Nrg issue 47 by Will Carmichael

NRG

NRG NEWSBASE ROUND-UP –– GLOBAL –– AFROIL

 Algeria and the health of the body politic ASIAELEC

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 Coal’s comeback in Asia

3 5

ASIANOIL

 Demand forecasts reinforce South China Sea’s importance CHINAOIL

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 CNPC gas find prompts scepticism

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ENERGO

 A winter of content for the Russian power market EUROIL

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 Independence debate colours Wood Review FSU OGM

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 Is Urals Blend coming to the English Channel? GLNG

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 Japan’s LNG prices set to remain high 13 LATAMOIL

 Viva la revolucion: Phase two of Mexican reform under way DOWNSTREAM MEA

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 Dangote provides a ray of light for Africa’s refining sector MEOG

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 Demand for jack-ups continues to propel Middle East rig market NORTHAMOIL

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 Gulf of Mexico set for production ramp-up REM

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 Raw materials and the renewables supply chain UNCONVENTIONAL OGM

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 New Brunswick’s shale battle

February 2014

Issue 47  News  Analysis  Intelligence Published by

 NewsBase

NEWSBASE ROUND-UP GLOBAL

Shifting balance Changing dynamics could lead to new regions gaining importance as areas of significant oil and gas production.  The South China Sea is set to become more important on the back of a predicted boom in energy shipments to Asia. (Page 5)

 Mexico’s radical energy reforms could cause the US shale revolution to spread over the border, although legislative obstacles could delay the pace of change. (Page 15)

Up and down Some traditionally dominant areas are performing well, with this trend set to continue. Others, meanwhile, are taking steps to reverse declines.  The final version of the largest ever independent study of the UK North Sea offers guidance on how to maximise oil and gas recovery from the region.(Page 10)

 Middle Eastern utilisation rates for rigs indicate an industry in rude health.

(Page 19)

 Several major projects are set to come on stream in the US Gulf of Mexico this year, potentially marking the start of a phase of considerable growth for output from the region. (Page 21)

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Edited by Anna Kachkova

All rights reserved. No part of this publication may be reproduced, redistributed, or otherwise copied without the written permission of the authors. This includes internal distribution. All reasonable endeavours have been used to ensure the accuracy of the information contained in this publication. However, no warranty is given to the accuracy of its contents

NRG

February 2014, Issue 47

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AfrOil

Algeria and the health of the body politic As Algeria moves towards elections, cracks are emerging among the power brokers and kingmakers By Charles Coe  Elections are due in April and Bouteflika may run again  Powerful forces are carrying out smear campaigns in the press  A bid round is getting under way, with contracts due in September The failing health of Algeria‟s three-term president, 76-year-old Abdelaziz Bouteflika, has created an atmosphere of political uncertainty in the energy resource-rich North Africa country. Presidential elections are due to be held on April 17 and for once the outcome is not known in advance. Bouteflika suffered a mild stroke in April 2013 and spent months in a Paris hospital recovering. The president has yet to announce whether he will run for an unprecedented fourth term, despite the fact that he has received the nomination of his party, the Front de Liberation Nationale (FLN). Bouteflika, a veteran of Algeria‟s 1956-62 war of independence against France, has been in office since 1999. Questions about his candidacy have led to widespread speculation about whom Bouteflika might chose to run in his place and whether the military would support that person. Since independence, Algeria has been run by a group of military men and security officials who comprise the country‟s elite and who make certain that their interests remain intact. Algeria‟s first effort towards democratic legislative elections came in 1991 when the Front Islamique du Salut (FIS) won the first round. Fearing the election of an Islamist government, the authorities called a halt to the proceedings, sparking a decade of civil war during which Islamic militant groups targeted the army and civilians. As many

as 100,000 people were killed. When Bouteflika came to office he managed to restore political stability with pardons and a limited amnesty for Islamic fighters. But as all of Algeria‟s independence generation ages, there are questions about whether the decades-long political system can continue. In recent weeks, political squabbling between those within the political establishment has broken out within the country‟s media, with calls for Bouteflika to retire and criticism expressed for his supporters. More than 20 candidates are reported to have registered to run for president against a contested political backdrop that has been described as the “war of the clans”. Early February saw a number of outspoken statements in the Algerian press, triggered by the FLN‟s secretary general, Amar Saadani, who called for Mohammed Mediene – known as Tewfik – to stop interfering in politics. Saadani said the army and Departement du Renseignement et de la Securite (DRS), which Tewfik heads, should not play a role in the political process. The FLN official also accused the shadowy spy chief of incompetence, blaming him for the In Amenas attack, among others. Tewfik‟s relationship with Bouteflika is rocky and Saadani‟s statement led to a number of denunciations, including allegations about the president‟s brother, Said Bouteflika, and suggestions of wrongdoing connected to former energy

and mines minister, Chakib Khelil, and Sonatrach. Algeria issued an arrest warrant for Khelil in August 2013. Furthermore, a senior retired general, Hocine Benhadid, called for the president to step down, in an interview with El Watan. Ominously, Benhadid was reported as having said he was commenting on behalf of others in the army and that they “cannot let this situation continue”. A statement from the president, expressing sorrow over an accident that caused a military plane crash in February, tried to patch up some of the damage done by the warring camps. Bouteflika‟s statement said that no one, “whatever their responsibility”, had a right to criticise the army. Supplies Algeria is a key energy supplier to Europe and its political circumstances could have an impact on its ability to keep oil and gas flowing. Thus far, Algeria has managed to avoid getting caught up in the political upheavals that have swept through much of the Arab world since 2011. Natural gas resources are estimated at 4.5 trillion cubic metres and gas production in 2012 amounted to 81 billion cubic metres, 50 bcm of which was exported, primarily to Europe. Proven crude oil reserves are put at 12.2 billion barrels and production in 2012 averaged 1.67 million bpd, with about 1.3 million bpd exported.

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

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AfrOil But Algeria‟s economy and its hydrocarbon sector, which generates the bulk of the country‟s income, is facing serious problems, causing many to question whether change to the creaking political order might be necessary. Unemployment among the youth is high in a country where the elite are seen as corrupt and unscrupulous. Many foreign energy companies are active in Algeria but there is reluctance among them to get further involved in the country until security is improved. The North African country‟s reputation has been slow to recover from the January 2013 attack by al-Qaeda affiliated jihadists on the In Amenas gas production plant, which killed 67 people. Offered up Foreign companies are also keen to see an improvement in the terms that Algeria offers for oil and gas production contracts.

In January, Algeria opened its fourth licensing round, the first since changes were made to the hydrocarbon law a year ago with the intent of making the tenders more attractive to foreign firms. The country had seen little interest shown in its earlier licensing rounds and only a few blocks have been awarded since 2008. This new round includes both conventional and unconventional resources. Thirty-one blocks are being offered – 17 in the southwest, five in the north and nine in the centre and east of the country. Algeria‟s growing domestic demand, which is forecast to rise to 45 bcm by 2019 from 30 bcm in 2012, is pushing the country to develop more of its resources, including shale. Data for the new licensing round will be available from mid-March until late May and bidders will have the option to suggest changes in the model contract until the

bidding deadline on June 5. State-owned Sonatrach intends to sign contracts by September 5. A total of 93 wells were drilled in Algeria in 2013, most of them by Sonatrach, and 32 discoveries were made. Only three of the wells were made in partnership with other companies. Meanwhile, Sonatrach reopened its refinery at Skikda with a capacity of 368,500 bpd following an upgrade by South Korea‟s Samsung Engineering. The state-owned company also opened the new 4.5 million tonne per year LNG train at Skikda. The new plant replaces a facility that exploded in 2004 during routine repair work. The resource potential of Algeria, and its proximity to European markets, suggests there may be a good future for the country but continued political wrangling and questions over security raise questions that are not easily answered.

AsiaElec

Coal’s comeback in Asia The Asian power sector is importing coal at a record rate, despite Kyoto commitments to cut coal use, as LNG prices reach record levels By Nnamdi Anyadike  High LNG prices and rising power demand is driving rising coal imports into Asia  Southeast Asia’s generating capacity is projected to rise by 50% by 2020, and half of this will be coal-fired  Yet coal’s pricing advantage could just be temporary, with gas set to dominate the long-term future The “European paradox” – whereby coal consumption is rising at a time when ever more stringent environmental measures are in place to curb its demand – is clearly very much in evidence throughout Asia. “Not only is coal use rising in Europe but it is also rising in Japan and South Korea,” Dick Benschop, vice president at gas market development at Shell Netherlands, told a major industry event in London in February. “The Japanese government announced that it is to speed up the planning process

for coal-fired [thermal] power plants [TPPs] and the country is looking to significantly expand the import of coal. South Korea is also planning for higher coal imports as feedstock for its planned increase in coal-fired power generation,” he said. As a result of this unforeseen rise in global coal demand, coal prices are moving up. In the US, they climbed 12% during one of the coldest winters on record. Coal is now the “fastest growing fuel source,” the International Energy Agency (IEA) has suggested.

Indeed, between 2014 and 2018 it forecasts that coal demand will rise by 2.4%. This is a remarkable turnaround from only a year ago, when it was gas that was the fastest growing fuel source. High LNG prices Interestingly, the expansion of coal imports into Asia to feed the rise in its coal-fired power generation is going hand in hand with a rise in its gas imports.

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

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AsiaElec Yet hard choices are being made between the plentiful supply of still relatively cheap coal and high-cost LNG imports. Asian LNG prices are the highest in the world and the conference was told that if they move too far out of synch with alternative fuels then it could cap demand for LNG at a time when the new supply comes on stream in 20152017. In addition, it will also likely spur the resumption of nuclear power generation in Japan and South Korea from their mothballed plants. Professor Keun-Wook Pai, senior research fellow at the Oxford Institute for Energy Studies (OIES), told the event: “Such has been the rise in Japanese LNG prices that the country can simply no longer afford not to restart some of its nuclear reactors that have been off-line since Fukushima. The same is also true of South Korea.” Coal displaces LNG LNG, meanwhile, is in danger of being priced out of many smaller Asian countries including Thailand, Malaysia, Indonesia, India and Singapore, which in theory could add a further combined 28 million tonnes per year to global LNG demand. Thailand, the first Southeast Asian country to import LNG, is understood to be using only 30% of the 5 million tonne per year import terminal that it brought on line in 2011 because of the high price of LNG. In neighbouring Vietnam, state oil and gas group Petrovietnam unveiled plans this month to import coal from 2017 for its power plants. The company is understood to be looking to buy around 10 million tonnes per year of coal, mostly from Australia and Indonesia. Until recently, Vietnam was a net coal seller, but last year its coal exports dropped to 12.8 million tonnes, down nearly 16% from 2012, according to government data. “We have to feed three [TPPs], with operation slated to start from 2017,” said the official at Petrovietnam Power Coal Import and Supply (PV Power Coal), the importing arm of the state group. PV Power Coal has signed initial framework agreements for a combined

