2015 asia energy outlook

October 2014www.platts.com

NEW TARGETS FOR JAPANS REFINERSNew government regulations once again push Japanese refiners to make decisions on CDU capacity cuts

THE ROAD AHEAD FOR INDIA, INDONESIA WITH NEW LEADERS India and Indonesia embark on a journey on policy reform for E&P, oil subsidies and deregulation with their promising new leaders

2015 ASIA ENERGY OUTLOOK

BEIJING TIGHTENS OIL TAX NOOSE, BUT WILL WILY PLAYERS ESCAPE AGAIN?Beijing is relentlessly plotting to develop a foolproof oil tax regime, but will devious market players keep finding ways to outsmart the system?

ASIA POWERS UP2014 Platts Top 250 Global Energy Company Rankings

OCTOBER 2014 insight iii

CONTENTSinsight

1

4 REFINERS NEW TARGETSSeven months on, new government regulations once again push Japanese refiners to make decisions on CDU capacity reductions, after end-March cuts.

10 PNG LNG ARRIVESThe start-up of the ExxonMobil-operated Papua New Guinea LNG project ahead of schedule in April this year cemented the small Pacific nations position as a global gas producer, and there is more to come.

14 US, AFRICA LPG IN ASIAAsia is absorbing an increased flow of LPG from the US, West and North Africa, intensifying the competition faced by Mideast producers.

20 INVESTORS ROCKY ROADMyanmar, portrayed as the land of opportunities post-sanctions, starts to reap the benefits of opening its gates to foreign investment, but many challenges remain.

24 HOME AND AWAYEurope shut its doors to Indonesian biodiesel last year after the European Commission hit the Southeast Asian country with stiff anti-dumping duties. But other doors opened at home and in China.

30 ASIAS LOW CV DIETAs the coal-fired generation industry moves toward a lower quality product, it is increasingly frowned upon by those in the related yet more favorably perceived markets like crude oil and shale gas.

34 THE ROAD AHEADIndia and Indonesia embark on a journey of policy reform for E&P, oil subsidies and deregulation with their promising new leaders Modi and Jokowi.

38 BEIJING TIGHTENS THE NOOSEBeijing is relentlessly plotting to develop a foolproof oil tax regime, but will devious market players keep finding ways to outsmart the system?

46 SMOOTH SAILINGShipowners in the dirty tanker segment look forward to smooth sailing next year with the scrapping of aged vessels, lighter order books and more pooling of vessels.

50 THE PHILIPPINES ON THE RISEThe Philippines must transform good energy policies into a sustainable reality. From Asian Development Bank.

52 ASIA POWERS UPGlobal energy shake-up sees shale winners rival Asian energy growth. Platts Top 250 Global Energy Company Rankings reviewed.

insight

insight OCTOBER 2014

October 2014

2

EDITORS NOTEJust before I penned the editors note, one of my colleagues

asked me what was the main theme running through these articles, and of course, my initial answer was China and her response was Not again!

Well, I guess there is no running away from China continuing to be the main star on the energy stage. But, has China lived up to its promise or are we a bit disappointed as a slowdown in the countrys economic growth hits demand for all commodities?

Coming back to what the theme should be! Politics, Policies and Prices I thought these would more or less cover it all. Th e second half of 2014 was initially dominated by geopolitical tensions with unrest in Iraq pushing Brent crude above $115/b in June. Geopolitical tensions in the Middle East and North Africa had everyone sitting on the edge of their seats. But where are we now? Prices have slipped below $90/b! How have these price swings impacted Asia?

Policy changes triggered by the need for reform in Asias energy sector are infl uencing the scene in Indonesia, India, Japan and China. Myanmar follows closely behind as it starts to lay out its policy map to woo investors, but the challenges are plenty.

India and Indonesia promise to be very exciting following the unveiling of new leaders with humble backgrounds Modi, a former tea-seller, and Jokowi, a former carpenter. Th ere are high expectations of them to introduce reforms that would save these countries from their dire energy situation. Indonesias biodiesel is also in the focus with a shift in demand centers.

Whats interesting here is that even though the global shift is toward renewables and environmentally friendly resources, coal is still king in Asia.

Meanwhile, China is taking the countrys massive web of taxes by the horns, and trying to foolproof its tax regime against corruption.

In the Land of the Rising Sun, refi ners face the deadline of October 31 to respond to new regulations on proposed CDU capacity cuts will Japan become a net oil products importer?

On LPG, the petrochemical industry in Asia is drawing barrels from the US and Africa, intensifying competition faced by Middle East producers.

Th e props have now been set, so all eyes would be on the impact of these political, policy and price changes in Asia some of those Id look out for would be shifts in the subsidy burden, deregulation, capacity cuts and changes in importer/exporter status.

Geetha Narayanasamy, Editor

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JAPAN

Seven months on, new government regulations have once again pushed Japanese refi ners to make decisions on capacity cuts on crude distillation units, just after they slashed capacity to 3.95 million b/d at the end of March. Th ese refi ners face a deadline on October 31 to respond to the new regulations on proposed capacity cuts, which is expected to boost effi ciency and competitiveness among them, while triggering a heavier fl ow of oil product imports, especially during turnarounds.

Japans total refi ning capacity at the end of March tumbled 12% year on year, and slid 19% from a 10-year peak of 4.89 million b/d in early April 2008, as a result of local refi ners axing capacity to meet METIs previous regulations.

On July 31, Japans Ministry of Economy, Trade and Industry implemented new regulations that could result in trimming the countrys installed refi ning capacity to around 3.55 million b/d by the end of March 2017.

Th e expected reduction under the new regulation amounts to about 400,000 b/d, or 10%, of the current installed capacity of 3.95 million b/d, if local refi ners proceed with further cuts in the capacity of crude distillation units, according to a ministry source.

Similar to the previous policy for refi ners, the new regulation sets fi nes of up to Yen 1 million ($9,168) for companies that fail to meet the requirements.

But these fi nes are seen as minor compared with the heavy investments

REFINERSNEW TARGETS

TAKEO KUMAGAISenior EditorAsia Oil News

Courtesy: Petroleum Association of Japan

TonenGenerals Kawasaki re nery.

5OCTOBER 2014 insight

JAPAN

and costs of scrapping facilities to meet the new regulations. Th e thinking within the government is that companies will try to meet the new targets rather than to be seen to be violating them.

Th e ministry presented a draft of the new regulations at its oil and natural gas subcommittee meeting on June 30, and closed a public comment period on July 15.

New residual cracking capacity targetUnder the new regulation, Japanese refi ners are expected to boost their residue cracking capacity to 50% by the end of March 2017, compared with 45% on March 31, under a revised defi nition of the capacity.

Th e revision counts the capacity of units such as fl uid catalytic crackers, residue direct-desulfurizers and solvent deasphalting units, in addition to those that made the list previously cokers, residue fl uid catalytic crackers and residue hydrocrackers for residual cracking capacity of local refi ners.

Unlike the previous regulations, which required refi ners to close CDUs or install certain residual cracking units, the new policy would consider taking into account reductions in nameplate CDU capacity, as well as more effi cient use of residue at adjacent refi neries by building new pipelines.

In addition, METI is to consider refi ners eff orts to build new condensate splitters to produce petrochemicals, as well as their overall business restructuring plans in assessing their effi cient use of feedstock.

To meet the new regulations, local refi ners would be expected to make certain physical cuts on their CDU capacities in the face of diminishing domestic demand over ineffi cient and uneconomical options, such as trimming their nameplate capacities and building new cracking units, according to industry sources.

Under the new 50% residue cracking target, individual Japanese refi ners would have varying improvement goals, depending on capacity and based on the revised March 31 defi nitions of residue cracking capacity.

Residual capacity target for each refi ner variesBy March 31, 2017, Japanese refi ners with residue cracking capacity of less than 45%, 45%-55% and more than 55% as of March 31 this year would be required to show improvements of more than 13%, 11% and 9%, respectively, according to the regulatory targets.

Under these new targets, refi ners JX Nippon Oil & Energy, Cosmo Oil,

CHANGES IN JAPANS REFINING CAPACITY

Permanent closure

Re nery Owner Unit Capacity (b/d) Effective

Tokuyama Idemitsu Kosan Entire 120,000 Mar 31, 2014Muroran JX Nippon Oil & Energy Entire 180,000 Mar 31, 2014Kawasaki TonenGeneral No. 1 CDU 67,000 Mar 31, 2014Wakayama TonenGeneral No. 2 CDU 38,000 Mar 31, 2014

Capacity change

Re nery Owner New capacity (b/d) Effective

Hokkaido Idemitsu Kosan 160,000 Mar 31, 2014Aichi Idemitsu Kosan 175,000 Mar 31, 2014Yokkaichi Cosmo Oil 112,000 Mar 31, 2014Ichihara Kyokuto Petroleum Industries 152,000 Mar 31, 2014Kikuma Taiyo Oil 118,000 Mar 31, 2014

Source: Company reports


JAPAN

TonenGeneral and Taiyo Oil would likely be required to boost their residual cracking capacities by 13% from their current capacities of less than 45%, according to an industry calculation obtained by Platts.

