade as the global gas consumptionincreases.

Qatar has controlled the world’s LNG supply market, butsupply options from the US and Australia have started tochange this trend. Technological advancements, such as

hydraulic fracturing, have resulted in signicant gas productionfrom the shale gas reserves in the US. This is a game changer asthe US will be able to fulll its own gas requirements, andbecome a net gas exporter. Furthermore, Australia has sevennew LNG projects under construction that are expected tostart operations between 2016 and 2018. With a surge in LNGexports, Australia is likely to overtake Qatar as the world’slargest LNG supplier by 2018.

All of these factors have changed the dynamics of the globalLNG trade in the 2009 – 2013 timeframe. However, the oil pricecrash in 4Q14 has created uncertainty for the future LNG market.


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Asia-Pacific LNG demandIn the Asia-Pacic region, the adoption of cleaner and cheaperfuels has stimulated gas demand. In particular, the burgeoningeconomies of China and India have boosted gas consumptionin both countries. In order to curtail its carbon gas emissions,the Chinese government has encouraged the use of cleanerfuels. In India, the growth of the power and fertiliser sectors is

driving the demand for gas. In addition, a decline in domesticgas production in both of these countries has led to highconsumption of LNG.

As highlighted in Figure 2, Japan is the largest consumer ofLNG, and imports approximately half of the LNG into theAsia-Pacic region. The remaining 50% is split betweenSouth Korea, China, India, Taiwan, Thailand, and the rest of theAsia-Pacic region.

In Japan, the Fukushima disaster in 2011 was the catalyst forthe sudden increase in gas demand. As a result, gas has becomecritical to Japan’s economic growth, especially for the powersector, which solely depends on gas. Furthermore, a lack ofdomestic gas reserves has led the country to fulll its energyrequirements with imported gas. Japanese LNG imports haveincreased from 8.4 billion ft 3/d in 2009 to 11.59 billion ft 3/d in2014.1

Going forward, Japan hasplans to restart some of thereactors that are deemed tobe safe, even though there issignicant public opposition.In August 2015, KyushuElectric Power Co. restarted

the rst nuclear reactor,which will have an impact on Japan’s future demand forLNG. By 2025, Japan’s gasdemand is expected to reach11.63 billion ft3/d. To meetthis projected demand, thecountry has signed long-termcontracts for the supply of

LNG with the US and Australia. This includes both Japan CrudeCocktail (JCC) linked contracts, as well as Henry Hub linkedcontracts.

On the other hand, robust growth in China’s economy hastriggered the high gas demand scenario. China fullls its gasdemand by domestic sources and pipeline imports. However,going forward, it will be a challenge for the country’s gasproduction to keep pace with the increasing gas demand.

To secure the country’s gas requirements, China NationalPetroleum Corp. (CNPC), a state-owned corporation, signed a30 year natural gas supply agreement with Gazprom in 2014.Gas will be transported to China via the ‘Power of Siberia’pipeline, which is likely to start operations by 2019.

In addition, China is making efforts to bolster its gas suppliesthrough extensive shale gas activity. However, the country’sshale seams do not hold as much potential as those in the US.

China’s seams are deeper, so the new and advanced frackingtechniques are unlikely to show results. With minimum optionsavailable, the country’s future energy requirements are unlikelyto be met without boosting LNG import levels. At present,China has 11 LNG regasication plants, with a total capacity of~4.31 billion ft3/d. By 2020, the country plans to bring 17 LNGregasication plants online, with a handling capacity of~10 billion ft3/d, augmenting LNG supply.

In India, the discovery of the Krishna-Godavari (KG) gasbasin steered the power and fertiliser sectors towards gas as asource of fuel. However, gas production from the KG basinreduced drastically from 2.15 billion ft 3/d in 2010 to1.77 billion ft3/d in 2011, resulting in low supply levels. The

soaring gas demand, along with the declining domestic gasproduction, has driven the country to increase LNG importlevels to be able to meet the wide gap between demand andsupply. By 2025, India’s LNG demand is expected to jump to4.29 billion ft3/d from 1.91 billion ft3/d in 2014.

Figure 3 highlights the existing LNG trade and the futurepotential LNG trade routes that are likely to emerge as a resultof various market developments.

New liquefaction capacity toincrease LNG supply options

Australia to take over Qatar’s position asthe key LNG exporterIn 2014, approximately 52% of the total global LNG was suppliedby the key global LNG exporting countries – Qatar, Malaysia

Figure 1. In 2014, LNG trade was approximately 9.7% of the total global gas consumption.

Figure 2. Asia consumes approximately 11.59 billion ft3/d ofLNG.


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www.ChartLNG.com


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and Australia. Qatar’s North Field is the largest non-associatedgas eld in the world, and is the key supplier of LNG. However,in order to control the supply volumes, the Qatari governmenthas put a moratorium on any further expansion of the eld orthe supply volumes. As a result, Qatar’s LNG supply is likely toremain at approximately 9.85 billion ft 3/d.

So far, Qatar has been the largest LNG exporter due to itsvast gas reserves. However, going forward, new LNG supplyoptions from Australia and the US will become accessible. InAustralia, with most of the sanctioned LNG projects reaching

the completion stage, LNG exportswill increase exponentially. By 2018,Australia is likely to commissionapproximately 11.44 billion ft3/d ofliquefaction capacity. With a higherplant utilisation rate, Australia isexpected to surpass Qatar as the

prime LNG exporter. Figure 4highlights Australia’s seven LNGprojects that will come online in thenext few years.

