2014 ASIA ENERGY OUTLOOK - Platts · 2014 ASIA ENERGY OUTLOOK ASIA GEARS UP FOR LPG TSUNAMI Promise of growth in LPG exports from the US and ... oil, natural gas, coal, or biodiesel

www.platts.com October 2013

2014 ASIA ENERGY OUTLOOK

ASIA GEARS UP FOR LPG TSUNAMIPromise of growth in LPG exports from the US and the Middle East becomes a boon for shipbuilders

ASIAN ETHANOL MANDATESAsian countries try to stick to their goals on ethanol mandates with Thailand and the Philippines leading the way on a thorny path

CHINA’S COAL CHASEChina’s love affair with coal changes the face of global supply flows

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OCTOBER 2013 insight 1

CONTENTSinsight

1

4 ASIA GEARS UP FOR LPG TSUNAMIPromise of growth in LPG exports from the US and the Middle East becomes a boon for shipbuilders

10 CHINA GAS PRICES DEREGULATING THE MARKET

China tries to promote gas exploration, development and adoption through pricing reforms

14 AUSTRALIAN LNG BUSTING THE BUDGET

After a decade of boom in LNG development, Australia is struggling with cost overruns, delayed projects, opposition from farmers and rising gas prices. What does this mean for the industry?

18 RIDING THE EXPLORATION WAVEEven as international oil companies fall over themselves in their eagerness to enter the promising land of Myanmar, other countries in the region are pulling out all stops in their search for more crude to quench their thirst

24 JAPAN’S REFINING CONTRACTION MORE ACTION AHEAD?

As residue cracking regulation kicks in, Japanese refiners hope for better profit margins despite sluggish domestic market

28 REFINING: GET READY FOR ANOTHER MAKEOVER

A possible glut of oil products thanks to major refining capacity expansions in the Middle East and Asia, coupled with rising flows out of the US and declining demand in Europe, pose new challenges for export-oriented refiners in Asia

34 ASIAN ETHANOL MANDATES SHIFTING GOALPOSTS

Asian countries try to stick to their goals on ethanol mandates with Thailand and the Philippines leading the way on a thorny path

40 CHINA’S COAL CHASEChina’s love affair with coal changes the face of global supply flows

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insight OCTOBER 20132

OCTOBER 2013

EDITOR’S NOTETh e times, they are a changin’. Bob Dylan’s words ring more

true than ever in the energy space today – whether it is crude oil, natural gas, coal, or biodiesel. Th e world is in a fl ux, and industry observers and participants alike are trying to make sense of the changing trade fl ow patterns even as buyers turn into sellers and consumers become producers.

If there is a constant, it is that the spotlight remains on China. As the country’s relentless growth in refi ning capacity starts closing the door on product imports, and major new downstream projects in the Middle East start eying the European market, export-oriented refi ners from South Korea to India have to start scouting for new markets. When Australia digs deeper for coal, it looks to China to consume it, but is now faced with uncertainty on the latter’s demand growth rates. For some time now, China’s voracious appetite for commodities to feed its economic growth was a given. But as growth slows – Beijing has a target of 7.5% for 2013, the slowest in two decades – the dragon’s burp could mean a chilling wind for producers and sellers.

Changes in the energy sector are also redrawing trade fl ows. A glut of diesel east of Suez along with declining demand in traditional areas of high consumption such as Europe; the prospect of large volumes of LPG sailing across the seas from the US to Asia; the promise of a virgin market with the opening up of Myanmar – participants in energy markets need to have an eye on every market and juggle the world’s needs if they want to stay on top. Add to this, Australia’s struggle with cost overruns and delays in LNG projects, as Asia’s tussle with ethanol mandates, and it makes for an interesting if a slightly chaotic world.

Will China’s love aff air with coal lead to more changes? Will countries such as Th ailand and the Philippines stick to their ethanol mandates in the face of challenges? What is in store for Japan if oil products overfl ow the tanks even after mothballing refi ning capacity? Will China’s attempts to bring domestic gas pricing more in tune with global markets encourage more exploration? Again, to borrow Dylan’s words, gather around people, for the battle outside will soon “shake your windows/And rattle your walls” for the times are a-changin’.

— Shailaja Nair, Editor


LPG

Expectations of a jump in US LPG exports, with the ongoing widening of the Panama Canal and a rise in volumes from the Middle East, have spurred shipowners and trading fi rms to build very large gas carriers for long-distance trips to Asia, even as scrapping of old vessels is almost at a halt.

Demand for VLGCs and, as a result, rising freight rates, is pushing up sentiment in the medium term, encouraging at least one shipping major to plan a public listing to raise funds for newbuilds and vessel acquisitions.

But shipping consultants and brokers warn that the highly volatile LPG market would have to watch for signs of overhang and a vessel glut.

“Rising supply and expanding consumption base in developing economies indicate expanding consumption of LPG in the medium to long term, which could support freight markets,” said Shantanu Bhushan, lead research analyst for gas shipping at marine consultancy Drewry.

“However, the LPG shipping market is delicately balanced and over-enthusiasm could dampen future prospects,” he warned.

Erik Nikolai Stavseth, an analyst at Oslo-based Arctic Securities said he expected freight rates to be fi rm over 2013-2015, with 12-month time-charter rates averaging $1 million-1.1 million/month, which means spot rates will likely be higher. Another shipping source said bigger gas tankers off er shipowners a time-charter equivalent of more than $50,000/day.

“Th is is pretty solid given historicals, but then I think the market may soften slightly in 2016,” Stavseth added. “Are shipowners making the same mistake they tend to do – over-order at the height of the market?”

Daily VLGC rates on the major Middle East-to-Japan route jumped more than 30% in recent months hitting a peak in June, the highest since 2005.

Market sources attributed this to strong North Asian summer demand, especially

ASIA GEARS UP FOR

LPG TSUNAMIPromise of growth in LPG exports

from the US and the Middle East

becomes a boon for shipbuilders

MOHD RAMTHAN HUSSAINSenior Editor,LPG

Courtesy: BW Maritime

5OCTOBER 2013 insight

LPG

in Japan due to a heat wave; China’s April-September maintenance season that spurred imports; petrochemical makers switching to cheaper LPG from naphtha as feedstock; Indonesian festive season demand during Ramadan and Eid al-Fitr; and Th ailand hiking its imports after a gas plant outage.

“We have seen more than 10 new builds hit the market during January to August 2013, and would not say rates have dropped because of this,” said Sebastian Venjar, general manager of the gas department at Lorentzen & Stemoco Shipbrokers.

“We do see another two to three VLGCs to be delivered during the rest of this year and if the market repeats itself again, the fall/winter market usually has a negative trend on freight as demand drops. If so, we could be in for a rough time on shipping, especially in the east,” he said.

But he noted that freight rates have fallen around 20% from mid-June to early October, on slowing activity in the Middle East market and falling LPG prices.

No ships scrappedData compiled by Platts show at least 49 orders for newbuilds, or older ships acquired in 2013 and 2012, excluding recent activity in the second-hand market.

Drewry data show that new orders for 38 LPG carriers were placed over January-August, including 10 for VLGCs. A total of 37 vessels, including 16 VLGCs, have changed hands in the second-hand market during the period, Bhushan said.

Based on the LPG order-book at the end of August, LPG fl eet could see a compounded annual growth rate, or CAGR, of 3% in vessel numbers and 5% in volume during 2012-2016, without accounting for future orders and demolitions. Th e VLGC fl eet could grow by a CAGR of 6% during the same period both in vessel numbers and cubic capacity, Bhushan added.

Clarkson Capital Markets put the LPG fl eet at 1,266 vessels of 20.82 million cu m as of August 1. Th e order-book stands at 100 vessels of 3.46 million cu m, equivalent to 17% of the fl eet, up from 14% at the start of the year. It compares with a peak of 48% in 2006 and a low of 8% in 2011.

Th ere have been 35 orders totaling 1.7 million cu m and $1.55 billion in the fi rst seven months of the year. Spot earnings for an 82,000 cu m ship hit a year’s high of $57,199 in June, it said.

“We currently estimate a newbuild price for a VLGC to be $71 million. In 2012, total LPG trade totaled approximately 60 million mt, up from 46 million mt a decade previously,” Clarkson added.

Source: Drewry Maritime Research

Aug 2010 Aug 2011 Aug 2012 Aug 2013

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VLGC SPOT RATES AND LPG ASIAN IMPORTS

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Propane-Naphtha spread (Japan CFT, $/mt) Far East LPG imports (’000 tonnes)

Chinese imports (’000 tonnes) VLGC Spot rates (AG-Japan, $/mt)


LPG

Stavseth said all vessels ordered since May might have been in the range of $75 million each.

Meanwhile, only six VLGCs are over 25 years old, which could be deemed candidates for scrapping going forward, while there are 27 VLGCs on order, Bhushan said.

“Strategic decisions by many companies to consolidate, or to build in a particular size segment could also be one of the reasons why shipowners have been generous in placing new orders,” he said.

Analysts said that no ships have been scrapped since May 2011. Th e fl eet has a capacity of 12.1 million cu m, with only 4% being older than 25 years and 17% between 20 and 24 years, leaving limited scrapping potential.

Stavseth said the current VLGC order-book is around 25% of the sailing fl eet. “Th is means there will have to be relatively strong growth for volumes going forward,” he said.

Consolidation and growthStavseth sees the market going through some consolidation as growth is expected

to be higher in the future. He pointed to Frontline 2012’s acquisition of shares in Avance Gas in August in a joint venture with Stolt-Nielsen Gas and Sungas Holdings. Th ese come ahead of Avance’s proposed initial public off ering.

Talks are underway for Frontline’s eight newbuilds of 83,000 cu m each that are due for delivery from China’s Jiangnan Changxing shipyard during 2014 and 2015, to join the Avance fl eet. Th e joint venture will have a fl eet of 14 VLGCs, making it the second-largest owner in the sector after BW Gas.

BW Gas recently committed to buying four new VLGCs from South Korea’s Hyundai Heavy Industries, plus two on option. In May, it bought Maersk Tankers’ fi ve vessels and took over its fi ve existing time-charter commitments as well.

BW Gas is planning an IPO and also list BW LPG Ltd. on the Oslo Stock Exchange to help fund its fl eet expansion. BW LPG will have a fl eet of about 40 large LPG vessels including VLGCs, LGCs and newbuilds to take advantage of the US shale gas-led LPG market growth.

“Th e BW Group sees strong opportunities within the LPG segment and would like to provide new investors with the opportunity to invest alongside the BW Group,” said Andreas Sohmen-Pao, CEO of BW Maritime.

Oslo-listed Teekay LNG Partners and Exmar in December agreed to create a 50/50 joint venture to focus on Midsize Gas Carriers. Th e venture will receive 10 newbuilds between 2014 and 2017.