Refi ners Idemitsu Kosan, Fuji Oil and Showa Shell are expected to improve their residual cracking capacities by 11%, 11% and 9%, respectively, from their current residual cracking capacities of 49%, 48% and 57%, according to the calculation provided by an industry analyst who declined to be named.

Th e METI regulation counts JX as having an installed capacity of 1.426 million b/d, comprising 1.212 million b/d of its offi cial refi ning capacity, the 115,000 b/d Osaka export refi nery jointly operated with PetroChina International (Japan) as well as a 63,500 b/d Kashima condensate splitter and a 35,000 b/d Mizushima-B condensate splitter.

JX put its own offi cial refi ning capacity at 1.212 million b/d, which excludes the Osaka refi nery and the Kashima and Mizushima-B condensate splitters.

Taiyo Oil which was exempt from the previous round of cuts because it operates a single refi nery a 118,000 b/d plant on Shikoku island might also escape the new regulation after submitting its response plan to METI, sources said.

Th e same exemption might also apply to Fuji Oil, which operates its sole 143,000 b/d Sodegaura refi nery in Tokyo Bay. Nansei Sekiyu, which was exempt from the previous regulation for its annual crude processing volume of less than 3 million kl, or 52,000 b/d, at its sole 100,000 b/d Nishihara refi nery in Okinawa, could also be exempted from the new regulations as it also operates a single refi nery, sources said.

Japan may fl ip into net oil products importer during turnaroundsIndustry sources said it remains unclear how Japans supply and demand balance will shake out after the latest round of capacity cuts. However, what the Japanese downstream sector has witnessed so far is that there were year-on-year increases in oil products imports, coupled with improvements in light oil products margins over April-June.

A local industry analyst said South Korean suppliers have been seeking opportunities to sell oil products to the Japanese market after the series of recent refi ning capacity cuts.

In the wake of the latest capacity reduction, Japan turned into a net importer of gasoline over May-June during the countrys fi rst peak refi nery turnaround season following hefty cuts in capacity at the end of March.

Source: Petroleum Association of Japan and company reports

0

1000000

2000000

3000000

4000000

5000000

End-March 2014End-March 2013End-March 2012End-March 2011End-March 2010

JAPANS INSTALLED CAPACITY

B/D


JAPAN

Gross gasoline imports by refi ners and importers averaged 43,842 b/d over May-June, against average gross exports of 21,191 b/d, an analysis of METI data showed.

Japans gasoline imports in May-June had more than doubled from 19,245 b/d in the same period last year, while exports were down 6% from 22,538 b/d a year ago.

Japan had fl ipped back into a regular net gasoline exporter in November 2013, after turning net importer in the aftermath of the devastating earthquake and tsunami in March 2011.

Domestic gasoline demand, meanwhile, inched lower by 2.5% year on year to average 897,609 b/d over May-June, implying the steep hike in imports was to off set sharp cuts in domestic production ahead of seasonally higher summer demand. Japan produced 825,457 b/d of gasoline over May-June, down 7.5% from 892,630 b/d in the same period last year.

Th e sharp fall in gasoline output and ensuing imports were due to a heavy turnaround season, which saw at least 915,000 b/d of the countrys crude refi ning capacity taken offl ine in May and 1.2 million b/d in June, accounting for 23-30% of total capacity, according to Platts calculations.

Japan was also net oil products importer over April-June, with average gross imports at 553,169 b/d, up 4.2% from a year ago, against exports of 442,987 b/d.

Th is was led by a steep year-on-year drop of 20.1% in its oil product exports during the quarter, compared with a

mere rise of 4.2% in its petroleum product imports.

During Q2 this year, Japans overall gasoline imports surged 47% year on year to 31,999 b/d, while gasoil imports came in at 7,626 b/d in the quarter, up more than four times from 1,745 b/d a year ago.

Imports of fuel oil have also grown 8.4% year on year to 84,398 b/d in Q2, as a result of the capacity cuts and as refi ners opted to import low sulfur fuel oil for thermal power generation amid nuclear outages, rather than produce the product.

Th e heavy cut in refi ning throughput in Q2 2014 also saw major middle distillates exporter Japan slash exports of the straight-run products.

Exports of gasoil over April-June plunged 41.4% year on year to 116,277 b/d, while jet fuel exports edged down 7.9% to 190,935 b/d.

A local industry analyst said Japans steep hike in gasoline imports and sharp drop in gasoil exports were consequences of Japans recent cut in its installed refi ning capacity, which he said was excessive when considering domestic needs, especially during the countrys turnaround season.

Th e countrys refi ning throughput had plunged to multi-year lows in May and June at the peak of the spring turnaround season.

Japan refi ned 2.62 million b/d of crude in June, down 16.8% from 3.15 million b/d a year ago, and the lowest for the month since 2.5 million b/d in June 1989.


JAPAN

Th e June crude throughput fi gure was 11.2% lower than the 2.95 million b/d in May, which was the lowest for that month since 2.89 million b/d in May 2011 after the devastating March earthquake and refi nery outages.

Japans total oil demand averaged 2.83 million b/d in Q2 2014, down 4.4% from the same quarter last year.

Looking forward, Japan long known as a major exporter of oil products in Asia is expected to remain a regular importer of oil products, at least in the short term as domestic suppliers re-balance their output and imports after the capacity cuts.

Given falling domestic oil demand, supply might still exceed demand if local refi ners opt to cut total capacity to 3.55 million b/d by the end of March 2017, industry sources said.

On the fl ip side, domestic output might fall short of demand, especially during the countrys refi nery turnaround seasons of May-June and October-November, which could increase Japans requirement for oil products imports, industry sources said.

Margins improve after capacity cutsJapans refi ning margins improved over April-June from last year due to a combination of capacity cuts, heavy turnarounds and changes to several refi ners weekly wholesale oil products pricing systems.

Over April-June, several refi ners in Japan adopted new pricing systems based on crude costs for their weekly changes to wholesale oil products prices, rather than

heavily relying on domestic oil product benchmarks.

Th e pricing changes diff er among Cosmo Oil, Showa Shell and JX, which adopted new systems in April, May and June, respectively, according to the sources and company offi cials.

Th e wholesale pricing systems apply to weekly changes in wholesale prices of gasoline, kerosene, gasoil and A-fuel oil, a blend of gasoil and fuel oil in a 90:10 ratio.

Although exact details of refi ners new pricing mechanisms remain unclear, numerous industry sources echoed that they refl ect to a larger degree recent movements of international crude benchmarks such as Dubai, rather than being indexed to domestic oil product benchmarks.

Looking at overseas opportunitiesWhile trimming refi ning capacities in Japan in the face of shrinking domestic demand, several Japanese companies are eying refi ning or oil products business opportunities overseas.

Th e new president of JX Nippon Oil & Energy over the next two years plans to explore refi ning-to-retail opportunities in Indonesia and Vietnam while optimizing output and oil products trading amid contracting domestic demand.

We are aware that Indonesia is short of petroleum, and we have heard that there are plans for refi nery expansions as well as building new ones, Tsutomu Sugimori said in an interview with Platts in July.


JAPAN

Th e company has begun exploring integrated business opportunities ranging from building a refi nery to selling at service stations in Indonesia, said Sugimori, who took the helm on June 26.

In July, Japans Mitsubishi also said it will start gasoil imports, sales and distribution businesses in Australia by the April-June quarter of 2016, after completing a new gasoil import terminal at Port Bonython in South Australia.

Mitsubishi will be the fi rst Japanese company to own and operate an oil import terminal in Australia, where it intends to initially supply gasoil mainly to industrial users in the mining sector, a company offi cial said then.

Mitsubishi has an import capacity of 900,000 kiloliters (5.66 million barrels)/year of gasoil at the Port Bonython terminal, with three storage tanks with a capacity of 27,000 kl, or 169,825 barrels, each.

Australia is becoming increasingly reliant on imported transport fuels due to the closure of two of the countrys remaining six refi neries over the coming year.

JXs Sugimori also said that Japans largest refi ner could also be looking at Australia as a potential market to sell into.

In December 2012, Japanese refi ner Idemitsu Kosan acquired Australias Freedom Energy, which has put Idemitsu in a position to potentially directly move oil products to Australia for gasoil and gasoline sales in the eastern states of Queensland, New South Wales and Victoria, possibly by securing supply in

Singapore rather than by shipping from its refi neries in Japan.

Looking further ahead, Nobuo Tanaka, former executive director of the International Energy Agency, called for a change in Japans long standing post-war policy for refi ning and consuming, in the face of diminishing domestic demand.

Th e Japanese refi ning sector needs an alternative business model to the refi ning and consuming policy, said Tanaka, now a special adviser and global associate for energy security and sustainability at the Institute of Energy Economics, Japan.

Th e alternative business model can be entering refi ning or oil products businesses in growing markets, while another option can be participating in the refi ning sector in countries with aff ordable feedstock such as in the US or the Middle East, and bringing back oil products to Japan whenever necessary, he said in an interview with Platts.

Courtesy: Petroleum Association of Japan

JX Nippon Oil & Energys Kiire oil terminal.