annual volume of up to 12 million tonnes with mining firms in Indonesia and Australia, including Australia‟s Ensham Coal Sales. The new generation of coalfired power plants that are being set up throughout Asia will be more efficient than the ones built before. According to energy consultancy Wood Mackenzie, 20,000 MW of new coal-fired TPPs are forecast to come on line across Southeast Asia during the next five years – and they are expected to run at mostly full capacity. By comparison, the 15,000 MW of new gas-fired power generation capacity that will come on line in the region over the same period are anticipated to run at just 70% on average. Malaysia, which recently turned to LNG imports to meet rising demand for power in locations far from its gasproducing regions, is now constructing five coal-fired TPPs as it seeks to curb overseas purchases of the expensive fuel. Indonesia, once one of the world‟s top LNG exporters but now facing declining output, will see coal remain as its dominant fuel. Coal growth Southeast Asia‟s LNG import capacity could triple to nearly 50 million tonnes per year by 2018. But as long as the price differential favours coal, the outlook for the region's LNG demand will be bleak. Gas prices in Asia are about five times more expensive than in the US. According to the IEA, 1 MW of LNGfired power is currently around twice as expensive as 1 MW of coal-fired power in Asia. Although as host to the Kyoto accord Japan was said to have a “moral” as well as treaty obligation to the agreement, delegates at the event heard that this had so far not dissuaded it from increasing its coal imports in a bid to cap its high-cost LNG purchases. In mid-February, Japan was reportedly buying LNG at US$19.70 per million Btu, which is well above oilparity levels. This continued the trend from last year, which saw a surge in the country‟s LNG import bill to more than US$68.6 billion. It is seen as inevitable that Southeast Asia's power sector will

tilt away from gas to use more coal by the end of this decade, as the region of more than 600 million people tries to cut costs to meet soaring electricity needs. Power generation capacity in Southeast Asia is set to rise by 50% during the current decade, of which more than half will be coal-fired and only about a quarter will be gas-fired. Currently, coal accounts for one-third of Southeast Asia's energy mix while gas covers 44%, according to IEA figures. “People in this region keep talking about green growth, but when I look at the numbers, the growth is not green. It is black as coal,” said Fatih Birol, the IEA's chief economist. Gas future Although new LNG supplies from Australia, North America and East Africa that are set to come on line in the second half of the decade could help narrow this gap, the 7% per year rise in global LNG demand to 2020 will still result in a tight market. Meanwhile, the gains made in Asia‟s power sector seem to be too far entrenched now to be reversed. Laszlo Varro, Head of Gas, Coal and Power Market Division at the IEA, said: “The power sector gains in Asia are nothing short of phenomenal. China and Brazil are way ahead of Europe when it comes to power generation and electricity transmission.” “For example, China‟s Three Gorges dam that is the biggest power project in the world is three times the size of the Hoover Dam in the US. Since 2012 it is supplying the city of Shanghai, which is 2,000 km away.” “That would be like supplying electricity to Romania from a power plant in the UK. The scale is simply unimaginable in Europe, but it opens up new options for China,” he said. However, the Achilles heel is the price of gas. Because ultimately, the conference heard, coal‟s renaissance will only be temporary and the “future is gas.” But if that is the case, then Asia will continue to be in a seller‟s market and that does not augur well for its power sector in the long term.

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

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AsianOil

Demand forecasts reinforce South China Sea’s importance The South China Sea is set to become more important on the back of a predicted boom in energy shipments to Asia By Nnamdi Anyadike  Almost one third of global oil shipping passes through the South China Sea at present  Asian oil demand is expected to account for 75% of global demand growth by 2035  The South China Sea may hold 11-125 billion barrels of oil Asian oil and gas demand growth over the coming decades is projected to continue driving the market. Asian oil demand alone is expected to account for 75% of global demand growth by 2035 while gas demand will account for 40%. However, it is not just China that is in the driving seat, but also the rest of Asia. Speaking at the three-day International Petroleum Week conference in London, a BP oil demand analyst, Richard De Caux, said: “While over the past 10 years it has been Chinese demand that has been the main driver, this is starting to slow as

its economy matures. Instead, we are now seeing India and some of the other Asian industrial economies coming to the fore. This trend can be expected to continue in the coming years.” Asian demand Total liquid fuels consumption in nonOECD Asian countries is expected to rise at a rate of 2.6% per year, growing from around 20% of world consumption in 2008 to over 30% of world consumption by 2035. Similarly, non-OECD Asian gas consumption is to grow by 3.9% per

year, from 10% of world gas consumption in 2008 to 19% by 2035. China is expected to account for 43% of that growth. The continued rise of Asia means that countries in the region are engaged in an intense struggle for resources, no matter how marginal they may seem to be. A case in point is the South China Sea, which has seen exploration competition increase in recent years. One economist with the US Energy Information Administration (EIA), Alexander Metelitsa, said the sea‟s incremental production value is useful in a region where energy demand is rising so strongly. “The South China Sea may have a lot of problems. Clearly it is not the new Saudi Arabia and its 11 billion barrels of oil puts it in the same league as the Gulf of Mexico. Similarly, its gas reserves are only equivalent to about two thirds that of Europe, excluding Russia. But it is in a region where there is not a lot else going on, resource-wise,” he said. Reserve prospects In addition to the approximately 11 billion barrels of oil, the EIA estimates there is 190 trillion cubic feet (5.38 trillion cubic metres) of natural gas in proved and probable reserves in the South China Sea. Sourcing an exact figure is difficult because of underexploration stemming from territorial disputes.

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NRG

February 2014, Issue 47

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AsianOil The US Geological Survey (USGS) has estimated the South China Sea – not including the Gulf of Thailand and other areas adjacent to the sea – contains 5-22 billion barrels of oil and 70-290 tcf (8.21 tcm) of gas in as-yet undiscovered resources. It remains unclear at this time how economically feasible it would be to extract these reserves. Nonetheless, in November 2012, China National Offshore Oil Corp. (CNOOC) estimated the area held around 125 billion barrels of oil and 500 tcf (14.16 tcm) of natural gas in undiscovered resources. The majority of the reserves discovered so far are in the undisputed zones of the sea. But where there has been some resolution on border disputes, such as between Brunei and Thailand in 2009, and Thailand and Malaysia, who while not having reached a settlement have shown that it is still possible to work together, exploration may flourish. The South China Sea is a particularly challenging environment to work in, but the main players now working in concert are getting better at operating there. But the main importance of the South China Sea, perhaps, lies in its role as a key trading route between the rest of the world and Asia, rather than in its hydrocarbon resource potential. Trade route “We believe the South China Sea‟s importance is to be found in how much oil travels on top – rather than how much oil is beneath it,” said Metelitsa. He continued: “The Straits of Malacca are as important as the Straits of Hormuz. Half of the world‟s LNG trade passes through Malacca, with most of the cargoes destined for Japan, South Korea and China. The security implications for this weight of tanker traffic are significant and we are monitoring it very closely.” In addition to over half of the world‟s global LNG trade passing through the South China Sea, almost one third of global crude oil also passes through it and more than half of the world‟s annual

merchant fleet tonnage. Using data from PFC Energy and Cedigaz, the EIA estimates that around 6 tcf (169.92 billion cubic metres) of LNG passes through the Strait. Around 56% of this volume continues on as imports to Japan, 24% to South Korea, 19% to China and Taiwan, while the rest goes to other countries in the region. In total, the United Nations Conference on Trade and Development (UNCTAD) Review of Maritime Transport estimated 8.4 billion tonnes of total world maritime trade passed through the Straits of Malacca, Sunda and Lombok in 2012. In the case of crude oil, approximately 14 million barrels per day passes through the South China Sea and Gulf of Thailand, or almost one third of global oil movement, according to data from Lloyd‟s List Intelligence tanker-tracking service and GTIS Global Trade Atlas. Oil flows More than 90% of the total flow moves via the Strait of Malacca, while the rest comes from intra-Southeast Asia regional trade. A significant amount of crude arriving in the strait – 1.4 million bpd – goes to terminals in Singapore and Malaysia, where it is processed and shipped out

again as refined petroleum products. The rest of the flow – 12.8 million bpd – continues on through the South China Sea to Asia‟s two largest energy consumers, China and Japan – 4.5 and 3.2 million bpd respectively. Around 15% of the oil moving through the South China Sea goes on to the East China Sea, with most of that figure sailing to South Korea. Crude oil flow in the South China Sea also comes from within Southeast Asia, particularly from Malaysia with 400,000 bpd of exports and Indonesian with 300,000 bpd. One fifth of intra-regional crude oil flow, the most for any importer, goes to Singapore for refining. Around 200,000 bpd of crude oil pass south through the Strait of Lombok to Australia and the Pacific. Given that the straits are a key global trading route, and rising Asian energy demand will lead to more oil and gas flowing that way in the years to come, it is perhaps unsurprising that the US Department of Energy (DoE) is keeping such a close eye on it. As Metelitsa said: “Although no one expects military confrontations in the area to spiral out of control, the possibility is there and it is one that we are mindful of.”

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

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ChinaOil

CNPC gas find prompts scepticism CNPC‟s announcement of a major new gas discovery at its Moxi block has raised questions over when the gas production can be expected By Graham Lees  CNPC has announced major new discoveries in the past, only for nothing to come of it  Moxi has an estimated 308 bcm of technically recoverable gas  China’s inadequate pipeline infrastructure continues to hinder to the gas sector’s development Reports point to a huge new gas discovery in the central province of Sichuan as well as a promising shale gas find in neighbouring Guizhou Province. The news should prove heartening to the central government Beijing, which has been directing its major cities away from large-scale coal use in favour of gas despite widespread shortages of the latter. But although the hundreds of billions of cubic metres reportedly found by China National Petroleum Corp. (CNPC), plus the shale gas find by Sinopec, make good headlines, it is still a long way for it to reach the market. China continues to be plagued by distribution problems which are caused by a combination of inadequate pipeline infrastructure and a monopoly held by the country‟s Big Three – CNPC, Sinopec and China National Offshore Oil Corp. (CNOOC). Just recently, LNG producers in north and southwest China shut down more than a dozen liquefaction plants because severe winter weather was preventing distribution by truck, their only means of distribution, said the Interfax China news agency. The temporary plant closures affected almost 20% of China‟s domestic LNG production, said Interfax, quoting industry leaders. Moxi CNPC announced on February 10 that it had discovered one of China‟s biggestever gas reservoirs, in the Moxi block of the Anyue gas field in the Sichuan Basin. CNPC said the find was estimated at 440 billion cubic metres, of which 308 bcm were “technically recoverable”. The

NOC said it planned annual production of 6 bcm, but has given no timetable for development. Meanwhile, Sinopec announced on February 12 that it had found shale gas in Xishui, Guizhou Province, after drilling to a depth of 4,417 metres. “According to the Ministry of Land and Resources [MLR], the gas well is the deepest so far in the country and its exploration marks a technological breakthrough in China‟s deep shale gas drilling,” said Xinhua. These finds are in addition to an increase in China‟s proven gas reserves in 2013 of more than 670 bcm, according to official figures cited by Interfax. However, not all of these new finds will necessarily be pumped to the surface. Lack of access to a wider market across China is one of the reasons blamed by for the slow progress of shale gas exploration, much of which has been centred in Sichuan. Monopoly control of gas distribution has been another deterrent. Moreover, some of the big discoveries trumpeted by CNPC have a history of failing to deliver on some of its big discovery announcements.

bringing previously announced major discoveries to production,” said the South China Morning Post in Hong Kong on February 17. The paper referred to two “major” oil and gas discoveries previously reported by CNPC‟s former chairman, Jiang Jiemin, now under investigation by the Chinese authorities for alleged corruption, in 2007. One of these was in the same Sichuan field where CNPC is currently claiming its 440 bcm find and though promises were made that details of the finds would be released, none were. “For reserves to be booked under US securities regulatory rules as „proved‟ they have to be demonstrated to have a high probability of existence, which means positive results from the drilling of many more wells,” said the paper. Still, assuming that CNPC‟s description of its discovery is reasonably accurate, the next challenge will be in getting the gas to market. However, analysts are confident that with suitable production levels to justify a pipeline, the infrastructure side of things will be less of an issue.