At present, Australia has contractedmost of its LNG with Asia-Paciccountries, such as Japan, China, andSouth Korea. Chevron’s massive Gorgonproject was scheduled to ship its rstcargo by the end of 2015, but it is nowdelayed until early 2016.

On the other hand, theconstruction cost of greeneldprojects and expansion in Australia

was comparatively higher. This was a result ofhigh infrastructure costs, high raw materialcosts, high labour costs, and sudden inationin the country. Furthermore, with the currentlow oil prices, these projects are noteconomically feasible. However, Australiaholds the advantage of geographic proximityto Japan, when compared to the US and Qatar,and hence will have lower transportationcosts.

The US: unlocking theopportunity of LNGexportsA glut of shale gas production has put the USon the world map as one of the key LNGsuppliers. Figure 5 demonstrates how, with theincrease in shale gas production, LNG importshave declined. Until now, the US imported LNGto fulll its domestic energy consumption.However, with the availability of signicantamounts of gas, after securing domestic gassupplies, the US will be able to trade surplusgas in the international markets. The country

has 11 existing LNG import terminals and thecost and the time it takes to convert theseregasication plants to liquefaction plants islower than the cost and time required to buildnew liquefaction facilities.

This, coupled with US LNG contracts thatare mainly linked to Henry Hub gas prices, gave the US anadvantage over other LNG exporting countries that have crudeoil linked contracts. Henry Hub contracts were not onlycheaper, but gave destination exibility as well. With the USLNG supply as an option, the Asia-Pacic buyers took theopportunity to secure cheaper LNG contracts.

In addition, unlike the LNG supply contracts of theMiddle East and the Pacic basin, the US LNG supply contractsdo not follow ‘take-or-pay’ terms. However, with the oil pricedecline, LNG prices linked to the crude oil price have also

Figure 4. Australian liquefaction capacity.

Figure 5. US gas production and LNG imports.

Figure 3. The global LNG trade routes.


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dropped. Due to the exibility gained withHenry Hub contracts, the industry is nowinclined towards signing hybrid contractsthat have a mix of LNG prices linked toHenry Hub gas prices as well as crude oilprices.

So far, the US Department of Energy

(DOE) and Federal Energy RegulatoryCommission (FERC) have approved exportpermits of ~9.22 billion ft3/d, includingSabine Pass, Corpus Christi, Cameron LNG,Cove Point LNG and Freeport LNG. Table 1provides the details of these projects.

The US companies are waiting for the nal investmentdecision (FID) on the rest of the export projects, but low oilprices are threatenening to delay the development of theseprojects. Going forward, these LNG export projects have anuncertain future.

ConclusionIn the past 10 years, the global LNG industry has matured. As aresult of the expansion of LNG infrastructure, gas-decitregions now have access to LNG to fulll their energyrequirements.

Signicant developments, such as the US shale gas boomand Australia’s new liquefaction capacity, have changed thedynamics of the global LNG industry. The Asia-Pacic regionsare securing LNG contracts with these new suppliers that havedestination exibility. Additionally, the slow economic recoveryin Europe will contribute to the upcoming LNG demand.

The availability of excess LNG has resulted in a buyers’market, where consumers have the advantage to procure LNG atnegotiable prices. In the current low oil price scenario, theHenry Hub linked contracts and crude oil linked contracts arecomparable. Therefore, the contracts that are now being signedare hybrid contracts – a mix of both Henry Hub and crude oillinked contracts.

Reference1. ‘Global LNG Market Assessment Study 2015’, Frost & Sullivan.

Bibliography1. U.S. Energy Information Administration (EIA)

http://www.eia.gov/forecasts/aeo/pdf/tbla13.pdf 2. http://www.bp.com/content/dam/bp/pdf/Energy-economics/statistical-

review-2015/bp-statistical-review-of-world-energy-2015-full-report.pdf 3. http://www.globallnginfo.com/world%20lng%20plants%20&%20

terminals.pdf

This article was originally published in the November/December 2015 issueof LNG Industry . Register for your free copy of the magazine here: http://www.lngindustry.com/magazines/register/LNG-industry.aspx

Table 1. Approved US projects under constructionLNG project Owner Export capacity

(billion ft 3/d)Status

Sabine Pass Cheniere Energy 2.84 First LNG late 2015

Corpus Christi Cheniere Energy 2.14 First LNG late 2018

Cameron LNG Sempra Energy 1.7 First LNG 2019

Cove Point LNG Dominion Cove Point LNG 0.82 First LNG late 2017

Freeport LNG Freeport LNG Development 1.8 First LNG late 2018

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Oil and gas prices fell drastically in 2015. Due to an abundance of supply and reducedconsumption, global energy markets have had to find more economical ways of transportingoil and gas and put an abundance of pipeline projects on hold. Dr. Hooman Peimani seeks tosummarise the major global pipeline projects and how they have been affected.

global pipeline projects



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Perhaps 2015 will be remembered as an exceptional year in the contemporary history of the global energymarkets. Starting from the preceding year, oil and gas prices fell to atypical levels after experiencing aboutone and a half decades of increase. The phenomenal price decline has been caused in short by an abundanceof oil and gas supplies, way above the global demand, thanks to a large and growing number of suppliers and

lower than expected global consumption. Lowering economic activities, sluggish growth or recession in thedecade long troubled European countries, recession in Japan, below projected growth rate in China, and pooreconomic performance of many energy producers, such as Canada and Venezuela, have negatively affected energydemand. Economic meltdown in many Arab countries due to inter-state – but mainly intra-state – armed conictsand various sanctions on more than a handful of countries have all decreased their purchasing power. This has beentranslated to lower economic activities in the major western economies; declining energy consumption with a varyingextent has been the logical outcome.