Aug-08 Feb-09 Aug-09 Feb-10 Aug-10 Feb-11 Aug-11 Feb-12 Aug-12 Feb-13 Aug-13

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Saudi Arabia Algeria North Sea Mont Belvieu


LPG

One reason for there being hardly any ships available for scrapping is the ban on Iran LPG exports, Venjar said. Despite Western sanctions, Iran has been seeking to buy, or book on time charter, older VLGCs to export products on a CFR basis to North Asia.

“Because of this, many new players have emerged looking for second-hand VLGCs, which again is not positive for the shipping market,” he said. “We would have seen more scrapping if the Iran situation did not happen.”

Sources said more vessels are now regularly transporting Iranian LPG to South Korea and China. Th ese include VLGCs such as the Sam Russ, Gas Beauty, Schumi, Gas Jasmine and Senna Princess. A number of Chinese fi rms are also seeking older VLGCs, and at least three vessels have recently been purchased to ship LPG from the Middle East, according to industry sources.

Chinese ambitionsChina does not have a VLGC fl eet, but with imports – especially from the US – expected to jump with the development of propane dehydrogenation, or PDH, plants, it will seek to cut costs by forming its own fl eet, sources said.

Nine Chinese petrochemical companies are planning to build up to 11 PDH plants, which are estimated to require 8.04 million mt/year of propane by 2015, industry sources said. Another fi ve plants are proposed to be built after 2015, though experts are skeptical as to whether all the projects will go ahead.

China Oriental Energy, which is building a 1.2 million mt/year PDH joint venture plant to produce propylene

at Zhangjiagang, has ordered six VLGCs, with up to 16 options at a Chinese yard, and deliveries are slated to start by the end of 2014, local media has reported.

Recently, Hong Kong Southwest Maritime Company, a unit of China’s gas shipping group Tianjin Southwest Maritime, placed an order for two VLGCs of 83,000 cu m each with the Jiangnan Shipyard, the company said.

Th e average size of VLGC newbuilds have also risen to around 84,000 cu m from 82,000 cu m in the 2000s. Th e orders are for modern, faster, fuel-effi cient ships, which make better economic sense for shipowners and charterers, analysts said.

Enterprise will further expand its LPG export terminal on the Houston Ship Channel by 1.5 million barrels/month, which will boost its total monthly design capacity to 9 million barrels when completed by fi rst-quarter 2015. Enterprise also plans to build its second LPG export facility, which would have a 6.5 million barrels/month capacity.

Targa Resources has a 2.6 million mt/year terminal; while Williams and


2008 2009 2010 2011 2012 2013 2014 2015 2016

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AVERAGE SIZE OF VLGC FLEET

Cubic meters


LPG

Boardwalk would jointly develop an export terminal in Louisiana, with a a butane and propane loading rate of 25,000 barrels/hour. Others in the pipeline include the ConocoPhillips, Oxy, Sunoco and Williams projects, as well as the potential Valero, Martin Gas, TransMontaigne and Trammo terminals.

But the proposed Coastal Caverns and Itochu LPG export terminal project in Beaumont, Texas, has been scrapped in October, the companies said.

“If all planned projects become operational in time and if we assume that the major portion of US exports are shipped to Asian nations, then US exports could employ more than 30 VLGCs – with approximately 100% utilization – on US-Asia voyages,” Bhushan said.

Rise in tradeVenjar said a rise in trade via the Panama Canal will be seen probably after 2015. But Stavseth said some impact has already been seen this year. “US LPG exports to Japan have, through April 2013, surpassed previous full-year volumes. Th is is driving up ton-miles for shipping which requires more vessels,” Venjar added.

Trade sources put the VLGCs already being moved out of the US Gulf Coast in recent months at 20 per month, of which at least three spot cargoes come to North Asia.

Th e distance for a VLGC sailing from the US Gulf to Asia around the Cape of Good Hope is now about 15,000 nautical miles, taking some 45 days for a US-Japan round trip. Th rough the expanded Panama Canal, it will be about 9,000 nautical miles for a 25-day return voyage.

Shipping analysts said while this could negatively aff ect ton-mile demand – denoting demand for long-haul voyages, and calculated by multiplying the volume of cargo moved in metric tonnes by distance traveled in miles – the projected threefold rise in US propane export capacity by 2016 from end-2012 levels, could help boost demand for shipping.

“Th e real question here is whether Asian terminals, especially in developing countries, or buyers, are capable of absorbing this amount of supply. Or, whether US propane would still be competitive vis-à-vis Middle East LPG, once signifi cant amounts of propane start fl owing out of the US. Or, will Middle East suppliers change their pricing strategy?” Bhushan said.

Prices aff ectedTh e recent rise in Asian spot demand for US LPG cargoes, has impacted prices over the past year. While US FOB Mont Belvieu propane versus CFR Asian prices remain at a steep discount, the spread has more than halved to $293/mt as of October 9, from $635/mt a year ago. But even taking into account higher freight rates to ship LPG from Houston to North Asia, which shipowners estimate at $160-170/mt, US-origin cargoes are some $130/mt cheaper than Asian CFR prices, shipping sources said.

“Th e shorter distance will lift volumes from the US. Keep in mind that the major trade lane today is Middle East to Asia, which is around 6,500 nautical miles, so more volumes in total and longer distances through the Panama Canal are defi nitely a positive and key driver,” Stavseth said.


CHINA LNG

At a time when Asia’s major LNG buyers are clamoring for natural gas prices to be delinked from oil, China is moving in the opposite direction in a move aimed at deregulating the market, putting a higher value on a clean and increasingly important resource as well as encouraging more upstream development in unconventional plays.

Natural gas currently makes up 5% of China’s energy mix, which is heavily dependent on coal but demand for gas has accelerated rapidly in the last fi ve years, largely due to abundant domestic resources and strong political will backing adoption of the fuel across the economy.

At the heart of this support has been the government’s pledge to reform China’s domestic natural gas prices, which along with oil pricing, has been a key topic of debate in the current 12th Five Year Plan that will run till 2015.

Gas pricing reform was supported by the need:

To place a higher value on gas thereby encouraging conservation;

To align the prices of gas from diff erent sources, both domestic and foreign, for end-users;

To encourage more domestic output at the wellhead.

In July this year, Beijing started pegging incremental onshore, conventional gas to a basket price of alternative fuels, LPG and fuel oil. Th is was an extension of a reform introduced in late 2011, which linked natural gas prices in Guangdong and Guangxi provinces to about 90% of the 2010 basket of LPG and fuel oil prices in Shanghai.

At the same time as introducing the new pricing formula, the government also raised the prices for non-residential consumers – industrial and commercial users as well as central heating systems – which hiked citygate prices, eff ectively wholesale gas prices, by about 15.4% to an average Yuan 1.95/cu m, or about $8.90/MMBtu.

Two-tiered pricing systemAs it stands, China will now have two tiers of gas pricing, one encompassing

CHINA GAS PRICESDEREGULATING

MARKETChina tries to promote gas

exploration, development and

adoption through pricing reforms

SONG YEN LINGSenior Writer,China

THE


CHINA LNG

91% of supply, where prices will be set by the government, and another aff ecting incremental supply volumes, estimated to be 11 Bcm this year, which will be correlated to the average price of fuel oil and LPG in the second half of last year.

Th e maximum citygate price for both tiers in each province and region has already been set by the government. Beijing’s ultimate aim is for both price bands to converge by 2015.

In major cities, incremental supply gas prices will now reach Yuan 3.3/cu m or about $15/Mcf across the eastern seaboard, according to calculations by analysts. Th is brings prices in some areas on par with imported LNG, leading Bernstein Research to say in a July research note: “Th e price will be similar to that of an LNG contract price resulting [in] international gas pricing for the fi rst time.”

Gas prices in China were traditionally kept low largely because pricing was based on extraction of the gas at the wellhead, plus transport costs.

Th is, however, failed to keep pace with demand, which has surged exponentially and resulted in China’s dependence on imported gas rising steadily to more than 30% of total gas demand.

Th e burden then fell to commercially driven but state-controlled companies such as PetroChina, the largest importer of gas and LNG, to subsidize higher-priced imports that were being sold at a loss in the domestic market.

Last year, China’s total LNG imports stood at 14.7 million mt, averaging

$10.77/MMBtu, up 18.8% year on year. Its total pipeline gas imports from Central Asia rose 41.2% year on year to 14.63 million mt or 20.2 billion cubic meters, averaging $10.44/MMBtu.

By the end of 2013, China is expected to have up to eight operating LNG import terminals with the capacity to handle nearly 30 million mt/year of LNG. In addition, up to 400,000 Mcf/day of gas is expected to start fl owing from Myanmar via the Myanmar-China pipeline to the southern Yunnan province, while Central Asian supplies will likely receive a boost with more volumes coming from Uzbekistan and eventually, Kazakhstan.

Th e implication for upstream producers is signifi cant as average netbacked wellhead prices – citygate prices less transport tariff s – are likely to double to $10/Mcf over the next three years based on the new price formula, according to Bernstein Research analysts.

Source: China’s General Administration of Customs, National Bureau of Statistics

CHINA’S GAS BALANCE

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CHINA LNG

PetroChina’s average natural gas prices are estimated to rise by 10% in 2013 as a result of the new pricing mechanism, and it will likely reach near breakeven point on its gas imports.

Th is will do much to spur upstream development for unconventional resources, particularly shale gas, which has the ability to be the same game-changer in China as it was in the US, provided technological, cost and infrastructural hurdles are overcome.

Companies are already complaining about the high costs of drilling and extraction involved in shale gas reservoirs. Added to this is the cost of building additional infrastructure and pipelines to monetize these sources.

Th e reform will also encourage development of increasingly complex gas fi elds in China, such as those with low-permeability reservoirs or high sulfur content.

Th e higher gas prices are also likely to attract more non-traditional oil and gas players into the sector. Th is is already starting to happen with a number of coal and power companies investing in plants for synthetic coal-to-gas production, utilizing the country’s abundant coal reserves.

Aff ordability a concernNational targets for energy are, however, notoriously hard to achieve given the nature of the multiple markets across the country. Bernstein estimates there is only a 50% probability of Beijing reaching price convergence between the two tiers, given the “uncertainty on implementation.”

A more important question is whether much of China can absorb gas at this high level and if this reform is indeed sustainable, said Gavin Th ompson, lead consultant on China at Wood Mackenzie.

“Th rough the longer term, looking out to the end of the decade, China will have a huge amount of incremental gas supply and the impact of those citygate prices is actually quite signifi cant,” he said.

He added that if the aim of this reform was to encourage unconventional gas supply, once the production from this development is realized, the cost of this gas will be much lower than imported supply. “Once that lower cost gas comes in, in the longer term, China has got pretty high gas prices. How long does the [pricing] policy last? Th at’s open for debate,” Th ompson said.

According to JP Morgan, some segments might not be able to pay the

Source: HSBC Research, General Administration of Customs

CHINA’S AVERAGE GAS PRICES

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CHINA LNG

new gas prices as they are already relying on government subsidies, which will need to be increased substantially. For gas-fi red power plants in Beijing which use incremental gas supply and thus have to pay oil-linked prices, for example, the local government will have to raise its subsidy from Yuan 44/MWh to Yuan 186/MWh for them to remain viable, the bank estimated.