Verified? CNPC said the Moxi find has been verified by the MLR, but questions are being asked over what the industry should realistically expect from the discovery. “While a major gas discovery announced by PetroChina [CNPC‟s listed arm] last week triggered a spike in its share price, analysts said any such news should be taken with a pinch of salt, given the firm‟s tarnished track record in

Infrastructure “It is the lack of a big gas field in Sichuan with recoverable reserves that has delayed the regional infrastructure development,” the Oxford Institute for Energy Studies‟ Keun-Wook Paik told NewsBase. “Knowing the Chinese way of developing infrastructure, CNPC will develop a long distance gas pipeline development once the new discovery‟s production schedule is confirmed.”

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

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ChinaOil The Center on Global Change‟s ChiJen Yang, meanwhile, told NewsBase: “The barriers to China‟s natural gas pipeline construction are mainly institutional and economic, not technical or geological.” Sichuan is already connected by longdistance gas pipeline with Shanghai on the coast and the province‟s pipeline infrastructure “is in fact relatively better than in most other provinces”, Chi-Jen said. “Additional pipelines are under construction to connect Sichuan to the Myanmar-Kunming pipeline and further connect to Guangzhou and Hong Kong.” Chi-Jen said: “The extensive use of LNG trucking is because of many dispersed small natural gas wells whose outputs are too small to justify the costs of pipeline connection. Also, because the pipeline business is monopolised by the three [NOCs], independent developers cannot enter the business.” However, the researcher added that the National Development and Reform Commission (NDRC) was discussing the

possibility of breaking up the pipeline monopoly, which meant that the situation could be about to change. “When they discover a large gas reserve, pipeline construction should not be a major issue.” Monopoly breakup CNPC controls more than 60,000 km of pipelines in China, with more than half of those for gas. This monopoly has made it difficult for CNOOC and Sinopec to expand their domestic gas businesses, especially from the coastal terminals handling imported LNG. Keun-Wook has previously told NewsBase that a “number of players” were not happy with CNPC‟s pipelines monopoly. “But this position has been weakened by the removal of Jiang Jiemin who has been a guardian of the pipeline monopoly, so the anti-corruption investigation is a very big blow to CNPC.” Against this background comes an industry assessment forecasting that

PetroChina and Sinopec will reduce their capital expenditure over the next few years in a bid to halt falling income. “[PetroChina and Sinopec] are openly discussing a shift in strategy, which would place „quality over quantity‟ and „returns over scale‟ for the first time,” said a Sanford Bernstein research report. Expenditure on exploration and production is likely to remain steady by the two NOCs, but is expected to be “more than offset by cut backs on pipelines, refining and chemicals,” the South China Morning Post said. As the majors rein in spending on the midstream it will take a sizeable discovery to justify additional spending on new infrastructure. Moxi is a sizeable discovery at a time when Beijing is pushing the country‟s producers to deliver more gas, but until CNPC provides more concrete information about its plans any optimism should be kept in check.

Energo

A winter of content for the Russian power market Prices in Russia have been kept high thanks to a capacity shortfall, while neighbouring power generators and exporters have been able to expand, yielding positive results By David Flanagan  The mild Russian winter has seen lower power production, but stable higher prices through CSAs  NewsBase interviewed Fortum’s Pauliina Vuosio concerning its positive 2013 results  However, addressing the shortfall in Russian power via imports could see domestic prices falling Inward investors in Russia‟s power sector saw a very active year in 2013, with numerous upgrade and development plans taking shape. As operating and financial results for the year begin to emerge, it is becoming clear that Russia is succeeding in encouraging investors in their development of new and more efficient power market capacity.

With favourable pricing conditions provided by the Capacity Supply Agreements (CSAs), whereby Russia incentivises new power capacity development, inward investors are being strongly encouraged to “take a stake” in the future of Russia‟s power market. Market conditions are also playing a part. Wholesale power futures prices have

been high, especially in Price Zone 1, which includes Moscow and St. Petersburg. Challenges do remain, though, for example from the adverse effects on heat demand of the very mild Russian winter of 2013-2014.

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NRG

February 2014, Issue 47

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Energo Furthermore, if Russia starts to import electricity from Scandinavia and other European sources, it begs the question whether this could dampen Russian power prices in the years ahead. New capacity Fortum, the owner and operator of the recently opened Nyagan GRES plant, developer of the soon-to-open Chelyabinsk GRES plant and shareholder in regional power generator TGK-1, has reported an upturn in 2013 revenues and earnings. Fortum vice president of financial communications, Pauliina Vuosio, spoke to NewsBase about the reasons for the positive results. Vuosio said: “The main contributing factor to both increased revenues and profits is the new generation capacity we are building in Russia as part of the Russian government‟s capacity supply agreements (CSA). New capacity brings income from new volumes sold and receives considerably higher capacity payments than the old capacity. In 2013, we commissioned two new CSA-units in the town of Nyagan in Western Siberia. Both units are based on combined cycle gas technology and have a capacity of approximately 420 MW each.” “The positive effect from the commissioning of the new units [altogether five units in 2011 and 2013] amounted to approximately 163 million euros [US$224 million] in 2013. This includes a reversal of a previously made CSA provision, which was made in case projects are delayed, totalling 48 million euros [US$66 million]. In addition, Fortum received 40 million euros [US$55 million] in compensation for CSA penalties from the general contractor of the Nyagan power plant, E4.” However, not all the results were as pleasing. She continued: “On the other hand, the result was burdened by 39 million euros [US$54.5 million] in bad debt losses and unplanned outages. In addition, volumes were impacted negatively by the lower heat volumes due

to exceptionally warm weather at both the beginning and end of 2013 as well as by the divestment of heating network assets in Surgut, Western Siberia, in 2012.” Looking ahead to expected results in 2014, Vuosio commented: “As for 2014, Fortum does not give forecasts or estimates on its revenues or profits. In the Russia Division, our continued focus is on successfully completing our investment programme. Out of the programme‟s eight production units (altogether approximately 2,400 MW), the three last, large ones are under construction. The three remaining units are Nyagan 3 (capacity 418 MW, supply expected to start by the end of 2014) and Chelyabinsk 1 & 2 (capacity 248 MW each, supply expected to start during the first half of 2015).” On trend Italian-owned power generator Enel OGK-5 also recently published 2013 operating results. Net power output from its plants fell 6% to 41.9 billion kWh, according to Enel‟s statement, “broadly in line with the general trend for thermal generation across Russia.” Enel disclosed that the “decrease was largely attributable to weak consumption dynamics.” The company also reported “lower production at conventional gas-fired units due to the impact from newly commissioned generating facilities in the European part of Russia.” Additionally,

“The main contributing factor to both increased revenues and profits is the new generation capacity we are building in Russia as part of the Russian government’s capacity supply agreements (CSA)”

Enel OGK-5‟s output was impacted by lower production at Reftinskaya GRES, owing to increased maintenance activity. Enel‟s spokesman told NewsBase that its group strategy announcement, outlining plans and objectives from 2014 to 2018, was due within the next month, A spokesperson for E.ON Russia, owner of the Surgutskaya GRES and Berezovskaya GRES plants, told NewsBase that its 2013 results were due at the beginning of March. It is clear that weaker demand owing to the mild 2013-2014 winter in Russia has dampened the results of power generators. Of course, weather effects are obviously not permanent. Looking ahead, it is clear that the huge investments made by Fortum, Enel and E.ON are being continuously supported by the CSAs and this will continue to deliver benefits to participants. Whether Russia chooses to sign any further CSAs with new investors remains to be seen, but the likelihood now is that the country will await the full outcome of all inward investor projects. The current period of comparative stability in the market can thereby be preserved and the benefits to both sides maintained. Additionally, it is likely that strong power prices in Russia‟s Price Zone 1 have underpinned the value of sales. But these favourable effects may also change. The shortfall in Russian power which has supported prices may eventually be solved by imports of power. Already, Russia has seen rising imports of power from China and Mongolia in 2013 – in 2014, others may follow. Finland is emerging as a possible source for Russia of imported power, although Fortum told NewsBase that it could not disclose if it was engaged in any discussions or negotiations on this issue. However, the healthy market is certainly attracting interest from sellers, tending to suggest that the recent strong power prices may not climb much higher.

www.newsbase.com

Edited by Anna Kachkova

NRG

February 2014, Issue 47

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EurOil

Independence debate colours Wood Review The final version of the largest ever independent study of the UK North Sea was published in February, offering guidance on how to maximise oil and gas recovery from the region By Sam Wright  The report says production from the UK Continental Shelf could be increased by 3-4 billion barrels of oil  It advocates the creation of a new independent regulator to oversee future development  The UK government has reacted positively to the findings, with a new regulator to be formed this year Sir Ian Wood‟s long-awaited report on maximising North Sea recovery has been released, drawing praise from many in the industry and both sides of the independence debate in Scotland. On February 26, the final version of the Wood Review – the largest ever independent study of the UK North Sea oil and gas sector – was made public. Few were expecting much deviation from November‟s interim report, which predicted that production in the region could be increased by 3-4 billion barrels of oil – a figure that could be worth more than GBP200 billion (US$333 billion) – over the next two decades. As predicted, Wood was blunt in his assessment. He said the industry was not currently fit for purpose. He said the UK Department of Energy and Climate Change (DECC) was understaffed and too hands-off with the industry to drive

forward real change, which should be carried out by a new, independent regulator. In turn this new body would look to address the lack of co-operation and sharing of data between private companies, which has meant that valuable opportunities are being missed. Changing landscape Yet while the content of the review is little changed, the political backdrop has become significantly tenser. In recent weeks, the debate over independence has been fuelled by subjects such as Scotland‟s future currency and its potential admittance into the European Union, both of which have seen claims and counterclaims batted back and forth. In the Wood review, both sides have found a message to cling to, backing the report‟s recommendations more or less unanimously. For UK Prime Minister

David Cameron and the unionists, it is that the UK‟s “broad shoulders” are needed to support the North Sea as it matures. For Scottish First Minister Alex Salmond and his backers, it is that the region has been mismanaged for too long. Praise from the industry has been widespread too. Along with major operators such as Royal Dutch Shell, the plans have been back by industry body Oil & Gas UK, which described the review as “a seminal moment in the history of the UK Continental Shelf”. “The report is a game changer,” it continued. “We have the opportunity to secure a bright future for our industry and unlock at least a further GBP200 billion for the UK economy.” Time to act There is little doubt that Wood‟s projected increase in North Sea production is needed. According to Oil and Gas UK, investment in the region is set to plummet over the next three years following its record level of GBP14.4 billion (US$24 billion) during 2014. Despite this hefty spending during the year, production fell 8% to 1.43 million barrels of oil equivalent per day. Between 2010 and 2012, overall output dropped by 31%. Despite those stark numbers, Judith Aldersey-Williams, an Aberdeen-based oil and gas specialist and partner at law firm CMS, believes Wood‟s goals are feasible.