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Phenomenally low prices after years of three (or nearlythree) digit prices have reduced concerns over possible majoroil supply interruptions, as the large number of suppliers havepractically rendered such a scenario unrealistic. Led by Canadaand the USA, the so-called unconventional oil and gasrevolutions have been a major contributing factor to globalover-production, dwarfed by just about all suppliersmaximising their conventional oil and gas production at thesame time as newcomers emerge in previously unthinkablelocations (Cuba and Israel).

Certain factors have contributed to the vast availability ofgas supplies, which is set to last in the foreseeable future. Alarge and growing amount of piped gas, a major increase inLNG production thanks to ongoing global capacity expansionprojects (designed to raise annual production capacity by100 million t by 2018), and the rise of current (e.g. Papua NewGuinea since 2014) and future (Canada and USA) exportershave all contributed.

This certainty about supply availability even under the

worst case scenarios has caused the freefall of oil and gasprices, despite wars in exporting nations such as Iraq, Yemenand Libya, and emerging polarisation in the Persian Gulf pittingthe Saudi-led Arab coalition of oil/gas exporters (UAE, Qatar,Kuwait and Egypt) against Iran over Yemen, Syria and Iraq.

Falling prices has prompted a growing number ofcancelled, delayed, suspended and slowed-down conventionaloil and gas developments, repair, maintenance and LNGliquefaction projects now spilling over to shale gas andoilsands projects in North America. Of course, loweringinvestment in new projects and the inevitable loweringproduction at currently operating elds will likely cause

shortages in about a decade or so if the current trendcontinues.

ProjectsA slow down in pipeline projects, especially in the three majorenergy-consuming regions – Asia, Europe and North America– has been an unsurprising by-product of this situation.Respective examples include China’s cold feet about signing arm agreement with Russia for the Power of Siberia II project,the delayed Trans-Adriatic Pipeline (TAP) set to start in 2016,three years after the Nabucco project was aborted in itsfavour, and the unknown fate of the Keystone XL.

Politically-motivated measures have also aggravated thissituation, as reected in Russia’s cancellation of the SouthStream project in December 2014, when the EU stopped theconstruction of its Bulgarian segment on technical grounds(violation of the EU competition rules), which convincedMoscow to end a losing battle with Brussels.

Yet, many other projects have been envisaged, discussed,agreed and implemented. Russia has been involved in many ofthem, even in Europe, notwithstanding the EU’s worsening tieswith Russia, particularly over Ukraine and Syria.

The main arena, however, especially for major interstateprojects, has been Asia. China has remained the majorprotagonist as the engine of global growth, whereas India’s

domestic projects have been signicant. However, other partsof the world’s largest and most populous continent have beenless active, particularly West Asia, including the Persian Gulfand Southern Caucasus.

The Americas have been active mainly in intra-stateprojects. The US has also been pursuing inter-state projects withMexico. Its large joint project with Canada (Keystone XLPipeline) is frozen only partly on environmental grounds. Therecent increase in domestic conventional and unconventional(shale) oil production is set to continue its upward course tomake the US question the wisdom of committing the countryto long-term imports of more expensive and pollutiveoilsands-based Canadian oil.

Europe has also had its share of pipeline activities, but at amuch lower extent compared to Asia. Added to the previouslydiscussed factors, the continental ageing population, loss ofeconomic supremacy to Asia and the Americas late in the20th century and growing use of more pollutive, but muchcheaper coal explain this reality. The bulk of its ongoing andfuture projects concern gas, namely to replace Russian gas withthat of another supplier, and to decrease its CO 2 emissions. Therecent conclusion of the Russian-led Nord Stream II and thegrowing continental consumption of coal seem to serve the

opposite objectives.Pipeline activities have been modest in Africa. Excluding

Algeria, all other North African oil and gas rich countries (suchas Egypt, Libya, Sudan and South Sudan) have been shaken bythe 2010 – 2011 Arab Spring and its aftershocks, giving rise tonew dictatorial regimes and growing terrorist groups.

Asia

China

The East Route gas pipeline

Known as the East Route gas pipeline, the Russian-Chinese GasPipeline (38 billion m3/y) is the largest and most importantongoing pipeline project of Russia and China, but only forms acomponent of their US$400 billion energy deal of 2014. Theproject involves constructing a gas transportation system ineach country to be connected at a border. It will aid Russia indeveloping its East Siberian gas elds, and will consequentlyhelp sell gas to China for 30 years (38 billion m3/y).

The Russian pipeline for exporting gas to China, the Powerof Siberia GTS (POS), will facilitate gas transportation from theIrkutsk and Yakutia gas production centres to the existingpipelines in eastern Siberia, ending in Russia’s Port ofVladivostok as well as China. As a joint venture of CNPC andGazprom, the construction of its rst segment – the 3200 kmYakutia-Khabarovsk-Vladivostok line – will be operational inlate 2017. The second segment – an 800 km Irkutsk Region-Yakutia leg – will be constructed at a date that has yet to beannounced. The POS is approximately 4000 km, 52 in.,transports 61 billion m3/y, and is being built along the route ofthe East Siberia Pacic Ocean (ESPO). China started constructingits extension on 30 June 2015 near the Chinese city of Heihe inthe northern province of Heilongjiang bordering Russia. TheCNPC undertaking consists of northern, southern and centralsections passing through six Chinese provinces (Heilongjiang, Jilin, Liaoning, Hebei, Shandong and Jiangsu), the Inner Mongolia

Autonomous Region, Tianjin and Shanghai. Beijing willreportedly spend at least US$20 billion on it.