“Th e gas cost hikes will inevitably aff ect short-term demand, especially given that year-to-date supply growth [which is a proxy for demand], remains subdued,” it said.

Promise of growthGas is used mostly by residential and industrial consumers although consumption is growing rapidly among residential users, as city gas distributors expand their networks and hook up more households in second- and third-tier cities to their grids. Residential gas prices are now the lowest across user segments, about 20% lower than those paid by industrial customers and nearly half what the transport sector pays.

Companies such as PetroChina’s midstream gas subsidiary Kunlun Energy are building huge networks of distribution and gas refueling stations to serve the transport sector. Th e potential for gas consumption to rise in the transport sector is signifi cant as selling LNG and compressed natural gas here is the only unregulated part of the onshore gas value chain in China and it is a much cheaper alternative to oil, according to Macquarie Research. Gas in this sector is eff ectively at a 40-50% discount to diesel retail prices,

according to estimates by Macquarie Research.

In the last year there has also been a signifi cant push by local governments to use more gas-based vehicles especially in view of China’s chronic pollution problems.

Th e capital Beijing, for example, is hoping to abolish 1 million gasoline and diesel-fi red vehicles by 2017, replacing them with LNG and compressed natural gas vehicles.

At the moment, gas is still a rare feedstock for the power sector, which runs mainly on coal.

China’s power sector tariff s are controlled by the government and power producers frequently suff er losses because the on-grid tariff s, or wholesale electricity prices, are often not high enough to even cover the rising cost of coal, which is the cheapest and most abundant fuel in the country.

If the government extends pricing reforms to the electricity sector, however, it will pave the way for more power plants to switch to gas, which could signifi cantly increase its share in China’s overall energy mix.

CHINA’S GAS TARGETS UNDER THE 12TH FIVE YEAR PLAN (BCM)

2010 2015

Total demand 106 230

City gas demand 57.2 120

Total production 94.8 156.5

CBM production 8.6 30

Shale gas production 0 6.5

Gas fi red power generation capacity 26.4 GWh 56 GWh

Residential users 180 million 250 million

Source: Government data


AUSTRALIA LNG

Th e unprecedented boom that Australia’s LNG industry has enjoyed over the past decade has seen more than $200 billion committed to investments, with seven major projects still under construction.

But Australia is a costly place to invest in and the next wave of projects is looking much more likely to shift off shore, utilizing new fl oating LNG technology using massive vessels built in South Korea.

Six of the new LNG plants being built are onshore. Shell’s Prelude project was the world’s fi rst FLNG facility to be approved when it was given the go-ahead in May 2011.

Together the seven export plants will raise Australia’s nameplate LNG capacity from around 24 million mt/year now, to more than 80 million mt/year by 2017, potentially making it the world’s biggest producer ahead of current leader Qatar.

But the boom has not been all plain sailing. Most of the projects have suff ered budget blow-outs, estimated by analysts at anywhere between 15% and

50%. Th e increasing costs have led some projects to be delayed or even shelved. Woodside’s 12 million mt/year Browse LNG project at a remote site on James Price Point in Western Australia was one such casualty.

Soaring labor and equipment costs were behind Woodside’s decision in April this year to shelve the project. Th e original budget had ballooned, with some observers speculating the cost of the development would have been as high as $100 billion.

Woodside and its joint venture partners Shell, MIMI, PetroChina and BP subsequently decided to develop their Browse gas using a fl oating LNG production facility. Th e redesigned project will use FLNG technology pioneered by Shell.

Woodside has suff ered budget and timetable overruns at other LNG projects too. Its 90%-owned Pluto LNG project in Western Australia, which fi nally started exports in May 2012, was plagued by delays and came in nearly A$3 billion over budget at just under

AUSTRALIAN LNGBUSTING

BUDGETAfter a decade of boom in LNG

development, Australia is struggling

with cost overruns, delayed projects,

opposition from farmers and rising

gas prices. What does this mean for

the industry?

CHRISTINE FORSTERSenior Writer,Asia Oil News

THE


AUSTRALIA LNG

A$15 billion ($14.2 billion at current exchange rates).

Others have faced similar issues at their Australian LNG projects. In late 2012, US major Chevron, operator of the massive Gorgon LNG project, also in Western Australia, revealed that the budget had risen by 40% to A$52 billion. Th e project was expected to cost A$43 billion when the fi nal investment decision was taken in 2009.

Despite the blow-out, attributed to high labor costs, productivity issues and the stronger Australian dollar, Chevron said the project remained viable due to rising oil prices and because the company, and its partners Shell and ExxonMobil, had been able to hike the plant’s nameplate capacity by 4% to 15.6 million mt/year. Th e plant is due to be commissioned in late 2014, with the fi rst cargo expected to be loaded in the fi rst quarter of 2015.

Meanwhile, on the east coast of the country, the world’s fi rst coalseam gas-to-LNG projects, being built on Curtis Island in the Queensland port city of Gladstone, have also experienced cost pressures. Th e three plants now represent an aggregate investment of $63.6 billion, up from $51 billion when they were fi rst given the green light.

Although the Curtis Island proponents are all building their own pipelines and infrastructure, they now concede that some of the duplication could have been avoided and are looking for ways to cooperate. Th e plants will have a total nameplate capacity of 25.3 million mt/year of LNG and will be supplied with CSG from onshore fi elds in Queensland’s Bowen and Surat basins.

Santos, operator of the Gladstone LNG project, and BG Group subsidiary QGC, which operates the Queensland Curtis LNG project, recently agreed to connect the two pipelines that will feed their plants, in a move that is expected to be the fi rst of many cooperation deals. Th e interconnect points will enable gas to


AUSTRALIA LNG

fl ow from one project to the other when necessary, maximizing plant productivity, according to Santos.

Origin Energy, the upstream operator of the third Curtis Island project, Australia Pacifi c LNG, earlier this year agreed to sell Santos 365 petajoules (347 Bcf ) of gas for GLNG, in a move that was seen as foreshadowing consolidation among the players.

A fourth LNG export project, the Shell- and PetroChina-owned Arrow Energy, has also been proposed for Curtis Island. Rather than pushing ahead with another standalone project, however, Shell now appears to be favoring a deal under which Arrow’s CSG would be processed by one of the other plants.

Rising costs are not the only issue for the Queensland projects. Arrow is said to be struggling to secure the landholder

agreements it needs to develop its CSG acreage, much of which is on prime farmland.

Some of the region’s farmers fear CSG production could have an impact on precious underground aquifers and are concerned about the storage and disposal of the salty water that is a byproduct of CSG drilling. Environmental lobbyists are also mounting opposition to hydraulic fracturing, which will eventually be needed to increase output from most of the Queensland CSG deposits.

Aside from Prelude, the other two LNG projects currently being built – Chevron’s Wheatstone and Inpex’s Ichthys – will have onshore liquefaction facilities at Ashburton North in Western Australia and Darwin in the Northern Territory respectively.

Shell has been tight-lipped about the cost of the groundbreaking Prelude project. When it was approved, the company had indicated that Prelude would cost around $10.8 billion to $12.6 billion, and there has been no update since then. Prelude will produce 3.6 million mt/year of LNG, 1.3 million mt/year of condensate and 400,000 mt/year of LPG. Th e facility is expected to start up in 2017.

Onshore, Chevron has maintained its A$29 billion budget for the foundation Wheatstone LNG project. Th e liquefaction facilities will be designed to produce 8.9 million mt/year from two trains and start up in 2016.

Th e two-train Ichthys LNG plant being built in Darwin will process gas piped from the fi eld, nearly 900 km away, off

GREENFIELD AUSTRALIAN LNG PROJECTS UNDER CONSTRUCTION

Approved capacity Budget (US$bn)* Name Location Operator (mill mt/yr)/trains at FID/Now First cargo

GLNG Curtis Island, Santos 7.8/2 16/18.5 2015 Queensland

QCLNG Curtis Island, BG Group 8.5/2 15/20.4 2014 Queensland

APLNG Curtis Island, Origin Energy 9/2 20/$22.5* Mid 2015 Queensland (upstream); ConocoPhillips (downstream)

Ichthys Blaydin Point, Inpex 8.4/2 34 End 2016 Northern Territory

Gorgon Barrow Island, Chevron 15.6/3 37/52** Early 2015 Western Australia

Wheatstone Ashburton North, Chevron 8.9/2 26.4* 2016 Western Australia

Prelude Offshore, Shell 3.6/1 Approx. 12 2017 Western Australia

*At August 15, 2013 A$/US$ exchange rate

**At December 5, 2012 A$/US$ exchange rate

Source: Platts, company reports


AUSTRALIA LNG

Western Australia, and will have the capacity to produce 8.4 million mt/year of LNG. Th e project’s managing director recently said Ichthys remained on track with its original budget of $34 billion and would ship its fi rst LNG cargo at the end of 2016.

Like the rethink at Browse, the next round of investment in Australian LNG projects looks likely to be focused on the emerging fl oating production technology, and apparently for sound commercial reasons. According to calculations by Hong Kong-based analysts with Bernstein Research, the capital cost of fl oating LNG facilities ranges over $2,500-3,000 per metric tonne of capacity, compared with $4,000/mt for onshore projects in Australia.

Woodside is now eyeing a possible FID on the FLNG option for its Browse gas in 2015, and industry insiders say the project could be operational as early as 2018.

Elsewhere, ExxonMobil and partner BHP Billiton recently sought government approval to install the world’s largest FLNG production facility at their Scarborough gas fi eld off Western Australia. Th e FLNG project would process around 1.1 Bcf/day of gas, producing an estimated 6 million-7 million mt/year of LNG from fi ve trains mounted on a massive 495 meter barge.

France’s GDF Suez is also pursuing the development of its Bonaparte FLNG project off northern Australia. Th at project is expected to produce between 2 million mt/year and 2.5 million mt/year of LNG from the Petrel-Tern-Frigate gas fi elds in the Bonaparte Basin which the company owns in a joint venture with Santos.

Th ai state-owned upstream company PTT Exploration and Production is meanwhile eyeing an FLNG project to develop its 2-3 Tcf of gas in the Cash-Maple fi eld in the Timor Sea. PTTEP plans to choose a partner for the project at the end of 2013, with a view to starting production around 2016.

At present, the only other onshore project on the horizon is a small facility being planned by local junior Liquefi ed Natural Gas Limited, at a site at Fisherman’s Landing in Gladstone. Th at proposal, for a 3 million mt/year plant costing $1.7 billion, has struggled to get off the ground, however, as it has been unable to secure gas supply.

Flow-on eff ectTh e development of the LNG export projects is having a fl ow-on eff ect in the eastern Australian domestic gas market. Gas production in eastern Australia will need to rise from the current level of around 600 Pj/year to about 1,500 Pj/year in order to supply the export plants after they start producing in 2014 and 2015.

