NewsBase Energy Roundup (NRG) by Will Carmichael

NRG NEWSBASE ROUND-UP –– GLOBAL –– AFROIL

NRG January 2014

Issue 46  News  Analysis  Intelligence Published by

 NewsBase

NEWSBASE ROUND-UP GLOBAL

 Algeria hopes to reverse production falls ASIAELEC

2 3

 Generating boom in China

3 5

ASIANOIL

 OVL enjoys overseas success, but future looks less clear CHINAOIL

5 6

 Green Dragon emerges from unusual but beneficial 2013 ENERGO

 Hungary takes the Russian option EUROIL

 European E&P problems laid bare FSU OGM

 The rise of the NOCs? GLNG

6 8 8 10 10 11

13 15

 International investors give thumbs-up to Mexican reforms DOWNSTREAM MEA

15 16

 Kurdish export plans currently little more than pipe dreams MEOG

16 18

 Iran’s future growth hinges on sanctions decision NORTHAMOIL

18 20

 Rail accident sharpens focus on crude transportation REM

NRG comes to you entirely at our expense, which we hope will further increase the value you derive from subscribing to NewsBase. NRG covers developments from all global energy regions and sectors, and brings you the “best of the best” (as selected by our editors) from each of the previous month’s weekly Monitors.

11 13

 LNG import potential rising in Latin America LATAMOIL

This is the forty-sixth issue of the NewsBase Round-up of Global energy issues.

20 22

 Phase-shifting the blame in Central Europe UNCONVENTIONAL OGM

22 23

 China makes shale progress

The global nature of the energy industry means that no episode happens in isolation and we hope that NRG will help to tie up events around the world in one single issue. This month, LatAmOil examines the reaction from the international bond markets to Mexico’s constitutional energy reform, while MEOG looks at the potential of the Iranian energy sector to grow if Western-backed sanctions are lifted.

Please note, it is NOT possible to subscribe to NRG. It is, however, an additional service we provide to our existing subscribers.

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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

January 2014, Issue 46

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AfrOil

Algeria hopes to reverse production falls Last year got off to a bad start for Algeria and its energy industry. The government is hoping this year will stem its declining production By Kevin Godier  Algeria’s oil production fell to 1.14 million bpd in November  The country’s regulations are considered to be among the most onerous in the world  Results from the delayed bid round will be closely watched Algeria is hoping for a turnaround in its hydrocarbon production, after six years of declining output and dwindling interest from foreign firms. During 2013, despite oil and gas production continuing to fall, the North African country exhibited signs of improvement that should lead to rises in output over the next five years, according to Sonatrach‟s chairman, Abdelhamid Zerguine. In remarks reported on December 27 by Platts, Zerguine told reporters that Algeria was “showing signs of recovery”. Speaking on the sidelines of the company‟s general assembly, he attributed the recent decline to the award of some permits to small foreign operators that did not have the “financial capacity” to meet the requirements of local projects, leaving them “overstretched”. These companies had to relinquish their licences, Zerguine said, without naming any specific companies. Many of the world‟s biggest oil and gas companies are still active in Algeria, where Sonatrach dominates the sector, and is implementing a US$80 billion, five-year investment programme to expand its hydrocarbon industry. However, 2013 was a poor year for the country, beginning with the deadly terrorist attack in January on Statoil and BP‟s In Amenas gas facility, which ignited latent security concerns about a market where the threat of terrorist attacks has long preoccupied overseas players. Militants from neighbouring Mali claimed responsibility, with the raid leaving scores dead, including a number

of foreign workers. The country‟s crude oil production stood at 1.14 million bpd in November 2013, down from a peak of 1.37 million bpd in 2007, according to a recent Platts survey of OPEC and industry officials. Meanwhile, as its larger, more mature fields have depleted, gas production had also declined. Data from BP showed that output came in at 81.5 billion cubic metres in 2012, down 1.7% on the previous year and marking a steady decline since 2005. Local faults To some extent, Algiers has itself to blame. It sits on oil reserves of 12.2 billion barrels, the third largest in Africa, and natural gas reserves of 4.5 trillion cubic metres, the second largest on the continent. Even before the attack at In Amenas, though, international firms viewed Algerian production terms as unattractive at a time of rising global competition. This was mirrored in embarrassing auctions for oil and gas exploration licences from 2008 to 2011, with few foreign investors signing up acreage. Unsurprisingly, the Sonatrach explanation made no reference to local accountability – and in particular to Algeria‟s internal struggles with corruption – or its protracted legislative processes, a growing resort to resource nationalism as oil prices have soared and the increasing pain inflicted on its overseas production partners. Algeria‟s hydrocarbon production

began to slow in the wake of new revenue-sharing laws and taxes introduced in 2005, and a 2006 clause that imposed heavy tariffs when oil climbed over US$30 per barrel. In 2009 alone, production slumped by 5%, against a backdrop where there was talk of retroactive renegotiations of contracts. Confidence in the country‟s energy environment was undermined by a series of management shake-ups at Sonatrach, including one related to a corruption investigation in 2010, followed by the replacement 18 months later of the firm‟s head. As a result, some foreign firms threatened to quit the country for good. By mid-2012, though, Algiers was starting to show it might be ready to address these concerns, via a pledge to overhaul its hydrocarbon laws in a way that would prove more appealing to foreign explorers. However, when the new legislation was finally gazetted, in October 2012, the focus was on potential shale projects, frustrating existing partners engaged in conventional exploration and production. Last year brought little improvement, as output continued to decline, and the violent raid at In Amenas forced global companies to rethink their stances on oil and gas fields in the Maghreb region – and in many cases to consider higher levels of protection, as perceptions of regional risk head northwards. Algeria was also beset by a new corruption scandal, this time involving alleged payments involving Eni‟s subsidiary, Saipem.

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NRG

January 2014, Issue 46

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AfrOil As the year wound down, one item of good news came from an announcement that Norway‟s Statoil had decided not to sell its local assets, and would begin returning its staff to local Algerian sites as the fear of new terrorist attacks tapered off. The government and the military have maintained their focus on combating the Islamist threat from Libya, Mali and other regional trouble spots. High hopes Illustrating the more positive outlook for the sector, Algerian Minister of Energy and Mines Youcef Yousfi said on October 1 that he expected oil and natural gas output to double in seven to 10 years, as the country brings fields in under-explored regions on stream. Yousfi told reporters in London that the Maghreb state was continuing to make oil and gas finds in the eastern region, where most of its producing fields are located. New finds have added at least 1 billion barrels to the reserves of Hassi Messaoud, Algeria‟s oldest field that supplies about one third of its oil

production, he said. The minister went on to add that the government planned to step up exploration in the southwestern region, start offshore drilling and develop shale and tight gas reserves. “We have between 300 and 500 technically recoverable trillion cubic feet [8.5-14.16 tcm] of gas in tight gas,” he said while attending the Oil & Money conference. “We are progressing in the evaluation of shale gas in the country and it‟s above 700 tcf [19.82 tcm].” Importantly, Algeria is keeping export volumes unchanged by finding new customers to offset a drop in European fuel consumption that has affected sales to the countries such as Spain, where the economy has tanked. “We have accepted to reduce our exports to these countries for a small period of time but generally we didn‟t reduce our production,” Yousfi said. “We are exporting some quantities to new markets.” On the political front, stability seems assured. Algerian President Abdelaziz Bouteflika is seen by observers as very

likely to be re-elected in April, despite being afflicted by the stroke he suffered in April 2013. Constitutional changes allowing him to be elected for a fourth term must be put in place by February or March, opening the way for a regime where other senior cabinet members will assume key administrative and political roles. Less attractive to the global oil and gas community has been the delay in implementing Algeria‟s planned fourth licensing round. A number of dates had been given for this in 2013, but none came to pass. Reversing the ongoing decline in output by the end of 2018 is undoubtedly a feasible target, given Algeria‟s strong energy sector potential and options. But political and energy sector leaders will have to demonstrate a more flexible and entrepreneurial attitude, given persistent concerns that the incentives attached to the promised round may still be insufficient to attract foreign majors.

AsiaElec

Generating boom in China Low coal prices since 2012 have allowed China‟s big five generators to post their largest profits for 11 years. Cheap coal means consumption is set to rise further, despite Beijing‟s concerns about pollution By Graham Lees  Huadian Power is forecasting the largest profits for 2013, set to be 195% higher than in 2012  Yet the coal industry profits fell by 39% in 2013, leaving loss-making companies US$6.71 billion in the red  Low coal prices have not hindered rising imports or investment in new coal projects  The power sector is still set to be a major consumer of coal as generation move away from the cities China‟s big five state-owned power companies are enjoying their biggest profits bonanza for 11 years as low domestic coal prices help to reduce their operating costs dramatically. Coal fuels the bulk of the 584,000 MW of capacity operated by the big five, and

fuel represents about 70% of a thermal power plant‟s (TPP) operating costs, according to the Shanghai financial services company ChinaScope Financial. “While coal enterprises are suffering heavy losses, China‟s power generation sector, especially the five major power

generation corporations, has just started to make a fortune out of the sharp falling coal prices,” said ChinaScope. The big five are: China Huaneng Group; China Datang, China Huadian, China Guodian and China Power Investment.

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NRG

January 2014, Issue 46

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AsiaElec Profits The biggest individual company profit in 2013 was achieved by Huaneng, with US$3.44 billion, said the China Daily newspaper. It is a swings and roundabouts business, though. Domestic coal prices have been falling since the middle of 2012, but prior to then the five giants suffered severe losses owing to high coal prices, noted ChinaScope. In the five years up to the end of 2012, the corporations now enjoying record profits clocked combined losses of more than 100 billion yuan (US$16.54 billion), said ChinaScope. Huadian Power has signalled that it expects its 2013 net profit could be as much as 195% higher than for 2012, when its profit was logged at 1.42 billion yuan (US$234.7 million). The firm said its electricity production in 2013 was almost 12% more than in 2012, at 175 billion kWh. Meanwhile, overall profit levels in China‟s coal industry fell by almost 39% in 2013, and the “unprofitable producers” suffered a combined 40.6 billion yuan (US$6.71 billion) loss, according to the China Coal Industry Association (CCIA) last week. National coal production climbed by 50 million tonnes to 3.7 billion tonnes in 2013, but consumption grew only 2.6% to 3.61 billion tonnes, said the CCIA. This was a major slowdown – over the preceding 10 years up to 2012, the average annual production increase was 200 million tonnes, said the industry agency. “Excess supply is expected to last this year,” it said.

month, “I don‟t think the contradiction is intentional. China‟s national and local policymakers simply have not worked out a consistent plan for coal use.” Curiously, the slump in China‟s domestic coal prices has not curbed coal imports nor deterred the bigger state coal miners from planning to invest heavily in more production. Imports grew by more than 13% in 2013 over 2012 figures to 327.1 million tonnes, said the CCIA. Much of this was low-calorific value cheap coal from Indonesia – which the central government had pledged to curb as part of efforts to reduce urban air pollution. Even so, China Coal Energy, the country‟s second biggest miner, has just announced details of a US$2.8 billion investment in a large new mine in northern Shaanxi Province. Hong Kong-listed China Coal is targeting an eventual annual production from the mine of 15 million tonnes, although it will take five years to develop fully. Funding for the new mine will come from bank loans and the coal produced will fuel gasification and power projects, said Bloomberg Finance.