China will start receiving Russian gas in 2018 when the entireEast Route gas pipeline is scheduled to go online.



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The Central Asian gas pipeline systemThe Central Asian gas pipeline system is the world’s largestongoing pipeline project consisting of four sections throughwhich Central Asian gas (mainly Turkmen, but also Kazakhand Uzbek) will be exported to China. Once fully operationalby 2018, it will supply 85 billion m3/y of gas to China, equalto around 40% of its gas imports.

Lines A and B (each 1830 km; 42 in.; 30 billion m3/y) of theCNPC’s undertaking became operational in December 2009and October 2010, respectively. The parallel lines connectTurkmenistan to southern Kazakhstan through Uzbekistan,and cross the Kazakh-Chinese border at the border pass ofHorgos in China’s Xinjiang Uyghur Autonomous Region. Line C(1830 km; 48 in.) – which begins on the Turkmenistan-Uzbekistan border – runs through Kazakhstan and ends inXinjiang; it went online in May 2014 as a means of adding25 billion m3/y to the CAGPS’s capacity.

Line D (1000 km; 48 in.) – construction of which startedin September 2014 in Tajikistan’s Roudaki district linking

Turkmenistan across Uzbekistan, Tajikistan and Kyrgyzstan toChina – will increase the Central Asian gas pipeline system’scapacity by 30 billion m 3/y once completed in 2016.

IndiaThe construction of the rst phase of GAIL Ltd’s 2050 km Jagdishpur-Phulpur-Haldia gas pipeline began in October. TheUS$2 billion project will connect eastern India to thenational gas grid by transporting gas to West Bengal, Bihar, Jharkhand, and Uttar Pradesh. The pipeline consists of a 36 in.922 km mainline, and 1128 km of spur lines and feeder lines(12 – 30 in.). Its second phase will double the capacity to

32 million m3

/d. The pipeline will supply gas to industrialsites, such as the Barauni renery and the Barauni fertiliserplant.

IranIran will reportedly start constructing three pipelines in thecurrent Iranian calendar year (started on 21 March 2015) aspart of its plans to increase gas transfer capacity by300 million m3/d, while developing more phases of itsPersian Gulf South Pars Gas Field (SPGF). Thus, the sixthcross-country gas pipeline (611 km; 110 million m3/d;US$2 billion), the rst and second sections of which havebeen completed, is the rst priority designed for gas exportsto Iraq, Syria, Lebanon and Europe.

The ninth cross-country gas pipeline (1863 km;110 million m3/d; US$6 billion) is being built towards Iran’snorthwestern borders, aimed at increasing Iran’s existing gasexports to Turkey for supplying Europe in the future.

The eleventh cross-country gas pipeline (1100 km;100 million m3/d; US$4 billion) will connect the SPGF toIran’s northeastern region to enable it to stop relying on theimport of Turkmen gas (30 million m3/d).

Iran-Iraq gas pipelinesIran’s pipeline project to supply Bagdad was set to go online

in August 2015, but there is no news on its operation. Thepipeline (100 km; 48 in.) stretches from Charmaleh in Iran’sIlam province to Naft-Shahr bordering Iran and Iraq.Reportedly, its extension to the Iraqi Mansourieh power

plant is also nished, leaving a 7 km stretch to Baghdad forcompletion. Iran will initially export 4 million m 3/d of gas toIraq, to gradually increase to 35 million m 3/d. InFebruary 2015, Iran started the construction of a second gaspipeline to Iraq’s southern city of Basra – scheduled foroperation in 2016 – to export an additional 5 million m 3/d ofgas to Basra, rising to 30 million m3/d within six years.

Iran-Oman Gas PipelineThis is the most important future project for both countries,and would export 28 million m 3/d of Iranian gas to Oman for15 years, reportedly worth of US$60 billion. The projectcould become a reality if the P5+1 Group nuclear agreementis implemented to lift sanctions on Iran’s energy exports. Iranand Oman have signed an agreement to study itsconstruction to feed Oman’s LNG plants. Head ofthe National Iranian Gas Export Company, Alireza Kameli,announced in September 2015 that a contract had beensigned with two Iranian gas companies for the project.

The Iranian Offshore Engineering and ConstructionCompany is in charge of its offshore section, whose contractwas also signed by Director General of Planning and ProjectsEvaluation of the Omani Ministry of Oil and Gas, Saif BinHamad Al Salmani. Pars Consulting Engineers deals with theonshore section.

Europe

Russia

Nord Stream II

Gazprom and major European energy companies – Germany’sE.ON and BASF/Wintershall, Austria’s OMV, France’s ENGIEand Royal Dutch Shell – signed an agreement in Vladivostokon 4 September 2015 to double the Nord Stream gaspipeline’s current capacity of 55 billion m 3/y by constructinga new gas pipeline system (Nord Stream II), intended to becompleted by 2019. The Nord Stream II will transport gasfrom Russia to Germany via twin offshore pipelines – each1200 km transporting 27.5 billion m3/y – through the BalticSea. The New European Pipeline AG joint venture willimplement it, in which Gazprom’s share is 51%. E.ON, Shell,OMV and BASF/Wintershall each have 10%, with a 9% sharefor ENGIE.

Nord Stream II is a surprising project as it runs againstBrussels’ policy of decreasing the EU’s dependency on Russiaand, in fact, it questions the logic of building theTrans-Adriatic Pipeline in 2016 to serve that very purpose. Inhelping Russia to bypass Ukraine for gas exports to the EU,the pipeline project has been called by Ukrainian PrimeMinister Yatsenyuk “anti-Ukrainian and anti-European.”