Th e startup of the Curtis Island plants will coincide with the roll-off of major gas supply contracts in neighboring New South Wales, leaving consumers there facing the prospect of much higher prices and a shortage of supply.

Eastern Australian gas prices, which have historically been low at around $3-4/Mcf, are now heading for export-parity levels of around $10/Mcf, prompting calls for some gas to be reserved for the domestic market. So far those calls have been resisted by the state and federal governments.

SOUTHEAST ASIA

18 insight OCTOBER 2013

Th e Southeast Asian upstream oil and gas sector is poised to see a fl urry of activity with the new kid on the block – Myanmar – presenting exciting possibilities, and old hands Indonesia and Malaysia re-shaping policies to spur investment.

New drilling activity planned off shore Vietnam in 2013 could open up new prospective plays in the country’s frontier Phu Khanh Basin as well.

“With overall production expected to be peaking in Southeast Asia, countries in the region are looking to encourage exploration more aggressively,” Credit Suisse said in a report released in July. “Deepwater resources are set to play a greater role in exploration and production in the region.”

Myanmar is one of the least explored countries in the region, and though Indonesia, Vietnam and Malaysia have been successfully explored in the past, there are a number of frontier basins left, which are being targeted now, the bank added.

According to estimates by consultants Wood Mackenzie, Southeast Asia’s

liquids production is declining and is expected to drop from an estimated 879 million barrels of oil equivalent in 2013 to 838 million boe in 2018.

Gas production, however, is set to grow at an annual rate of 2.5% from around 1.25 billion boe in 2013 to 1.45 billion boe in 2018, the oil and gas consultancy said.

In terms of prospectivity, Wood Mackenzie estimates that Southeast Asia holds about 60.92 billion boe in commercial and technical oil and gas reserves, while total yet-to-fi nd volume is estimated at 14.6 billion boe, of which liquids comprise 5.5 billion boe and gas 9.1 billion boe.

Th e bulk of the region’s recoverable reserves are located in Indonesia and Malaysia, which contribute 29.55 billion boe (48%) and 15.41 billion boe (25%), respectively.

“Indonesia, Malaysia and Myanmar are highly prospective for gas reserves, while Vietnam’s YTF liquids volume is the highest in the region at 1.87 billion boe,”

RIDINGEXPLORATION WAVE

Even as international oil companies

fall over themselves in their

eagerness to enter the promising

land of Myanmar, other countries in

the region are pulling out all stops

in their search for more crude to

quench their thirst

MRIGANKA JAIPURIYARSenior Editor (Asia),Oilgram News

THE


SOUTHEAST ASIA

Wood Mackenzie said in a report published in July.

Indonesia’s choicesIndonesia’s traditional oil and gas producing basins – Sumatra, Java and East Kalimantan – are well explored and mature, but the country still holds considerable oil and gas resources. Wood Mackenzie estimates Indonesia to hold about 3.67 billion boe of YTF reserves in the eastern basins, where large areas, both onshore and off shore, remain relatively unexplored.

“Th e major problems faced by potential explorers in these basins is the sheer size and remoteness of the areas to be explored,” it said. “Th is, in combination with the lack of infrastructure and the harshness of the terrain (many of the prospective onshore areas are in remote jungle regions), makes the logistics of petroleum exploration very diffi cult.”

Disappointing results from deepwater exploration works carried out over the past few years have not helped.

Ten international oil and gas companies spent a total of $1.65 billion over 2009-2012 in deepwater exploration off shore Indonesia, but failed to fi nd commercially viable hydrocarbon reserves, a document from the Energy and Mines Ministry showed.

Some of these companies have relinquished their blocks, but offi cials argue that a failure by some should not be taken to mean that Indonesia’s deepwater areas are not prospective.

“We can’t [say] deepwater [fi elds] are not economically viable just by looking at

the document. Deepwater fi elds still have the potential to be explored ... I believe that there are areas that remain unexplored [that could hold resources],” Gde Pradnyana, deputy chief of operations at upstream regulator SKKMigas, said in January.

Priagung Rakhmanto, a Jakarta-based oil and gas analyst, says adequate incentives, regulatory certainty and enough data on the acreage are needed to exploit Indonesia’s deepwater potential.

Concerns about declining production and rising demand have prompted Jakarta to revisit its fi scal regime and discussions are going on about providing a better production split to contractors and easing their tax burden, though no formal change has been endorsed.

Currently the production split between the government and the contractor is 85:15 for oil and 70:30 for gas. But in the frontier fi elds, the split could be increased to 60:40, according to the vice minister for energy and mines, Susilo Siswoutomo.

Source: BP Statistical Review, Credit Suisse research

1965 1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009 2012

500

0

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3500

SOUTHEAST ASIAN OIL PRODUCTION

mbd


SOUTHEAST ASIA

Uncertainty surrounding the domestic market obligation clause in contracts is also seen as a hurdle by oil and gas companies wanting to invest in the country. DMO refers to a certain percentage of oil and gas output that the contractor must commit to the local market. It is generally set at 25%, but can be higher.

“Th e domestic market obligation is implemented on a case-by-case basis. Th is creates uncertainties for developers, as they are uncertain what proportion will be allocated domestically and some projects may have to supply up to 100% sales to the local market,” Wood Mackenzie said in its report.

A recent rise in domestic gas prices could, however, be the catalyst Indonesia needs to spur exploration and development activities. Domestic gas prices for the power and fertilizer sector have risen from $2-3/MMBtu to $5-7/MMBtu.

“Th e new price benchmark appears to be the standard across Indonesia in all

sectors. Th is is a distinct improvement compared to agreements in the past. It signals a shift in the government’s position to allow price increases to refl ect the scarcity of the resource and the higher-priced alternative of imported LNG,” Wood Mackenzie said.

Th is is expected to encourage more upstream exploration and production, which will lead to the development of marginal onshore fi elds and unconventional gas resources, it added.

Malaysia gets innovativeA couple of years ago, Malaysia set itself on the path to reverse its declining hydrocarbon production by using a combination of creative contracts to encourage development of marginal fi elds, enhanced oil recovery techniques to get more out of its giant but aging fi elds, and fl oating liquefaction technology to monetize stranded gas fi elds.

Th e country has halted a decline in its domestic production, with 24 new discoveries made in 2012 alone.

“Malaysia has a target to grow production capacity by 5% per year up to 2020 in order to meet domestic demand growth, whilst sustaining hydrocarbon exports,” Credit Suisse said in its report.

In the EOR space, Petronas, Malaysia’s national oil company has signed two multi-billion dollar contracts: one with US oil major ExxonMobil to enhance recovery from the Tapis, Seligi, Guntong, Semangkok, Irong Barat, Tabu and Palas fi elds located off shore peninsular Malaysia; and another with Shell for two EOR projects off shore Source: BP Statistical Review, Credit Suisse research

1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010

50

0

100

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SOUTHEAST ASIAN GAS PRODUCTION

bcm


SOUTHEAST ASIA

Sarawak and Sabah in the eastern part of the country.

ExxonMobil’s EOR project is slated to start up at the end of 2013, the US oil major said in July, but declined to provide any production fi gures.

Th e Shell EOR projects are expected to result in the recovery of more than 750 million barrels of oil from the two permit areas, Petronas said last year.

“Th e aim [of the EOR projects] is to squeeze another 20-30% more output from producing fi elds,” Credit Suisse analysts said.

Separately, the Malaysian government and Petronas in 2011 launched Risk Service Contracts – a new fi scal regime to encourage investment in the country’s marginal fi elds.

According to Petronas, Malaysia has around 106 marginal fi elds – fi elds which have under 30 million boe of reserves – and these are estimated to hold a total 580 million boe.

Under the RSC arrangement, Petronas remains the project owner while the contractors are service providers. Up-front capital investment is contributed by the contractors, who start receiving payment from fi rst production and throughout the duration of the contract.

Petronas awarded the fi rst RSC to London’s Petrofac and local companies SapuraCrest and Kencana Petroleum for the Berantai fi eld located off shore peninsular Malaysia in January 2011.

Since then it has awarded two more RSCs: Australia’s Roc Oil and Malaysia’s

Dialog won an RSC for the Balai cluster of oil fi elds off shore Sarawak; and Coastal Energy was awarded an RSC for the Kapal, Banang and Meranti or KBM cluster of small fi elds off shore peninsular Malaysia.

Th e Berantai fi eld began producing at 50,000 Mcf/d in October last year.

“Th e third RSC round is widely reported to have attracted over two dozen players, which indicates a growing acceptance of this contracting model,” Credit Suisse said.

To strengthen its commitment to developing marginal and mature fi elds, Petronas in July formed Vestigo Petroleum – a subsidiary dedicated to this eff ort.

“Vestigo aims to optimize production from clusters of small, marginal and mature fi elds through operational, technical and cost-eff ective methods,” Petronas said while announcing the set-up of the new unit.

One of the strategic objectives of Vestigo is to build niche technical and

Source: BP Statistical Review, Credit Suisse research

1965 1969 1973 1977 1981 1985 1989 1993 1997 2001 2005 2009 2012

-1500

-2000

-1000

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0

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SOUTHEAST ASIAN OIL SURPLUS/DEFICIT

mbd


SOUTHEAST ASIA

executional capabilities in the development and production of small and marginal fi elds which can later be replicated for the company’s overseas ventures, Petronas Carigali President Anuar Taib said.

Focus on frontier basinsWith oil and gas reservoirs in the Cuu Long and Nam Con Son basins maturing, Vietnam has turned its attention to the challenging Song Hong Basin, where the gas is believed to have a very high CO2 content, and the frontier Phu Khanh Basin.

Italian oil company Eni’s drilling program in two blocks – 120 and 105-110/04 – in the Song Hong Basin and Phu Khanh Basin could open up new plays that participants are keenly looking forward to.

KrisEnergy, a Southeast Asia-focused oil and gas independent, which is partnering Eni in the two blocks, said in July that there are some very large prospects in the two blocks that the companies are targeting.

“With oil production in decline since 2004, Vietnam is increasing eff orts to accelerate exploration eff orts and we expect this to trend more toward virgin, off shore areas, and often this comes in partnership with IOCs [international oil companies],” Credit Suisse said in its report.

According to Wood Mackenzie, Vietnam holds about 4.78 billion boe of total remaining reserves, 62% of this being gas. Wood Mackenzie estimates total YTF potential in Vietnam at 2.43 billion boe of liquids and gas.

Th e consultancy pointed out that because of low gas prices and a lack of infrastructure, a large portion of Vietnam’s gas reserves has remained undeveloped.

“Gas prices in Vietnam have historically been very low, which has hampered development of gas fi elds,” it said.

Th ere are signs that prices are rising, however. Recently, PV Gas has been increasing the price of gas sold to industries and fertilizer plants. Prices have risen from $8.35/MMBtu to $10.55/MMBtu, Wood Mackenzie said.