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

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EurOil “The figure of 3-4 billion barrels of increased production over the next two decades is based on increasing exploration from its current historically low level, as well as other measures, including the successful deployment of enhanced oil recovery [EOR], improved use of infrastructure, and postponing the decommissioning of fields,” she told NewsBase. “All of these targets seem achievable but the window of opportunity for some of them is small, and this will require very rapid action to seize these opportunities before the existing infrastructure is decommissioned.” The signs are that this message seems to have hit home. The government has already said it intends to appoint a CEO for the new regulator by the summer to steer through legislation in the autumn. As Aldersey-Williams added, this suggests that Cameron and company “have grasped that urgency”. Yet while Wood himself has said the report has no bearing on the independence debate, instead arguing that the reforms will be the responsibility of whoever finds themselves in charge of the North Sea region, the practicalities seem hard to avoid. “As with many institutions, if there were to be independence there is the potential that the UKCS would need two regulators, one for Scotland and one for the remainder of the UKCS, dealing with the Southern gas basin and with shale gas in England,” said Aldersey-Williams. “Questions of how they would work together, and what rules would apply to use of shared or connecting infrastructure, would have to be addressed.” At the moment though, necessity seems to have taken precedence. Previously, Wood has said that as it stands, the DECC is “significantly underresourced and far too thinly spread” to manage the complex business and

operating environment of the North Sea effectively. The report has shown that staff numbers within the DECC charged with North Sea supervision has fallen by half over the past 20 years, despite the number of assets under the department‟s remit climbing to around 300 fields. “The report is not a criticism of the staff at DECC, but more a question of defining the government‟s priorities – DECC has 50 staff in its oil and gas licensing, exploration and development team,” said Aldersey-Williams. “Compare that with the Norwegian equivalent which has 200 staff members. There is only so much 50 people can do to regulate an industry of this size and complexity.” Carrot and stick To many in the industry, the current government has something of a mixed record in the North Sea, given the windfall tax controversy of a couple of years ago, together with its subsequent reversal in the form of brownfield tax allowances. However, its assurances over the Wood review seem promising. Earlier in

February UK Energy Secretary Ed Davey said he fully backed Wood‟s recommendations and that his department would “start implementing them immediately”. “This will be good for our energy security, good for the economy and good for jobs,” he continued. “The fact that Ed Davey has announced government plans to introduce legislation, as soon as the next session of Parliament, and recruit a CEO for the new regulator by the summer suggests a real commitment to Sir Ian‟s proposals,” said Aldersey-Williams. “However, unless the new regulator is able to build up a close and effective relationship with the Treasury, the new regime might not achieve the returns being sought – you need the fiscal carrot as well as the regulatory stick if you are going to increase exploration and development.” It is clear the creation of a new regulator will be the most important result of the Wood Review. The new agency must hit the ground running to ensure best practice is implemented in the exploitation of the UK North Sea‟s remaining resources.

www.newsbase.com

Edited by Anna Kachkova

NRG

February 2014, Issue 47

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FSU OGM

Is Urals Blend coming to the English Channel? Summa Group‟s acquisition of Shtandart, a Dutch company, will give it control of a planned terminal in Rotterdam By David Flanagan  Shtandart’s Tank Terminal Europoort West will have a storage capacity of over 3 mcm  The new depot could give Russian crude oil and petroleum products a higher profile in Europe  However, replacing existing benchmarks will be a long-term and complicated endeavour Russia‟s Summa Group recently acquired full ownership of Shtandart TT, the Dutch firm that intends to build Tank Terminal Europoort West (TEW), a new oil storage terminal in Rotterdam. Shtandart was previously part-owned by VTTI, a Vitol affiliate, but the acquisition means that it is now fully under the control of the Russian group. The deal raises a number of questions. What are the objectives of TEW and its Russian backers? Will the acquisition raise the profile of Russian crude oil and products in the European market? Is the timing right for these proposals? Additionally, will the project have the same level of continuity now that Summa Group has taken full control of Shtandart? Supporting players In written comments to NewsBase, a spokesperson for Summa Group stated that TEW would have “more than 3 million cubic metres” of oil storage capacity, and that “Russian oil will be the priority” for the project. The spokesperson declined to comment on the projected turnover and expected profits of TEW or to disclose the price that Summa Group paid for the additional 25% stake in TEW. It is clear, though, that the parties now standing fully behind TEW have extensive interests and operational experience in oil terminal management. According to the spokesperson, Summa Group is the “co-owner of the

two biggest Russian oil tanker ports, Novorossiisk and Primorsk,” along with Novorossiisk Commercial Sea Port (NCSP Group). The group is majorityowned by Novoport, a company backed by business executive Ziyavudin Magomadev and the state-owned oil pipeline operator Transneft. NCSP is extensively involved in the development and operation of oil terminal projects at these ports. Additionally, Summa Group has its own gas production assets in Russia. In 2007, the group acquired Yakutgazprom, a producer and supplier in the Far Eastern Republic of Sakha (Yakutia) that has been renamed YaTEK. Higher profile Will TEW raise the profile of Russian crude oil and petroleum products in Europe, perhaps even elevating them to the status of benchmarks? With respect to the petroleum product market, the timing of the project is in line with the behaviour and underlying objectives of Russian oil refiners. Practically all of the companies that operate Russia‟s crude-processing plants – including Rosneft, Surgutneftegaz, LUKoil and Gazprom Neft – have been actively upgrading refining facilities in recent years to produce diesel that complies with Euro-5 quality standards. This modernisation is a necessary prerequisite for exporting diesel to the European Union. Indeed, Russian refiners have few incentives to supply

petroleum products to the EU market that do not comply with the relevant standards. Hence an increasing share of the Russian refining sector‟s output now meets current EU standards and is ready for a higher profile in the European market. This is where Summa Group‟s acquisition comes in. What TEW will give Russian petroleum products is a dedicated berth in the region. Benchmark challenges With regard to the evolution of the crude oil market, the role of TEW looks like a much longer-term proposition. Russian crude oil is mostly exported to Northern Europe by overland pipeline and to Southern Europe by tanker via Black Sea ports. Hence there is already plenty of Russian crude oil that can be stored and traded in Europe, assuming that this is permitted by Russian suppliers under the terms of the original contracts. If Russia wants to promote the profile of Urals Blend, its main export grade of crude oil, so that it can emerge as a benchmark in certain parts of the European market, TEW can help lay the foundation for such a development. However, we must remember how oil benchmarks emerge and why the market wants a benchmark. Here we can see some challenges. Brent may be on the retreat as a benchmark, owing to falling output in the North Sea.

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

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FSU OGM Nevertheless, it has served the market well because of its high liquidity for speculators and hedging – and also, crucially, because it is used as an index for other commodities, particularly natural gas. Russia is of course a key player in the very heart of the gas trade in Europe, so Urals oil could conceivably play a role here, although many buyers of Russian gas have complained about Gazprom‟s practice of using oilindexation to price its supplies. Additionally, LNG will soon be flowing to Europe from the US, even as the US is stepping up oil sands production. These developments could see the main US benchmark crude, West Texas Intermediate (WTI), emerging in some quarters as a benchmark for oil trading. In short, the concept of how Urals crude oil can fit into trading patterns in Europe could certainly change, but there are many influential factors at play. Improved market liquidity and benchmarking come not only from creating a more recognisable face to the market, although that is indeed a

desirable element of the process. EU rules There is also the need to keep a close eye on another element – namely, energy legislation in the EU. At the moment, the Regulation on Energy Market Integrity and Transparency (REMIT) applies only to physical gas and power trade in the EU. However, its principles may eventually extend into oil trading. Brussels is also known to be looking more closely at the European fuels market, with a particular interest in market transparency. REMIT is concerned with how sensitive information related to prices and available storage and output capacity are conveyed to the market. This has the objective that all market participants, as far as possible, should get the same information at the same time. Available storage capacity for fuels is a price-sensitive variable. And since oil storage and terminal operations have the important role of transmitting such information into the oil market, we should be prepared for some

intensification of the regulatory climate in this area. Awareness of the implications of these changes will be important for the higher profile of Russian petroleum products and crude oil in the European market. Good timing Moving forward, we can see that the TEW project is well timed. With Russian petroleum products making inroads on European markets and Russian refineries showing strong interest in expanding their European client portfolio, this may indeed be a good moment for a venture focusing on Russian fuels. The change of ownership structure may not have any particular effects, since Summa Group/NCSP is well established and experienced in oil port management and terminalling operations. Indeed, the continuity behind the project should be fully maintained with overall ownership now resting with Summa Group. Hence in the quest to create a higher profile in Europe for Russian crude oil and fuels, TEW has an important and noteworthy future role to play.

GLNG

Japan’s LNG prices set to remain high Japanese efforts to cut LNG prices by launching new market mechanisms and restarting nuclear reactors could have little effect, says independent analyst Andy Flower By Tim Daiss  Japan is looking at futures contracts, a spot reference price and an over-the-counter derivatives market  Yet analyst Andy Flower maintains that Japan is unlikely to see contract prices drop to US$12 per million Btu  Restarting reactors would replace more expensive oil generation, leaving LNG import needs unaffected  US supply could put pressure on LNG’s oil indexation in Asia and attract cargoes back to Europe, he said In the aftermath of the March 2011 earthquake in Japan and the ensuing tsunami and Fukushima nuclear meltdown there was an immediate loss of approximately 10,000 MW of nuclear capacity, as the country shut down all but

two of its reactors. By September 2013, the country had closed its last nuclear reactor, as a result of which Japan lost the source of 26% of its pre-Fukushima electricity supplies. Since then, the loss of over a quarter of

the country‟s supply has been replaced with expensive imported LNG. This presents Japan with unprecedented energy and economic challenges that it is still trying to address.

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

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GLNG One way to rein in high LNG prices is by developing the world‟s first LNG futures contracts, establishing a new spot LNG reference price, and by forming a joint venture with a Singaporean firm to start an over-the-counter (OTC) derivatives market for LNG. In addition, Japan has held talks with other major LNG importers – South Korea, India, Taiwan and China – to form a buyer‟s consortium. Last month Japan announced that it would jointly procure LNG with India. Nuclear restart However, of all of the variables in Japan‟s energy equation, the most prominent are talks of re-starting its nuclear reactors. Yet that may be easier said than done. As far back as July 2011, Japan‟s Energy and Environmental Council, chaired by the Minister for National Policy, decided to reduce further mid- to long-term dependence on nuclear power, with the goal of a nuclear-free Japan. In August 2012, Japan‟s Minister of Economy Trade and Industry announced that the country could completely phase out nuclear power by 2030 without hurting the economy. Yet the growing anti-nuclear stance changed demonstrably, however, on December 16, 2012, when the Liberal Democratic Party (LDP) retook the reins of government in a landslide election victory after a three-year hiatus. Ten days later LDP leader Shinzo Abe became Japan‟s prime minister for a second time, with promises to resurrect the country‟s ailing nuclear industry. The Japan Daily Press said last month that the long-term energy plan of Abe‟s administration, including using nuclear power as a way to stabilise the country‟s energy-supply demand structure, was set to be made public by mid-January, but public opinion caused such an announcement to be delayed. The report added that despite Abe‟s popularity, polls showed that a majority of the nation remains against the use of nuclear power. Meanwhile, international media report that any Japanese nuclear restart is

currently bogged down in safety checks and paperwork from the country‟s Nuclear Regulation Authority (NRA), which was created in 2012 to set new guidelines. Reuters reported on February 8 that the NRA now had four teams vetting reactors at nine nuclear power plants (NPPs) on a list of those seeking to restart, while a deadline to complete the checks had been missed as the NRA sought additional information. The report said that no one could predict when the first of 48 reactors might be turned back on. Yet in a positive development for Abe, media reported on Sunday, February 9, that Yoichi Masuzoe, a former welfare minister backed by Abe, easily won Tokyo‟s gubernatorial election, “brushing aside his rivals‟ attempts to turn the election into a referendum on nuclear policy.” The Wall Street Journal said the election outcome had provided relief for Abe‟s pro-nuclear policy. LNG price projections One and a half years before the Fukushima disaster, the Platts JKM price for spot LNG was US$4-10 per million Btu. A few months after the Fukushima disaster, prices jumped to US$18 million Btu, five times the Henry Hub price for natural gas in the US. Meanwhile, Asian spot prices peaked at US$19.40 per million Btu last year. Therefore Japan‟s decision to put its reactors back on line is integral to its own energy future and is a major factor influencing LNG prices in Asia. Andy Flower, former director of LNG at BP, and now an independent Londonbased consultant, does not believe that the restart of Japan‟s nuclear capacity is a cure-all for the country‟s energy woes. He told NewsBase that factoring in the restart of Japan‟s reactors would not have much of an impact on LNG spot prices or long-term contract prices because any increase in nuclear generated electricity would be offset by higher industrial electricity demand in Japan. “Japan won‟t likely bring all nuclear capacity back on line,” Flower said.