PAPUA NEW GUINEA LNG

Th e start-up of the ExxonMobil-operated Papua New Guinea LNG project ahead of schedule in April this year cemented the small Pacifi c nations arrival as a global gas producer, and the signs are increasingly positive that there is more to come.

PNG enjoyed its tenth straight year of economic expansion in 2012, when real gross domestic product rose by 8.1%, according to fi gures from the Australian government. Growth slowed to an estimated 4.6% in 2013 and is forecast to be 6% in 2014.

But with the PNG LNG project now online, the country is poised for unprecedented growth. At a price tag of $19 billion, the project represents the biggest investment in the countrys history.

According to the 2014 CIA World Factbook, the massive gas development has the potential to double PNGs GDP in the near-term and triple its export revenue from the $5.6 billion recorded in 2012. It will boost government coff ers, generate local employment

opportunities and royalty payments to landowners, and provide infrastructure which could spur further industry development.

Natural resources already dominate PNGs export mix, headed by oil, gold and copper. ExxonMobils project adds to this list export capacity of 6.9 million mt/year of LNG from two production trains at the liquefaction facilities near Port Moresby.

ExxonMobil holds a 33.2% operating stake in PNG LNG. Its joint venture partners are PNG-based Oil Search (29%), the governments National Petroleum Company of PNG (16.8%), Australias Santos (13.5%), Japans JX Nippon Oil & Gas Exploration (4.7%) and local landowner company MRDC (2.8%).

Th e project is an integrated development that includes gas production and processing facilities in PNGs Southern Highlands, Hela, Western, Gulf and Central provinces. More than 700 km (434 miles) of pipelines connect the project facilities, including a gas

PNGLNG

ARRIVES

CHRISTINE FORSTERSenior WriterAsia Oil News



conditioning plant in Hides and the liquefaction and storage infrastructure on the coast.

Th e LNG plant began producing in April and delivered its fi rst cargo in May, well ahead of the scheduled October start date. By the end of June, the project had loaded seven LNG cargoes, all of which were sold on the spot market.

Around 95% of the projects LNG capacity is covered by long-term contracts, set to begin later in 2014. Th e projects term customers are Chinas Sinopec, Tepco and Osaka Gas from Japan, and Taiwan-based CPC.

Th e project partners have been focused on ramping up operations to full capacity. With that now achieved, they are already eyeing the potential to add a third LNG production train at their liquefaction facilities.

Th e joint venture is looking to expand the reserves base in the projects Hides fi eld and will drill the Hides Deep prospect late this year or early next year, searching for gas to underpin a third train. In addition, plans are being progressed for the submission of a development licence for the nearby Pnyang gas fi eld, which Oil Search has fl agged as a potential expansion resource.

Oil Search is listed in Australia but is PNG-focused and is the operator of all of the countrys existing crude oil production. It is also one of the main players behind what analysts are now tipping will be PNGs second LNG project, the Elk/Antelope development.

Th e Elk/Antelope project has a long and at times controversial history. Th e fi eld is operated by US-listed InterOil which, in years gone by, has been at odds with

Courtesy: ExxonMobil

Vessel loading at the PNG LNG facility.



the PNG government over how best to develop the resource.

Under the terms of InterOils 2009 project agreement with PNG, Elk/Antelope was to be developed to deliver a 7.6 million-10.6 million mt/year LNG project, using internationally recognized technology and operators. InterOil subsequently earned rebukes from senior government offi cials over its plans to develop a smaller, staged LNG project with a number of joint venture partners, none of which Port Moresby deemed met its requirement for international project operating experience.

In response, InterOil opened negotiations over the sale of a stake in the project with the three industry heavyweights ExxonMobil, Shell and Total who were on the ground looking for opportunities in PNG. In December 2013, an initial deal was unveiled with Total, then reworked and fi nally agreed in March this year.

Th e eventual acquisition by Total came just after Oil Search bought into the project, via a takeover of one of InterOils joint venture partners, Pacifi c LNG Group Companies. Pacifi c LNG, an affi liate of Clarion Finanz, held a 22.8% stake in Elk/Antelope.

Oil Search has since claimed that this acquisition aff orded it pre-emptive rights in relation to the joint venture and has sought arbitration of the dispute. Th e arbitration is expected to be heard in late November and decided in the fi rst quarter of 2015.

Notwithstanding that hiccup, with French major Total and experienced local

operator Oil Search on board, the prospects for a development of Elk/Antelope are looking bright.

Total agreed to pay $401 million for its 40.1% share of the project, reducing InterOils stake to 36.5%. Th e remaining equity is held by minorities.

Under the terms of its acquisition, Total will make further payments dependent on the size of the gas resource which is certifi ed, at a fi nal investment decision on a development, and again at the shipment of the fi rst LNG cargo.

Should the resource be determined at 7.1 Tcf of gas, the certifi cation payment would be $580 million, taking the total return to InterOil, including all other contingent payments, to $1.62 billion. InterOils eventual pay-out could rise to as much as $3.5 billion, should the resource turn out to be as big as 11.8 Tcf.

According to Oil Search, the key objective of drilling at Elk/Antelope over the next six months is to narrow the contingent resource range and determine whether the fi eld can underpin one or two LNG production trains. In parallel, the joint venture is considering the scope for concept selection phase studies and surveys, which will address viable LNG development options.

Although there is still a long way to go, Oil Search sounds increasingly confi dent that the expansion opportunities at PNG LNG and the development potential of Elk/Antelope will see it involved in two, and possibly three, additional LNG production trains by the end of this decade. Should that occur, PNG will be able to claim its place as a signifi cant player in the global LNG market.

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LPG

Asia is diversifying its sources of LPG and absorbing an increased fl ow from the US, West and North Africa to meet rising levels of demand from Chinese and North Asian petrochemical industries.

Th is is intensifying the competition faced by Middle Eastern producers Qatar, the United Arab Emirates, Saudi Arabia and Kuwait, who could however look forward to rising demand from India, traders and analysts said.

Iranian cargo fl ows to Asia, which resumed in May 2013 after an eight-month hiatus on worries over an EU ban on shipping insurance, have touched levels close to the pre-sanction period and are also fi nding their way to China.

Th e increased Atlantic Basin supplies did not immediately prompt a marked drop in Asian prices till recently, refl ecting equally steady demand so far and due to a shortage of very large gas carriers in the spot market for trading fi rms to move free-on-board cargoes, traders and shipping analysts said.

Th is was unlike the volatility seen over the past three years. However, a supply build-up in the region, moves by some Chinese petrochemical companies to resell cargoes bought for their propane dehydrogenation plants and tepid summer demand, had pushed prices to around 14-month lows in early August.

Prices have since slid to 27-month lows due to the large infl ows, expected soft winter demand and the plunge in crude futures, traders said.

Th e tight vessel supply had driven up global VLGC rates to record peaks twice so far this year and helped shipowners and trading companies with time-chartered tonnage to strengthen their stranglehold on the LPG spot market, traders and shipping sources said. Th e high freight rates have also supported premium levels for cost-and-freight LPG cargoes.

A typical VLGC steaming under ideal conditions can make eight to 10 voyages in a year loading in the Middle East and discharging in the Far East. However, if it is loading in the US Gulf and

US, AFRICA LPGIN

ASIA

MOHD RAMTHAN HUSSAINSenior EditorLPG (Asia Paci c and Middle East)


LPG

discharging in the Far East, it can make three to four voyages, not passing through the Panama Canal, said Kumar Shantanu Bhushan, Lead Research Analyst, Gas Shipping, at shipping consultancy Drewry.

If a vessel loads once in the US for discharge in East Asia and is back to load again after around 90-92 days, this leads to a tight supply situation in the loading region.

Th erefore, a slight mismatch between cargoes available to load and available tonnage can help rates move on either side in a very short span of time, Bhushan said. Both tonnes and miles are increasing, taking tonne-mile demand higher for larger vessels. As a result, freight rates have shot up.

Congestion at ports, such as those in India, have also held up tonnage and tightened vessel supply, he added.

US Gulf Japan (via Cape of Good Hope) 15,600 nautical miles 100 days round voyage 6.4 vessels/million mt LPG

Middle East Japan 6,600 nautical miles 46.5 days round voyage 3.0 vessels/million mt LPG

US Gulf Japan (via Panama Canal) 9,200 nautical miles 65 days round voyage 4.2 vessels/million mt LPG

ROUTES TO JAPAN COMPARED


LPG

US LPG starts to make mark in AsiaOver the past year, fi ve to six LPG cargoes from Houston dominated by propane and totaling some 264,000 mt are shipped each month to Asia, against the odd one to two parcels seen more than a year ago, said traders, brokers and shipping sources polled by Platts.

Around four to fi ve more cargoes are moved each month from West Africa. Algeria is also making more regular shipments to Asia, ranging from none in some months to up to fi ve monthly cargoes, they said. So overall it makes for typically 12 arbitrage cargoes per month coming to Asia, one trader said.

An unprecedentedly high number of 15 cargoes could arrive in Asia from the US, West Africa and Algeria around October/November through early December, which would help end-users stock up for the winter, shipping and trade sources said, adding that these are expected to rise further next year.