Similarly, gas sold to fertilizer plants in Phu My and Ca Mau has gone up by 40% from $4.59/MMBtu to $6.53/MMBtu.

Gas sold to the power sector has not seen the same levels of increase. “As the power sector still consists of 80% of the total market, pricing reform in this sector will be needed to attract upstream investments,” Wood Mackenzie said.

Myanmar is widely seen as a hotbed for E&P activity going forward given its Source: BP Statistical Review, Credit Suisse research

1970 1974 1978 1982 1986 1990 1994 1998 2002 2006 2010

20

10

0

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40

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50

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SOUTHEAST ASIAN GAS SURPLUS/DEFICIT

Bcm


SOUTHEAST ASIA

vastly unexplored terrain, growing domestic demand and proximity to readymade markets such as Th ailand, China and India.

“Th e proposition in Myanmar is compelling due to the high success with very little exploration so far,” Credit Suisse said. “Off shore Myanmar is primarily dominated by gas, although not much exploration has taken place. Most of the shallow off shore is very under-explored and the entire deep off shore is unexplored.”

Until a couple of years ago, it was national oil companies from Th ailand, China, South Korea and India that dominated Myanmar’s upstream sector. But following the easing of sanctions in April 2011, international oil and gas companies have been falling over each other in their eagerness to secure a foothold in the country.

Huge prospectsMyanmar is estimated to hold 17.5 Tcf of gas reserves and 3.2 billion barrels of crude oil, according to its energy ministry. It has three main prospective basins in off shore: Rakhine, Moattama and Tanintharyi. Th e country’s biggest gas project, Yadana, is located in the Moattama Off shore Basin and is producing 800,000-900,000 Mcf/d of gas.

According to existing seismic data, some interesting prospects for hydrocarbons were encountered in Pliocene, Miocene and Pre-tertiary sediments of the Rakhine and Tanintharyi basins.

“Th is is [a] very good indication for hydrocarbon exploration in deepwater [areas],” Th an Tun, director of the off shore department at state-owned

Myanma Oil and Gas Enterprise, said in March.

While the nascent nature of Myanmar’s upstream sector provides opportunities, it also comes with its own set of challenges.

According to a report published in June by the World Economic Forum, a key risk to the development of Myanmar’s upstream sector lies in MOGE, which plays a pivotal role in the upstream sector.

MOGE’s expertise lies in onshore operations, which are run by its own technical staff , the report said, adding that it has limited experience of off shore operations. According to some stakeholders, it lacks the technical capabilities required to even review the fi eld development plans drawn up by international oil companies.

Th e other challenges include a lack of fi nancing, poor technical equipment, and not enough skilled manpower.

Th e WEF report, however, applauded the steps taken by the Myanmar government to strengthen its energy sector, such as the creation of the National Energy Management Committee and an Energy Development Committee to strengthen coordination and planning among the energy sector’s institutions.

Myanmar is estimated to hold 17.5 Tcf of gas reserves and 3.2 billion barrels of crude oil ... – Myanmar energy ministry“

”

JAPAN

24 insight OCTOBER 2013

In 2010, Japan put in force a regulation requiring a minimum cracking-CDU ratio of 13%, and in the last three years, refi ners have opted to cut refi ning capacity in their bid to comply before the deadline of March 2014. Most of them have opted not to install expensive new units such as cokers and residual fl uid catalytic

crackers in view of sluggish domestic demand.

Even when refi ning capacity is ultimately cut to 3.94 million b/d by the end of March 2014, the deadline to comply with the regulation, refi ners are likely to see only a temporary relief from the current glut in oil products as demand at home continues on a downward spiral, according to industry sources and analysts.

Th e residue cracking ratio is calculated by dividing the cracking capacity (RFCC, residue hydrocracker and coker) with the crude distillation capacity. Before the 2010 regulation, the residue cracking ratio was around 10%.

Nobuo Tanaka, former executive director of the International Energy Agency, pointed out that in the wake of the regulation, some market consolidation and restructuring were inevitable in the face of Japan’s increasing surplus refi ning capacity over domestic demand. Now a special adviser and global associate for energy security and sustainability at the Institute of Energy Economics, Japan, an affi liate of the Ministry of Economy,

JAPAN’S REFINING CONTRACTIONMORE ACTION

AHEAD?As residue cracking regulation kicks

in, Japanese refiners hope for better

profit margins despite sluggish

domestic market

TAKEO KUMAGAITokyo News Editor


JAPAN

Trade and Industry, Tanaka said that some major shifts in market structure were likely.

So what are the various refi ners doing to ensure compliance with the regulation as the deadline looms? TonenGeneral, for instance, plans to hike the capacity of a heavy oil cracking/desulfurization unit at its Kawasaki plant to 34,500 b/d from 31,000 b/d by March 2014. Th is is in addition to reducing its refi ning capacity by 105,000 b/d by March next year.

Cosmo Oil, meanwhile, is still mulling over the merits of scrapping another CDU or increasing the nameplate capacity of a coker at its 100,000 b/d Sakai refi nery. It would certainly not opt to close another entire refi nery, Cosmo’s President Keizo Morikawa told reporters in March this year. Cosmo has already announced its decision to shut the 140,000 b/d Sakaide refi nery and is looking at increasing the capacity of the Sakai coker to 29,000 b/d from 25,000 b/d, Morikawa said at the time.

“It would be suffi cient if our 4,000 b/d increase in capacity [at the Sakai coker] is approved by the government,” he said. “In order for the increase to be approved ... we are required to make a certain investment [at the facility] ... We are currently examining whether we can respond to the regulations [that way],” he added.

Cosmo Oil plans to turn the facility into an oil storage terminal.

With the closure of the Sakaide refi nery, Japan’s installed refi ning capacity fell to 4.33 million b/d.

In August, however, Japan’s refi ning capacity increased to 4.34 million b/d

after Toa Oil, a Showa Shell group refi ner, hiked the capacity of its sole CDU at the Keihin refi nery in Tokyo Bay to 70,000 b/d from 65,000 b/d. Toa Oil’s move was aimed at improving effi ciency and increasing fl exibility of its 27,000 b/d coker.

Apart from Cosmo Oil and TonenGeneral, refi ners Idemitsu Kosan and JX Nippon Oil & Energy plan to mothball the 120,000 b/d Tokuyama CDU and 180,000 b/d Muroran CDU by the end of March 2014.

As a result of all these changes, a gradual supply tightness is likely for oil products after April next year. Industry sources, however, expressed skepticism about how long the eff ect of the capacity cuts would last, given the demand-supply situation during the heavier-than-usual peak refi nery turnaround season this year.

Close to 1 million b/d of Japan’s refi ning capacity was shut due to scheduled and unscheduled maintenance over May-June. After that, Japan’s oil products market witnessed an uptick in gasoil demand due to early signs of economic recovery led by Abenomics, the popular name for the economic policy being pursued by Prime Minister Shinzo Abe since he took over offi ce in

JAPAN REFINING CAPACITY OVER 2008-2013

Year Number of refi neries Total Refi ning Capacity

March 2009 29 4.89 mil b/d

March 2010 28 4.79 mil b/d

March 2011 27 4.62 mil b/d

March 2012 27 4.5 mil b/d

March 2013 26 4.47 mil b/d

March 2014 23 3.94 mil b/d

Source: Data based on company announcements


JAPAN

December last year. It consists of massive monetary easing, fi scal spending and a series of reforms aimed at freeing up businesses.

Gasoil is used in Japan as transportation fuel for trucks, for power generation, and in the agriculture and mining sectors.

Independent oil economist Osamu Fujisawa estimated Japan’s gasoil demand would rise about 2-3% this year from 2012 levels as a result of the impact of Abenomics.

Mid-term oil demand outlookAnalysts and industry players are in agreement when it comes to Japan’s oil demand outlook – that demand will continue to decline as a result of decreasing population, improved effi ciency of fuel use, and the deliberate shift to alternative fuels.

Since annual oil product sales peaked at 246.81 million kiloliters (4.24 million b/d) in 1996, volumes sold have been falling except for the rare occasion when it shows a year-on-year hike, according to METI data.

Th e one exception is fuel oil demand for thermal power generation. Th is is expected to play a key role in Japan’s total demand for oil products in the short to mid-term. Fuel oil has been driving demand following the fall in nuclear power output in the wake of the devastating March 2011 earthquake and tsunami and the subsequent nuclear outages.

In 2012, Japanese refi ners and importers sold 199.84 million kiloliters (3.43 million b/d) of oil products in the domestic market, up 3.5% from a year

earlier, as fuel oil sales surged 37.4% year on year to 28.28 million kl (486,000 b/d), according to METI data.

Since July this year, Japan’s power utilities have begun applying to the Nuclear Regulatory Authority asking for an assessment of whether their nuclear reactors are in compliance with the country’s new safety standards that came into eff ect on July 8.

Th is is the fi rst step toward restarting the nuclear reactors, but it remains unclear how long the NRA will take to carry out the checks. It is also unclear as to who will have the fi nal say on whether to restart or not.

But looking ahead, Japan’s fuel oil demand for power generation is expected to be about 100,000 b/d in 2020 when the country is forecast to have 3.24 million b/d of domestic oil demand, Fujisawa said. Th is is nearly as much fuel oil as was bought by all the major Japanese power utilities in 2010, according to data compiled by the Federation of Electric Power Companies.

“As I forecast domestic oil demand to be about 3.235 million b/d by 2020, so crude throughput will be about 2.75 million b/d in 2020,” Fujisawa said.

“Th is means [the country] would need to cut another 500,000 b/d from [the installed capacity of ] 3.93 million b/d at the end of March 2014 because the required nameplate CDU capacity [is expected] to be 3.43 million b/d [in 2020],” he added. “In the face of domestic demand decline, there are chances that we may see mergers as a result of corporate reorganization.”


JAPAN

Commenting on some local refi ners’ plans to hike oil product exports, Fujisawa said this was not economically feasible as more new refi neries are coming up in China and the Middle East between now and 2015. And all the oil products from these countries will come into the Asian markets, he added.

Cosmo Oil decided to close the Sakaide refi nery because of the poor outlook for oil product exports. According to the mid-term oil market report released by the International Energy Agency in May, oil products output in the Middle East will reach 10.5 million b/d by 2018, while China will be able to churn out 17.71 million b/d by 2018, up from 13.41 million b/d at the end of 2012.

Some domestic refi ners may, however, hike their sales of oil products overseas without sourcing the material from Japan, industry sources said. For instance, Idemitsu Kosan plans to expand its Singapore trading operations over the next three years, according to its new president, Takashi Tsukioka.

He said in June that the company was looking at supplying oil products to Australia, but securing the volumes in Singapore rather than sending them from Japan. “We have started leasing tanks in Singapore,” he said, adding that the tanks would be used not just as storage for hedging but also for blending products such as gasoline to sell to Australia or New Zealand.

Idemitsu acquired Brisbane-based Freedom Energy Holdings in December 2012. Before that, in June 2010, it

acquired US oil products wholesale unit New West Petroleum.