Imports and investment It is sometimes hard to comprehend national policy on coal, which seems to suffer a kind of schizophrenic existence: loved on the one hand for its abundant energy value, reviled on the other for its devastating pollution and huge effects on the national health. As energy research scientist Chi-Jen Yang, of the Center on Global Change in the US, told NewsBase earlier this

“China’s power generation sector, especially the five major power generation corporations, has just started to make a fortune out of the sharp falling coal prices”

Policy and reforms China‟s coal industry is clearly not about to collapse owing to the sliding prices which are helping the power firms to profit. The central government is enacting new rules to help miners survive and prosper. State aid plans on tax reforms designed to ease the financial pressure on coal miners are imminent, according to the

China Resources Journal. These reforms include a scheme whereby coal tax collection will be based on sales value rather than the existing system linked to production volume, said the Beijing Global Times. The maximum resource tax is expected to be reduced to 5% from 8% at present, it said. Coal stocks at major mining enterprises are high, while inventories at the big power groups are being deliberately kept low in order to benefit from sliding prices, the CCIA. About 300 million tonnes of coal production, mostly from ageing mines, was taken out of the supply market in 2012, but 300 million tonnes of new production is due to come into operation during 2014, said John Foley, China editor of Breakingviews, a financial analysis service of Reuters. This is in addition to the 100 million tonnes of new capacity given the goahead for development in 2013. “If the authorities are serious about cleaning [urban air pollution in] China, deeper reforms are needed. Local governments have little incentive to enforce [the] closure of inefficient mines only to see smarter new facilities built in someone else‟s town,” said Foley in a January 14 analysis. “Curbs in imports of the dirtiest varieties may just serve to keep low-quality domestic producers alive.” As NewsBase has noted before, the central government‟s promise to tackle coal pollution which suffocates dozens of big cities does not mean reducing the volume of coal burnt for energy; it appears to mean relocating coal burning away from the urban areas. Huge new mines are planned in sparsely populated northern and northwestern areas, and the coal from these will fuel new mine-head power plants or massive coal-to-gas projects which will in turn feed into power plants. It will be a costly business. The closure of small, inefficient mines and power plants in cities will continue, but the rise of coal energy in China is a long way from over yet.

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Edited by Anna Kachkova

NRG

January 2014, Issue 46

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AsianOil

OVL enjoys overseas success, but future looks less clear After years of misfires, OVL has racked up a string of foreign acquisitions. Indian energy policies, however, may cause financial problems for the major further down the line By Siddharth Srivastava  OVL completed the acquisition of a 12% stake in Brazil's Block BC-10 in January  Its acquisition of a 10% stake in Mozambique's Rovuma Area-1 gas field should complete in February  ONGC has warned output growth and overseas acquisitions are at risk owing to its fuel subsidy burden Over the years ONGC Videsh Ltd (OVL) has been roundly criticised for failing to snatch up major foreign oil and gas assets, frequently losing out to quickfooted Chinese rivals that enjoy greater financial and political muscle. Recent events would suggest that all this might be changing, with OVL enjoying a streak of successes in Latin America, Africa, Southeast Asia and Central Asia. Though the company appears to be getting to grips with buying into high value energy targets, however, its abilities to compete on the world stage remain at the mercy of New Delhi‟s domestic energy policy and the resulting impact this has on parent company Oil and Natural Gas Corp. (ONGC). Overseas victory list In January, OVL acquired an additional 12% stake in Brazil‟s Block BC-10 from Petrobras by exercising its pre-emption rights. OVL now owns 27% of the deepwater Campos Basin Block, while operator Royal Dutch Shell holds balance. Significantly, the Indian firm managed to outmanoeuvre Sinochem, preventing the Chinese state firm from investing in the block. OVL agreed to pay US$529 million, matching Sinochem‟s offer. The block produces about 50,000 barrels per day of oil and, according to ONGC, has the potential to reach 75,000 bpd by 2017. The Brazilian success follows OVL and Oil India Ltd‟s (OIL) completion of their acquisition of Videocon‟s 10%

stake in Mozambique‟s giant Rovuma Area-1 gas field for US$2.4 billion this month. OVL has also bought a 10% stake in the block for US$2.6 billion from the US‟ Anadarko Petroleum, with the Indian explorer set to complete the deal before the end of February. “Area-1 has [the] potential to become one of the world‟s largest LNG producing hubs and is strategically located to supply LNG to growing Indian gas market,” OVL said in a statement last week. OVL‟s other successes include winning two onshore oil blocks in Myanmar in October 2012, adding to existing stakes in the A-1 and A-3 gas blocks and three other offshore acreages in the Southeast Asian country. In 2013, meanwhile, OVL acquired a 2.7% stake in Azerbaijan‟s Azeri, Chirag and Guneshli fields for US$1 billion. In December 2013, OVL bid for three blocks in Sri Lanka in the Mannar Basin where Cairn India has made two gas discoveries. In Venezuela, meanwhile, OVL signed a memorandum of understanding (MoU)

with Venezuela‟s PDVSA in October 2013 for co-operation in the oil-rich Faja area. “Venezuela has world‟s highest reserves and we have a huge market,” OVL said. OVL, buoyed by its successes, appears ready to take on more foreign ventures and acquisitions in the near future. Future moves The company, along with partners, is looking to buy a 9-10% stake in Russian gas producer Novatek‟s US$20 billion Yamal LNG project. Sudan offered OVL two oil and gas blocks this week, with the company set to take 100% stakes in the licences if it finds them feasible. Vietnam has offered the company five offshore exploration areas in South China Sea as well as the Kossor Block in Uzbekistan without having to bid. OVL is also set to discuss a possible partnership with Ecuador‟s state-run Petroamazonas later this month. Moreover, the company is also looking into investing in Kazakhstan‟s “Eurasia Project”, which will see the development of oil and gas assets in the northern Caspian Sea. The sea boasts 300 oil and gas fields, including super-giants such as Karachaganak, Tengiz and Kashagan. ONGC officials have said the company has set aside misgivings over Astana‟s decision last year to block OVL‟s US$5 billion bid to buy US super-major ConocoPhillips‟ 8.4% stake in Kashagan in favour of China.

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NRG

January 2014, Issue 46

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AsianOil Yet, while OVL has a racked up a number of notable achievements, its ability to maintain that momentum lies with the Indian government‟s domestic energy policy decisions. Domestic Policy ONGC has said it intends to spend 11 trillion rupees (US$178.62 billion) by 2030 to add reserves both at home and abroad. Indeed, it plans to invest more than US$9 billion in bringing discoveries in the prolific eastern offshore KG Basin into production. Yet at the very same time, the major has warned that its output

growth and overseas acquisitions are under “serious threat” owing to the “disproportionate rise in fuel subsidy burden”. “There has been significant reduction in ONGC‟s net realised prices over the years, from about US$54.5 to in 2012 to US$40 presently. Profit after tax from crude oil has already eroded by almost 50% over last three years,” ONGC has warned. India needs to focus on ramping up domestic exploration efforts, as a result of net annual oil imports costing the country around US$100 billion per year

leaving the country on the brink of a severe energy crisis. The country may be forced to seek a loan from the IMF, Indian Oil Secretary Vivek Rae warned this week, saying: “We haven‟t gone to the IMF yet, but we are pretty close.” If the government does not work to free up ONGC‟s finances then the company is going to find it increasingly a challenge to finance development at home and acquisitions abroad. This will likely leave the country with fewer stable supplies of foreign oil in the long run.

ChinaOil

Green Dragon emerges from unusual but beneficial 2013 The past year has proved eventful for the CBM developer, with the discovery of more than 1,500 wells drilled across its licences By Andrew Kemp  Green Dragon's production soared by 304% year on year in 2013, driven by third-party drilling  Around 1,300 wells were located on the producing Shizhuang South Block (GSS)  The company estimates its 1P reserves have jumped more than sevenfold as a result of the drilling China-focused Green Dragon Gas‟ production soared unexpectedly in 2013, driven by other companies drilling on its concessions – it was a most unusual year for the coal-bed methane (CBM) developer. In its January 21 statement, Green Dragon said total gas output for the year rose by 304% from a year earlier to 7.19 billion cubic feet (203.62 million cubic metres). Breaking that down, the firm said it had produced 2.9 bcf (82.13 mcm), up 11% year on year, while current audits of “third-party activities” had delivered the remaining 4.29 bcf (121.49 mcm), with potentially more to come. The extra production came from some of the 1,500 wells drilled by a handful of the country‟s biggest state-owned majors

on its licences, of which Green Dragon said it had no knowledge. At the heart of how this strange state of affairs came to be is state-owned China United Coalbed Methane‟s (CUCBM) claim in 2011 that Green Dragon‟s licences had been revoked, the central government enforcing the independent‟s rights in 2013 and the subsequent revelation that third parties had carried out extensive drilling work in the intervening period. From there… In March 2011, CUCBM announced via its website that it had ended its cooperation with Green Dragon in four of the five production-sharing contracts (PSCs) it has with the independent and would not be extending those contracts. These were the Qinyuan and Shizhuang

North (GSN) Blocks in Shanxi Province, the Fengcheng Block in Jiangxi and the Panxie East Block in Anhui. Shizhuang South (GSS) was left untouched, while Green Dragon‟s PSC for the BaotianQingshan Block is held with PetroChina. Despite the announcement Green Dragon affirmed its claim to the PSCs, saying that all financial commitments had been met and that the contracts were in full force and effect. Such a move was highly unusual for a privately owned foreign company to make in China, given the power of the country‟s state-owned enterprises (SOEs). Nevertheless, the company continued to operate the licences, while CUCBM refused to answer NewsBase’s requests for clarification on the matter.