Th e number of cargoes from West Africa and Algeria are coming into the

East with some regularity at least during the summer, another trader said.

Trading companies that have concluded term contracts with US exporter Enterprise Products Partners included Japans Astomos, Eneos Globe, Itochu, TonenGeneral, Sumitomo, Iwatani, South Koreas SK Gas and E1 Corp., Geogas, Naftomar, Petredec, Petrobras, Petroecuador, Repsol, Shell, Statoil, Total, Trafi gura, Vitol and Texas Gas and Oil, market sources said.

Among fi rms holding term deals with US-based Targa Resources are Gunvor, Gazprom, Geogas, Petredec, Vilma, Itochu as well as Chinese buyers such as China Soft Package, Everglory and Oriental Energy, market sources said. Th e duration of these contracts ranges between 2013 and up to 2017-2021.

En *Vantage analyst Peter Fasullo recently said the US has terminal capacity to export about 428,000 b/d of natural gas liquids each month, while Energy Information Administration data showed the US shipped 446,000 b/d of propane in May, up from Aprils 414,000 b/d and 308,000 b/d in May last year. Th e US also exported 79,000 b/d of butane in May, versus 75,000 b/d in April and 30,000 b/d in May 2013.

US propane exports are projected to surge 50% over the next two years to 626,000 b/d, while normal butane exports are forecast to jump to 120,000 b/d next year and 146,000 b/d in 2016, according to Market Call: North American NGLs, by Bentek, a unit of McGraw-Hill Financial.

Exports are set to gather steam especially after the projected startup of the Source: EIA, analysts

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US PROPANE SUPPLY/DEMAND BALANCE

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LPG

expanded Panama Canal by mid-2016, which would almost halve the round voyage to Japan.

US exports of NGLs hit a record of 17.2 million barrels in May, up around 2 million barrels above the previous record set in April, the EIA said. Exports were over 7 million barrels higher than the same month last year.

Brazil, Canada, Japan, Mexico and the Netherlands were the biggest importers of US NGLs, getting a total of 9.1 million barrels. Th is was enabled by growing US shale production and the on-track development of NGL export terminals, inland transportation infrastructure as well as processing, piping and fractionating capacity.

Overall, this has made us more confi dent on our current estimates on future export volumes out of the US, Norwegian bank DNB said in a recent report.

It said 2.2 million mt, or 25.6 million barrels, of propane inventory were built-up from March to June 2014 in the US, the largest since 2005. About a third of US exports have now moved to the East, in line with DNBs 2014 estimate of 30%.

Other than Enterprise and Targa, other US exporters include Sunoco and refi ner Phillips 66 which is aiming to raise its total refrigerated LPG handling capacity to 12 million barrels/month, if a plan to build a second natural gas liquids fractionator in Texas gets board approval. Phillips 66 sealed its fi rst long-term propane supply contract in March, with China International United Petroleum & Chemicals Co. Ltd., or Unipec.

Sage Midstream, a privately held US company focused on NGL infrastructure projects, is also eyeing the Asian market with the fourth-quarter 2016 startup of an LPG marine terminal operated by wholly owned unit Haven Energy at Port of Longview, Washington state. Washington on the US West Coast is also the site of the Ferndale terminal, where Japanese refi ner Idemitsu Kosan loaded its fi rst butane cargo for export in early August. Other terminal developments include those by Occidental Chemical and Crosstex Energy.

Th e monthly fl ow of cargoes to Asia from the Atlantic Basin, come on top of the 36 million mt/year from the Middle East in 2014. Middle Eastern LPG fl ows to Asia in 2016 are projected at 37 million mt. US export capacity is forecast to grow to more than 30 million mt/year by 2017 from 13.7 million mt/year of propane and butane exports projected for this year.

US gains from rising Asian demandJapan has been increasing imports from the US to secure diverse and cheaper supply sources. Tatsuhiko Yamasaki, chairman of Japan LP Gas Association had said Japanese buyers have signed contracts to import at least 2 million mt/year of US LPG by 2016.

If all the committed US LPG is brought back to Japan in 2016, US LPG imports could make up about 17% of the countrys total 2013 imports of 11.57 million mt, according to Platts calculations based on the association data.

Japan imported 9.1 million mt of LPG from the Middle East last year, accounting for 78.6% of total imports, down from 84% in 2005, while the US accounts for 952,000 mt of Japanese LPG

Photo by Ramthan Hussain

Chinas rst propane dehydrogenation plant, Tianjin Bohua Petrochemical Co.


LPG

imports, or 8.2% of the total, up from 0.2% in 2005, the association said.

Yamasaki had also said Japans imports of US LPG are expected to rise further to around 3 million mt/year, including spot purchases, by 2017 and will make up about 25% of the countrys total imports.

Th is has led Japanese buyers to push for a new pricing system, which takes into consideration the Saudi Aramco Contract Prices and the typically lower-priced US Mont Belvieu benchmarks.

Backed by growing demand from the new propane dehydrogenation plants three are now operating with three more due to start by year-end Chinas LPG imports are soaring. In the fi rst half of the year, overall imports jumped 97% year on year to 3.12 million, General Administration of Customs data showed.

Chinas net LPG imports totaled 2.44 million mt in the fi rst half, up 150% from the year-ago period. Net propane imports were at 1.84 million mt, up 167% year on year, while net butane imports totaled 592,439 mt in the fi rst half, up 108% .

While Middle Eastern producers the UAE and Qatar remained the top two suppliers, the US has raced into third spot in the fi rst half with 243,280 mt.

Indias LPG imports for public and private sector consumption are expected to grow at double digits to more than 8 million mt in fi scal 2014-2015 (April-

March) from 6.3 million mt in 2013-2014, after the government raised the number of subsidized cylinders early this year, India-based traders said.

While the Middle East remains the major source of Indian imports due to geographical proximity and the countrys

focus on using butane, sources said that US exporters are exploring possibilities of selling to India, especially if the country moves to raising the proportion of propane in its demand mix.

Tight vessel supply to last through 2015Th e rise in Asian demand for US LPG has impacted US prices over the past year and tied up vessels on the long-distance route.

Mont Belvieu propane was assessed September 9 at 106.5 cents/gal ($554.87/mt), while propane for delivery along the key Singapore-Japan route was assessed at $840/mt, making for a discount of around $285/mt, narrower than $323.5/mt around the same time last year, Platts data showed.

But taking into account the current high Houston-Japan VLGC freight of around $280/mt compared with $200/mt a year ago the discount between US and North Asia prices narrows to just above $5/mt, Platts data showed, making it less economical for most traders to make regular long-distance journeys to Asia, except for shipowners, or those with term-charter

tonnage. VLGC rates on the Persian Gulf-to-Japan route have also jumped to record highs twice this year, the latest above $140/mt on July 23, and hovering above $100/mt in September.

Traders and shipowners said tightening vessel supply and the trend of escalating freight could persist till second-half 2015 or even into 2016, with one shipowner expecting the Persian Gulf-to-Japan rates to soar to above $200/mt.

Shipowners and analysts said there are currently 1,195 LPG carriers with a capacity of 1,000 cubic meters or more. Of these, 157 are VLGCs accounting for 12.6 million cu m, they added.

Analysts said 146 new LPG carriers, including 73 VLGCs, are lined up for delivery during 2014-2016, with the majority slated to hit the market from the second quarter of 2015 through Q2 2016 for now. With more VLGCs in operation, as well as the opening of the expanded Panama Canal, vessels would not be tied up too long, which could help to reduce freight rates, analysts said.

But with major shipowners already making orders, along with Chinese and Japanese companies, while a new trend of building very large ethane carriers is emerging, shipyards are booked to the maximum and are unable to rush for earlier delivery dates, analysts said.

In view of such high demand and expectations of a surge in global LPG fl ows, the industry could consider building ultra large gas carriers, or ULGCs, to cater to the growing long-distance, one shipping expert said, though others said this may be a premature idea.

Japan has been increasing imports from the US to secure diverse and cheaper supply sources.


MYANMAR

Myanmar, portrayed as the land of opportunities post-sanctions, is starting to reap the benefi ts of opening its gates to foreign investment. Th e country with open arms welcomed investors in various fi elds, including the energy sector, but it is still new to the game and has yet to smoothen the path for these investors. Th e challenges bureaucratic red tape, shortage of skilled labor, corruption, non-existent infrastructure seem daunting and may threaten to stymie progress.

Th e country is estimated to hold 17.5 Tcf of gas reserves and 3.2 billion barrels of crude oil reserves, according to the countrys energy ministry. Th e oil and gas sector in 2013 was valued at some $14.4 billion, second only to the power sector, which was just under $20 billion, according to the Ministry of National Planning and Economic Development.

Foreign oil and gas players had been eager to re-enter Myanmar after it lifted its curtain in April 2011 with the easing of sanctions, attracted by promising geological prospectivity and its proximity to energy consumers such as China.

A lack of transparencyBut in Myanmar it is obvious that regulatory delays and corruption are endemic, creating a greater need for transparency in all fi elds.

In the energy fi eld, analysts pointed out that more needs to be done to enhance transparency in upstream bid rounds. For example, the government should disclose more information about the criteria it uses to assess bidders and how it selects the winners of the oil and gas blocks, according to consultancy IHS.