“Some will undoubtedly be restarted but [this] will be limited, while the first impact will be to displace more expensive oil used for electricity generation.” He said that many were pegging their hopes on cheaper US gas exports, but that these would not be cheap once the price of liquefaction and shipping to Northeast Asia was factored in. In this regard, he said that there was simply no cheap LNG to be found. “Even in the best scenario,” he said, “Asia will pay at the very least US$12 million Btu for long-term contracts, while spot prices will continue to remain very high.” Chinese demand Other factors that will influence LNG prices in Asia in the short term include exports from LNG projects scheduled to open in the US in 2016 and Australia later this year, together with other projects in those countries and Canada further in the future. These added supply variables will put pressure on LNG‟s oil-indexation in Asia. Flower said that these new projects would create a surge of new supply, pushing some cargoes from the Atlantic Basin back to Europe and offering some relief on spot prices and long-term contracts in Asia. However, China will continue to increase its LNG purchases, particularly on the spot market during peak winter demand, as the country replaces coalburning thermal power plants (TPPs) with cleaner burning natural gas-fired plants to satisfy government policy. This could potentially offset any downward pricing pressure caused by increased supplies from the US, Canada, and Australia. The LNG market in Asia consequently will likely remain constrained up to 2020. Some analysts forecast Japan‟s LNG spot price at US$22 by 2020, not factoring in any restart of Japan‟s nuclear generating capacity. If Flower‟s predictions are correct, the re-firing of the country‟s reactors will not offer much help and that forecasted US$22 per million Btu price could be even higher.

www.newsbase.com

Edited by Anna Kachkova

NRG

February 2014, Issue 47

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LatAmOil

Viva la revolucion: Phase two of Mexican reform under way Mexico‟s radical energy reforms could cause the US shale revolution to spread over the border, although legislative obstacles could delay the pace of change By Amanda Beard  International investors have endorsed the proposed changes and are gearing up for projects in Mexico  Former president Vicente Fox has secured investment pledges worth US$500 million from American firms  Some concerns have been raised about Mexico’s ability to harness its unconventional potential Mexico has won backing from the international business community for the sweeping constitutional changes that promise to open up the country‟s oil and gas industry to private investors for the first time since 1938. Mexican President Enrique Pena Nieto, whose Institutional Revolution Party (PRI) has been the key driving force behind the reforms, signed the bill into law in December. He has since promised to set the proposed changes in stone via secondary laws, which must pass the legislature by April 20. But opposition to the reform amongst some quarters remains strong and the process is bound to face more obstacles as it moves forward. External enthusiasm Outside Mexico, investors have lauded the changes. The Mexican government and state-run oil company Pemex have both seen their bond ratings upgraded in the six weeks since the president signed the constitutional leg of the reform into law. Moody‟s Investors Services raised long-term international ratings one notch to A3, making Mexico only the second Latin American country to achieve such status. Market-friendly Chile is the other. Fitch, which rates Mexico at BBB+, or one notch behind Moody‟s, issued a report saying it expected the energy reform to be positive for Pemex‟s financial stability, which is closely tied to that of the country as a whole. Pemex often accounts for upwards of

30% of government revenues. But the government also pays back a variable amount to the firm via tax rebates for selling fuel at a loss. Standard and Poor‟s, the third big ratings agency, also rates Pemex as BBB+. Analysts expect both Pemex and the government to rise to A grade status within the year. The most watched change in bond ratings is from so-called junk grade to the coveted investment grade, which begins at BBB-. Each move higher up the scale allows Pemex, or any other borrower, to access a greater range of potential investors. As Pemex is not listed domestically or overseas, its bonds tend to act as a weathervane for the perception of the company. At the start of this year, Pemex was able to sell US$4 billion of international bonds to investors in one sitting; a groundbreaking achievement for an emerging market borrower. Investment buzz Mexico‟s energy sector as a whole will also have to get used to new types of investment strategy. In early February, Vicente Fox, who was the country‟s president from 2000 to 2006, announced that a fund he was leading had secured investment pledges worth US$500 million from 25 companies he had visited in Washington DC, Oklahoma and Toronto. His visit to Oklahoma raises the possibility that many of the companies he courted were shale specialists. The US state was at the heart of the first wave of the shale revolution in the 1990s. The US

government‟s Energy Information Administration (EIA) estimates that Mexico could have as much as 545 trillion cubic feet (15.4 trillion cubic metres) of natural gas in shale formations. In a June 2013 report, it highlighted that the Eagle Ford shale formation that begins in Texas stretched across the border and down through northern Mexican states like Coahuila, Nuevo Leon and Tamaulipas deep into Veracruz, which is part of the country‟s more traditional Gulf Coast oil corridor. Fox, from the business-friendly National Action Party (PAN), had himself tried to reform Mexico‟s energy industry. But instead, his administration created a complex factoring scheme for energy projects, which was annulled in another energy reform in 2008 that was led by his successor Felipe Calderon. Legislative battleground Despite the growing investment buzz, there remains plenty to fight over in the final version of the laws. Constitutional changes open the door to the direct tendering of resource-bearing blocks and the sharing of resources, production and profits. However, they do not make such arrangements obligatory. The next phase, which ruling party deputies estimate will require 28 laws to be changed or brought in, will determine which agency will take charge of opening the market and also how private companies and Pemex will pay royalties, income tax and for the blocks they win.

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

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LatAmOil A fair assumption is that the regulators will be given a free hand to determine the structure of those tender auctions that do take place. A sign of turbulence behind the scenes emerged recently with news that Carlos Morales Gil had resigned as head of Pemex Exploration and Production for “personal reasons”. He has been replaced on an interim basis by Gustavo Hernandez, his second in command. Talking to Reuters, Tony Payan, director of the Mexico Center at Houston‟s Rice University, said: “Right now is a key moment for Pemex, and this is actually a bad sign … What this tells me is there may be some internal disagreements playing out.” There have been operational changes elsewhere in the system too. At the state-run Federal Electricity Commission, which faces equally radical changes, its chief Francisco Rojas was replaced by Enrique Ochoa. The latter is one of the energy reform‟s primary architects from the Mexican Energy Ministry. Both Hernandez and Ochoa are seen to be pro-reform and have close ties to Pena Nieto, suggesting that the president is manoeuvring loyal supporters into key positions as the battle to get the second stage of the reform package passed heats up; and it could prove to be bloody. There remains considerable legislative opposition to the reforms from the Revolutionary Democratic Party (PRD) and from demonstrators on Mexico City‟s streets. The PRD has fervently opposed the reforms since their inception and one of the party‟s MPs, Antonio Garcia Conejo, infamously stripped down to his underwear to protest against the bill when it was debated in Congress before the latter shut down in December. The legislature resumed its work on the package in early February. One particular focus of the reform, the need for Mexico to harness hydraulic fracturing methods pioneered in the US to exploit unconventional reserves, is likely to stir up considerable debate in the coming weeks. At the December

signing ceremony for the constitutional changes, Pena Nieto made much of shale‟s potential to drive down Mexico‟s power prices. The CFE is the nation‟s largest buyer of natural gas, consuming around 1.2 billion cubic feet (34 million cubic metres) per day, or around a third of the country‟s total. It already sells electricity at a loss, and has been responsible for a series of power outages that have affected Mexican citizens and industry. Pena Nieto noted that in the US over the past 15 years fracking had driven down energy prices by freeing up huge amounts of natural gas. The country has also enjoyed a turnaround in crude production, as fracking has spurred soaring production from tight oil formations. The president said he hoped the reforms would prove the catalyst for a similar fracking revolution in Mexico, along with a rise in deepwater development, which together could revitalise falling oil and gas production. However, it might not be as simple a process as Pena Nieto hoped. Institutional, geographical and infrastructure conditions in the US were much better than they are in Mexico. Those factors were key to the rapid pace of development of unconventional resources in America. The initial signs suggest that things could take much

longer in Mexico. For the most part, Mexico‟s shale is in areas with far less water than in the US. Furthermore, the shale is made harder to tackle by the Sierra Madre mountains, which have risen up beneath shale formations causing greater fragmentation than has been seen in Texas and the flat broad plains in the Midwest. US fracking also took place in regions that had pipelines, which were swift to bring new production to market. And, critically, it was pioneered by small companies that were able to make direct deals with landowners, whilst the process in Mexico is likely to be led by the federal government, which means it will be less agile. Nevertheless, the geographical proximity to shale production in the US means the fracking revolution could easily extend over the border if conditions in Mexico prove attractive enough to developers. And the fact that Vicente Fox‟s fund has already secured investment pledges totalling US$500 million suggests there is an appetite amongst US developers to venture south. There is still a long way to go in terms of the legislative process, however. And given that whoever wins 2018‟s election will be able to set the agenda by appointing new regulators and Pemex bosses, secondary laws will be an important battlefield.

www.newsbase.com

Edited by Anna Kachkova

NRG

February 2014, Issue 47

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Downstream MEA

Dangote provides a ray of light for Africa’s refining sector Nigeria‟s Aliko Dangote is hoping to succeed where many have failed: in building a large refinery in sub-Saharan Africa. State interference has historically proven a problem, and will be tough to overcome By Nnamdi Anyadike  Dangote plans to build a 400,000 bpd facility near Lagos  African refined product demand is expected to increase by around 60% by 2025  Refining margins in the continent suggest that with the current lack of capacity, refiners are missing out The landscape of Africa is littered with poorly managed and abandoned refinery projects that have left the continent increasingly reliant on the import of refined products from the Middle East and the US. Speaking at London‟s three-day International Petroleum Week Conference and Exhibition, Anthony Ogbuigwe, Group Executive Director, Refining and Petrochemicals Nigerian National Petroleum Corp. (NNPC), and President African Refiners Association, said: “Of the 120 refinery projects mooted in the past 10 years, only four have actually been built.” Yet, despite this dire legacy, Ogbuigwe said that there may be room for hope. “Dangote‟s proposed 400,000 barrels per day refinery near Lagos has certainly moved from the „possible into the probable‟ category,” he said.

told NewsBase. “Government policy in Africa is now playing an important role in getting the Lobito, Mthombo, Algerian, Ugandan and Nigerian refineries off the ground. It is also very likely that the Mostorod Cairo refinery will be built,” he added. However, he noted that the refineries “must adopt new business models and government policy must encourage greater private sector participation. At a time when the cost of building a 400,000 bpd refinery can be as high as US$10 billion – and with the added worries over margins that make the refining industry such a volatile and high risk venture – the only way that large African refinery projects can be supported is to link them to petrochemical projects.”