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January 2014, Issue 46

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ChinaOil In July 2013, however, Green Dragon announced that the Chinese Ministry of Land and Resources (MLR) had reaffirmed the validity of its licences. What Green Dragon describes as CUCBM‟s “erroneous” statement was removed from the company‟s website just days prior to the independent‟s announcement. On October 8, Green Dragon revealed that CUCBM, China National Offshore Oil Corp. (CNOOC), China National Gasolineeum Corp. (CNPC) and PetroChina had informed it of 1,500 wells that had been drilled across five of its PSCs. Around 1,300 of those were located on the company‟s sole producing block, Shizhuang South (GSS), and had been drilled at an estimated cost of US$500 million. The company has since revealed the signing of a memorandum of understanding (MoU) with PetroChina to confirm the state-owned company‟s “participating interests” in the Chengzhuang Block (GCZ), which is part of GSS, as well as a heads of agreement (HoA) with CNOOC on a “potential transaction” relating to the drilling work. In an interview with NewsBase, Green Dragon‟s chairman and founder, Randeep Grewal, described the situation as “globally unprecedented”, stressing

the protections that should have stopped such a situation from arising in the first place. He pointed to the company‟s PSCs as being “directly authorised, certified, accepted and approved by the State Council” and the fact that they were protected by a bilateral investment treaty between the Netherlands and China. Green Dragon signed the PSCs via a Dutch-listed subsidiary. … to here … Grewal explained that it had taken two years for the company to secure its PSC rights because it had adopted a “conciliatory approach” in lobbying the State Council, the Ministry of Commerce (MOFCOM) and the MLR, rather than pursuing legal recourse. With Green Dragon‟s claim to the licences having received Beijing‟s support, the four state-owned companies submitted information on their drilling activities. Grewal explained that while the company had seen signs of some thirdparty drilling following CUCBM‟s move to revoke the contracts, he insisted that the company had no idea of the scale, which he described as “overwhelming”. Green Dragon, he said, had encountered external drilling activity around 10-15 times prior the concessions‟ reinstatement, with the company

“notifying” CUCBM of each encounter. “At no time, until recently, did we have any idea that there was a campaign to the tune of 1,500-odd wells. That‟s a whole different level,” he said. “It‟s so unprecedented that it‟s difficult to comprehend that something like this could happen, let alone be vigilant to such activity.” While the heavy focus on GSS is of little surprise, given that it is the only concession in production, what is startling is that drilling activity even took place, given that CUCBM never issued a statement ending Green Dragon‟s involvement there. When asked about this, Grewal simply responded by saying: “GSS was never threatened because of the existence of the [overall development plan] ODP.” However, Grewal said that, after having conducted field studies, it was clear from the amount of infrastructure in place at GSS that the block was “well over 50% developed”. … and beyond Green Dragon‟s plan for its six licences has been based on first developing GSS, before expanding its operational scope. With GSS‟ development so much further along than originally expected, the company‟s development plans have been accelerated. With 150 LiFaBriC wells, which use technology adapted from traditional horizontal drilling techniques, slated to be drilled in GSS this year, Grewal does not expect to there to be much development work left before the block is fully completed. When pressed on the exact relationship with its newfound state partners, whether there would be a farmin agreement and if co-development was on the cards, Grewal declined to comment. However, Grewal said: “By the time we hit the end of 2015 we should pretty much be done with GSS and the logical thing would be to continue that drilling campaign into GSN.” He added that there was only a lease boundary between GSS and GSN, with the former enjoying extensive infrastructure development.

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NRG

January 2014, Issue 46

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ChinaOil While the past six months have brought about significantly better news for the company, spurring a 40% rally in its share price in the same period, there is still some way to go before it recaptures the value lost in the wake of CUCBM‟s original statement. Market watch The uncertainty surrounding Green Dragon‟s position has seen the Londonlisted company‟s value drop from around US$1.6 billion in March 2011 to slightly more than US$600 million at present. Commenting on the valuation, Grewal said Green Dragon had enjoyed a “very productive period of time” despite the uncertainty caused by the CUCBM notices. He said: “Our wells have continued to perform remarkably well, our production levels are up, our infrastructure has built up. In every regard operationally we‟ve done well.” He added: “What are my expectations [of the market]? At a minimum we need to go back to the point before these erroneous notices were put out. From there all the accretive activity we have accomplished should be compounded on top.” He pointed to the fact that prior to

CUCBM‟s statement Green Dragon‟s 1P gas reserves stood at 40 bcf (1.13 bcm) and 2P reserves stood at 270 bcf (7.65 bcm). Following the retroactive application of the licences by the MLR, Green Dragon‟s engineers‟ estimates based on information provided by the third parties put 1P reserves at 300 bcf (8.5 bcm) and 2P reserves at 600 bcf (16.99 bcm). The company expects to have completed an audit on its assets in the next few months, with Grewal adding that the “abundance” of data delivered may delay the announcement of its reserve data until the end of the first quarter, rather than in February. Lessons Last year, therefore, was an unusual year – but not unsatisfactory – with Green Dragon closing out 2013 in a better position than it entered. Still it remains to be seen whether investors rally behind the company, returning its lost market value. China is certainly hungry for gas, and having its licences confirmed by the central government will be a mark in its favour. Yet, understandably, cautious onlookers will want to see how the

company handles its development partners in the future. Even as the company seems to be emerging from a somewhat turbulent time, taken from a fairly lengthy period in the country, it raises serious questions about foreign independents and their participation in China‟s CBM sector. Could this to happen to other CBM developers that do not have similar guarantees to fall back upon? While it is difficult to say with any degree of certainty, in Green Dragon‟s case Grewal highlighted the company‟s “first generation” of licences that had been maintained in their original form as having afforded it a much stronger position from which to protect its interests. Speculating on what may have prompted such a unilateral approach to Green Dragon‟s licences by the stateowned giants, Grewal said: “There is a tremendous amount of pressure on all domestic producers, including us, to get domestic gas production up and we‟re all incentivised to achieve that. [However], we still have to do it within the confines of the rules, regulations, PSCs and rigid obligations in place.”

Energo

Hungary takes the Russian option Hungary‟s deal with Russia to expand the Paks NPP is causing considerable controversy, with critics saying the electricity produced will be too expensive for consumers By Robert Smyth  Russia is to lend US$13.55 billion over 30 years to fund the 2,400-MW expansion of the Paks NPP  Critics say the deal could be seen by Brussels as illegal state aid  The terms of the deal could make the price of power from Paks far too high Hungary‟s US$10 billion loan deal with Russia to expand the Paks nuclear power plant (NPP) has come under intense scrutiny at home as Hungarians wait to hear the full terms. The deal was signed last week and was

described by Hungarian Prime Minister Viktor Orban as an “excellent professional agreement.” However, the agreement was struck without any involvement from the Hungarian Parliament, while it could also come

under fire from Brussels. “The information provided about the deal is way too insufficient,” Judit Barta, managing director of Hungary‟s GKI Energy Research Institute, told NewsBase.

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Energo “The government had no right to make such an agreement, as Parliament had only given a mandate for the government to look into the possibilities,” she noted. The loan Russia has pledged to lend Hungary as much as 10 billion euros (US$13.55 billion) as a 30-year sovereign loan to expand the Paks NPP by building two new reactors that will add 2,400 MW of new capacity. This sum should cover around 80% of the costs of the work, the ceiling of which is estimated at 12 billion euros (US$16.25 billion). Russian nuclear agency Rosatom is set to build the new blocks, which will more than double the NPP‟s existing capacity. The agreement was signed by Russian President Vladimir Putin and Orban in Moscow on January 14. Since then, Orban has said that Hungary cannot be competitive without it. Political controversy Orban has come under criticism at home for increasing Hungary‟s energy dependence on Russia, as well as for rushing into a deal for the plant‟s nonurgent expansion. The opposition E-PM electoral alliance leader and former Prime Minister Gordon Bajnai has called for a demonstration against the expansion on February 2, with the goal of forcing a referendum on the issue. Parliament reconvenes on February 3 ahead of a general election on April 6. The ruling Fidesz party has hit back at Bajnai‟s comments, saying that when he was in power before 2010 he was in favour of expanding the Paks NPP. Despite the controversy, the Russian deal represents a quick and decisive piece of business when compared to the long drawn-out expansion of the Czech Republic‟s Temelin NPP. The first new block could start operating in 2023, Hungarian State Secretary Janos Lazar told the press. He also mentioned that the European Union had already given its backing to a draft plan for the building of the new units.

Pricing problems However, GKI Energy‟s Barta questioned whether the deal had really been approved by the EU and said that there was no pressing need to decide on the expansion for at least the next five years. She also claimed that Lazar‟s statement that the Hungarian government would be responsible for paying back the loan, while the Paks NPP effectively received the investment cash as a grant, could represent a case of illegal state aid. “Brussels will surely launch an inquiry into illegal state aid should electricity prices not include interest on the loan taken. There may also be a probe if the Paks NPP receives a capital injection or other state money to help repay loans already taken for capacity expansion,” Attila Vago, a senior analyst at Concorde Securities in Budapest, told NewsBase. While Vago said there was no question that Hungary needs cheap energy, as the country‟s gas and oil imports are high, he expressed concerns about the potential terms of the deal. “The interest on the loan will be huge, and therefore the sale price of electricity produced by the new blocks would be too high,” he said. Assuming an annual return of 8% on the equity, which is around 20% of the estimated investment cost, the eventual price of the electricity would theoretically be around 95 euros (US$128.68) per MWh, more than double the current wholesale price in Hungary. “Someone will cover the difference and that will probably be the tax payer,” he said. The 10 billion euro loan will increase state debt by 10% in terms of

GDP and the interest burden may represent 0.4% of GDP in the years after the new nuclear capacity comes on line, most probably in 2023-24, he added. “Everything depends on financial terms. What really concerns me is that all parties are fully convinced of the economics and the necessity of this project, but nobody knows exactly about the real cost, construction time and future energy prices,” said Vago. Hungarian Economy Minister Mihaly Varga told local TV news channel HirTV on January 15 that the government was negotiating to secure the cheapest deal for Hungary. Not all analysts have questioned the agreement. Takarekbank analyst Gergely Suppan told Hungarian news agency MTI that the expansion would drive investment and with it Hungary‟s GDP growth. He also welcomed the stable financial background that the loan provides, adding that if the interest rate was below market rates, then a good return on investment could be realised. No tender The agreement also means the tendering process that was expected to involve five international players will not see the light of day. There is already a Russian connection at Paks, as its existing four VVER-440 reactors – with 2,000 MW of combined capacity – were built in the USSR. They were installed between 1982 and 1987 and fuel is currently provided by Rosatom subsidiary TVEL. Vago observed that Hungary, a member of the EU since 2004, is the first EU member country to accept Russian nuclear technology on such a large scale. “No doubt this is a huge victory for Russia as well as Putin,” said Concorde‟s Vago. However, nuclear energy is not natural gas, in that Russia cannot utilise it as a geopolitical weapon, as it often does with gas. Therefore Hungary is not necessarily increasing its energy dependence on Russia.

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Energo However, Hungary does remain overly dependent on expensive Russian gas, even if natural gas imports from Russian have dropped by as much as 35% since 2008 because of lower consumption and the growing availability of cheaper gas from the west. “If Hungary sufficiently diversified its

gas supply towards the west, it could achieve lower electricity prices as well, ceteris paribus [all other things being equal],” said Vago. The Paks NPP contributed 43% to Hungary‟s electricity supply in 2011. Last October, Orban told a HungarianIndian business forum in Mumbai that

Hungary was planning to raise nuclear output by 50-75% by 2023. The deal with Russia seems to be a technically and financially expedient way to achieve this for the government, but Budapest will have to contend with further political fall-out and reassure consumers that price will not rise.