Th e Ministry of Energy also failed to reveal signature bonuses off ered by each company, making it diffi cult to assess the standard of less known companies and their proven oil and gas track record.

Th is heightens the risk that smaller, politically connected bidders with little E&P expertise will be awarded contracts. In turn, they may fail to develop the blocks but instead sell them on once asset prices rise, IHS warned.

Sixteen onshore blocks were awarded to foreign companies, including Eni,

INVESTORSROCKY ROAD

SONG YEN LINGSenior WriterAsia Oil News


MYANMAR

Petronas, PTT Exploration & Production and ONGC Videsh, during the 2013 bid round in October last year. Th e awarded off shore acreage was evenly split between shallow-water and deepwater blocks.

Th e formal signing of the production sharing contracts, however, only took place in the third quarter of 2014, some 10 months later. Th e formal award of the PSCs for the 20 off shore blocks, which were announced in March 2014, may take just as long.

My personal view is that it took longer than some of them had thought, said Nomita Nair, partner at UK law fi rm Berwin Leighton Paisner, which has off ered its consulting services to the Myanmar government in dealing with oil and gas joint ventures.

But I think all the players have been quite realistic, they have operated in challenging situations [before], so I dont think delays would have necessarily been unexpected, Nair added.

While noting the bureaucratic delays in fi nalizing and executing the PSCs, Sanjeev Gupta, Asia-Pacifi c Oil and Gas Leader at Ernst & Young, said the key challenges facing operators also include under investment in infrastructure as well as an under-developed fi nancial sector that results in onerous processes for transactions with domestic and overseas suppliers of oil-fi eld services.

Compared with other countries in the region, Myanmars upstream fi scal regime is considered relatively burdensome, particularly for deepwater developments because of the high costs involved.

Th e biggest pull, however, is Myanmars perceived superior geological prospectivity that trumps its neighbors the country has yielded regular signifi cant discoveries and many of the off shore basins are still considered frontier acreage and lightly explored.

Th e entry of companies during the latest annual bid rounds followed an initial wave of interest from Chinese, Th ai,

SouthChina SeaBay of

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MYANMAR-CHINA CRUDE, GAS PIPELINE ROUTES

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MYANMAR

Indian and South Korean companies along with Frances Total, in the decades before Western economic sanctions were lifted in 2011.

Myanmars legacy gas projects are the Yetagun and Yadana fi elds, where production is mostly exported to Th ailand.

Following the start of production from the deepwater Shwe gas project last year, where South Koreas Daewoo the operator contracted to sell gas to China National Petroleum Corp., the Zawtika project from the M9 block spearheaded by Th ailands PTTEP came on stream in February 2014. Th e next two projects in line for development are likely to be M3, also operated by PTTEP, and M2, operated by PetroVietnam.

Strong bond with ChinaTo date, China has been one of the biggest investors in Myanmars energy sector. Myanmar received a revenue

boost last year with the start of the deepwater Shwe gas project in August.

Chinas state-owned CNPC will purchase 80% of production, or 400,000 Mcf/day of gas from the block in the Bay of Bengal, off western Myanmars Rakhine state. Th is will be delivered via the 12 billion cubic meters/year Myanmar-China gas pipeline, which the Chinese funded.

CNPC is also building a parallel 440,000 b/d crude pipeline that will transport Middle Eastern grades which it typically imports from the Burmese port of Kyauk Phyu on the coast of northwestern Rakhine state. Th e pipeline will traverse Myanmar before reaching Chinas southern Yunnan border, thus allowing CNPC to reduce its reliance on the narrow Strait of Malacca between the Malay Peninsula and Indonesia that connects the Pacifi c Ocean with the Indian Ocean, which is prone to piracy attacks, for at least some of its imported crude.

Construction of the pipeline is in progress and Burmese energy ministry sources expect the segment within Myanmar to be completed before the end of 2014. It is still unclear as to when the pipeline will be operational.

Th e crude was meant to feed a new refi nery in Yunnan, originally to be commissioned by this year, but due to protests from local residents unhappy about a refi nery sited at their doorstep and the current overcapacity in Chinas refi ning sector, the refi nery could be delayed by two years, according to analysts.

Th e World Economic Forum estimated last year that the crude pipeline is

SELECTED FOREIGN OPERATORS BEFORE LIFTING OF SANCTIONS

ONGC Noble GroupEssar Energy PetronasChina National Petroleum Corporation PetroVietnamCNOOC PTTEPDaewoo International SinopecJX Nippon Oil & Energy Total

SELECTED FOREIGN WINNERS IN 2013 UPSTREAM BIDDING ROUNDBG PTTEPBrunei National Petroleum Reliance IndustriesChevron Roc OilConocoPhillips ShellEni StatoilOil India TotalOphir Energy WoodsidePetronas


MYANMAR

expected to raise some $900 million in earnings for Myanmar annually in value added taxes alone. A further $900 million a year is expected to be reaped from long-term gas sales from the Shwe project.

Besides CNPC, Chinese oil trader Guangdong Zhenrong Energy, an affi liate of state-owned Zhuhai Zhenrong, has been keen to build a greenfi eld refi nery in Dawei, in the Th anintharyi region in central Myanmar, as early as 2012 but needs the green light from the Chinese government.

Other challengesOne of the most pressing problems facing the business sector is a lack of skilled labor. Despite a relatively youthful population, many lacked access to higher education during the decades of military rule while those that were skilled left Myanmar for greener pastures, resulting in a brain drain.

Companies looking to expand their positions in the country highlight the search for skilled labor as one of the larger stumbling blocks. In addition, the high wages needed to attract skilled labor could undercut the advantages of investing in Myanmar.

One unique obstacle that operators may face in Myanmar is simply because of the fact that there are still live sanctions in place, said Nair. Th e US still prohibits American companies and individuals from doing business with Burmese individuals who were involved in the repression of the democracy movement since the mid-1990s.

One such individual is Myanmar tycoon U Zaw Zaw, who is on the US treasury departments Specially Designated

Nationals list. He tried to gain access to Singapores capital market by engineering a reverse takeover of Singapore-listed bedlinen maker Aussino in 2012 with Max Myanmar his chain of fuel service stations in Myanmar.

Th e move was rejected by Singaporean regulators last year due to concerns over alleged human rights violations and tax investigations by the tax authorities associated with Max Myanmar.

Energy strategyAside from opening its doors to foreign investment, the government has yet to formulate a concrete energy policy for the long term.

In early 2013, the National Energy Management Committee was established to oversee the sector and tasked with introducing reforms and new legislation to help with the transition to a new economy but progress has been slow.

But energy offi cials know this is urgently needed, given so much is at stake for a country facing an acute energy shortage.

Th ere are currently few regulations governing the use of resources for the domestic market. For instance with an energy plan, gas exports to other countries currently unrestricted could be slapped with domestic market

obligations. Th is, however, could have repercussions for future investment.

Energy subsidies are mainly in the power sector, where tariff s are low, although over 50% of the country is still not connected to a power grid.

Because it was closed off from global trade for so long, Myanmars reliance on oil for its energy needs has been minimal, although that is expected to grow signifi cantly with urbanization. State-owned Myanma Petrochemical Enterprise currently imports gasoline, diesel, jet fuel and LPG to meet the countrys needs.

Myanmar currently has three refi neries with total nameplate capacity of 51,000 barrels/day a 6,000 b/d facility in Chauk, a 25,000 b/d refi nery in Th anbayakan and a 20,000 b/d refi nery in Th anlyin.

A vestige of the British empire, the Th anlyin plant not far from Yangon was rebuilt in the 1950s after being destroyed during World War II. Running at about half its capacity now, the refi nery has been prioritized for an upgrade, with an open tender launched this year looking for well-capitalized partners for the revamp. Other similar joint ventures have been proposed for LPG production facilities and jet fuel marketing at domestic airports.

MYANMARS OIL AND GAS FACILITIES

Thanlyin Re nery 20,000 b/dChauk Re nery 6,000 b/dThanbayakan Petrochemical Complex 25,000 b/dSeiktha Methanol PlantMinbu LPG Extraction PlantNyaung-Don LPG PlantThanlyin Bitumen Plant

Source: Ministry of Energy


INDONESIA BIODIESEL

Europe slammed its doors shut to Indonesian biodiesel last year after the European Commission hit Indonesia and Argentina with stiff anti-dumping duties, while Chinas consumption tax on diesel with less than 30% of palm methyl ester eff ected January 1 marked the end of that blended fuel trade from Southeast Asia to China.

Th e anti-dumping duties meant that Indonesian cargoes would be prohibitively expensive Eur150-180/mt ($191-230/mt) higher.

But other doors opened for Indonesian biodiesel a new market emerged in China for bigger-sized, 100% biodiesel cargoes while Indonesia increased the biodiesel blend for subsidized diesel from B7.5 to B10. Th is pushed state-owned oil and gas company Pertamina to seek its increased requirements via tenders, last year and this year.

Th e move by Indonesia was to trim its refi ned oil import bill after its current account defi cit ballooned to $9.8 billion in the second quarter of 2013 the widest since the Asian fi nancial crisis of the late 1990s.