Czech Prime Minister Sobotka echoed this by saying theproject would help Russia destabilise Ukraine. Slovak PrimeMinister Fico suggested it was a betrayal, which cost Ukraineand Slovakia billions of Euros. Finally, the EuropeanCommission’s Vice-President, Maros Sefcovic, questioned

how the project ts with the EU’s energy security andregulatory priorities. In reply, OMV CEO Seele stressed thatthe project would increase security of supply to the EUthrough “our trustful partnership” with Gazprom.



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The Turkish Stream Gas PipelineThe Nord Stream II has affected Russia’s Turkish Stream GasPipeline project, which was designed to replace the SouthStream Pipeline (cancelled by Moscow in December 2014).Gazprom’s Chairman Alexey Miller and Botas PetroleumPipeline Corp.’s Chairman, Mehmet Konuk, signed an MoI inDecember 2014 to enable Russia to increase gas exports to theEU without requiring Brussels’ approval.

In October 2015, Gazprom announced it was reducing theproject’s capacity from 63 billion m 3/y to 32 billion m 3/y infavour of the Nord Stream II, of which 50% would be forTurkey and the rest for exporting to Europe. Russia seeminglyintends to use the South Stream’s allocated resources. Theestimated US$12.5 billon pipeline will run across the BlackSea from the currently under-construction Russkayacompressor station near Anapa on the northern coast of theBlack Sea, to Kiyiköy village in the European part of Turkey. Itwill further run, via Luleburgaz (delivery point for the Turkishcustomers), to the Ipsala border checkpoint on the

Turkish-Greek border, the delivery point for the Europeancustomers. Consisting of four offshore strings (each 910 km),the pipeline will pass 660 km under the Black Sea within thedecided corridor of the South Stream Pipeline, followed by250 km within a new corridor towards the European part ofTurkey. The length of the Turkish onshore line is reportedly180 km, while that of Greece is unknown.

It is unclear whether the pipeline will becomeoperational in December 2016 as planned, given a delay inbeginning its Turkish part for which Ankara and Moscow arenegotiating.

NorwayNorway completed the Polarled Pipeline (482.4 km, 36 in.;70 million m3/d) in September to increase its gas exports fromthe Norwegian Sea to Europe. It is the deepest pipeline(1260 m) on the Norwegian continental shelf and the rst oneon that shelf to cross the Arctic Circle. The pipeline(approximately US$0.9 billion) extends from Nyhamna inMøre og Romsdal, western Norway, to the Aasta Hansteeneld in the Norwegian Sea.

Americas

CanadaTransCanada is working on the proposed Eastern MainlinePipeline (4600 km) to increase mainly oilsands-based exportsto the USA by converting an existing gas pipeline.

The US$12 billion project would transport 1.1 million bpdof oil from Alberta and Saskatchewan to reneries and portterminals in Eastern Canada by converting an existingwest-east gas pipeline and adding an extension to connect itto Canada’s Atlantic ports, from where oil could be shipped tothe US by tankers. The extension would l ink Canada’sOntario-Quebec border to the port of Saint John, NewBrunswick.

TransCanada expects to amend its application for

the Eastern Mainline project by adding a new natural gaspipeline in the Toronto-Montreal corridor (250 – 300 km) toreect its agreement with three Canadian gas distributorsopposing the project as it is affecting their operation.

USA

Permian-Mexico PipelineAmerican ONEOK Partners and Mexican Fermaca Infrastructurehave entered into a 50/50 joint venture to construct a pipelinefor transporting gas from the Permian Basin in West Texas toMexico. The US$450 million project connects ONEOK Partners’ONEOK WesTex Transmission gas pipeline system at Coyanosa,Texas, to a new international border-crossing connection at theUS-Mexico border near San Elizario, Texas, to be connectedwith Fermaca’s Tarahumara gas pipeline. The project includesapproximately 320 km of 30 in. pipeline for transporting up to640 million ft3/d of gas with no less than 570 million ft 3/dbeing transported to Mexico. ONEOK Partners will manage itsconstruction and operate the pipeline.

The project’s rst phase will provide 170 million ft 3/d ofcapacity, which is scheduled for completion in 1Q16. Thesecond phase is to increase the pipeline’s available capacity to570 million ft3/d in 1Q17. The nal phase is to realise the

projected capacity of 640 million ft 3/, which is set forcompletion in 2019.

Africa

Algeria

Galsi Gas PipelineAlgeria and Italy agreed in February 2015 to work on the GalsiGas Pipeline, whose construction has been delayed for over adecade due to uncertainty about Italy’s gas demand. Algeria’sSonatrach leads the Galsi project consortium with a 41.6%

equity interest in partnership with Edison (20.8%), Enel (15.6%),Hera Trading (10.4%) and the Sardinia Autonomous Region’sSrs (11.6%). Worsening EU-Russian relations, and uncertaintyabout Russian gas in the future, have made Italy committed tothe Galsi Gas Pipeline. With an estimated cost ofUS$2.5 – 3.96 billion, the project will enable Algeria to supplygas (8 billon m3/y) to Italy and the rest of Europe through anapproximately 856 km pipeline, of which 565 km will beoffshore. A 285 km offshore line connects Algeria’s KouduetDraouche on the Mediterranean coast to Porto Botte in Italy’sSardinia. This will be connected to an onshore north-southSardinian section (300 km) to link to a 280 km offshore sectionthat will deliver gas to Piombino on the Italian mainland.