EurOil

European E&P problems laid bare The decline of European oil and gas production continues to thwart the continent‟s hopes of energy independence By Nnamdi Anyadike  E&P offshore the UK and Norway and in the Netherlands disappointed in 2013  Decline rates in Europe tend to be understated and are accelerating  A lack of exploration risks a collapse in capital spend in a few years’ time, meaning lower future production European oil and gas exploration and production has been in the doldrums over the past two years, with a marked lack of success offshore in both the UK Continental Shelf (UKCS) and Norway. This was the dominant theme of the Outlook for Oil in North West Europe conference in London last week, which used the latest exploration and production data to assess whether Europe‟s quest for energy independence is possible or a pipedream. Speaking to NewsBase on the sidelines of the conference, David Bamford, one of the conference organisers, a former BP executive and now CEO of New Eyes Exploration, said that rising costs were a critical issue. “What is clear is that high costs are killing the North Sea,” Bamford said. “This is despite … the UK Treasury continuing to incentivise oil recovery and [looking at] the creation of a new Norwegian-style regulatory authority. That will not alter the fact that costs are rising exponentially and as a result, projects have been either cancelled or delayed.” He said several high-profile schemes had been cancelled, such as the Kristin

Gas Export project and plans to develop the Rosebank and Bressay fields. Other projects that have been delayed include Johan Castberg, Johan Sverdrup, Linnorn and Tressak. “But in fact, most of the projects in the Barents Sea are delayed,” he added. UK Despite such setbacks, there are some shafts of light in the gloom. Delegates heard that the rate at which North Sea fields were being brought on stream after initial discovery had improved considerably, rising from 15 years in the 1980s to around five years now. But this is doing little to halt the overall production decline rate. Oswald Clint of Bernstein Research said: “Although the decline rates in the fields of the UKCS and the Norwegian Continental Shelf are not as bad as the Gulf of Mexico, the „real decline rates‟ in Europe tend to be understated and the unavoidable truth is that they are accelerating.” Clint went on to say: “Last year, we saw a decline of 13.8% in the UK and 12% in Norway. This was mainly due to the higher water cut and it is clear that a

decision will have to be taken soon at the highest levels on EOR [enhanced oil recovery] to offset this problem.” For Malcolm Webb, the CEO of Oil & Gas UK, the problem is a perennial one. Commenting on Wood Mackenzie‟s annual review of UK upstream oil and gas, which followed on the heels of data released by the Department of Energy (DECC) on drilling activity in the UKCS, he said: “We are just not drilling enough wells in UK offshore waters and those that we are drilling are not finding enough oil and gas. This worrying trend has been growing for some time. It started in 2011 with a 50% drop in the number of exploration wells drilled, [and] has since failed to recover.” Webb carried on by saying that the industry in Europe was facing a crisis that required immediate action. “Our members tell us that drilling rig availability and the ability of smaller companies to secure equity capital are major hurdles. In any event, it is clear that we now face a crisis which demands urgent concerted action … if we are to maximise economic recovery of our offshore oil and gas resource and sustain future production.”

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EurOil The Oil & Gas UK chief said the situation was a strange one, given the record amounts of investment in offshore developments. “The paradox is that the UK continues to record annual levels of capital investment at over GBP13 billion [US$21.6 billion] … Meanwhile, production from existing fields has fallen significantly and the total number of exploration wells has dropped to just 15 in 2013, according to data just published by DECC.” For Webb, it is a problem with longterm exploration planning. “We are simply not putting enough reserves into the hopper for future development,” he said. “Unless we do something about exploration now, we face a risk of a collapse in capital spend in a few years‟ time and hence lower future production.” An OPEC report released last week backed up the DECC‟s conclusions, saying the UK‟s oil supply of 860,000 barrels per day in 2013 was at its lowest level “since1977.” Norway In Norway, Bente Nyland, director of the Norwegian Petroleum Directorate (NPD), said: “The biggest challenge is that costs have increased. Higher costs

have already led to some projects being delayed ... and higher costs and uncertain future oil and gas prices are a significant challenge.” The NPD cut its 2014 oil production forecast to 1.46 million bpd, in line with last year, but below a previous 1.52 million bpd forecast. It also anticipates flat gas production after earlier predicting a rise. The agency also lowered its investment forecasts, predicting just 2% growth over the next two years before a decline. “If oil and gas prices fall and costs remain stable or rise, this will have an impact on decisions to start up new projects, and will entail lower investments than included in the forecasts. To improve efficiency, mergers and acquisitions activity may increase. There are a lot of companies on the shelf,” Nyland said. “We have said earlier that this kind of restructuring is possible, particularly now when you see the capital strains and you need the capital to fulfil your obligations. That might be tough for some of the smaller companies with no production or income,” she added. The Netherlands The Netherlands‟ government has also revealed that output from the country‟s

giant Groningen field will decline in the coming three years. Production last year stood at 54 billion cubic metres, but output from the field is expected to drop to 42.5 bcm per year in the next few years, before falling to 40 bcm per year in 2016. Gas from the Groningen field currently makes the Dutch government around 12 billion euros (US$16.4 billion) per year. But by 2016 the loss of gas production from the field will knock 2.3 billion euros (US$3.1 billion) off that total. Previously production to 2020 was projected to average 49 bcm per year. Henk Kamp, the Dutch Economy Minister, said the production cut would be the result of concerns raised by locals living nearby who are worried about an increase in earth tremors, which they allege have been caused by the high rate of drilling at the site. Looking at developments in all three countries, Bamford‟s conclusion was: “While the US can contemplate a vision of oil independence, North West Europe could be destined to remain hooked on the global geopolitics of oil, increasingly shovelling money in the direction of OPEC.”

FSU OGM

The rise of the NOCs? In striking a deal on the acquisition of Morgan Stanley‟s oil trading arm, Rosneft is advancing into new territory. Current market conditions may inspire other state-run energy operators to follow its lead By David Flanagan  The agreement is roughly in line with the Russian giant's drive to expand into new markets  It may give the company a boost as it seeks to move into the LNG export trade  Commodity trading may offer NOCs new avenues for profit in the face of tough competition In a move that might have given Gordon Gekko a heart attack, Morgan Stanley, one of Wall Street‟s most revered and illustrious trading houses, has sold its oil

trading business to Rosneft, a Russian state-controlled company. The deal was struck in late December, when the two sides announced that they had signed a

binding agreement that would allow the Russian firm to purchase the Global Oil Merchanting unit of Morgan Stanley‟s commodities division.

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FSU OGM But now that the initial raised eyebrows have dropped again, what does this deal actually tell us about how Russian energy companies‟ attitudes are changing? Moreover, what does it say about how the oil and gas trading markets are evolving? Metamorphosis First of all, the deal concluded a dramatic and successful year for Rosneft. The company was once the steady but unremarkable workhorse of the Russian oil sector, but in recent years it has transformed into a trend-setter and a rapidly evolving global operator. Its metamorphosis continued in 2013 with the acquisition of a stake in the Italian refiner SARAS, the full takeover of the Russo-British venture TNK-BP and the completion of its campaign to acquire 100% of the Russian natural gas operator Itera. Beyond these transactions, it also stands to benefit from the step-by-step revamp of the Russian gas market, including LNG export opportunities. And now the deal with Morgan Stanley marks, in quite spectacular fashion, the elevation of Rosneft into a more mature and calculating oil trading enterprise. New direction Secondly, Rosneft‟s position as a national oil company (NOC) underscores the interesting and unusual nature of this agreement. It is difficult to think of a precedent for such an acquisition, given that we are accustomed to seeing NOCs following a predictable pattern in their development. But under present conditions, they appear to have become more aware of their power and therefore more aware that they have different options. This may explain Rosneft‟s bold step in buying the Morgan Stanley oil “book.” The value of the deal has not been disclosed. However, Rosneft may be less interested in the “mark-to-market” value of the trades and more keen on the prospect of buying a trading structure and contractual relationships that it can now use as it chooses. It is also interesting that fellow

Russian energy firms such as Gazprom and LUKoil have largely built up the trading sides of their business through organic growth, rather than through acquisitions. By contrast, Rosneft, by building its market presence through a high-profile acquisition, has seemingly tried to play catch-up with rivals in a short space of time, and it has arguably now established the foundation needed to accomplish this feat in one fell swoop. Changing market conditions Along with telling us about the changing nature of Russian energy companies, the new deal also reflects shifting fundamental conditions in the oil trading market. Indeed, rather than being a huge surprise, the deal between Rosneft and Morgan Stanley is really a sign of the times. That is, oil prices traded in a narrow range of US$100-110 for most of 2013, so the prospects for banks and trading companies have become quite limited. With such a calm market, banks and trading houses cannot make much money. They need price volatility to make good profits, and that is simply not happening. So together with the ongoing need for rationalisation after the credit crunch and the increased regulatory burden, market fundamentals have not favoured banks in recent years. Nor have they created the conditions necessary for banks to make money in oil trading. This is part of the reason for Morgan Stanley‟s decision to unload its oil trading arm. Others are sure to follow – most notably Deutsche Bank, which is closing down its commodity trading operations. Higher profile Rosneft‟s new deal is also consistent with its ambitious recent evolution. As noted above, the company succeeded in building up its activities through the acquisition of oil-producing and refining assets in 2013. However, its strength is not confined to the oil sector. Rosneft also stands to benefit from other changes. Specifically, Russia moved

quickly in 2013 to relax rules and regulations relating to LNG exports, an area of activity that had previously been the exclusive province of Gazprom. The new regime is clearly good news for Rosneft. The company‟s future involvement in LNG exports is now virtually assured, given that it has teamed up with ExxonMobil of the US to draw up plans for an LNG plant capable of supplying Asian markets. Under these circumstances, the higher profile that the Morgan Stanley deal gives Rosneft is highly favourable. It could even facilitate the company‟s successful entry into the LNG export trade by encouraging the development of synergies in cross-commodity trading, thereby allowing it to develop additional gas trading expertise. As such, the agreement between the two companies illustrates Rosneft‟s ambitious new attitude to its own future. But does the deal also mark the start of a trend among NOCs across the world? Facing competition Certain market trends appear to support this idea. One of the key problems for NOCs lies in the serious level of competition presented by the growth in US shale gas production. This is not a problem faced by Russian oil producers alone. In the Middle East, it has created a dilemma for OPEC, which must now determine how it can represent its members‟ interests in the face of competitive pressure from US shale gas. Consequently questions about the future role of OPEC, which is of course dominated by NOCs, are surfacing. Already some tension within OPEC is evident, and the largest Middle Eastern producers – including Iran, Iraq and Saudi Arabia, all of which may end up pulling in different directions in the future – have a growing incentive to strike out on their own. In other words, these countries may feel that OPEC membership will increasingly serve as an obstacle to their freedom to negotiate and sign contracts.