Shift in Chinese buyingChina has been importing biodiesel from Southeast Asia, mainly Indonesia, Th ailand and Malaysia, since 2012, but as B2-B5 cargoes diesel blended with 2-5% PME. Traders on both sides of the South China Sea declared these cargoes as biodiesel in order to avoid paying

HOME ANDAWAY

ESTHER NGEditor, AgricultureAsia

Courtesy: Shutterstock

Palm oil fruit transported from plantation to processing plant.


INDONESIA BIODIESEL

Chinese customs fuel consumption tax which, for gasoil, is Yuan 941/mt ($153.38/mt).

It was a lucrative trade. Th e imported cost of the biodiesel blend was around Yuan 7,600/mt, while the average wholesale price for biodiesel was Yuan 7,700/mt in Guangzhou and the wholesale price for 100% diesel or gasoil was around Yuan 8,350/mt. Th e blended fuel was preferably sold as gasoil at the higher retail prices, eating into Chinas domestic gasoil market share. Th e imports of the cheaper blended fuel exacerbated an oversupplied gasoil market and forced state-owned oil companies to export excess gasoil.

According to customs data, China imported 2.53 million mt of the biodiesel blend in 2013, up nearly 25-fold from 101,156 mt imported in 2012. Chinas 2013 gasoil imports fell 71% year on year to 270,000 mt, while its gasoil exports surged 50.3% year on year to 2.78 million mt.

But on January 1, the Chinese government closed this loophole by levying Yuan 941/mt on these blended fuel cargoes with less than 30% biodiesel content.

For a while in January, it appeared that the biodiesel trade was dead. Certainly, the B2-B5 trade was, but it heralded in a new trade: the B100. Instead of buying 3,000-5,000 mt PME, the Chinese started buying bigger parcels of 10,000-15,000 mt of 100% PME.

Th e Chinese preferred Indonesian PME because it was some $30/mt cheaper than Malaysian product. Th e

fi ve major Indonesian biodiesel producers and exporters are Wilmar International, Musim Mas, Permata Hijau Group, Ciliandra Perkasa and AAA Oils and Fats.

In January, China imported 52,862 mt of PME, almost of all of it from Indonesia (see table), Chinese customs data showed. Imports fell to 25,499 mt in February but this was mostly because the Chinese were on holiday for two weeks for the Lunar New Year. Many Chinese workers return to their hometowns during this time.

But trade resumed in March and April to slightly over 100,000 mt each month. Around this time, traders reported that their Chinese buyers had trouble getting letters of credit. Th e Chinese governments eff ort to rein in excessive lending at low inter-bank rates in December had fi nally caught up with the biodiesel trade. And this resulted in a 54% drop in imports to 48,331 mt in May.

Chinas credit crunch In the years after the global fi nancial crisis, an infl ux of hot money at low interest rates has given rise to a shadow banking sector in China.

CHINESE PME IMPORTS (MT)

2014 YTD volume

Jan 52,862 52,862 Feb 25,499 78,361 Mar 102,902 181,263 Apr 105,191 286,454 May 48,331 334,785 Jun 57,292 392,077Jul 116,105 508,182 Aug 82,595 590,777

Source: China customs data


INDONESIA BIODIESEL

Largely unregulated by the government, non-bank fi nancial intermediaries are able to access these funds directly or through large state-owned banks at low interest rates. Arbitrageurs obtain short-term loans in the form of letter of credit, typically 30 -90 days, from these banks or agents with strong connections to banks by buying commodities.

Th ese commodity fi nancing deals are not restricted to biodiesel, but include soybean, palm olein, rubber, zinc, aluminum and nickel.

After receiving the LC, they would use the credit and re-loan it to an investor at a higher interest rate, making money on the interest spread.

As for the agents, they would keep re-using the documents issued by logistic companies showing the ownership of the underlying asset a few times as long as the value is within their credit line, a trader said.

Th en in December last year, the Chinese government repeated what it

did last June: It kept money supply tight and inter-bank borrowing rates went up. Lenders in the shadow fi nancing sector were hit by more expensive credit.

Th e eff ects of the credit crunch remain, but not tight enough as Chinese buyers continue to buy Indonesian PME spot cargoes all the way to December. About 70% of Chinese PME demand is driven by shadow banking, and the remainder for transport and power generation use, a trader estimated, though other sources say it is the other way around.

Chinese customs data showed PME imports in May dropped by 54% to 48,331 mt, but were up 18.5% to 57,292 mt in June. Th e bulk of imports in June were from Indonesia and include 52,145 mt of PME and 5,138 mt of used cooking oil methyl ester from Hong Kong.

Biodiesel traders point out that customs data do not always capture the large volume of biodiesel cargoes from Southeast Asia in bonded storage off the Dongguan, Yantai, Huangpu, Nansha and Zhanjiang ports.

Prices of biodiesel from these tanks were Yuan 6,200/mt in August, which works out at $847/mt on an import parity basis, after deducting value added tax. Th ere is no import tax on cargoes from ASEAN, of which, Indonesia is a member.

Market sources had expected July and August import fi gures to be lower due to the tightening of credit lines in China. A number of traders said letter of credit openings for July were slower than usual.

RESULTS OF FIRST PERTAMINA BIODIESEL TENDERTotal volume secured 1,237,069 KLPrice Discount (0.1 to 2.05%) to MOPS 0.25% gasoil assessmentSellers Musim Mas, Pelita Agung Agrindustri, Darmex Biofuels, Indo Biofuels Energy, Eterindo Wahanatama

RESULTS OF SECOND PERTAMINA BIODIESEL TENDERTotal volume secured 1,146,884 KLPrice Discount (0.005 to 0.02%) to MOPS 0.25% gasoil assessmentSellers Wilmar International, Primanusa Palma Energi

RESULTS OF THIRD PERTAMINA BIODIESEL TENDERTotal volume secured around 600,000 KLPrice 3% to MOPS 0.25% gasoil assessmentSellers Wilmar International, Darmex Biofuels


INDONESIA BIODIESEL

But PME imports in July went up by a whopping 102.65% to 116,105 mt, customs data showed. Biodiesel traders said the hike in July imports were most likely trades done in June when the discount of palm oil against gasoil dropped from minus $130/mt in May to minus $150-167/mt in June.

A POGO palm oil versus gasoil spread of minus $150/mt and greater starts to become attractive for both producers and buyers because it means that crude palm oil has become cheaper, and therefore so would PME. CPO, RBD (refi ned, bleached and deodorized) palm oil and RBD palm olein are feedstocks of PME.

Overall, China has imported 590,777 mt from January to August.

But not all of this demand for biodiesel is for credit fi nancing. In the summer, the Chinese blend 35-40% of PME with gasoil for power generation in their factories. Th ey also blend 10-15% of PME with kerosene to make diesel for bunker use, and with light cycle oil to increase heating value.

Indonesias oil demandIndonesias oil production has decreased over the last 10 years and in 2004, Indonesia became a net importer of oil with imports growing further amid population and economic growth.

Over time, the countrys current account defi cit widened to $9.8 billion in the second quarter of last year the widest since the Asian fi nancial crisis of the late 1990s, prompting the Indonesian government to fi nd ways to cut fuel imports. In September last year, it announced that it would raise the

biodiesel content in subsidized gasoil to 10% from 7.5%.

Th e move would reduce the countrys foreign exchange bill on gasoil imports by at least $2.6 million/year, or by 3.5 million kiloliters/year (60,313 b/d), and absorb biodiesel exports which would have gone to Europe were it not for anti-dumping taxes.

Th e government has set a biodiesel consumption target of 4 million kl for 2014, but the realization is currently only 54% of the target due to the lack of blending facilities, logistics and price.

Pertamina had launched a tender last September to buy 6.6 million kl over 2014-2015. When the tender was fi rst launched, Pertamina only managed to cover 1.2 million kl. Th e price awarded was at a discount to the Mean of Platts Singapore 0.25% sulfur gasoil assessments on a CIF basis. Th is was the main reason why the volume was small, biodiesel traders said.

Pertamina then re-issued a tender in December, securing only 1.15 million kl for this year. Th e price awarded was slightly under the MOPS 0.25% sulfur gasoil assessment.

Th e tenders have been dogged by late payment although this could not be offi cially confi rmed with the major exporters preferring to sell PME in the export market.

In May, Pertamina issued a tender to buy 1.7 million kl for delivery to Sulawesi, Papua, Kalimantan and Nusa Tenggara. Th e results were released in September, and the state-owned oil and gas


INDONESIA BIODIESEL

Elsewhere, there has been some PME exported to the US, but these volumes are small compared to what goes to China.

company had secured around 600,000 kl, some 250,000 kl below market expectation.

In total, Pertamina has secured 2.95 million kl of biodiesel for 2014-2015. Th e government has revised Indonesias biodiesel consumption target from 4 million kl to 2.3 million kl for 2014.

Elsewhere, there has been some PME exported to the US, but these volumes are small compared to what goes to China.

In August, for the second month in a row, the top origin for US biodiesel

imports was Indonesia at 34,974 mt, up 45% from the previous month. Traders attributed the surge in imports from Indonesia over the past few months to lower palm oil prices.