Ethiopia and DjiboutiThe two neighbours have agreed to construct the Horn ofAfrica Pipeline (550 km; 20 in.; 240 000 bpd;US$1.4 – 1.55 billion) to connect the Djiboutian ports via DireDawa to a fuel depot in Awash, Ethiopia. Planned forcompletion in 2018, Africa’s Black Rhino Group is expected tomanage the pipeline for transporting rened oil productsbetween the two countries. The project also includes animport storage facility (950 000 bpd) in Damerjog, Djiboutilinked to a storage terminal in Awash, Ethiopia, near AddisAbaba. A nal investment decision on the project is expected

in 2016.

This article was originally published in the December 2015 issue ofWorld Pipelines . Register for your free copy of the magazine here: http://www.energyglobal.com/signin/?mgz=world-pipelines



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Over recent years, Australia has seen a huge wave ofinvestment into its oil and gas industry, spurred onby growing demand, both globally and in the AsiaPacic region. This surge of investment has seen

Australia become host to some of the world’s biggestupstream projects, which look set to signicantly expand thenation’s hydrocarbon output over the coming years.

The majority of investment has been directed towardsprojects across northern Australia, including Western

Australia, the Northern Territory and Queensland. Adistinguishing feature of these new projects is that they havebeen designed to make use of the country’s signicant naturalgas reserves and focus predominately on LNG production

rather than crude oil. According to Geoscience Australia, thecountry’s reserves are recorded at 132 trillion ft 3, or 11th largestin the global rankings.1 The scale of these projects can perhapsbe best understood when one considers that they areestimated to supply around 100 million t of additional LNGproduction by the beginning of the next decade. Such anincrease would take Australia from 3 rd place in globalproduction rankings up to 1 st place, overtaking Qatar, which iscurrently the leading exporter by convincing margin.

However, despite the signicant investment of recent years,it is not all plain sailing ahead for Australia’s oil and gas industry.A global economic slowdown, Japan’s decision to revert backtowards nuclear power, and a reduced crude oil price has seen

David Bizley, Oilfield Technology , takes a look at some of the challenges facing

the Australian oil and gas industry.



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the protability of many of the region’s major projects take ahit. The International Energy Agency (IEA) has even announcedthat no fewer than six major LNG projects, valued at roughlyUS$200 billion in total, are likely to struggle to break even. 2

Major project examples

Prelude & ConcertoThe Prelude and Concerto elds, situated in the Browse Basin,200 km offshore Western Australia, will act as host to the veryrst deployment of Shell’s oating LNG (FLNG) technology.Rather than piping gas to an onshore plant, the Prelude facilitywill be able to cool and condense natural gas into its liquidform offshore. The key advantage of this system is the abilityto move the processing facility to more isolated natural gas

reserves that might have been too remote to be economicallyviable with conventional infrastructure.

Once operational, the Prelude facility is expected toproduce 3.6 million t of LNG, 400 000 t of LPG and 1.3 million t

of condensate. The facility will be able to store 220 000 m 3 ofLNG, 90 000 m3 of LPG and 126 000 m3 of condensate.According to Shell, the LNG output from the facility, which isdue to be moored on location for 25 years, will be enough tocomfortably meet the demand of a consumer like Hong Kong.

IchthysThe colossal Ichthys project, lies some 220 km off thenorthern coast of Western Australia. The eld, which whenrst discovered represented the largest hydrocarbon nd inAustralia for 40 years, contains estimated reserves amountingto 500 million bbls of condensate and 12 trillion ft 3 of naturalgas. Once Ichthys is up running at peak output, it should becapable of producing 8.9 million t of LNG and1.6 million t of LPG and 100 000 bpd of condensate. The eld

is estimated to have a life-span of approximately 40 years.However, like many major oil and gas projects in Australia,

Ichthys has encountered delays and cost overruns. In 2015,Inpex, the operator of the project, announced that



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development would cost roughly 10% more than the originalUS$34 billion budget and that initial production would bepushed back from late December 2016 to September 2017.

GorgonThe Gorgon project, operated by Chevron, covers the Gorgonand Jansz-lo gas elds and is located within the GreaterGorgon area between 130 and 220 km offshore northwestWestern Australia. The Greater Gorgon area is estimated tohold approximately 13.8 trillion ft 3 of proven hydrocarbonreserves. Initial production from the 15.6 million tpy LNG plantlocated on nearby Barrow Island is expected in early 2016.

All of this makes the Gorgon project a giant operationand, according to Chevron, it is “the largest single-resourceproject in Australian history.” 3 In fact, Gorgon was consideredto be so signicant that an early 2005 version of its ‘DraftEnvironmental Impact Statement/Environmental Review andManagement Programme for the Gorgon Development’ statedthat: “In response to increased revenues and economic

growth, governments may increase expenditures, and reducethe average personal income tax rate to keep the ratio ofpublic debt to GDP from falling.”4

Gorgon also happens to be the world’s most expensiveLNG project, with total costs amounting to roughlyUS$54 billion after rising signicantly over the developmentperiod. These rising costs, coupled with falling LNG prices andan oversupplied market, have taken some of the shine off theoptimistic comments from 2005.

The oil price downturnThe downturn in oil prices has hit producers around the world

and nowhere has escaped completely unscathed. Australia iscertainly no exception to this rule with, as mentioned earlier,some US$200 billion worth of LNG projects likely to struggleto break even over the coming years. Exactly why low oilprices are impacting the protability of Australian LNG isdown to the fact that LNG prices in Asia, a key market forAustralia, are indexed against Brent crude.