As late as June this year, METI said that Japan’s demand for oil products was expected to fall by an average of 1.8% annually in the next fi ve years to hit 162.17 million kl (2.79 million b/d) in fi scal 2017-2018. Th e Japanese fi nancial year runs from April to March.

On June 12, METI released its fi ve-year outlook for oil products and LPG for the fi rst time since the March 2011 earthquake. It usually carries out this exercise annually but the quake and tsunami made for a lot of uncertainty when it came to forecasting demand. Th e previous fi ve-year forecast was released in April 2010.

METI’s latest fi ve-year oil demand outlook excludes a forecast for fuel oil for power generation, however. In fi scal 2013-2014, Japan’s fuel oil demand for power generation was 19.615 million kl or 338,012 b/d.

In the fi ve years to March 2018, Japan’s gasoline demand is expected to fall by an average of 1.7% every year to 891,100 b/d as an aging population buys fewer cars and vehicles become more fuel effi cient. Gasoil demand is also expected to fall by an average of 1.1% to 544,972 b/d due to fewer trucks being bought. And kerosene demand is expected to decline by an average of 3.2% to 278,543 b/d due to a switch in heating fuels.

With all the demand destruction that is forecast for the future, Japan’s refi ning sector is likely to see much more reorganization and restructuring as it tries to balance refi ning capacity with domestic demand.


DIESEL

Th e writing is on the wall: An expected diesel glut looms east of Suez in the coming years, while demand in Europe, the biggest sink for the middle distillate, is forecast to continue to shrink.

A relentless growth in refi ning capacity in China and India, a slew of mega projects coming up in the Middle East, and refi nery upgrades in Russia, along with a rising fl ow of surplus US product crossing the Atlantic – especially ultra

low sulfur diesel – represents a new tidal wave in the global downstream sector.

And it’s making the export-dependent refi ners in Asia re-examine their marketing strategies.

South Korean refi ners, facing stagnant domestic demand and the gradual decline of China as an export market, are looking at Japan, Australia and Hawaii as export destinations, Ryu Yul, executive vice-president at S-Oil, the country’s third-largest refi ner, told the Asia Oil and Gas Conference in Kuala Lumpur in June.

Th at does not bode well for the Koreans. True, Japan is mothballing about 1.12 million b/d of capacity between 2010 and March 2014, the deadline for refi ners to comply with a government regulation requiring a minimum cracking-CDU ratio of 13%. But that can hardly be expected to make the country any more reliant on imports than it is today.

Japan has excess installed capacity, and a declining to fl at domestic demand trend. With a utilization rate of just over 80% of the “operable refi ning capacity”

REFININGGET READY FOR

ANOTHER MAKEOVERA possible glut of oil products thanks

to major refining capacity expansions

in the Middle East and Asia, coupled

with rising flows out of the US and

declining demand in Europe, pose

new challenges for export-oriented

refiners in Asia

VANDANA HARIAsia Editorial Director,Singapore


DIESEL

of 4.32 million b/d, the country exported an average of around 472,000 b/d of products in the fi rst seven months of this year, while importing around 608,000 b/d.

In Australia, Shell shuttered its 79,000 b/d refi nery in Sydney last year, and Caltex is poised to mothball its loss-making 135,000 b/d Kurnell refi nery in the same city in the second half of 2014.

Th e two closures, along with Mobil’s 78,000 b/d plant that was shut in mid-2003, will leave the country dependent on imports for roughly half its needs of around 1 million b/d of oil products.

But any incremental demand from Australia after the Kurnell shutdown would be more than off set by a gradually increasing self-suffi ciency in fellow importer Vietnam.

Even if one regards Hanoi’s stated objective of having a total refi ning capacity of 1.2 million b/d – nearly 10 times the current capacity – by 2025 a pie in the sky, a couple of projects right now have enough momentum to justify the optimism. Th ese include the Vietnam-Japan-Kuwait joint venture 200,000 b/d Nghi Son project, expected to start up in 2017.

Any of the subsequent developments, such as the 160,000 b/d wholly foreign-owned Vung Ro refi nery or PetroVietnam’s 200,000 b/d Long Son project, will tip Vietnam into a surplus of refi ned products.

Hawaii, with a population of around 1.4 million and average oil demand in the vicinity of 117,000 b/d as per fi gures

from the Hawaii State Energy Offi ce, is a limited export market.

Indonesia, a regular importer of gasoil in Asia, this year began mandating a higher blending ratio of biodiesel in an eff ort to reduce gasoil imports and government spending on fuel subsidies. Th e measure, which made 20% biodiesel blending compulsory for power utilities and plans to hike the ratio to 10% for other uses of the middle distillate, could cut imports by as much as 76,000 b/d in 2014, according to deputy energy minister Susilo Siswoutomo. While the blending target is ambitious and would be contingent on the availability of additional domestically produced biodiesel, among other factors, if successfully implemented, it would squeeze out a substantial chunk of Indonesian import needs, which currently stand at around 98,630 b/d.

Indonesia, a regular importer of gasoil in Asia, this year began mandating a higher blending ratio of biodiesel in an eff ort to reduce gasoil imports and government spending on fuel subsidies. Th e measure, which made 20% biodiesel blending compulsory for power utilities and plans to hike the ratio to 10% for other uses of the middle distillate, could cut imports by as much as 76,000 b/d in 2014, according to deputy energy minister Susilo Siswoutomo. While the blending target is ambitious and would be contingent on the availability of additional domestically produced biodiesel, among other factors, if successfully implemented, it would squeeze out a substantial chunk of Indonesian import needs, which currently stand at around 98,630 b/d.

Unlike Japan, attrition is not the route the South Korean refi ning sector is taking. Refi ning capacity was boosted in the


DIESEL

1990s to cater to growing domestic demand, but had a low upgrading ratio – cracker capacity averaged 21% versus a global average of 33%. Th e refi ners suff ered their fi rst hit as consumption stalled with the onset of the 1997 Asian fi nancial crisis.

Th e second jolt came in the form of competitive threat from new high-complexity private refi neries in India, and the South Korean refi ners responded by pumping in billions of dollars over 2007-2012 to upgrade their facilities.

Meanwhile, China diminishing as an export market for the Korean refi ners is inevitable.

China refi nery expansionsChina is adding an estimated 1 million-1.2 million b/d of refi ning capacity over 2012-2013 and looks set to grow its downstream sector by an average of 1 million b/d annually over 2014-2018.

Average nationwide refi nery operating rates were 77% in 2012 and 79% in the fi rst eight months of this year. As the country piles on refi ning capacity, utilization rates could drift lower, including at the newer plants. But that is unlikely to stand in the way of China continuing to build capacity as a policy.

Despite the lackluster run rates, China’s oil product exports jumped 23% from a year ago over January-July, averaging 2.4 million mt a month or about 620,000 b/d. While imports are still higher, the country’s net imports over the same period declined by 16% to an average of around 300,000 b/d, according to offi cial data.

Conventional wisdom has it that China expands its refi ning capacity to be self-suffi cient and is not just uninterested in the

export market, but will actually remain restrictive in this regard, except possibly for Sino-foreign joint venture projects. Th e proposed 260,000 b/d Tianjin refi nery in northeastern China by Russian Rosneft (49%) and state-owned China National Petroleum Corp. (51%) last year received the right to export products.

While Chinese refi ning capacity grows apace, growth in consumption has been slowing this year, with apparent demand over January-July as calculated by Platts up only 4.3% from a year ago – a pale fi gure for China – at 9.86 million b/d. More signifi cantly, perhaps, gasoil demand in the fi rst seven months of the year was 1% lower from the year before.

Chinese demand is once again expected to catch up with downstream capacity growth only by 2020, according to consultants Wood Mackenzie.

Running on full tankIndia’s current and upcoming refi ning capacity creep, while sharing the basic Chinese principle of meeting rising domestic demand, does diff er in some key attributes.

First, the country currently has a surplus of around 1.16 million b/d, mostly with the private refi ners Reliance Industries Limited and Essar Oil that are export oriented. A steady growth in capacity in the public sector that is aimed at satisfying domestic demand, could hike exports by the private refi ners.

Second, unlike China, India’s refi neries typically run fl at out or even above 100% of capacity utilization.

Diesel accounts for nearly 60% of Reliance and Essar’s combined product


DIESEL

exports, with gasoline a distant second at around 15%.

Th e public sector refi ners, including Indian Oil Corp., Bharat Petroleum Corp., Hindustan Petroleum Corp., Mangalore Refi nery and Petrochemicals and upstream player Oil and Natural Gas Corp., export mostly naphtha and fuel oil.

Th e Middle East and Europe are the top two destinations for India’s diesel exports, and together absorbed 56% of the barrels in 2012, according to US-based consultancy Energy Security Analysis. East Africa and Latin America accounted for 14% each.

Even as the Middle East and Europe become smaller markets for India’s diesel in the coming years – for different reasons – the country plans to continue growing its refining capacity.

India added just over half a million barrels per day of capacity over 2011-2013, and while new projects abound, conservative estimates by Platts show at least another 734,000 b/d being brought on stream over 2014-2016.

Th e other side of that equation – domestic demand growth – is suddenly not looking so good.

Oil product sales over January-July this year increased a tepid 2.4% year on year to around 3.43 million b/d, according to government data. Th is year’s unprecedented depreciation of the rupee against the US dollar, a steady increase in pump prices, runaway infl ation and a slowing economy could conspire to push

demand growth even lower in the coming months or even years.

Th at would impact domestic gasoil consumption more than gasoline, as has been the case this year. Gasoil use, which accounts for roughly 45% of Indian refi ned products consumption, inched up 1.6% year on year in the fi rst seven months of 2013, while gasoline, which is about a tenth of the total demand, was up 9%.

Around 46% of car sales in India are diesel-powered, though this fell to 42% in the April-June quarter, according to JD Power, which, like Platts, is a unit of McGraw Hill Financial.

Car sales in the country were below the corresponding year-ago fi gures for nine straight months to July.

Th e oil ministry’s Petroleum Planning and Analysis Cell pegs India’s current installed refi ning capacity at 215.07 million mt/year, or about 4.32 million b/d.

Audience response to a survey question at the Platts annual Mumbai Commodity Forum in September, 2013

SHOULD INDIA HOLD BACK ON REFINING CAPACITY ADDITIONS BECAUSE OF THE LOOMING SURPLUS IN ASIA AND THE MIDEAST?

0

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Yes, it will become progressively

difficult to export surplus product

and refiners will suffer

No, because domestic demand

will quickly catch up with the

higher capacity

No, because refining is a cyclical

business and exports could

become lucrative again


DIESEL

Based on the current projects most likely to materialize, Platts calculates the country will have a capacity of about 251.62 million mt/year or 5.03 million b/d by 2016-2017.

Th e PPAC earlier this year estimated domestic demand at the time would be around 186 million mt/year. Average annualized demand in the second quarter of 2013 was 161.17 million mt/year.