Two producers from Indonesia are already registered with the US Environmental Protection Agency and would be capable of generating Renewable Identifi cation Numbers if they used approved feedstock.

Although palm oil has not been approved as an eligible feedstock to generate RINs under the US Renewable Fuel Standard, grandfathered biodiesel plants construction of which started prior to December 19, 2007 can assign

RINs with a D6 code to palm oil-based biodiesel if they keep up with the appropriate documentation.

Indonesian biodiesel could fi nd more homes in the US if the blenders credit is reinstated. Qualifi ed biodiesel producers or blenders are eligible for an income tax credit of $1/gallon of pure biodiesel (B100) or renewable diesel produced or used in the blending process.

Th e tax credit expired in December last year. An attempt in May by the US to advance a tax extenders package that would have retroactively reinstated and extended for two years a $1/gal blenders tax credit for biodiesel and a $1.01/gal production tax credit for cellulosic biofuels, failed. A decision on the tax credit is not expected until after the US November mid-term elections.

In the meantime, the new administration of Indonesian president-elect Joko Widodo is said to be committed to renewable energy and fulfi lling the B10 mandate. But it faces a tough challenge of declining oil production, which means the government will have to import a huge volume of fuel to meet growing domestic demand.

As Indonesia tries to meet its biodiesel blending targets, it will continue exporting biodiesel mostly to China. Its a win-win situation for both countries, just as long as the Chinese government does not clamp down too aggressively on shadowing fi nancing. Market sources expect the Chinese government to strike a balance reining in excessive lending, though not too tightly as to crash the economy.

Bringing energy to lifeTaiwan, 7:30 pm. Sunny looks forward tothe Lantern Festival.RasGas is there.

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ASIA COAL

Coal traditionally gets the thin end of the publicity wedge, particularly in the broad press where it tends to receive less than complimentary coverage. In recent years, as the coal-fi red generation industry moves towards a lower quality product, it is increasingly frowned upon by those in the related yet more favorably perceived markets like crude oil and shale gas. Th e mature commodity markets in Europe and America have moved on somewhat, but here coal is by no means a relic of the past. It is really in the developing countries in Asia where coal dominates the grid and continues to reign supreme.

Customs statistics show that China imported over 220 million mt of coal in 2012 and racked up imports of over 260 million mt in 2013. China is now the largest importer of coal in the world, having overtaken Japan in 2011. India is on track to overtake Japan as the worlds second largest importer of coal this year with anticipated thermal coal volumes in excess of 150 million mt. Europe, in comparison, is hovering steadily around the 135-140 million mt mark and the much publicized shale gas revolution has

decimated the US coal mining industry where it is now a net exporter of some 50 million mt of coal per annum.

600 GW of planned buildCoal burn globally is only going to increase, not decrease, in the next 6-8 years as India, China and several other Asian nations expand their generation capacity. Over 600 GW of new coal-fi red capacity is either under construction or forecast to get built in Asia alone by 2020, accounting for almost 60% of power plant capacity in the region, research by Australia-based consultancy group Salva suggests. Th ere have been major increases in seaborne thermal coal demand, particularly in Asia, which has seen trade fl ows radically change and grow to over 1 billion mt in 2013, from 527 million mt in 2005, a compound annual growth rate of over 8%. Australias Macquarie Bank is suggesting that seaborne coal demand could potentially exceed 1.3 billion mt by 2020. Asia is expected to account for 90%, or some 350 million mt, of this increase. Th ose who think coal is dead, be they governments, trading houses or publishers, are barking up the wrong tree.

DIET

JAMES OCONNELLEditoral DirectorCoal

ASIASLOW CV


ASIA COAL

One could argue that the patient has never been more robust or fi t-for-purpose. Th e largest exporter in the world is Indonesia and its steam coal exports have doubled in the last fi ve years. Offi cial government fi gures for 2012 saw 387 million mt in exports most experts agree the unoffi cial fi gure is 30-50 million mt north of that. Th e 400 million mt mark was breached in 2013, and exports for the fi rst-half of 2014 amounted to 213 million mt, up almost 8% year on year. Th e majority of this growth since 2008 has come from lower quality coal sub-bituminous that has up to 10 times less sulfur and 300-400% less ash than standard benchmark Australian or South African coal. Its also quite cheap

and, consequently, in cash-strapped or price sensitive nations like India, China or even Japan the last bastion of high cv coal addiction in Asia lower calorifi c value coal has become more than a viable prospect it has become the lifeblood of countries trying to sustain or revive economic growth.

Prices tumble from highsTh e price volatility that had been the hallmark of thermal coal prices for the previous years continued in 2013. Th is year saw FOB Newcastle 6,000 Net As Received, Australia (and Pan-Asia) benchmark prices slide from a high of $87.70/mt in late December to fall through support at $70/mt by late



ASIA COAL

June. Th is 20% fall has been echoed elsewhere, with European delivered prices falling from $87/mt in early January to a year-to-date low of $71/mt in late June, before recovering to touch $77/mt in August.

Away from the benchmark level, looking particularly at the new liquid markets, 5,500 NAR prices have also echoed a 20% plus decline. FOB Newcastle 5,500 NAR prices have

traded in a $72-56/mt range as Australian producers endure major competition from domestic China-based miners. In H1 2013, the even lower calorifi c value coal products, dominated almost exclusively by Indonesian exporters bucked the trend with a completely diff erent trading pattern. Th e FOB Kalimantan 4,200 kcal/kg Gross As Received and 3,800 kcal/kg GAR price series posted respectable gains. Th e 4,200 GAR assessments rose 13% to $43.50/mt in the fi rst six months while similar gains were seen in the sister 3,800 GAR market. However, since then, producers renewed emphasis on increasing production to reduce unit costs has seen an oversupply situation in the market develop and overshadow modest consumption growth. By August 2014, 4,200 GAR prices had sunk to levels just north of $36/mt, while 3,800 GAR prices fell through support at $30/mt for the fi rst time ever.

Conservative Japan trials low CVPre-Fukushima, nuclear energy accounted for around 20% of the countrys total installed power generation capacity across 54 reactors. In September 2013, Kansai Electric took offl ine the countrys last operating nuclear reactors, raising concerns about fuel supply shortages. Th e March 2011 natural disaster did not have a major impact on Japans demand for coal for the simple reason that its power plants had maxed out their baseload allocation and were already running at full steam.

Japan, as mentioned earlier, is the last country in the Asia Pacifi c region to consider low calorifi c value coal as part of its fuel mix. It seems contrary to expectations at a time when its capacity is stretched to breaking point that it would increase their exposure to a lower quality product. However, when placed in context of an increasing reliance on expensive oil, gas and LNG imports and a current account defi cit that continues to slide in and out of the red, somethings got to give.

Th e land of the rising sun has stubbornly refused to increase its exposure in the spot market over recent years unlike all of its neighbors. It continues to negotiate annual and term contracts with Australian producers for 6,080 kcal/kg NAR branded coal, frequently paying 15% and higher premiums to market prices. In 2012, news fi ltered through that trial-cargoes of 5,500 kcal/kg NAR coal had been accepted by several power plants. In June this year, the market was stunned by an announcement by Chubu Electric trading that it was carrying out trials with low calorifi c value coal at the Hekinan power station and would likely increase its portfolio to 14% from 6% in

Japan is the last country in the Asia Pacifi c region to consider low calorifi c value coal as part of its fuel mix.


ASIA COAL

the short term. Toshimi Tsuchiya, director of Chubu Energy Trading Singapore, has said Chubu is trial burning thermal coal with a calorifi c value of 5,000 kcal/kg NAR specifi cally to cut costs.

Restrained by technical limitationsSources at Japanese power utilities have, however, said that they face technical limitations despite their desire to increase the importation of sub-bituminous coals from Indonesia and the US. One source estimated that Japanese utilities would increase sub-bituminous coal imports by around 5 million mt to 10-12 million mt in 2014. General industry in Japan has less strenuous regulations and sources estimate that totals could range between 3-5 million mt. On the whole, this would account for just over 10% of total imports and while not overtly signifi cant in size, it represents a large shift in policy and strategy.

In recent years, cheap supplies of shale gas has fl ooded the US power market, elbowing coal to the fringes of the countrys energy mix and forcing US coal producers to embark on frantic eff orts to export their product to overseas markets. In fact, 2012 is a year defi ned in the US natural gas, power, and coal markets as one with astonishing volumes of coal to gas displacement. Th e US winter of 2011-2012 was the warmest winter in 62 years, crippling natural gas demand and leaving storage inventories at all-time record highs exiting the winter season. Prices crashed to the lowest levels seen in over a decade. Th is price crash left natural gas competitive with coal for generation for a sustained period of time, driving large

volumes of generation to be fueled by natural gas in just a few months, displacing coal in the process. Th is ability to switch fuel types in large volumes so quickly was developed over 10 years ago.