Origin Energy is one company dealing with the downturn.CEO Grant King said in the company’s recent annual reportthat “While changes in oil price do not have an overly materialimpact on Origin’s current earnings, should these conditionspersist for a longer period of time, earnings from Origin’sinvestment in Australia Pacic LNG will be lower thanpreviously estimated.” 5 The company has already put incost-saving measures designed to shave US$1 billion off theAustralia Pacic LNG facility, US$650 million of which hasbeen achieved so far, with a further US$350 million to besaved by the end of the 2016 nancial year. 6

Woodside Petroleum, operator of the Browse FLNGproject, is also facing challenges posed by the low-priceenvironment, and has been pushing hard to sign up SouthKorea as a potential customer for future LNG supplies fromthe project. The company has also attempted to lobby theSouth Korean government for reduced costs, especially as thevessels to be used on the project are being constructed in

South Korean yards; Reinhardt Matisons, Executive VicePresident of Marketing was quoted as saying, “We valueKorea’s support – both in terms of cost reductions and LNGpurchases – in achieving a nal investment decision.” 7

As Brent crude has fallen to around US$30 at the time ofwriting, and with no rapid recovery on the horizon, it looks asthough the immediate price woes facing the Australian gasindustry are not likely to disappear overnight. Some analystslooking at future crude prices see it rising to no higher thanthe mid US$70s over the coming decade, meaning that thelong-term nancial viability of several major LNG projectscould be in jeopardy.

Japan’s nuclear u-turn Japan has long been one of Asia’s (and the world’s) largest LNGimporters, relying on the fuel for a signicant percentage of itsenergy needs. Prior to the Fukushima nuclear disaster, whichwas to result in the nation shutting down all of its nuclearreactors, this gure was in the region of 29%. By the end ofMarch 2015, it had risen as high as 46% or 89 million t of LNG.8

Sadly for the LNG market, this trend now looks set toreverse as Japan begins bringing its reactors back online andgradually cutting back on LNG imports until they reach

pre-Fukushima levels by 2030.9 The process is alreadyunderway, with the Abe government pushing for nuclearpower as a key energy source. Several reactors have alreadyrestarted, the rst returned to commercial power generationon 10 September 2015. However, it is not just LNG demandthat is expected to take a hit; fossil fuels across the board arelikely to see reduced Japanese demand, with oil consumptionestimated to fall by 80 000 - 100 000 bpd.

ConclusionThe current outlook for many of the major oil and gas projectsin Australia is certainly somewhat bleaker than it was a few

years ago. The natural gas and LNG markets of Asia, Australia’smain export destination, are oversupplied and demand growthhas slowed. Operators of mega projects that are already indevelopment are looking at ways to cut costs and get throughthe downturn.

However, the all-important crude oil price is expected torise over the next few years. Global demand for hydrocarbonscontinues to grow, and current low prices will likely drivefurther consumer demand. Like much of the global oil and gasindustry, the focus for operators in Australia now is to cutcosts, plan for the long-term and endure the downturn.

References1. ‘Key Statistics 2015’, http://www.appea.com.au/wp-content/uploads/2015/05/APPEA_Key-Stats15_web.pdf2. ‘LNG: $200b worth of Australian projects ‘probably not breaking even’’,

http://www.smh.com.au/business/energy/lng-200b-worth-of-australian-projects-probably-not-breaking-even-20150906-gjggi0.html

3. ‘Gorgon Project’, https://www.chevronaustralia.com/our-businesses/gorgon4. ‘Chevron claimed Gorgon bonanza would pay for tax cuts for everyone’,

http://www.afr.com/business/energy/gas/chevron-claimed-gorgon-bonanza-would-pay-for-tax-for-cuts-for-everyone-20151116-gl0jo1

5. ‘Shareholder Review & Annual Report 2015’, https://www.originenergy.com.au/about/investors-media/reports-and-results/shareholder-review-annual-report-20150918.html

6. Ibid.7. ‘Woodside Petroleum urges South Korea to help on Browse LNG sales,

costs’, http://www.smh.com.au/business/energy/woodside-petroleum-urges-south-korea-to-help-on-browse-lng-sales-costs-20151004-gk0s7g.html

8. ‘Japan’s Nuclear Restarts Seen as Long-Term Drag on LNG Prices’, http://www.bloomberg.com/news/articles/2015-08-14/japan-s-nuclear-restarts-seen-as-long-term-drag-on-lng-prices

9. ‘Japan LNG imports to drop to 62mtpa by 2030 - METI’, http://www.icis.

com/resources/news/2015/09/16/9924240/japan-lng-imports-to-drop-to-62mtpa-by-2030-meti

This article was originally published in the December 2015 issue ofOilfield Technology . Register for your free copy of the magazine here: http://www.energyglobal.com/signin/?mgz=oilfield-technology


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The global petrochemical industry is navigating many challenges and adapting to very volatilefeedstock prices, changes in global supply and demand patterns, and strict environmentalregulations. The collapse in oil prices added another layer of complexity to the fundamentalchanges taking place in global energy markets and impacting the dynamics of the

petrochemical sector.The drop in naphtha prices has re-addressed the competitive position of European and Asian

petrochemical producers vs Middle Eastern and US producers. European and Asian naphtha-based crackershave regained some competitive strength vs ethane based crackers and enjoyed strong margins throughout2015. Ethane price advantage vs naphtha has been signicantly reduced and the stronger Dollar vs the Euroadded strength to European petrochemical producers.

Ekaterina Kalinenkoand Luisa Sykes,

Euro Petroleum Consultants,explain how the global

petrochemical industry canadapt to the high level of

uncertainty and volatility inenergy markets and still

remain competitive.