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FSU OGM Other trends have also shaken up the position of NOCs and may spur them into more self-motivated action. For example, one trend seen in 2013 – one of cheap coal stealing market share away from oil – is sending a signal to NOCs about the need for action. In light of these developments, Rosneft now appears to be leading the market by example. Middle Eastern NOCs may be unable to engage in a transaction like the Morgan Stanley/Rosneft deal for various reasons, but they will not have failed to notice it and could be spurred into action by it. In any event, NOCs cannot rely on the old-fashioned strategy of simply increasing oil output, as this will be inadequate over the longer term. They must, as Rosneft has now demonstrated, employ more lateral thinking in order to ensure that they can make their own future commercial positions more lucrative. Picking up slack The NOCs now have a big opportunity to pick up any slack in the oil trading

market left by departing banks and trading companies. But while there are many opportunities for NOCs in the year ahead, they will not have it all their own way. And indeed, market conditions will not necessarily work in their favour. Many market observers suspect that oil prices will fall in 2014, as a result of the potential for increased Iranian crude oil exports following the relaxation of sanctions and the continued rise in US shale gas production. If they are right, the shift may signal a turn in the so-called commodity “super-cycle” (if such a thing exists), whereby rising commodity prices in the early part of the century are now being replaced by falling commodity prices. If oil is vulnerable to such a price correction, this is not such good news for the NOCs, as it obviously erodes their revenues. But even if oil market conditions do get tougher for NOCs, this in itself is also potentially a driver of change.

Landmark Last year was a landmark period for Rosneft. It was the year in which the company changed its own market position and in which it altered market perceptions of its objectives and ambitions. With the culmination of the year‟s work being the acquisition of Morgan Stanley‟s oil trading business, the group is now set up for another interesting year in 2014. We might not see quite so many headline-grabbing announcements, but the consolidation work, which will have the objective of transforming Rosneft into one of the world‟s foremost NOCs (and in the longer term, into one of its most significant energy trading groups) will now begin. Perhaps the most interesting element of this is the question of how Rosneft‟s changing character may set an example to other NOCs. That is, on the back of this deal, it is worth asking whether we are about to see the rise of the NOCs and a change in the tide that will be hard to stop.

GLNG

LNG import potential rising in Latin America Argentina, Chile and Brazil could become larger importers of LNG, yet price will be key, as there is competition from domestic production and pipeline imports By Kevin Godier  Latin American countries require LNG to supplement their energy needs in the medium to long term  Mexico is importing LNG to deal with rising demand, falling domestic output and US pipeline bottlenecks  Imports to Latin America are forecast to rise by 10% per year until 2020, Cedigaz forecasts Latin America‟s potential to serve as a key destination market is being closely examined by the embryonic US LNG industry, which is continuing to shape up for a long-term role as one of the world‟s largest gas exporters. The opportunity certainly exists, given that Latin America is becoming an integral part of global gas

trading, with imports rising in Chile, Argentina and Brazil. Driving the paradigm is the US LNG market, which “has the potential of becoming the single largest LNG producer in the world,” said Todd Peterson, an advisor to US LNG projects at Japan‟s Itochu Group. Speaking on a January 15 panel at a

regional LNG forum in Houston, he predicted that the US‟ Henry Hub benchmark “could have quite an impact on natural gas prices around the world.” He said that was “going to help develop LNG projects in the Caribbean, Central America and South America and around the world.”

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GLNG Other panellists forecast that, even if there is a marked rise in oil and gas exploration and sales activity, many Latin American countries will still require LNG to supplement their energy needs in the medium to long term. Developing markets across the world are energy-hungry, but the specific growth in demand for LNG will pivot upon a number of factors, including pricing, politics and the level of hydrocarbons imports needed, especially by Brazil and Argentina. Together, these two markets accounted for 2% of global LNG imports in 2012, according to International Gas Union data. Brazil is, of course, focused upon its huge pre-salt reserves and Argentina is a potential producer from vast shale reserves, and both markets will always look very hard at the price of regional pipeline gas, which averages between US$1 to US$2 per million Btu. LNG, by contrast, might be available in a US$4-8 per million Btu range if commodity prices remain at current levels. However, analysts see the fuel acting as a hedge if pipeline shipments fall prey to politics. LNG could also address seasonal and yearly supply variations. Brazilian imports In both 2012 and 2013, Brazil was a robust user of spot LNG to compensate for the fall in hydropower owing to drought conditions. The trend has continued this month, with ship-tracking data showing that the Brazilian parastatal Petrobras received a spot cargo in mid-January, which was loaded out of storage from Portugal and delivered to its floating regasification terminal at Guanabara Bay, near Rio de Janeiro. Petrobras has another regasification plant in the northeastern port of Pecem in Ceara. Drought in 2013 left Brazil‟s main hydro reservoirs at their lowest levels since 2001, when the country had to impose energy rationing. Brazil‟s trade balance and Petrobras‟ bottom line were both hurt by the spot cargoes, and the need to import large amounts of gasoline and diesel earlier in

2013. However, Brazilian independent HRT Participacoes em Petroleo completed a study in 2013 that indicated LNG might be the best way to bring to market natural gas deposits found in the country‟s remote Solimoes region, where HRT has a 55% interest in 19 exploratory blocks. Imports into Argentina are also subject to seasonal fluctuations and weather conditions, but demand undoubtedly exists. On January 15, Argentina‟s YPF closed a tender for five cargoes delivered to the country‟s Bahia Blanca and Recalada ports, according to industry media. The ports were built in 2007 and 2011 respectively. Argentina has no long-term contracts to import LNG, but by October 1, 2013, YPF and state-run Enarsa had issued seven spot tenders since December 2012, seeking as many as 150 LNG shipments. Of course Argentina sits on sufficient gas reserves to provide self-sufficiency. The US Energy Information Administration (EIA) has estimated that the nation sits on the world‟s second largest shale gas reserves at 802 trillion cubic feet (22.7 trillion cubic metres). YPF is beginning to drill and develop shale resources but it could take up to four years to gain clarity, said Alejandro Fernandez, operations manager for YPF's gas and energy department. “We don‟t have the crystal ball ... LNG will stay for the next couple of years,” he was quoted as saying by Upstreamonline on January 16. Mexican quest Latin America‟s second largest economy, Mexico, has been stepping up its imports of LNG as rising demand, falling domestic output and pipeline bottlenecks for cheap US imports have sometimes forced it to pay at least four times more for added supplies. In March 2013, an energy crunch in Mexico underlined the country‟s growing dependence on imports to keep power flowing. State-run Pemex sought to buy LNG at any price in order to avert potential grid failures, paying a price of US$19.45 per million Btu for a spot LNG cargo in March, after imports from

the US costing about US$4.40 per million Btu hit the limit of pipeline capacity. Mexico is likely to reduce its costly imports towards the end of 2014 as major pipeline expansion works allow more US gas into the country. Chile is another Latin American buyer, as shown by state-run copper mining company Codelco‟s recent agreement to buy two cargoes of LNG for the Mejillones LNG terminal in the north of the country. Chile began importing LNG in 2010, but last year saw the scrapping of a scheme to add 50% of capacity at Mejillones because of lack of demand. In Uruguay, the need for imported fuel to run its power plants will decline, as more than 132 MW of wind capacity is expected to be installed by the middle of 2014, reaching 450 MW by the end of the year. Nevertheless, GDF Suez has begun work on the US$1.13 billion GNL del Plata (Punta Sayago) LNG regasification terminal, located offshore of Montevideo, which is expected to come on line as early as mid-2015. Starting in 2015, GNL del Plata is predicted to produce up to 10 million cubic metres per day of regasified LNG, supplying this to Uruguay‟s first combined cycle power plant at Punta del Tigre. GNL del Plata will more than cover Uruguay‟s demand, and so will be positioned to export gas, particularly to Argentina. The world‟s fleet of LNG vessels are undoubtedly making more stops than ever in Latin America. Although the region now only accounts for around 5% of global LNG imports, it is anticipated by market commentators to witness one of the fastest rates of growth this decade. Imports are forecast to rise by 10% annually up to the end of 2020, according to Cedigaz, a compiler of gas market data. If there were a corresponding recovery of the nuclear power business in the world‟s leading LNG consumer, Japan, the downward pressure on pricing would greatly enhance the process.

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LatAmOil

International investors give thumbs-up to Mexican reforms International investors have rushed to snap up new bonds issued by the Mexican government and Pemex in a sign of confidence in the country‟s energy reform By Amanda Beard  Pemex borrowed US$4 billion from international bond markets last week  The government also placed US$4 billion worth of bonds with investors  The reform process will gather momentum in February when the proposals go before the legislature The reaction from the international bond markets to Mexico‟s constitutional energy reform has been positive, with atypically high demand seen for new borrowing from the government and from state-run Pemex. Yet the response to the reforms within Mexico itself remains mixed. The lower prices and economic benefits promised by the reform are years away from becoming a reality, assuming they do actually materialise. And the legislative sessions starting in under two weeks will have to tackle the laws that will enact the constitutional changes and allow foreign and private companies to explore for and produce oil and gas in Mexico for the first time since 1938. Bond success Pemex set records last week by borrowing US$4 billion from the international bond markets, the largest ever by any company from an emerging market. The company found investors for three bonds – US$3 billion due in 2043, and US$500 million each for five-year and 10-year bonds. It had initially planned to borrow just US$2 billion worth of 30-year bonds. The firm usually makes its largest bond market forays in January, when bond funds are usually flush with cash from new allocations. A week earlier the government had placed US$4 billion worth of bonds with investors, meaning Mexico as a whole has been able to tap US$8 billion of investor demand in 10 working days; a

rare feat. Demand was no doubt spurred by the December decision by credit ratings agency Standard and Poor‟s to boost ratings for both the government and Pemex to BBB+ from BBB. Typically, the most watched increase is to BBB- from BB+, a measure that lifts a borrower out of junk into investment grade. This opens the door to a vastly larger number of investors, because so many funds are barred from investing in junk-rated companies. Standard and Poor‟s specifically cited the December 20 approval of a constitutional reform that ended Pemex‟s monopoly on oil and gas exploration as a key reason for boosting ratings for both entities. When upstream investment begins to flow in, which the Mexican Energy Ministry estimates will start in late 2015 or early 2016, it will represent a significant macro-economic boost for the country and additional revenues for the federal government. There are also financial market drivers stabilising domestic and company borrowing. Mexico created a system of private pension funds, which have a mandate for investing in pesodenominated debt, switching from a central government pay-as-you-go system. The rising pool of workers‟ pension deposits has been meant lower interest rates and more exchange rate stability for the government and statebacked companies, which suffer less when there are sudden moves in pesodollar rates. This was a factor that helped trigger a debt crisis and a vicious circle

of financial collapse between 1994 and 1995. Reform push Attention has now shifted to two factors – the secondary laws that will contain the nuts and bolts of how new companies are to participate, and which fields Pemex will seek to hold on to via its so-called “round zero”; in which it has first refusal on all existing resource-bearing blocks. Transitory articles demand that the ruling Institutional Revolution Party (PRI) pass the second phase of energy reform within three months of the constitutional reform. The PRI has said publicly that it intends to change 23 laws to enable the direct licensing of resourcebearing blocks, the sharing of resources, production or profit, or combinations of the above. Pemex must claim its round zero blocks by March 21 sending detailed plans of how it intends to produce from the fields it wants to keep under the control of the National Hydrocarbons Commission (CNH), the energy regulator. Pemex has so far made it clear that it wants to hang on to its Bay of Campeche fields, which delivered around 80% of the firm‟s output in November. It is also expected to offload low margin natural gas fields so it can focus on higher-margin deposits, a position reiterated by Pemex‟s director general, Emilio Lozoya Austin, at several public events since last April.