US coal regains ground on gas Last year, however, coal made somewhat of a comeback, with statistics from Bentek Energy a unit of Platts showing generation data from independent system operators that cover approximately 60% of the country increased 15% year on year. Th e rise in coal generation is due to an increase in electricity loads year over year across all ISOs, along with a decline in gas generation, down 16% over the same period. Gas generation has been curtailed by rising gas prices at the same time coal delivery costs to power plants have remained reasonably fl at year on year. Overall, coal may have reclaimed some lost territory in 2013 but as far as US policy is concerned the war is over with new plant build shifting signifi cantly towards gas.

Coal growth is increasingly becoming an Asia-centric story and that story is steeped in low calorifi c demand in the new economic centers of India and China. Th e dynamic is presenting a new set of challenges to the industry a plethora of new grades, radically diff erent purities requiring normalization with regards to ash, sulfur and moisture and an infantile paper market. One could argue that the coal industry has one foot in the grave in the West but as China, India and Asia in general rely on it to power their industry and economic growth, and as the balance of world power shifts east, King Coals reign looks set to continue.


INDIA AND INDONESIA

2014 has been a historic year for two of the worlds largest democracies.

In India, the Bharatiya Janata Party, led by Narendra Modi a former tea-seller secured a decisive win in the national elections, booting out the ruling National Congress Party and ridding India of the shackles of a coalition government for the fi rst time since 1984.

Indonesians in July brought to power Joko Widodo a former carpenter. Widodo, widely known as Jokowi, is the fi rst president not to come from the countrys political elite or to have been a former army general.

Besides having democracy in common, another commonality between the two countries is the dire energy situation they face.

Both are increasingly reliant on oil imports, vulnerable to oil price hikes and/or exchange rate volatility, spend billions of dollars on fuel subsidies, and have suff ered from a policy paralysis that has stunted growth in their oil and gas industries.

So, what can the industry expect from Modi and Jokowi, as they wade through the various challenges?

Fuel subsidiesAs Jokowi settles into his presidency, one of the fi rst issues he needs to tackle is that of Indonesias astronomical fuel subsidy bill. Subsidies not only use up valuable budget funds, but also contribute to a widening current account defi cit by artifi cially propping up demand for the subsidized fuels. In Indonesias case, subsidized fuels include 88 RON gasoline, gasoil and kerosene.

Indonesia has allocated Rupiah 246.5 trillion ($21 billion) for fuel and biodiesel subsidies this year.

According to estimates by energy consultants Wood Mackenzie, Indonesias fuel subsidy bill is expected to be around $120 billion during 2014-2020, assuming crude prices stay around the $110/barrel mark.

Subsidies are indeed at the top of Jokowis agenda, but given the political sensitivity of the issue, no change in

THE ROADAHEAD

MRIGANKA JAIPURIYARSenior EditorOilgram News


INDIA AND INDONESIA

pricing regime should be expected in the near future.

Jokowis priority after taking offi ce on October 20 will be setting up his government and subsidy cuts are unlikely to be the fi rst order of business, suggesting they are unlikely to happen within the year, Nomura said.

We think Jokowi is also unlikely to do something so unpopular so early in his term after such a divisive election, not to mention the fact that, as it stands, his coalition does not have a parliamentary majority, the bank added.

Instead, Jokowi and his team have talked about trying to get consumers to switch

from using subsidized auto fuels to natural gas.

Darmawan Prasodjo, chief of Jokowis economy team, said in July that the party was thinking about fuel subsidies and intended to cut expenditure on fuel subsidies by getting more people to switch to using gas in the transport sector.

Jokowi estimates that a 30% conversion from oil to gas in the transport sector will cut the annual subsidy bill by Rupiah 60 trillion ($5.2 billion), Prasodjo told Platts after his party came to power.

Jokowis plan is to provide incentives to attract investment in building gas



INDIA AND INDONESIA

infrastructure, a lack of which is often seen as the reason for the countrys low gas demand.

Declining productionAnother immediate challenge facing Jokowi is to reverse the decline in crude oil production and boost natural gas output.

Indonesias crude oil output peaked at 1.6 million b/d in 1995 and has since fallen. It hovers around 800,000 b/d today. Gas production is expected to rise to 9.35 Bcf/d over the next few years from 8 Bcf/d currently, but growth in demand is expected to outpace supply.

Against this backdrop, the industry is urging the government to do whatever is necessary to kickstart the E&P engine. Th eir demands include making the necessary amendments to the oil and gas law of 2001 to remove the regulatory uncertainty currently plaguing the industry, cutting the number of permits required, and making the fi scal regime more attractive.

Oil and gas contractors in Indonesia currently need 284 permits and have to go through 12 diff erent ministries before they can get a project off the ground. It is therefore not surprising that it takes around 10 years to convert a discovery to production.

Prasodjo did not outline any concrete steps that the new government intended to take, but said that Jokowi is keen to boost domestic exploration and production and sees the current fi scal regime as outdated.

Each oil fi eld has its own characteristics, therefore [what is required is a] fl exible fi scal system that is able to answer the

diff erence, Prasodjo told Platts in an interview soon after the election results were announced.

Jokowi will also look at promoting the application of enhanced oil recovery techniques to boost production from ageing wells, Prasodjo said.

Consultants Wood Mackenzie are optimistic that Jokowi will accelerate E&P. Jokowi aims to boost oil and gas output by providing enhanced fi scal terms for mature fi elds and exploration, and removing red-tape, WoodMac said in its report.

Modi better off than Jokowi?Th e challenges facing Modis government are not too diff erent, but he is better off than Jokowi in two ways. Firstly, the previous government had already got the wheels rolling on some big policy changes. Secondly, they have come to power with a full majority, which will make implementation of policies relatively hassle-free.

On fuel subsidies, the Congress government in January 2013 announced a managed deregulation of diesel prices, wherein oil companies are allowed to raise diesel prices by Rupees 0.50/liter ($0.008/liter) every month.

Th e new government simply continued this, and as a result domestic diesel prices are now almost in line with international prices. At the time of writing, there was talk that the government may use this opportunity of low diff erentials between international and domestic diesel prices to completely deregulate diesel.

If diesel deregulation indeed goes through, the eff ect will be manifold.


INDIA AND INDONESIA

Th e money spent on subsidizing diesel, which amounted to Rupees 90 billion in the April-June quarter, can be better spent elsewhere; state-owned upstream oil companies that share the subsidy burden, by discounting the crude oil they sell to state-owned refi ners, will be able to cut the discounts and get a higher price for their oil; and state-owned refi ners will not suff er from a liquidity crunch as they wait to get reimbursed by the government.

Analysts are optimistic that a full diesel deregulation is not too far away.

Moodys anticipates a full deregulation of diesel prices over the next few months, the ratings agency said in a report issued in August.

Analysts at Hong Kong-based Bernstein Research also expect diesel to be deregulated, but they are concerned, and rightly so, about LPG and kerosene that continue to be subsidized.

India spent Rupees 75 billion on kerosene subsidies and Rupees 121.3 billion on LPG subsidies in the April-June quarter.

Th e Modi government has been quiet on LPG and kerosene.

Gas pricingAnother challenge facing the government is boosting Indias oil and gas production. Here the issues are that of pricing, especially in the case of gas, and of fi scal regime.

Th e Congress-led government had almost implemented a gas price hike on April 1 this year, which would have seen prices at the wellhead double to $8.40/MMBtu, before backtracking due to the elections.

Th e proposed price hike by the Congress government had faced severe opposition from various stakeholders, so when the Modi government took over, they decided to tread with caution and have launched a review of the pricing formula that was to have been implemented.

India has to increase gas prices, although the dilemma remains how to

fund this increase given it is uneconomic for power and fertilizer users, which make up 80% of demand, Bernstein said in a report issued in August.

While the new pricing formula implies a more than doubling of gas prices ... We suspect this will be too big an increase for the market to absorb in one go. As such, we suspect the government will either limit the increase ... Or look at ways in which state energy fi rms will indirectly subsidize this increase, the analysts said.

Th e issue of gas prices is critical to unlocking Indias gas potential.

Indias state-owned Oil and Natural Gas Corp. and privately held Reliance Industries have long called for higher gas prices, saying that several of their discoveries are economically unviable at $4.20/MMBtu.

According to Reliance, operator of the deepwater KG-D6 block, lack of clarity on gas prices has held up close to $4 billion worth of upstream investment this year.

Upstream policyOn upstream fi scal regime, the ongoing debate centers around whether India should continue with its existing cost recovery model or switch to a revenue sharing model.

Under the cost recovery model, the contractor recovers all costs incurred for developing a block before sharing profi t

with the government. Th e focus on costs under this model has been a major bottleneck in exploration with the contractor and the government often disagreeing on the actual cost and delaying progress of a project.

Under the revenue sharing model, which was recommended by a special committee, contracts would be awarded based on the volume of oil and gas a company is willing to off er the government.

According to Narendra Taneja, the chief of the BJPs energy cell, the partys plan is to treat deepwater and ultradeepwater blocks diff erently from shallow water and onshore blocks and provide diff erent policy solutions for diff erent types of blocks.

Our philosophy is very simple. We want to incentivize in such a way that we can produce more of our own oil and gas in the country for our consumption. Some of our geologists say that the Bay of Bengal is fl oating on gas. If that is the case, we want to bring that gas

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