Next step There is also every reason to believe that African governments are starting to study the lessons learned by their counterparts in Asia and the Middle East. “We are seeing worldscale plants opening up in the Middle East because governments deem them to be a strategic imperative as a means to capture the Asian markets,” Ogbuigwe

Challenging environment Africa‟s planned and existing refineries will have to operate in an increasingly hostile environment. “We are seeing the international oil companies [IOCs] walking away from the downstream. Unlike other industries there is no push for vertical integration,” he said. And while African governments may wish to consider the admittedly small „job creation‟ effect of building a new refinery as a driver, they will also need to ensure that they are run as bona fide business enterprises. Questioned as to whether Dangote‟s proposed Lekki refinery had the necessary commercial safeguards built into its concept – indeed whether the Nigerian market could support such a large refinery – Ogbuigwe answered in the affirmative. “Dangote has identified a Nigerian market of 750,000 bpd. The existing installed oil refining capacity is 400,000 bpd, but the four refineries in the country are operating at much less than this, so there is indeed room for a new refinery of this proposed size.” But David Bleasdale, Executive Director, UK-based downstream consultancy CITAC Africa sees Nigeria and the rest of the West African sub-region as being continually hamstrung by excessive government interference that has interrupted West Africa‟s past growth prospects.

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February 2014, Issue 47

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Downstream MEA CITAC says that following years of strong growth that significantly exceeded world averages, African oil products demand growth slowed to 1.6% in 2012. It blamed the slowdown on the large drop in Nigerian demand, which in turn affected total sub-Saharan African growth data. In Nigeria, a combination of government efforts to remove gasoline subsidies in early 2012 and a scandal over subsidy payments, as well as debt repayment issues caused a 16% year-onyear drop in demand. Growing demand However, despite the apparent temporary slowdown in oil products demand growth in Africa, CITAC now expects growth of 3.9% per year, leading to a 60% increase in total demand between now and 2025. “This equates to a 94 million tonnes [2.1 million bpd] increase in demand to 250 million tonnes per year [5 million bpd] in 2025. Sub-Saharan Africa will contribute nearly two thirds of this increase, or 59 million tonnes [1.3 million bpd], while North Africa will contribute 35 million tonnes [800,000 bpd],” CITAC said. In its latest long-term forecast, CITAC expects the gap between clean products consumption and production in Africa to more than double to 122 million tonnes per year [2.45 million bpd] by 2025. “Tackling such a large increase will require a regional approach to attracting investment, including harmonisation of specifications, pricing policies and reducing barriers to trade,” it said. CITAC forecasts that sub-Saharan Africa‟s oil demand will continue to grow at a constant rate of 4.5% year on year

through to 2014 while China will grow by only 3.7% and India by around 3% over the same period. The outlook for Africa for the remainder of this decade is similarly buoyant, CITAC says. Facilitating the growth Infrastructure investment will be crucial to meeting the oil products required to fuel economic growth in Africa. Although other energy sources, including gas, coal and hydropower, are replacing some oil demand in the electricity and industry sectors, transportation fuels remain entirely oil-based and their reliable and competitively priced supply is an important prerequisite to economic growth and poverty reduction. The removal of barriers to trade within and between countries as well as a concerted effort for the regional optimisation of regulation (pricing and specifications) will be essential to attract and facilitate such investment in the petroleum supply chain and to ensure reliable and competitively priced supply of oil products. But the question of whether or not to build new refineries in Africa could

ultimately come down to the question of how much it will cost the region „not to‟. As mentioned, oil demand in subSaharan Africa is expanding at a significant rate and demand growth has now outstripped that of both China and India. However, this unprecedented rate of growth will put an enormous strain on the continent‟s limited infrastructure. “To put this level of increased demand into perspective, every additional 10 million tonnes [200,000 bpd] of oil product imported per year equates to approximately 330 30-40,000 tonne MRsized vessel movements into Africa. The infrastructure needed to cope with this volume increase is simply not in place,” said CITAC. Some infrastructure projects are already underway, however, including a new single point mooring (SPM) in Dar es Salaam, progress on clean product pipelines in South Africa and Cote d‟Ivoire and the Kenya Petroleum Refineries Ltd (KPRL) facility at Mombasa, which may be converted to an import terminal. But as Ogbuigwe said: “If margins are taken into consideration there is no real difference between margins in Europe and Africa. Indeed, with the oil, the refining feedstock right on our doorstep, expanding our refining capacity should be a no-brainer.” [CITAC has developed the West African Refining Margins Indicator (WARMI), a daily indicator of hypothetical margin in West African refineries. The model used represents a refinery located on the coast of the Gulf of Guinea, running 100,000 bpd of West African crude oil.]

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February 2014, Issue 47

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MEOG

Demand for jack-ups continues to propel Middle East rig market Middle Eastern utilisation rates for jack-up, semi-submersible and drillship rigs indicate an industry in rude health. With competing firms all reporting success and new drilling programmes on the horizon, the future appears bright By Peter Shaw-Smith  Total offshore rig utilisation worldwide increased to 88% in January, up from 86.9% in December  Major contractor Lamprell spoke to NewsBase about issues affecting the rig-building business in the region  The region’s other main players include Dubai Drydocks World, NPCC, Noble and Rowan Rig availability in the Gulf is tight but new-builds are expected to alleviate in part the situation over the coming months. According to data provided by Houston-based Rigzone, there are today around 760 different rig types operating globally offshore, including drill barges, drillships, inland barges, jack-ups, semisubmersibles and rigs under construction. In total, the global fleet saw an increase of 8.7% year on year, from around 700 rigs. In January, rig utilisation stood at 80.7%, lower than a peak of 86.1% seen in summer 2013. Classification society the American Bureau of Shipping (ABS) has become the leading international oversight provider in the rig construction market, creating rules and setting standards. Its technical terminology for the market is instructive: ABS claims to be “the market leader in the classification of mobile offshore drilling units (MODUs) worldwide, including self-elevating drilling units (SEDUs or jack-ups), column-stabilised drilling units (CSDUs or semisubmersibles) and drillships.” Data for these three most important

worldwide rig categories show that utilisation rates have of late been fairly stable around 90% in the past six months. Jack-ups worldwide appear to have a fraction more spare capacity than semisubmersibles and drillships at the moment. Rigzone said a total of 150 rigs were available in the Gulf and Red Sea areas. All are jack-ups except for one drillship and one platform rig, both based in the Red Sea. A total of 134 rigs are operating or available in the Gulf, while the remainder are in the Red Sea region. Rigzone data showed that 94 wells were in full operation in the Gulf and eight in the Red Sea. Nine rigs are under construction. Of the rest, 22 are ready stacked, seven under modification and five cold-stacked. Market and players The jack-up market is easily the largest for rigs in the Middle East by size, and the region accounts for more than 33% of the total jack-ups available worldwide (Table 2), out of a total of 426 available worldwide (Table 1).

Three players dominate the regional jack-up construction market: London AIM-listed Lamprell, Dubai Drydocks World (DDW) and National Petroleum Construction Co. (NPCC) of Abu Dhabi. All three companies are among the top 20 Gulf Co-operation Council (GCC) engineering, procurement and construction (EPC) contractors. The main base of operations of all three is the UAE, with Lamprell‟s main yard at Hamriyah Port and Industrial Zone in Sharjah. Because of the shallow water conditions prevalent in the Gulf, jackups, rather than semi-submersibles or drillships, are very much the regional focus. Lamprell entered the new-build jackup market in 2007, delivered seven vessels in 2012, and its 14th jack-up rig in 2013 (Table 3). According to Rigzone, the leading rig managers by volume in the Gulf are Abu Dhabi‟s National Drilling Co. (NDC, with 17 rigs) – an affiliate of the Abu Dhabi National Oil Co. (ADNOC), Noble Drilling (15) and Rowan (10)..

Table 1: Global rig utilisation rates for Drillships, Jack-ups and Semisubmersibles, 2013-14 Month Jack-ups Semisubs Drillships Total Jan-14 369 426 86.60% 170 189 89.90% 85 94 90.40% 624 709 Dec-13 360 424 84.90% 168 189 88.90% 84 91 92.30% 612 704 Nov-13 355 416 85.30% 171 189 90.50% 79 89 88.80% 605 694 Oct-13 355 412 86.20% 172 189 91.00% 77 89 86.50% 604 690 Sep-13 359 409 87.80% 172 188 91.50% 75 87 86.20% 606 684 Aug-13 354 406 87.20% 173 188 92.00% 75 85 88.20% 602 679 Source: Rigzone

88.00% 86.90% 87.20% 87.50% 88.60% 88.70%

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February 2014, Issue 47

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MEOG Accommodation Cold Stacked Drilling En route Inspection Modification Ready Stacked Under Construction Grand Total Source: Rigzone

Table 2: Middle East rig market Persian Gulf Red Sea Jack-up Total Drillship Jack-up Platform rig 1 1 4 4 1 94 94 1 7 2 2 2 2 6 6 1 16 16 5 1 9 9 134 134 1 14 1

Egyptian Drilling is the top Red Sea manager, with five of the total. Ian Henderson, marketing manager at Lamprell, noting that his firm has a 60% share of the regional market, told NewsBase that the company had a full new-build order-book at the moment. “We are building seven [jack-ups] right now, four for NDC, one for the Caspian for Eurasia Drilling, one for Greatships in India and one more for Jindal. That‟s the seven. We previously delivered two for NDC so we had six originally ordered as well as one for Eurasia Drilling, one for Jindal and one for Greatships.” Henderson said that Saudi Aramco was so busy in other areas, mainly off the east coast, that it had little time to devote attention to the Red Sea. “I think Saudi Aramco is really busy in all of their regions. I was in a meeting with Aramco in Saudi Arabia in [December 2013]; they are working towards increasing rigs on charter steadily during 2014. The Red Sea is mostly deepwater, so they are going to have to have some floaters in there. Semi-submersible rigs are currently in high demand and next availability is Q4 2015.” He noted that Lamprell was a major

player in the global jack-up market. “This region (Egypt Suez to West Coast India) has about 25% of the world‟s jackup population – we have got about 160 jack-ups. If you go into the Mediterranean, you go into deep water, drillships and other floaters.” Competition time Aramco is understood to be satisfied with oil prices as low as US$85 per barrel in order to enable the Saudi government to balance its annual budget. Henderson believes that a per-barrel price of US$100 or more will remain sticky for some time. “I think every time I attend anything at all, the opening statement is: „The days of cheap oil are over. I can‟t see that there is going to be any change in the current industry level at the moment,” he said. DDW has been making steady inroads into the jack-up market in recent years, and Lamprell admits that it is the largest threat to its position of regional market dominance. DDW‟s acquisition of three yards in Singapore and Indonesia led to the creation in 2012 of the DDWPaxOcean Asia joint venture, which today appears a masterstroke. The 52-