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January 2014, Issue 46

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LatAmOil “People will be asking how the round zero will be implemented,” Rogelio Lopez Velarde, a partner in Lopez Velarde, Heftye and Soria, a law firm in Mexico City that specialises in energy, told NewsBase. “Pemex has to prove why it should keep the fields based on their capacity.” A key question will be whether Pemex will be allowed to keep fields where it lacks capacity on its own, based on the argument that it will be able to find a skilled collaborator via its own tender or a negotiated partnership. “It could be that the government will

insist that they enter an open tender with their proposed joint venture partner,” he added. Since the rules have not yet been made public or passed by the legislature and regulators have yet to publish their views on those topics, the round zero decisions look set to be a watershed moment for potential participants. Mexico‟s legislature reopens in February and the Revolutionary Democratic Party (PRD), which staunchly opposes the reform, is seeking to add a referendum on the reform on to mid-term ballots. It is improbable that Mexico‟s politicians would yield to the

referendum‟s results, but the issue remains highly divisive and is likely to bring PRD supporters out onto the streets in protest. Furthermore, PRI deputies in marginal constituencies could choose this legislative session to pressure the party to narrow the proposed opening up of the market suggested by the constitutional reform in order to defend their seats. Such political concerns are unlikely to derail the project, though, a fact emphasised by the appetite amongst international investors for Pemex and Mexican government bonds.

Downstream MEA

Kurdish export plans currently little more than pipe dreams Technical issues mean that the volumes of Kurdish crude arriving at Ceyhan are far lower than have been suggested, and an agreement with Baghdad now looks to be essential if they are to increase By David O’Byrne  Despite weeks of claims, it appears that a paltry 180,000 barrels of Kurdish crude have reached Ceyhan  The Turkish terminal has not been able to deal with the different crude blends, creating a choke point  With the cork still in the bottle, progress appears impossible without talks between Baghdad and Erbil It is no secret that the statements of politicians should often be taken with a pinch of salt. But even so few observers have doubted that the announcement that oil from the Kurdistan region of Northern Iraq was flowing to Turkey‟s Mediterranean oil hub at Ceyhan meant anything less than that oil exports would begin sooner rather than later. The more so after the Kurdistan Regional Government (KRG) announced its plans to export 2 million barrels in January, rising to 4 million in February and 10-12 million by the end of the year, after operator Genel Energy announced that it was ramping up production and even less so after the Iraqi central

government in Baghdad warned that it would respond to the start of exports by taking legal action against shippers, buyers and against Turkey. Which meant that the statement by Turkish energy minister Taner Yildiz last week confirming that only around

Turkish officials were able to explain that the unusual nature of the KirkukCeyhan pipeline has meant that to date little Kurdish oil has been able to be pumped

180,000 barrels of Kurdish crude had been pumped to Ceyhan despite the pipeline – which was expected to carry up to 400,000 barrels per day – being in operation for close to a month, all the more surprising. Piping problems Turkish officials were able to explain that the unusual nature of the KirkukCeyhan pipeline has meant that to date little Kurdish oil has been able to be pumped. The line consists of two parallel pipelines of 40-inch (1.01 metres) and 46-inch (1.17 metres) diameter respectively both of which were constructed to carry crude from the Baghdad-controlled Kirkuk oilfields.

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Downstream MEA Now while the 40-inch line has been co-opted to carry Kurdish crude, the two lines still feed into the same pipeline network at Ceyhan meaning that it is only possible to fill the Ceyhan storage tanks from one line at a time without mixing crude from the two lines. As the crudes carried by the two lines have a different specific gravity, mixing is not an option. And as Turkey has contracted obligations to Iraq to carry the Kirkuk crude, it has been obliged to allow Kirkuk crude to flow into the Ceyhan tanks with Kurdish crude only able to flow for a few hours a day during periods when Iraqi flow is halted for maintenance on the Iraqi section of the line. So assuming Yildiz‟s statement is correct, with little Kurdish crude flowing there seems little danger of Turkey reneging on its promise of not allowing the export of Kurdish crude until a deal has been brokered between Baghdad and the KRG in Erbil. But this does raise some questions. Firstly, why would Turkey and the KRG have been so keen

to give the impression that exports were imminent? Turkey must have known in advance that flow would be limited while the KRG must have been aware that flows were far lower than the volumes needed to make their planned exports. That would appear to be a simple ploy to force Baghdad to conclude a deal rather than be left with a fait accompli – predictable and hardly surprising. Equally unsurprising given Baghdad‟s history of intransigence on the issue, it has failed to produce anything more than threats of litigation. Ceyhan chokepoint Secondly though, there has been plenty of warning from both the KRG and developers in the region that they want to export through the 40-inch KirkukCeyhan line. One developer – Genel Energy – has completed a line from its producing field to connect with KirkukCeyhan and two more are reported to be under construction. So why has no work been done at Ceyhan to allow crude from the two

pipelines to be tanked separately and simultaneously? This is less clear. It could be that it just did not occur to anyone in Ankara to check the specs of the Botas Ceyhan terminal to find out what was possible. The cock-up theory of history is an enduring one but given the age of the terminal and experience of Botas personnel who run it, it seems unlikely it would have escaped notice. It could be that the work would be difficult to complete without alerting Baghdad as to what was happening, or that the Iraqi government has some sort of veto over such work being undertaken on the line. This though would imply that Baghdad should be aware of the technical bottleneck, which apparently it was not. Pipeline politics More interesting perhaps is the question of why Ankara chose now to confirm the problem and expose the KRG‟s export plans as unfeasible. This strongly suggests some level of dissatisfaction with the KRG‟s apparent preference for baiting Baghdad rather than actually trying to negotiate an agreement. Yildiz announced before Christmas that Baghdad and the KRG had decided to settle the issue between them, without the help of Ankara. But those talks do not seem to have actually commenced until around two weeks ago with only three meetings having apparently taken place. Whatever the truth, the fact now appears clear that with currently no possibility of operating both pipelines simultaneously without the two crudes being mixed in the tanks, any agreement between Baghdad and the KRG to allow exports to start would have to be for a blended crude, at least until such time as new pipes can be added to allow separation and simultaneous flow – a fact that will be sure to further complicate negotiations and may have wider implications for buyers used to buying Kirkuk crude.

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MEOG

Iran’s future growth hinges on sanctions decision There is plenty of optimism that Iran‟s energy sector can grow if Western-backed sanctions are lifted. The issue now appears more one of „when‟ rather than „if‟ By Peter Shaw-Smith  Optimists are hopeful that Iran's energy sector is due for an investment boom  The country’s oil and gas fields are in dire need of foreign technologies to increase recovery rates  With sanctions now being eased, Tehran is whipping up interest among IOCs November‟s interim agreement between Iran and the P5+1 was a watershed in relations between the international powers and the maverick Islamic Republic. While recent news reports have set out conflicting interpretations of that agreement, and the likely implications once the real work of a possible complete dismantling of sanctions begins, should Iran comply with their demands, many companies, some with previous business experience in Iran, stand to gain if sanctions are eased further. When the interim agreement ends in May, the question of progress in the goal towards Iranian compliance will be thrown into relief. Iran insists that its nuclear programme exists to provide conventional power, but sceptics, such as Canada, Saudi Arabia and Israel, remain unconvinced. Understanding the scope of the sanctions, and the implications of their removal, is key.

in 1979, is a denial of the machinery of the US dollar-denominated banking system to Iran. EU sanctions are much more recent, with a new raft imposed in 2012, but appear to be just as effective. Murphy said the November deal meant no new sanctions would be imposed for six months, and involved the lifting of embargoes on gold and precious metals, Iran‟s automotive sector and the country‟s petrochemical exports. The licensing of safety-related repairs to Iranian airlines was also allowed. Some restrictions on Iran‟s vital oil sector were lifted: the deal allowed purchases of Iranian crude to remain in force at current levels – amounting to a 60% reduction on 2012 – and that the proceeds from such sales could be repatriated back to Iran up to limit of US$4.2 billion. There also seemed some likelihood of the lifting of prohibitions on insurance of the transport of those crude sales.

Key concepts In December 2013, Patrick Murphy, legal director at Clyde and Co., gave a presentation in Dubai outlining the nature of international sanctions against Iran. He said that the brunt of the measures had been introduced by the US and the European Union, and that with interim relief being offered in November, time had come for a reassessment of where their possible removal might lead. The key aspect of US sanctions, broadly in place since the return of Ayatollah Ruhollah Khomeini to Teheran

Renewed optimism An Iranian official speaking at TOC Container Supply Chain Middle East underlined Iran‟s efforts to capitalise on the new optimism by setting out a list of tenders for port equipment required at Bandar Abbas. Port representative Behzad Alsafi said Bandar Abbas would be bidding for several items of equipment and technology, including vessel traffic monitoring systems, automated ship mooring systems, cameras, access control identification and container

inspection technology. Another Iranian official attending the conference in Dubai expressed pessimism about the chances of a long-term deal being brokered in May. “I don‟t think anything‟s going to change,” he said. Energy expert Justin Dargin, of the University of Oxford, is more optimistic, sensing that the time is ripe for change. He told NewsBase: “Without a doubt, increased incremental removal of sanctions appears to be quite likely in the near future, as Iran has continued its good faith steps. The latest negotiations that occurred with the election of Hassan Rouhani created a much more conducive environment to move to rapprochement between Iran and the Western powers.” He said that the sanctions relief in the Geneva agreement was a significant first step. “Arguably, the most important aspect of the sanctions suspension in the precious metals, petrochemicals and vehicle industries is that on the energy sector. It grants potential Iranian customers the optimism that a comprehensive agreement is around the corner and that they can begin to negotiate with Iran over substantially increasing its exports to their markets in the short to [medium] term.” Taking steps Recently, he said, Iran has begun to disconnect centrifuges at Natanz plant, and it has started to curb some of its most sensitive uranium enrichment as well.