So the surplus production looking for export markets is expected to grow to around 1.4 million b/d. In itself, a rise of about 200,000 b/d in the surplus from the current fi gure over the next three years is not too worrying. But that assumes a healthy 15% rise in Indian consumption to 2016-2017, which would be unattainable if the growth remains around the current levels of 2-3% per annum.

Th reat across the seasTh at’s not the only threat for Reliance and Essar, or for that matter, the refi ners in South Korea. Th eir markets are also being squeezed by rising exports from the US, and competitive threat looms from a wave of greenfi eld and brownfi eld expansion projects planned and underway across the Middle East.

Th ese will not just make the region more self-suffi cient, but actually turn it into an exporter, especially of diesel.

Th e fi rst of these mega projects, the high-complexity 400,000 b/d Jubail refi nery in Saudi Arabia, is expected to begin churning out products in December. With 235,000 b/d of ultra low sulfur diesel production, this JV between Total and Saudi Aramco is expected to turn the country into a net exporter of diesel. Th e ULSD would be aimed at the European market, as Saudi Arabia consumes 500 ppm.

Th e other Saudi project on the horizon is the 400,000 b/d Yanbu refi nery, a joint venture between Aramco and China’s Sinopec, which is expected to be ready by 2016. Th is refi nery is expected to churn out around 263,000 b/d of ULSD.

In the UAE, Abu Dhabi National Oil Company is expected to complete the expansion of the Ruwais refi nery from 400,000 b/d to 817,000 b/d by 2015, a time frame estimated by Asia Pacifi c Energy Consulting for the actual start of commercial operations, in contrast to the offi cial early-2014 schedule, which it says likely refers to mechanical completion.

SAUDI ARABIA

EGYPT

SUDAN

YEMEN

OMAN

UAE

IRAQ

IRAN

KUWAIT

Yanbu, 400 kb/d, 2016 (e)

Iraq, various, total 700 kb/d by 2018 (e)

Rabigh, phase 2, upgrade work, 2016 (e)

Duqm, 250-300 kb/d, after 2018 (e)

Ruwais Expansion, +417 kb/d, 2016 (e)

Jazan, 400 kb/d, after 2018 (e)

Al Zour, 615 kb/d, by 2020 (e)

Fujairah, 200 kb/d, 2016 (e)Jubail, 400 kb/d,

2013 (started)

Las Raffan 2, 146 kb/d condensate

splitter, 2016

MIDEAST CAPACITY EXPANSIONS

(e) refers to estimated timeframe for project start-up

Source: Platts


DIESEL

Separately, ADNOC plans to shift its entire gasoil production from 500 ppm to 10 ppm by 2016.

Th e timelines for other Saudi developments, including a 400,000 b/d refi nery at Jazan and upgrade of the Rabigh refi nery, are farther out, and less certain at this point.

Th e same goes for major greenfi eld and upgrading projects elsewhere – among them in Kuwait, Oman and Iraq. If all of these get off the ground, along with Saudi Arabia’s Jazan, they would add an estimated 2 million b/d capacity in the region by 2020.

Th e other more immediate threat to exports by Asian refi ners is the US’ growing role as a supplier of refi ned products to the world markets. After fl ipping from being a net importer to a net exporter in February 2011, the tight oil boom has steadily pushed up US’ net exports of refi ned products to an average of around 1 million b/d.

Th e country is exporting products ranging from LPG to petroleum coke. Diesel accounts for the biggest share, with barrels fl owing to South America, France, Italy and the Netherlands, according to data from the US Energy Information Administration. June exports of “distillate fuel oil” of less than 15 ppm sulfur – the US nomenclature for ULSD – averaged 890,000 b/d, the highest since January 2009, when the EIA began collecting data.

US gasoline and blending components, which go mostly into Latin America, Canada and Nigeria, are also seeing a rising outfl ow.

Another development that in isolation might not have caused any tectonic shifts but could now pile on the pressure, is planned refi nery upgrades in Russia by 2018, aimed at reducing fuel oil output in favor of higher value products. Th e International Energy Agency in its medium term outlook released in May, said though the refi nery modernization program is behind schedule, the impact is already visible, with Russian 10 ppm diesel exports surging 12% year on year in 2012.

“As upgrading is accelerating, it is likely that Russian exports of low-sulfur diesel will keep on increasing, fi nding outlets in North Europe, in Turkey and the Mediterranean. Low-sulfur diesel exports from Russia could rise to about 300,000 b/d in the coming years,” the IEA said.

Against this backdrop is European oil products demand, which has fallen by 7-8% since the start of the economic slowdown, according to industry group Europia.

While around 3 million b/d of capacity has been shut in Europe since 2008, an additional 600,000 to 900,000 b/d needs to close, according to various estimates. But even if that capacity disappears, it would be dwarfed by all the new barrels from Asia, the Middle East and the US looking to flow into that market. The IEA expects European refined products demand to decline to 14.2 million b/d in 2013 from 14.4 million b/d in 2012, and slip further to 14.1 million b/d in 2014, according to its August monthly report.


ASIA ETHANOL

Making green and renewable fuels mandatory seemed the right thing to do when crude prices hit more than $145/barrel in May 2008 and concern over long-term energy security was on every country’s radar. Th at was when a number of countries in Asia Pacifi c announced ethanol or biodiesel blending requirements.

Fast forward to 2013 and the Philippines and Th ailand seem really committed to these long-term goals. Th e rest seem to have gotten mired among mandates and logistics.

Indonesia has a 2% ethanol mandate, but it is not implemented as the price is high in spite of subsidies and consumers are not willing to pay the cost of going green, explained Budiman Ricardo Saragih from the Directorate of New, Renewable Energy and Energy Conversation.

Vietnam has six ethanol plants with a combined design capacity of 535 million liters/year. Most were operating below design capacity due to feedstock supply problems and poor production margins.

But Vietnam has some time to work on its E5 mandate, which is to come into eff ect in December 2014 in fi ve large cities and two provinces, and nationwide by 2015.

India has an E5 ethanol mandate in place since 2008, which requires oil companies to sell petrol blended with at least 5% of ethanol. Five years on, oil companies have sourced just 440 million liters of ethanol against a target of 1.05 billion liters for the 5% mix. Th e blended petrol is available only in 13 out of 28 states, and even there, the extent of blending is just 2%. Its goal of a 20% biofuel blend by 2017 looks tough to achieve, according to market sources.

Australia was an early entrant into the biofuel sector with New South Wales the fi rst state to introduce an ethanol mandate in October 2007. But in the absence of a federal mandate, limited plant capacity and high excise tax on imports, the country’s ethanol policy has faltered.

Australia’s ethanol mandates are strongly opposed by various groups – farmers,

ASIAN ETHANOL MANDATES

SHIFTINGGOALPOSTS

Asian countries try to stick to their

goals on ethanol mandates with

Thailand and the Philippines leading

the way on a thorny path

ESTHER NGAgriculture Associate Editor,Singapore


ASIA ETHANOL

service station operators, motoring and marine groups, feedstock manufacturers, environmentalists – who argue that in the years when grain production is low, the artifi cial and infl exible demand created by the mandate would infl ate grain and hence food prices.

Th ey also point out that the production costs are higher than for regular gasoline, and that ethanol mandates only benefi t a handful of producers gaining monopoly in a captive market.

In short, problems such as feedstock, production under-capacity, lack of investment in operations, and the political environment, hinder the march toward fulfi lling these mandates.

Sticking to goalsTh e Philippines was to have fully implemented its E10 mandate, making it compulsory to sell unleaded, premium and special gasoline products with at least 10% ethanol blended in, on April 1, 2013. But it has been postponed twice so far.

While the Department of Energy did not give a reason for the postponement, market sources said that local ethanol production was insuffi cient to meet the mandate.

Th e supply tightness with Th ailand not exporting anhydrous ethanol after phasing out 91 RON gasoline on January 1, and exports coming mainly from the US, possibly prompted the authorities to stop and consider whether the E10 mandate could be implemented nationwide.

As of July 2013, 97 RON gasoline is still exempt from being blended with 10% ethanol, or blending with 10%

bioethanol is optional, due to “logistical and compatibility issues” raised by petroleum companies.

In spite of this hiccup, the Philippines remains committed to fulfi lling its ethanol mandate.

At a Platts energy forum held in Manila in July, Zenaida Y. Monsada, director of the Oil Industry Management Bureau at the Department of Energy, said that there was “close to 90% compliance” on the E10 mandate nationwide, admitting, however, that there were challenges to implementation in far-fl ung areas.

She reiterated that the government had no intention of moving away from the 10% ethanol blending mandate.

Th e Biofuels Act of 2006 became law in January 2007 and mandates that ethanol-blended gasoline comprise at least 5% of the total amount of gasoline sold in the country from February

Source: Kingsman

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

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20

25

30

35

40

45

PHILIPPINES ETHANOL IMPORTS

MILLION LITERS

2009 2010 2011 2012 2013


ASIA ETHANOL

2009, and 10% by February 2011. Full implementation of the E10 mandate was scheduled for February 6, 2012. Th e country sought to implement the mandate partially in August 2011.

According to data from the Department of Energy, local ethanol production can currently meet some 17% of the country’s requirement of around 380 million liters/year, while 83% is imported.

A dependency on exports, which make up some 80% of the Philippines’ ethanol supply, not only adds a hefty bill to the treasury, but could also aff ect its energy security if ethanol prices worldwide shoot up due to El Nino, bad weather, and increased demand from other countries.

Th e Philippines has four ethanol producers: San Carlos Bioenergy Corp., Leyte Agri Corp. and Roxol Bioenergy Corp., each with a production capacity of 30 million liters/year, and Green Futures Innovations with the ability to

output 54 million liters/year. All four plants use sugar cane or molasses as feedstock.

One of the main diffi culties for the mills is securing feedstock, with small and fragmented farms unable to reap economies of scale. According to the Sugar Regulatory Authority, there are about 59,600 sugar cane farmers in the country, but less than 1% have farms bigger than 100 hectares, and 79% have landholdings of less than 5 hectares. Th e Philippine land reform policies prevent consolidation of farms and thus prevent small-scale operations from becoming more effi cient.

Unreliability of feedstock supply, fl uctuations in price and operational issues have led to under-capacity, with some plants operating at 50% of capacity, market sources said.

In the past two years, the price of molasses has soared. Th e price of ex-mill molasses in September, at the start of the 2011-2012 crop year, was Pesos 2,600 ($60)/mt. It then rose incrementally to Pesos 6,321.67/ mt in July, before dropping to Pesos 6,255/mt in August to close the year. Mill-site prices for molasses for the current 2012-2013 crop year reached Pesos 6,625/mt in June, before falling to Pesos 6,125/mt in July, data from the Sugar Regulatory Authority showed.

“If you can control your feedstock, production will be sustainable,” said San Carlos BioEnergy’s former CEO Romeo Sangalang. “But if you have to rely on market forces for it, then it is not good.”