Table 3: Lamprell Plc Ongoing Projects to 2015 RIG / VESSEL DESIGN EDC Neptune (Delivered) LeTourneau S116E Nexen 14,500 Ton Topside NDC Rig Quarnin LeTourneau S116E NDC Rig Marawah LeTourneau S116E Jindal Star (Delivered) LeTourneau S116E EDC Mercury LeTourneau S116E NDC Rig Butinah LeTourneau S116E NDC Rig Al Shuwehat LeTourneau S116E Seajacks Hydra Gusto MSC 2500X Jindal Pioneer LeTourneau S116E Greatship GreatDrill Chaaru LeTourneau S116E Source: Lamprell Plc

FACILITY START DATE Hamriyah Nov-10 Jebel Ali Oct-11 Hamriyah Oct-11 Hamriyah Oct-11 Hamriyah Nov-11 Hamriyah Apr-12 Hamriyah Apr-12 Hamriyah Apr-12 Jebel Ali Aug-12 Hamriyah Feb-13 Hamriyah Aug-13

Total Total

Total 1 8

1 6 16

1 5 102 2 2 7 22 9 150

hectare (210,437-square metre) yard in Graha, Indonesia is the focal point of DDW‟s rig construction effort. According to a DDW-PaxOcean statement, “Graha has the capability and resources to undertake turnkey projects for any offshore requirement. It is capable of delivering five rigs per year and the yard is currently undergoing significant expansion to accommodate two additional building berths.” The company is guarded about recent orders, which appear to be on the increase. Its website says that UWM Standard Drilling and Saipem each have ordered two MSC CJ-46-X100D jack-up drilling rigs. One unit each was delivered to both companies in October 2009. “The remaining two units are being built at our Graha yard, with one more unit built as a speculation project,” the company said in an undated statement. In January, DDW announced that it had won a contract with Drill One Capital to build what it called a mega jack-up rig to be known as named Dubai Expo 2020 NS. Chairman Khamis Buamim said the rig would be the “largest rig” ever built, with Bloomberg quoting the contract at around US$730 million. DELIVERY DATE With drilling on the Sep-13 agenda in horizon May-14 areas like offshore Feb-14 May-14 Oman and Yemen, the Nov-13 demand for rigs in the Nov-14 Middle East is likely to Nov-14 enjoy continued Jan-15 resilience. Jun-14 Dec-14 Mar-15

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February 2014, Issue 47

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NorthAmOil

Gulf of Mexico set for production ramp-up Several major projects are set to come on stream in the US Gulf of Mexico this year, potentially marking the start of a phase of considerable growth for output from the region By Kevin Godier  Several companies are planning to start up major new projects in 2014  Exploration is also picking up in the Gulf, with the Lower Tertiary trend in particular generating excitement  The US government is planning two lease sales in March as it seeks to boost Gulf exploration and production The recent start of production from Royal Dutch Shell‟s second Mars platform presages a bout of fresh activity in the US Gulf of Mexico this year. Chevron, Hess and Anadarko Petroleum are poised to bring new projects on line in 2014 that would add roughly 300,000 bpd of new output. The temporary moratorium on drilling in the Gulf after BP‟s massive 2010 Macondo oil spill placed the oil industry on the back foot, but Gulf drilling activity has come surging back. The revival became apparent in summer 2013, when Royal Dutch Shell‟s 100,000 bpd Olympus platform was towed out to sea 130 miles (209 km) south of New Orleans, marking the first of seven new ultra-modern systems starting up by 2016. Oil exploration remains a sensitive topic on the Gulf

Coast, where communities are still recovering from the disaster that resulted in nearly 5 million barrels of oil being spilled into the Gulf over 84 days in 2010. The court case to determine the final payouts and fines stemming from the accident is ongoing, and there has been a far greater focus on offshore safety since the Macondo blowout occurred. At the same time, the boom in onshore drilling in the US has been the focus of most producers. However, Gulf exploration has been making a comeback during this time, and by September 2013 the number of drilling permits issued in the region had hit a record 807. This year, Gulf production is set to surge by 15% to about 1.5 million bpd, according to energy consultancy Wood Mackenzie. Chevron, in particular, is planning a huge ramp-up in its Gulf

output over the next few years. In March, the US Department of the Interior (DoI) will offer more than 40 million acres (161,874 square km) for oil and gas exploration and development via consecutive lease sales. There is also optimism that the increasing activity on the US side of the maritime border could even extend to Mexico‟s waters as the latter moves to open up its oil and gas sector to foreign companies through planned energy reforms. Chevron lead The largest project slated to come on line this year is Chevron‟s Jack/St Malo. The project involves the development of the Jack and St Malo fields using a floating production unit (FPU) located between the two in water depths of 7,000 feet (2,134 metres). This will tap the Lower Tertiary trend at a depth of 26,000 feet (7,925 metres), at an estimated cost of US$7.5 billion. The production facility will have a capacity of 177,000 barrels of oil equivalent per day, which will account for 94,000 boepd from Jack and St Malo, as well as output from third-party tiebacks . Chevron holds a 51% working interest in the St Malo field, while Petrobras has a 25% stake, Statoil has 21.5%, and ExxonMobil and Eni each hold 1.25%. Chevron has a 50% interest in the Jack field, where its partners Maersrk and Statoil each hold a 25% stake.

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February 2014, Issue 47

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NorthAmOil Chevron‟s second new platform due to come on stream this year, Big Foot, will be secured to the sea floor by 16 miles (26 km) of interlocking metal tendons, located roughly 225 miles (362 km) south of New Orleans in 5,000 feet (1,524 metres) of water. Chevron, the operator, owns a 60% interest in the field, while Statoil owns 27.5% and Marubeni Oil & Gas holds the remaining 12.5%. Combined, Big Foot and Tubular Bells will contribute more than 150,000 boepd of net production when operating at full capacity, more than doubling Chevron‟s deepwater Gulf output compared with 2012. Chevron is also involved in the US$3 billion Tubular Bells project, which is operated by Hess with a 57.14% working interest. Chevron holds the remaining 42.86% interest. The Tubular Bells deepwater field, which is due to begin operations in the third quarter of the year, will see the use of a subsea wet tree infrastructure tied back to a three-level topside structure and supported by a design spar. The project will have a peak production capacity of 40,000-45,000 boepd and Hess has cited some potential additional upside from Tubular Bells in terms of production and reserves on the back of recent drilling results. Meanwhile Anadarko‟s Lucius project is on schedule to start up in the second quarter of this year. In its fourth-quarter earnings release, Anadarko said it has completed the installation of the 80,000 barrel per day Lucius floating production facility. The other partners at Lucius are Plains Exploration & Production with

23.3%, ExxonMobil with 15%, Apache with 11.7%, Petrobras with 9.6% and Eni with 5.4%. Anadarko is another of the companies that are currently exploring the Lower Tertiary trend, which is presenting considerable technical challenges for deepwater drillers but nonetheless is thought to hold massive potential. Olympus launch A milestone was recorded by Shell on February 4, when the super-major began production from the Mars B development through the Olympus platform, which is its seventh, and largest, floating deepwater structure in the Gulf. Sitting in approximately 3,100 feet (945 metres) of water, Olympus is the first deepwater project in the Gulf to expand an existing oil and gas field with significant new infrastructure, which should extend the life of the greater Mars Basin – where BP is Shell‟s 28.5% partner – to 2050 or beyond. Combined future production from Olympus and the original Mars platform is projected to deliver an estimated resource base of 1 billion boe. Elsewhere in the Gulf, progress on the 50,000 boepd Cardamom project, in which Shell holds 100%, continues toward a 2014 production date, Shell said. Work is also under way on a Lower Tertiary project – Stones – which will have a capacity of 50,000 boepd and is due to come on stream in 2016. Lease sales Pointing to the Gulf‟s revitalisation, the US government is preparing for

consecutive March lease sales, the DoI stated in a February 13 press release. Citing a “safe and responsible” push to develop new domestic energy resources, Secretary of the Interior Sally Jewell said that the proposed sales would protect “the human, marine and coastal environments” and ensure a fair return to US taxpayers. The two lease sales, Lease Sale 231 in the Central Planning Area offshore Louisiana, Mississippi and Alabama, and Lease Sale 225 in the Eastern Planning Area south of eastern Alabama and western Florida, will be held on March 19 in New Orleans. It is estimated that around 1 billion barrels of oil and 4 trillion cubic feet (113 billion cubic metres) of natural gas could potentially be produced as a result of Lease Sale 231. Meanwhile Sale 225 is projected to lead to output of up to 71 million barrels of oil and 162 billion cubic feet (4.6 billion cubic metres) of gas, according to the Bureau of Ocean Energy Management (BOEM). The DoI is hoping to use the forthcoming sales to tap into a more bullish attitude among explorers compared with three years ago, when there were fears that the post-Macondo Gulf would have fewer players as a result of stricter regulations and higher operating costs, particularly for smaller companies. There are undeniably additional requirements involved, as Gulf producers must now provide more detailed plans for offshore operations, submit to more frequent inspections and prove they have access to a rapidresponse system to cap a gushing well. Higher costs have deterred some projects. Notwithstanding these adaptations, the Gulf is poised to deliver around 700,000 bpd of new crude over the next three years, reversing a decline in production and potentially rivalling shale hotspots such as Texas‟ Eagle Ford formation in terms of growth. This year seems set to be an exciting one for Gulf producers.

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February 2014, Issue 47

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REM

Raw materials and the renewables supply chain Growth in renewables could be undermined by the availability of raw materials. A new WWF report explores the supply chain, revealing both potential bottlenecks and solutions By David Appleyard  The availability and cost of elements such as gallium, tellurium and silver can affect solar cell production  Politics and the control of resources may dictate renewables supply as much as technology and production  The report also highlights the importance of effective recycling and waste management systems An effective supply chain is fundamental to any manufacturing industry and the renewables sector is no different from any other in that respect. However, one of the characteristics of renewable energy industries such as solar and wind is their requirement for relatively large volumes of comparatively uncommon elements. For example, thin-film photovoltaic modules typically use elements such as gallium, tellurium and silver, while the permanent magnet generators found in many offshore wind turbines feature socalled “rare earth elements” such as yttrium and neodymium. As a result, projections for continued growth in renewable energy development have prompted concerns that supply chain bottlenecks could emerge as demand for these materials mounts. Inevitably, such a scenario would be expected to push the prices of raw materials up or even constrain growth in the event of shortages. A recent analysis from consultancy firm Ecofys working with the WWF sheds light on this issue. The report “Critical Materials for the transition to a 100% sustainable energy future” considers potential raw material bottlenecks out to 2050 and a “fully sustainable energy system” as depicted in their 2011 document, “The Energy Report” (TER). The authors note that supply chain concerns have focused more recently on rare earth metals in particular, but also include more common metals such as

copper and aluminium in their analysis. Furthermore, alongside renewable energy industries, other sectors such as IT and transportation are predicted to place ever greater demands on these extractive, nonrenewable minerals. The document cites the increase in demand for smart phones and light emitting diodes (LEDs), both of which contain gallium. Evidently, the energy system transition will lead to a change in raw material requirements, though the majority of the materials currently in demand worldwide are not generally considered to have near or even long-term supply chain bottlenecks. Nonetheless, although many of these resources are anticipated to be available for a century or more, there are notable exceptions. For example, the report identifies molybdenum, where resources are only projected to last for 56 years at current production levels. Pressure points In the TER scenario, solar energy supplies half of the total electricity demand in 2050, half of building heating requirements and 15% of industrial heat and fuel. Although solar covers a broad range of technologies, it is thin-film photovoltaics (PV) in particular, which require several types of scarce elements, where bottlenecks can occur, the report says. For thin-film PV, four different technologies exist, including cadmium telluride (CdTe ) film (where tellurium supplies present a potential bottleneck)

and copper, indium, selenium and optionally gallium (CIS/CIGS) film, where indium is a potential bottleneck. In addition, a large increase in PV will drive demand for silver, tin and for crystalline technologies which use silicon, the world‟s most abundant element. According to the Ecofys analysis, with silver being the notable exception, the maximum annual demand for gallium, indium and tellurium exceeds current production by far, though current reserves and resources are, in principle, able to accommodate the cumulative material demand for photovoltaics until 2050. However, in addition to bottlenecks caused by a mismatch between supply and demand, geopolitical relationships and constraints are also highly influential. The report notes that more than half of global refined indium production is controlled by China, for example. In the wind power industry, rare earths are used in direct drive and superconducting generator technologies. In 2050, the TER scenario assumes that 5% of global electricity production comes from offshore wind. Even with high penetration of these technologies, constraints for neodymium and yttrium are unlikely by 2050. It notes that the maximum annual demand for neodymium and yttrium for wind technologies is a lot lower than current production requires.