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MEOG The International Atomic Energy Agency (IAEA) has concurred, he believes, that Iranian progress is authentic, and has announced that Iran has indeed halted uranium enrichment above 5% purity at both the Fordo and Natanz plants. “If Iran continues, which is quite likely, its steps to fulfil the elements of the nuclear agreement, a partial regeneration of the Iranian energy industry would likely take place within the year. It is partial in the sense that Iran still needs to upgrade its energy-related infrastructure, and that would take a longer time. The restrictions on the insurance and transport of Iranian oil by American and European companies are anticipated to be removed soon as well.” Not every country is supportive of the framework of negotiations, Dargin said. “For instance, Canada, Israel and Saudi Arabia tend to view the Iranian intention to negotiate as being a cover to continue to develop nuclear-weapon technology, and as a result, Canada vowed not to remove sanctions.” Sanctions dance Unsurprisingly, Iran has sought ways to avoid the sanctions, and in particular, directed its global oil trading effort eastwards, in order to step up deliveries to countries such as China, Japan, South Korea and India, which were explicitly allowed to trade with Iran, although not to make payment in US dollars, because “US banks are prevented from facilitating transactions with Iran”, noted Murphy. “In order to work around sanctions, Iran developed a multifaceted strategy to forestall total economic breakdown. These strategies were both short-term and long-term in scope, as Iran had expected the sanctions regime to last for some time. Iran offered significant discounts on its crude exports to its Asian customers in a bid to get them to break Western sanctions. This was part of its overall strategy to rely more upon the Asian market instead of the Western market,” Dargin said. “Additionally, Iran moved to expand the role of the private sector in the export market. This was thought by the leadership to provide a means to bypass

sanctions that were aimed at governmental agencies. Iran also created numerous front companies or traders for export in a bid to evade surveillance. Moreover, at one point, Iran was estimated to be storing between 26 to 30 million barrels of oil on its supertankers.” One of the most pressing issues for Iranian shipping has been the denial of insurance cover from international underwriters during the sanctions regime. As a means to reassure its customers, Iran created sovereign-backed reinsurance companies in order to resist sanctions directed towards its global shipping network and that of shipping networks from countries that imported from Iran, Dargin added. “This move was not that successful, as the funding offered was not in line with global standards,” he said. Looking downstream Iran has looked beyond oil exports to its downstream industry to provide succour in its time of need, Dargin said. “As a long-term strategy, Iran sought to reduce dependence on crude oil exports through the expansion of the downstream industry. This was thought by the Iranian leadership to provide, on the one hand, more revenue stability and job creation, and would also reduce the dependence of Iran on the vagaries of the Western oil market.” Iran requires massive investment in its economic sectors that were hit by

sanctions, he said. “In particular, the oil and natural gas sectors are in horrendous shape. As Iran‟s oilfields are mostly mature, Iran needs the latest oilfield technology in order to improve reservoir production rates. The technology that Iran requires includes more advanced drilling equipment, equipment to maintain pressure in more mature oil wells, as well as some of the latest seismic imaging technology.” Iran‟s 2,800-km coastline is served by 13 major commercial ports. “Iran is in dire need of port refurbishment. Some of Iran‟s Asian customers, such as India and China, have offered generous loans to refurbish Iran‟s ports that would buttress its exports to the Asian markets. As an example, the somewhat decrepit port of Chabahar, which is essential for Asian exports, has been the source of interest from India to provide significant upgrade and expansion,” Dargin said. He suggested that Iran could return to some kind of normality in the near future. “As the sanctions were just suspended, it will take a bit of time for Iranian exports and imports to reach full capacity. Additionally, not all sanctions have been lifted. As Iran was shut out of the global banking sector for some time, it will take some time for international customers to begin to reintegrate payments to Iran as well,” he said. “The most important issue is the ability for Western companies to trade in the Iranian petrochemical sector. However, the ultimate impact is likely to be limited in scope, as prior to the imposition of sanctions most of Iran‟s petrochemicals exports went to the Asian market,” he noted. “Nonetheless, the partial removal of some of the Iranian sanctions has allowed Iran some breathing room with the expectation that exports and imports will substantially increase to head towards the pre-sanctions level within a period of months.” Despite his optimism, Dargin is under no illusions about the way forward. “Suffice it to say, much of the interim progress depends on the success, or lack thereof, [of] a final agreement.”

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NorthAmOil

Rail accident sharpens focus on crude transportation Another crash involving a train carrying oil has intensified the debate on the comparative safety of crude transportation by rail and pipeline once again By Kevin Godier  A number of major accidents involving oil trains have occurred in recent months  The comparative safety of pipelines and trains feeds into the greater debate on the Keystone XL project  There are concerns that Bakken crude may be more flammable and requires extra safety measures The ongoing debate on the comparative safety of rail and pipeline transportation of crude oil has been re-ignited after the train derailment and fire that led to the evacuation of a North Dakota town in late December. Coming as the US moves nearer to a decision on whether to approve the Keystone XL pipeline, the incident involved the crash of a 106-tanker BNSF train carrying crude east from the Bakken shale, which collided with another BNSF train that was carrying grain near the town of Casselton, about 25 miles (40 km) west of Fargo. Public safety officials urged the evacuation of more than 2,000 residents as a fire engulfed the oil tankers and burned for over 24 hours. The train carrying oil originated in Fryburg, North

Dakota, and was bound for Hayti, Missouri, on the Mississippi River. Although no injuries were reported, the incident marked the fourth major North American derailment in six months among trains transporting oil, and has generated widespread calls for new and enhanced safety features for crude oil tankers. The North Dakota crash is “a wake-up call for what increased oil production in North America is going to mean” for US communities, said Oil Change International‟s executive director, Stephen Kretzmann. The Washington-based group opposes the use of more fossil fuels. According to Consumer Energy Alliance‟s executive vice president, Michael Whatley, more rail accidents can

be expected with the greater use of trains to carry oil to market. “Trains need to be a supplement, not a replacement” for pipelines, Whatley was quoted on January 1 by Bloomberg as saying. While both forms of transportation are safe, in that there are very few incidents relative to the amount of crude they transport, “we need expanded pipeline infrastructure,” he said. Consumer Energy Alliance is an industry-backed group that supports Keystone XL. Record levels of North American oil are now being moved by rail as US crude output has hit its highest level since 1988, driven mainly by shale formations in Texas and North Dakota. Canadian production – primarily from Alberta‟s oil sands, is also on the rise. At the same time, plans for new pipelines have stalled and existing infrastructure has struggled to keep up with surging output. The recent accident will intensify scrutiny of the safety and environmental risks that are involved in rail transportation, and will likely renew questioning of whether pipelines may be a safer shipping method. Some believe that the accident may yet play out in favour of the proposed US$5.4 billion Keystone XL, which would run from Canada to the US Gulf Coast. The pipeline would primarily carry oil sands crude, but it would also receive about 100,000 barrels per day of light oil from the Bakken formation in Montana and North Dakota.

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NorthAmOil US President Barack Obama is expected to rule definitively on the 1,179-mile (1,897-km) pipeline within the next few months, when the US Department of State (DoS) will have completed work on a report that will weigh up the project‟s environmental impacts. Pipelines vs trains A growing part of the Keystone XL debate has been on the relative safety of pipelines versus trains. The evidence to date has not proved conclusive, with some suggesting that oil pipelines are generally safer, with pipeline accidents having resulted in fewer injuries, but that they have a higher risk of leaks and spills than trains. Meanwhile, in March 2013, a draft supplemental environmental impact statement released by the DoS indicated that while derailments probably would release less oil than a pipeline rupture, trains have an “increased statistical likelihood of spills”. Opponents of Keystone XL have pointed to pipeline spills that have recently occurred in Alabama, Michigan and North Dakota, citing the risk involved in major projects in particular. Further concern has been caused by the fact that two pipelines carrying oil sands crude from Canada have ruptured in recent years. Train accidents have also been prominent, though. A train carrying oil to the Gulf Coast from North Dakota derailed in Alabama in November 2013, triggering fires. A month earlier, residents were evacuated from a rural area of Alberta after 13 rail tankers, four of which were carrying crude, derailed and also ignited. The worst accident occurred in July, when a runaway train transporting crude exploded and killed 47 people in the Quebec town of LacMegantic. In addition, following the recent crash in North Dakota, a CN train carrying crude and LPG was reported to have derailed in New Brunswick in early January, resulting in a fire and the evacuation of 150 people nearby. Pipelines have an additional advantage in that they generally cross more sparsely populated regions, whereas there are

more rail lines going through more populated areas. Costs are also a factor for companies. It currently costs about US$7 to transport a barrel of oil from Alberta to the US Gulf Coast by pipeline. This is slower than if the oil were transported by rail, but is also cheaper, with rail transportation costing between around two to four times as much. Developers of several major North American pipelines awaiting approval decisions will be watching the unfolding debate with keen interest. As well as Keystone XL, notable projects include Enbridge‟s C$6 billion (US$5.5 billion) Northern Gateway and its Line 9B reversal, TransCanada‟s C$12 billion (US$11 billion) Energy East project and Kinder Morgan‟s Trans Mountain expansion. North Dakota relies on both methods to transport its crude, as the growth of output from this remote area has outstripped pipeline capacity. The state produced nearly 950,000 bpd of oil in October. Roughly 700,000 bpd of this was reportedly shipped by rail, most of it consisting of the light, sweet Bakken crude that safety officials are now saying could be particularly flammable, because of its high propane and butane content. Almost 2,500 miles (4,023 km) of new pipelines were also built in North Dakota in 2012, and the state has been encouraging midstream operators to expand the network to keep pace with record production in the oil patch. North Dakota now has about 17,500 miles (28,164 km) of pipelines. However in September, a Tesoro pipeline ruptured and spilled 20,000 barrels of crude at a remote rural site in northwest North Dakota, which is the US‟ largest oilproducing state behind Texas. This led to

“Even people within the oil and gas industry that I’ve talked to feel that sometimes we’re just going too fast and too hard”

the revelation that North Dakota had recorded almost 300 small oil spills in under two years but that these had gone unreported to the public. New approach? Although rising output has driven North Dakota‟s unemployment rate down to the lowest in the US, calls for a slowdown in the state‟s oil production have been voiced in some quarters. The chairman of North Dakota‟s Republican Party, Robert Harms, who is also an energy industry consultant, told Reuters on January 2 that a “moderated approach” was required. “Even people within the oil and gas industry that I‟ve talked to feel that sometimes we‟re just going too fast and too hard,” said Harms. Surging output is forecast to propel the US past Saudi Arabia as the world‟s largest oil supplier in 2015, and there are many doubts over whether the safety debate will ultimately hold back the rise of crude by rail, in which shipments have soared from less than 5,000 tanker loads in 2006 to an estimated 400,000 in 2013. Petroleum products were the fastestgrowing category of rail shipments in 2013, the Association of American Railroads (AAR) said in a recent report. This indicated that the volume of shipments rose 31% last year, while overall traffic rose 1.8%. The topic of rail safety will not go away. Regulators are actively seeking public input on proposed updates to old crude-by-rail rules covering tanker toughness and other standards. However, the commercial pressures are immense. Against the slow pace of pipeline approvals, the dynamic crude-by-rail market looks set to keep growing, as shown by the number of crude producers and coastal refiners that have committed to multi-year contracts to transport Bakken crude by rail. Indeed, a reported manufacturing backlog of about 60,000 oil tankers is slated for delivery by 2015, which makes it inevitable that further accidents will occur as North America‟s hydrocarbons industry continues its learning curve.