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The global petrochemicals landscape was changing prior tothe collapse of oil prices in 2H14. A large amount ofpetrochemical capacity has been added in China, the US and theMiddle East, threatening the fragile supply-demand balanceglobally. The strategies implemented by the petrochemicalindustry in each region are quite distinct and are shaped by theparticular conditions and characteristics of each region. Some ofthese strategies have been challenged by the decline in oilprices, leading to a potential re-shaping of the globalpetrochemical sector.

In the US, low ethane feedstock prices have triggered arevival of the US petrochemical sector – a substantial number

of ethylene and ethylene derivatives plants have been built andnew projects are in the pipeline. Six large scale ethyleneprojects with a total capacity of 600 000 bpd are currentlyunder construction in the US and are expected to be completedbetween 2017 and 2018 (Figure 1). The US propylene business isalso thriving. The tight US propylene market and the increasesupply of propane from natural gas production has driven theinvestment in propane dehydrogenation plants (PDH) – sixprojects are currently at various stages of development and areexpected to add 190 000 bpd to current production levels inthe US. As the scope for expansion in the domestic market isfairly limited, US ethylene producers and even producers ofon-purpose propylene production will be targeting exportmarkets.

China is the largest consumer of petrochemical feedstockand petrochemical derivatives. But it is also committed to astrategy of import substitution that will impact global marketsby reducing a signicant volume of petrochemical imports intothe country. China’s import substitution strategy has led tosubstantial investment in the domestic petrochemical sector,leading to overcapacity in some segments of the industry andthe recourse to export markets. However, the expected increasein domestic demand is likely to absorb excess supply in the notso distant future. China has limited crude and gas resources butplenty of coal availability. In order to utilise the vast coal

resources, a large number of coal to chemicals projects arecurrently underway in China. However, current low naphthaprices are challenging the fragile coal to olens economics andsome projects could be in jeopardy. Additionally, the lack of

infrastructure, high capital investment,water availability and environmentalissues are also expected to restrict theexpansion of coal to chemicals projectsin the future.

The Middle East enjoys the world'slowest cost ethylene production thanksto cheap ethane – US$0.75/million Btuvs an average of US$3.5/million Btu in theUS in the last three years. The region hasseen substantial capacity additions in thelast decade, growing at an average of 10%since 2008. The expansion rate isexpected to be more moderate in thefuture but several petrochemical projectsare still underway or at planning stage.The majority of the additionalpetrochemical production will betargeting export markets.

It becomes quite clear from highlighting developments inseveral parts of the globe that the expansion of thepetrochemical industry in the three geographical regions couldlead to overcapacity and intense competition amongstpetrochemical producers. The question facing many producersaround the world is ‘how to cope with greater degree ofuncertainty and still run protable operations and make theright investment decisions’. Petrochemical producers globallywill need to win competitive advantage to maintain or increasemarket share based on feedstock costs, location and efcientrunning of their operations. Promoting maximum organisationalefciency and improving operational performance should betop objectives for all petrochemical operations.

‘Recipes’ to promote efficiencyduring times of great uncertaintyIn times of great economic uncertainty, companies aresearching for ways to maximise their returns and obtain ‘thecompetitive edge’. A very effective way to promote theseobjectives is to implement operational excellence models,which are gaining a good track record within the oil, gas andpetrochemical industries. Many petrochemical companies areadopting operational excellence models using keyperformance indicators (KPIs) to measure business andoperational systems such as management and leadership, lossof production and control, production optimisation, reliabilityand maintenance, etc.

The main objective of operational excellence programmes isto neutralise risk and maximise value creation. The operationalexcellence approach is placing people at the centre of businessimprovement practices. Key drivers of operational excellence forimproving organisational performance include strong leadership,conductive organisational structure and clear focus, and a plan ofaction. Strong leadership implies commitment by corporateleaders to embrace the operational excellence approach – theleadership must present clear and unambiguous goals and plans.A suitable organisational structure can be categorised as including

a well informed workforce with well integrated team structures, aclear line of accountability and performance measurements andmotivational feedback on goals and achievements within theteams. A clear focus and plan of action is the ‘touching stone’ of

Figure 1. US ethylene and propylene capacity expansions (1000 bpd).


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the operational excellence process requiring a goodcommunication system. The aim is to identify all the areas thatneed to be tackled and improved with particular emphasis ontraining and development. A clear plan of action is designed topromote best practices and work towards improvingorganisational performance.

Implementing operationalexcellence programmesPetrochemical companies can post dozens of implementedoperational excellence projects similar to the programmedeveloped and implemented by Petrochemical IndustriesCompany (PIC). The achieved results were presented at theInternational Operational Excellence Conference, organised byEuro Petroleum Consultants (EPC) in Istanbul, Turkey inspring 2015.

Based in Kuwait, PIC was founded in 1963 as the rstchemical fertiliser complex of its kind in the region. Today, PICis a petrochemical industry leader in Kuwait and throughout

the Middle East. In addition to manufacturing and marketingfertilisers, olens and aromatics in Kuwait, PIC participates inmultiple joint ventures that also produce and marketchemicals both locally and internationally.

At the initial stage of the programme development, PIC’sconcept of operational improvements implied formulation ofvision, strategy and objectives. The company decided todevelop the programme on the basis of three classicalprinciples: lean production (lean), quality management(six sigma) and project management (PM).

Among the top priorities were HR performance, focus onthe consumer’s individual needs and the process approach

under the slogan ‘Better, Faster, Cheaper!’. The operationalperformance metric included criteria such as expenditurelevel, produ

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