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REM The analysis concludes that even though demand growth for rare earths is forecast to rise sharply in the next five to ten years (driven by alternative applications such as energy-efficient lighting or vehicles), rare earths will most likely not be a bottleneck for the implementation of wind energy. However, it adds that the reason these rare earths are considered bottlenecks is not because the quantities of the material are not enough to meet demand, but rather that the majority of global production is concentrated in China. While projects to expand rare earth production are under way, opening new reserves requires a significant investment of both time and money. As a result, the authors acknowledge, increasing supplies in the short term may be challenging. Furthermore, with China‟s history in imposing export restrictions on similar rare earths raising concerns in Japan, the US and Europe, politics may indeed be more pressing than production. Resource recycling The report also presents a number of key mitigation measures and potentially influential market developments, including recycling and substitution. For example, indium is currently considered an impurity in the production process of zinc, but an increase in prices potentially presents an economic incentive to produce indium as a co-product of zinc. Furthermore, the recycling of indium from flat panel displays will become an

important aspect of maintaining an adequate supply, the report claims – 74% of total indium consumption is for flat panel displays currently. Tellurium recycling rates are currently very small, but could increase if and when larger volumes of PV modules are being recycled. However, the report notes that recovery of tellurium from electronic scraps is difficult owing to its dissipative use in small electronics. For most of its uses, tellurium can be substituted, although this does lead to production efficiency losses or product characteristics. For the wind sector, the analysis suggests that the recycling of rare earths from pre-consumer magnets requires further research. While recycling from consumer waste (such as rare earths found in hard-drives) is a possibility, it will take some time before significant quantities enter the waste stream. Furthermore, the substitution of rare earths used in permanent magnets is difficult and has a negative effect on performance. Nonetheless, a potentially more effective solution is presented by the authors. Commenting on the analysis, WWF global energy policy director Dr Stephan Singer says: “A new political legislation is needed in all major economies to promote material recycling and drive substantial technological development to ensure that critical materials required to make renewable energy technology remain available.

“Governments must legislate strong incentives and create regulations for enhanced recycling and reuse of precious and rare materials. In parallel, research and development must be fostered for new materials and high material efficiency,” he concludes. As if illustrating this point, the official 18-month transposition period for the revised EU Waste Electrical and Electronic Equipment Directive (WEEE) ended mid-February, with only the UK and Bulgaria actually having enacted national legislation so far. A 2012 amendment to the original 2003 WEEE Directive sees PV modules included for the first time. “Under WEEE, PV companies will not only have to ensure the collection and recycling of their discarded end-of-life products but are required to also guarantee the financial future of PV waste management”, said PV Cycle managing director Jan Clyncke, who operates a European take-back and recycling scheme. He adds: “Waste management has been a reality for a vast majority of the European PV market since 2007. Including PV modules in the enlarged scope of the recast WEEE Directive has simply created a mandatory framework for every PV actor putting PV modules on an EU market for the very first time.” Of course the relative scarcity of any particular element depends on a number of factors, not least the (movable) commercial recovery threshold. Perhaps more significant in terms of short-term supply chain risk is its geographical distribution. So while overall the globe no doubt possesses more than enough of all these elements to meet our clean energy needs, these two factors will dictate their economic recovery and use. It is perhaps for this reason that the Ecofys study concludes the overall impact on scarce resources in a highly renewable powered and energy-efficient world is likely to be substantially smaller than in a scenario with more modest sustainable energy ambitions.

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February 2014, Issue 47

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Unconventional OGM

New Brunswick’s shale battle The premier of the Canadian province of New Brunswick is determined to push ahead with shale development, but opposition from First Nations is proving to be an obstacle By Sam Wright  New Brunswick Premier David Alward is openly supportive of shale development in the province  First Nations and environmentalists are opposing SWN Resources' shale drilling plans  There are complex issues related to aboriginal treaty rights at play in the conflict On January 30, New Brunswick Premier David Alward made his annual State of the Province speech. His message, as he said, was “crystal clear” on unconventional development in the province. “We are supportive of shale gas, and its potential as an industry to help us achieve our goals,” he said. “To not take advantage of this opportunity would be one of the most irresponsible things a government could do.” Rightly or wrongly, many in the province are hoping the address will be his last. In September, New Brunswick is due to hold its next general election. Earlier this month a poll by Angus Reid placed Alward among Canada‟s least popular premiers, ranked joint third lowest behind Manitoba‟s Greg Selinger and Newfoundland and Labrador‟s Kathy Dunderdale, who has since been forced to resign. In New Brunswick, public opposition – and occasional violence – over shale gas exploration has been prominent during Alward‟s tenure as premier. So far, however, he has remained undeterred. “I‟ve had many people ask me why we are doing all these things, slow down, take the easy way out,” he continued. “That may be the most politically prudent approach, but I didn‟t sign up for this job to stand still and press pause,” he said. “Three years of hard work to bring our fiscal situation back from the brink has set the stage for a New Brunswick resurgence, but only if we choose to take advantage of the opportunities before us.”

A bitter cocktail There are sound reasons behind his determination. In December, the provincial government announced that revenue for the coming year was anticipated to fall by C$172.9 million (US$155.8 million), widening its fiscal deficit to C$538.2 million (US$484.7 million). The brink, his detractors say, is still well in view. In total, New Brunswick is estimated to hold enough shale gas to meet current demand for up to 100 years, which supporters of drilling say would be sufficient to completely transform the region‟s economy. In February 2013, former premier Frank McKenna predicted that shale gas could bring more than C$7 billion (US$6.3 billion) in royalties and tax revenues to New Brunswick – enough to wipe out the debt of a province that it is suffering from 20% unemployment. Yet these arguments have done little to sway the region‟s inhabitants. Over the past two years, a coalition has emerged between the Mi‟kmaq community of the Elsipogtog First Nation – which numbers around 10,000 – and environmentalist organisations in opposition to hydraulic fracturing in the province. Their focus has centred on SWN Resources, which plans to drill two exploratory shale wells in New Brunswick. For two years, the company has faced local opposition as it has attempted to get the project off the ground. Despite this, in early October 2013, it seemed that progress – however slight –

was being made. Following daily protests, Alward and members of the Elsipogtog had agreed to form a working group to reach some form of compromise. This proved to be a false dawn. On October 17, the town of Rexton briefly drew the eye of the world‟s news after the Royal Canadian Mounted Police (RCMP) began enforcing an injunction to end the ongoing anti-fracking demonstration. This rapidly escalated, with the RCMP making more than 40 arrests after six of their vehicles were set alight. Reports emerged that Molotov cocktails had been thrown, while the police attempted to break up the demonstration with fire hoses, tear gas and rubber bullets. No about-turn Since then, the province has refused to back down. SWN, which has committed to investing C$47 million (US$42.4 million) in New Brunswick in exchange for its 2.5-million acre (10,117-square km) licence, was granted an extension of a court injunction that prohibited protesters from interfering with its work. Further arrests have been made and an Elsipogtog warrior chief, John Levi, who is widely seen as a key organiser of the demonstrations, has been charged with obstruction and ordered to keep away from SWN‟s operations. The company has since completed the seismic mapping of shale deposits and is preparing to drill at two locations, both of which, unsurprisingly, are being kept secret.

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

page 26

Unconventional OGM Indigenous issues However, one of the more intriguing aspects of the conflict over SWN‟s plans is that the Mi‟kmaq‟s claims that the land belongs to them may be legally enforceable. In 1999, Canada‟s Supreme Court declared that while the Mi‟kmaq and the Maliseet First Nations had agreed trade and political alliances with the Crown under the Peace and Friendship Treaties, signed in 1760-61, they had not handed over any rights to their traditional territory. As a result, these First Nations maintain that they still hold aboriginal rights and title throughout their land. Quoted in The Star newspaper in December, an Olthuis Kleer Townshend lawyer, Michael McClurg, said this served as the basis for understanding why aboriginal protesters felt justified in setting up blockades to stop SWN‟s seismic testing and prevent any potential

future fracking operations. “The rule of law in this case would arguably dictate that the protesters have every right to be on their traditional land and that in fact, others, including the Crown and resource extraction companies, are trespassers,” McClurg wrote in a recent blog post cited by The Star. Others have contended that protesters should nonetheless respect the court injunctions aimed at ending the

demonstrations, as they are not above the rule of law. McClurg contends, though, that it is a mistake to think of the rule of law as an inflexible concept that should apply equally to everyone. “The Supreme Court of Canada has referred to the rule of law as highly textured,” he said. “There are many other elements, including aboriginal and treaty rights, and including legitimate title claims to land.” As a result, any legal case would be long, complex and hugely expensive, placing it well out of the reach of the Mi‟kmaq – although it is thought that they have considered their options, but have felt forced to resort to direct action. For this reason, it seems certain that the protests against New Brunswick‟s nascent shale sector will continue, despite Alward‟s rhetoric. How far they escalate again, though, is far less clear, whoever is in charge to see it.

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Edited by Anna Kachkova

NRG

February 2014, Issue 47

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NEWSBASE INFORMATION HEADLINES FROM A SELECTION OF NEWSBASE MONITORS THIS WEEK

CUSTOMERS INCLUDE

Oil and Gas Sector

AfrOil Cobalt has racked up a fifth pre-salt find offshore Angola, at the Orca 1 well.

AsianOil Indonesia’s SKKMigas has said the country is unlikely to meet its already lowered 2014 production targets.

ChinaOil Chevron has pushed back the start of the Chuandongbei sour gas project to 2015.

FSU OGM Kazakhstan will borrow US$700 million from Beijing to expand a gas pipeline to China.

GLNG Tokyo Gas has ordered two new carriers from Japan Marine United to import LNG from the Cove Point project.

LatAmOil Petrobras has opted to remain in Argentina after scrapping plans to sell its assets in the country.

MEOG LUKoil has invited bids for three construction contracts for the development of Iraq’s West Qurna 2 oilfield.

NorthAmOil BP will form a separate business to manage its onshore oil and gas assets in the Lower 48 US states.

Unconventional OGM Pemex will only drill 10 test shale wells in Mexico this year. For further details on the stories above and NewsBase’s entire product range:

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