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REM

Phase-shifting the blame in Central Europe The Czech Republic and Germany have agreed to install phase-shifters to regulate transmission, but this may be ignoring a wider problem – the lack of a single EU market By Mike Scott  Both Poland and the Czech Republic are to control their cross-border transmission from Germany  However, with a true single market, electricity tariffs could be lower and savings passed to consumers  This market would require better investment in transmission and infrastructure, slated for 2016 onwards Germany‟s attempts to increase its renewable energy capacity massively have thrown up another illustration of the uneven pace of development. The European leader in renewable energy capacity and its neighbour, the Czech Republic, are to regulate power flows across their borders so that surges in the amount of German clean energy do not overload the Czech grid and increase the risk of power cuts. A similar deal is likely to be signed between Germany and Poland later this year. Prague and Berlin have agreed to install phase-shifting transformers along their border with the aim of making power trading between the two countries smoother and boosting the security of supply in the Czech Republic. The transformers are an unforeseen result of the massive expansion of wind energy assets in the north of Germany – where the country‟s best wind resources are located – and the need to transport that power to the main centres of population and demand in the industrial south of the country.

Schwerin in the east of the country and Hamburg was opened in 2013 but only after years of delays, and any further upgrades will be similarly slow to emerge. Eventually, a new link from Thuringia in the east of Germany to Bavaria will solve the capacity problems, but the 250 million euro (US$342 million) link is not expected to come on line for another two to four years. The result is that if Germany wants to transmit renewable power to Bavaria, it sends it via its eastern neighbours, which distorts their ability to trade power with other countries and threatens to overload their grids. Both Poland and the Czech Republic have threatened to shut down their links to Germany when it is very windy, typically in the latter part of the year. The Czech Republic‟s position at the heart of Europe means it has five

Interconnection While a large amount of generating capacity has been built – in November last year, some 60% of demand was being met by renewable sources at certain times – Germany‟s grid infrastructure has not kept pace. A new power line between

interconnections that make it a natural transit point for power trading in the region. CEPS, the Czech transmission system operator (TSO), explains: “Electricity flows along the path of least resistance, consequently, a significant proportion (up to 50%) of electricity exports from Germany to Austria flows through Poland and the Czech Republic since this path offers less resistance than a more direct path through the internal German network.” The result is that these surges of mainly wind-derived electricity make balancing power in the Czech grid difficult, although not impossible. CEPS says: “The installation of the phase shifters will significantly improve control of unplanned flows on the interconnector.” While the immediate cause of the problem is the lack of internal transmission infrastructure in Germany, it is not helped by infrastructural weaknesses in its neighbours and it illustrates the inefficiencies thrown up by Europe‟s lack of a single electricity market. Market rates If there were a (true) single market, then Germany‟s cheap wind energy would be bought by its neighbours when it was available, reducing prices for consumers as well as helping to decarbonise the system overall.

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REM However, because power markets remain defined by national borders, consumers are losing out on such substantial efficiencies and economies of scale. As it is, national power companies have incentives to stop cheap power from neighbouring countries reaching consumers because it reduces the profitability of their own generating capacity. The EU is aiming for the single energy market to be completed in 2014, but it seems a forlorn hope. EU member states‟ energy systems are characterised by a range of different market mechanisms, regulatory and tax regimes and technology mixes. Finally, national politicians guard their countries‟ energy independence jealously. So even though, as the Agency for the Co-operation of Energy Regulators said recently, delays to the single market for electricity are costing consumers billions

of euros, many providers are in no hurry to make it a reality. According to the chair of ACER‟s board of regulators, Lord Mogg, “The advantages brought about by the single market, such as lower wholesale electricity prices or a more efficient use of interconnectors identified in the study, still have fully to benefit final consumers in the retail market.” Yet a single energy market will be vital for markets looking to exploit their renewable resources fully, such as Scotland, Portugal, Ireland and Romania, which will be able to produce far more energy than they consume – but will only benefit from this if they have someone to sell the energy to. Northern Europe Some progress is being made, particularly in Northern Europe, where the UK has interconnectors in place with

Ireland, France and the Netherlands, with plans under way for a link with Norway – which is also strengthening links with Denmark and Germany. Norway, with its abundant fastreacting hydropower capacity, could play a crucial role in integrating the wind resources of the North Sea into a Europewide system by acting as a kind of battery for Europe – providing stand-by power to compensate for fluctuations in the contribution of variable renewable energy. At the moment, though, the focus appears to be on mollifying incumbent producers rather than on securing cheaper power for consumers. Placing the blame on “unreliable” German wind energy shifts blame, rather than addressing the wider problems of the market – to the detriment of further renewables development.

Unconventional OGM

China makes shale progress China‟s shale gas production reached 200 million cubic metres last year and there are signs of increasing optimism over the unconventional sector, despite some challenges By Nnamdi Anyadike  China has the world's largest shale reserves and ambitious targets, but development has been slow  Obstacles include challenging geology and a lack of pipeline infrastructure  Beijing is stepping up efforts to encourage shale development Chinese shale gas production witnessed a surge in 2013, climbing five-fold to 200 million cubic metres, according to China‟s Ministry of Land and Resources. The government has pledged to spur the shale industry‟s development and meet rising gas demand by prioritising land approvals, allowing tax-free imports of equipment and offering subsidies to explorers. National Energy Administration (NEA) deputy head, Zhang Yuqing, said: “We will continue to work closely with other departments to reduce problems regarding government policies and other

regulations reflected in the development of shale gas, and create a better environment for shale gas producers.” Beijing has set an ambitious target of boosting the country‟s shale gas output to 6.5 billion cubic metres per year by 2015. The Five-Year Plan, which runs from 2011 to 2015, includes not just exploration and production but also transportation and infrastructure, which China is currently struggling with. The pipeline network is widely acknowledged to be insufficient to transport such huge quantities of gas and the country‟s terrain makes it even more

difficult to lay any pipelines. This, says a report released by Kuick Research, will require huge levels of investment in the future. Another problem is the lack of water supply, as hydraulic fracturing requires large amounts of water. Vast resources Beijing is confident, though, that it will achieve its shale goals. Kuick describes the country as “basking in the glory of its recent world‟s largest shale finds.”

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Unconventional OGM The US Energy Information Administration (EIA) reduced its estimate of Chinese technically recoverable shale reserves from 1.275 quadrillion cubic feet (36.1 trillion cubic metres) to 1.115 qcf (31.6 tcm) of of gas, but China nonetheless remains the largest holder of shale resources globally. China‟s enormous shale gas resources have been mainly found in the Sichuan and Tarim Basins, but other shale deposits are also scattered all over the country. Generally, however, the reserves can be divided into four regions – North China, South China, Northwestern and Northeastern China. The exploration of shale gas in China is still in its infancy and concerns were expressed last year over the pace at which development was proceeding, amid speculation that the country would fail to meet its 2015 production target. However, exploration is picking speed and Royal Dutch Shell recently announced that the exploratory results in the Sichuan Basin were satisfying. Sinopec, the country‟s largest refiner, has set a target of 3.2 bcm in 2015 for its shale gas project in the ChongqingFuling area, which is almost double its previous target. Slow progress There are still concerns, though, that government targets may be hard to reach, as development thus far, despite last year‟s progress, has been slow. A National Development and Reform Commission (NDRC) researcher, Zhang Yousheng, recently raised doubts as to whether the goals could be achieved – much of which rest on domestic companies PetroChina and Sinopec. A recent analysis by Forbes was also pessimistic, saying that the shale gas revolution would “not be coming to China anytime soon.” The report draws

development. Gas use in China is anticipated to double between 2010 and 2015 to 230 bcm and domestic output is growing slowly, which means more imports are required, predominantly from Central Asia and Russia. “Judicious investment in shale gas might change the balance,” said Forbes, although it added that there would likely emerge a gap between China‟s desire for cleaner-burning fuels and its ability to source them.

on US Secretary of Energy Ernest Moniz‟s visit to China at the end of 2013, where he met government officials and oil industry executives. Moniz pointed to China‟s “above-ground issues” with bringing gas to market, which mean that the country lags behind the US. “It‟s often forgotten that in the US not only did we have obviously a favourable geology for producing these resources, but we also had by far the most mature natural gas infrastructure in terms of pipelines, market structures, trading hubs, futures contracts, regulation of production, etc.,” he said. For China to develop its resources “at a large scale and in a rapid fashion”, he said, it must tackle these issues. Unlike in the US, where independent producers drove the shale revolution, taking on risks that oil majors declined, in China the three giant state-run oil and gas companies have monopoly power and developers with North American shale expertise can only enter the sector through partnerships with them. Although China has set ambitious targets for natural gas production, the above-ground framework – including regulations on how much cities will pay to gas suppliers – still needs to be adjusted to account for shale

Growing interest Nevertheless, China‟s shale prospects are sufficiently appealing to invite foreign companies to take a look at what is on offer. In early January, the Financial Times reported on the Scotland-based Weir Group – a leading manufacturer of pumps used for fracking. Weir‟s CEO, Keith Cochrane, told the paper: “It‟s going to be a long time before China reaches the US level. But there‟s no question they are serious.” It is thought that as development takes off, China could become a sizable market for companies such as Weir. Other international oil firms including ExxonMobil, Chevron, ConocoPhillips, Shell, Total and Eni have already entered into agreements to explore China‟s shale resources. Services firms, such as Schlumberger, Halliburton, Baker Hughes and Weatherford, have also increased their presence in China. The rest of the world has been warned not to underestimate China‟s determination to launch its shale gas sector. Beijing has been said to be fully aware of the challenges involved, and is taking steps to solve them. China‟s political will is expected to help accelerate development despite the obstacles the shale sector is facing.

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January 2014, Issue 46

Back Page

NEWSBASE INFORMATION HEADLINES FROM A SELECTION OF NEWSBASE MONITORS THIS WEEK

CUSTOMERS INCLUDE

Oil and Gas Sector

AfrOil Vanoil appears set to lose its Kenyan licences after failing to satisfy its contractual commitments.

AsianOil Myanmar may award 30 offshore licences this month.

ChinaOil PetroChina plans to invest US$250 million in drilling up to 30 shale gas wells in Sichuan this year.

FSU OGM Gazprom is reportedly close to a deal with Greece's DEPA on gas price cuts.

GLNG Japan’s Toho Gas has signed a deal to take 300,000 tonnes per year of LNG from the Cameron LNG project.

LatAmOil Malaysia’s Petronas is considering investment in Argentina’s Vaca Muerta shale play.

MEOG Aramco expects to begin the prequalification process for EPC contracts for its Khurais field expansion in mid-2014.

NorthAmOil XTO Energy has struck two separate deals in the Utica shale and Permian Basin.

Unconventional OGM Suncor Energy has reportedly suspended its plans to develop its Montney shale acreage in British Columbia.

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