Th en, there is the competition from sugar. In 2010, San Carlos’ 30 million

Source: Kingsman

PHILIPPINES DENATURED ETHANOL IMPORTS BY COUNTRY

MILLION LITERS

0

30

60

90

120

150

180

VietnamThailandSingaporePakistanSouth KoreaIndonesiaChinaUSAEU

201220112010


ASIA ETHANOL

liters/year ethanol plant at Negros Occidental was converted to produce sugar syrup on the back of bullish sugar prices. Margins and economics for ethanol production had turned negative due to intense competition from the sugar industry and San Carlos did not supply ethanol to local refi ner Petron for a year.

A Department of Energy offi cial, who did not want to be named, admitted that “if the sugar cane price is higher than the price of ethanol, then the local ethanol producers would rather produce sugar.”

Critics of the ethanol mandates point out that adding it to gasoline to the extent of 10% has not led to a drop in prices at the pump. Local ethanol is more expensive. It costs Pesos 47/liter versus Pesos 30/liter for imported ethanol. Furthermore, of the Pesos 47/liter price of ethanol, farmers get only around 50 centavos. Th e ethanol program is benefi ting mainly producers and traders, the critics added.

During the Platts forum, several voices were raised against the Biofuels Act, with those opposed arguing that development of biofuels must not compete with food security.

Th e Department of Energy said that the country’s sugar and coconut industry regulators had identifi ed areas for biodiesel and bioethanol production and that production allocations by market destinations were strictly regulated, with those found violating the rules subject to stiff penalties.

“When it comes to feedstock regulation for bioethanol, the Sugar Regulatory

Authority has the power to regulate land that can be devoted to bioethanol through the issuance of certifi cation. Sugar is also allowed for bioethanol production but it is only sugar classifi ed by SRA for world export that is allowed, for the time being,” said SRA Manager Rosemarie Gumera. Sugar for the domestic market is priced higher than that for export and bioethanol production, Gumera added.

Meanwhile, Brazilian ethanol producer Raizen Energia is exploring the possibility of setting up production facilities in the Philippines in a joint venture and is looking at tie-ups with possible suppliers of feedstock. Th e company has not yet decided on the capacity of the plant.

Additionally, Philippines-based conglomerate Universal Robina, which owns three sugar mills and a refi nery, started the construction of its 30 million liters/year ethanol plant in April, aimed at reducing the country’s dependency on imported ethanol. Th e plant, located in Manjuyod town in Negros Oriental, is expected to begin operations in March 2014. Th e plant will produce ethanol from blackstrap molasses, a byproduct of sugar.

Cavite Biofuels was to have started on the construction of its 34 million liters/year plant last year, but seems to have hit a bump when it revised the investment estimate from $75 million to $100 million. CEO Job Ambrosio said the company is looking at getting 70% of the fi nancing from a local bank and the rest from private equity investors.

Th e renewable energy law provides certain incentives to investors such


ASIA ETHANOL

as a seven-year tax break, zero value-added tax for the sale of biofuels; operating loss carryover during the fi rst three years of commercial operation deductible from gross income for the next seven years of operation; and special realty tax rates of not more than 1.5% on equipment and machinery, civil works and other improvements.

Investors are, however, also seeking a 20% tax on imported ethanol instead of the current 12%.

Th ailand troublesTh ailand has lofty goals as delineated in its Renewable and Alternative Energy Development Plan for 2012-2021. It aims to hike national alternative fuel consumption to 9 million liters/day of ethanol, 7.3 million liters/day of biodiesel and 3 million liters/day of renewable fuels by 2021.

Th is is expected to reduce dependency on imported energy sources and, at the same time, cut greenhouse gas emissions.

Th ailand’s current consumption stands at 2.2 million liters/day of ethanol and 2.8 million liters/day of biodiesel, comprising 5.5% of the country’s total fuel consumption of 90 million liters/

day. When it announced its targets in 2011, the government said it wanted alternative fuels to comprise 44% of total fuel consumption by 2021.

Some industry participants such as the Federation of Th ai Industries Chairman Phichai Tinsuntisuk have called the targets as too challenging, but Apiradee Th ammanomai, spokeswoman for the Department of Alternative Energy, Development and Effi ciency, has said that Th ailand has enough feedstock to hike its ethanol production.

“We produce 25 million mt/year of cassava, of which about 600,000 mt/year is used to make ethanol. Th ere is potential to produce more ethanol from cassava,” she said. Th ailand’s current ethanol production from cassava is around 120 million liters/year.

Th e country also produces 4 million mt/year of molasses, of which, only 40% or 1.6 million mt/year is currently channeled into ethanol production, Th ammanomai said. Ethanol from molasses amounted to 532 million liters in 2012, up 39% from 381 million liters/day in 2011. It accounts for 80% of anhydrous ethanol production in Th ailand. Th e rest of the 3.4 million mt of molasses were either exported or used to make seasonings for beverages and food.

Cassava-based ethanol production, on the other hand, was 75 million liters/day in 2012, down 27% from 103 million liters/day in 2011. Come 2021, molasses output is expected to be 4.2 million mt/year and cassava output 35 million mt/year. Unless cassava-based ethanol production steps up, molasses-based output will reach its maximum capacity

ANNUAL FUEL ETHANOL 2013 ESTIMATES (MILLION LITERS)

Country Production Consumption Exports Imports

China 2155 2155 0 0

India 750 750 0 0

Japan 25 415 0 390

Pakistan 12 0 12 0

Philippines 95 395 0 300

Thailand 960 880 130 0

Vietnam 40 5 35 0

Asia Total 4037 4600 117 690

Source: Kingsman


ASIA ETHANOL

based on availability of feedstock in a year or two, something which the government is aware of.

It, however, costs more to produce ethanol from cassava rather than molasses, and plants that use the former as feedstock are running at 60% of capacity, ethanol producers said. Plants that use molasses as feedstock are running at 82% of capacity, they added.

Th is is refl ected in prices too with molasses-based ethanol costing Baht 26 (83 cents)/liter, and cassava-based ethanol Baht 29-30/liter.

Th is was partly due to high cassava prices, which was the result of government intervention via the Cassava Pledging Program between February 1, 2012 and March 31, 2013. Th e price of cassava was set at Baht 2.75/kg ($87/mt), which is 50% above market prices. Some cassava-based ethanol plants stopped production altogether as they could not compete with molasses-based ethanol, which is about 27% cheaper.

In May this year, the government scrapped the cassava subsidy as prices recovered amid high demand and are now about Baht 3-3.10/kg.

Also, cassava-based ethanol plants have to shut for fi ve to 10 days every month for maintenance due to the mud, sand and fi ber from the root clogging up the machine, producers said.

Ethanol producer Eastern Power’s Senior Vice President Littisak Wattanavekin disagreed: “Th ose using fresh root have no problem and I believe they are running at 100% capacity. However, if they are using cassava chip, then they

have problems, and are running at 65-70% capacity at best.”

Th e ethanol yield from cassava is about 60-62% against 85% from molasses, he added. Eastern Power uses molasses as feedstock

Th e Th ai government had allocated 62% of domestic ethanol supply to come from molasses and 38% from cassava. Currently molasses-based ethanol accounts for 80% of the market share.

In spite of these diffi culties, cassava-based ethanol producers said that they were confi dent they could raise their market share to 30% in the third quarter, and possibly 38% in the fourth quarter or early next year.

Th ailand’s ethanol consumption is likely to continue to grow due to an increase in the number of E20-compliant vehicles and gasohol stations as the country phases out 91 RON gasoline. Furthermore, gasohol prices remained 10-17% below regular gasoline due to the excise tax and a price subsidy for E20 and E85 (a mixture of 85% ethanol and 15% premium gasoline) gasohol.

Th e government also off ers tax incentives to manufacturers of eco-cars. Excise tax has been cut by Baht 50,000 for E85 cars or fl ex-fuel vehicles and Baht 30,000 for eco-cars.

So the government seems committed to meeting its lofty goals despite all the stumbling blocks. Despite a production shortage, the government refuses to allow Th ai oil companies to import ethanol. A license from the Excise Tax Department is required for imports and so far none has been given. Imported ethanol also incurs a tax of Baht 6/liter or 72 cents/gallon.


CHINA COAL

China’s economic growth has radically altered trade fl ows, revolutionizing the international coal market. It has sparked a boom in domestic coal production, huge spike in power generation capacity and signifi cant shifts in population dispersion. Th e country’s growing dominance in the seaborne market and the trading opportunities arising as a result of it becoming a net importer is

having a butterfl y eff ect on trading patterns and across the industry.

With the shale gas revolution in the US leading to a signifi cant increase in the availability of thermal coal, consumers have wrestled back the upper hand in the market. Once an importer, American coal producers are now competing with Colombia for customers in Europe and Asia. Since 2008, Indonesian output has doubled to exceed 400 million mt and Australian exports have risen by 35% to over 170 million mt.

China’s rapid industrialization and soaring economic growth have been fueled by coal-fi red power plants, with virtually all the coal sourced domestically. It may be producing almost 4 billion mt of coal each year but it is now the world’s largest importer of thermal coal.

Th is has radically changed the end-user dynamics of the Asian seaborne market for thermal coal in just a few years, a market that has traditionally been dominated by Japanese, Taiwanese and South Korean buyers. China’s infl uence as an importer of thermal coal has

CHINA’SCOAL CHASE

China’s love affair with coal

changes the face of global

supply flows

JAMES O’CONNELLEditorial Director,Coal


CHINA COAL

continued to grow with each successive year, and it eventually overtook Japan as the number one importer in 2012.

A huge consumption boom in electronic goods, automobiles and the ever-increasing migration of population from rural areas to urban centers and megacities have been fueling China’s economic growth, leading it to record double-digit GDP growth year after year. It slid a bit in 2012 with the National Bureau of Statistics putting GDP growth at 7.8%. China has undergone a metamorphosis in just fi ve years from being a coal-producing nation and a signifi cant supplier in Asia to becoming a voracious consumer importing from Australia, Indonesia and South Africa, and, to a lesser degree, Russia, Colombia and the US.

Th e urbanization of China has seen traditional three-generation households break up into smaller nuclear family units, while migration patterns from the interior provinces to coastal cities are no longer seasonal, but permanent or semi-permanent.

Over half, 52.5% in 2012, of China’s 1.35 billion people now live in urban areas, a sea-change from 1990 levels when about 26% lived in the cities, according to NBS data. Th is has resulted in a housing boom with each new apartment creating additional demand for white goods and electricity.

Experts suggest this workforce fl ow is unlikely to stop any time soon, with forecasts for China’s urbanization as a proportion of its population ranging between 60% and 70% by 2035.

About 10 years ago, China produced around 1 billion mt/year of coal – more

than enough to satisfy its own fuel and steel-making requirements. Domestic production began to grow, breaking 2 billion mt in 2005. China’s import/export balance for thermal coal began to change dramatically in late 2008 and the swift nature of the transformation caught many market players by surprise.

Change in trade fl owsA prolonged collapse in seaborne market prices for thermal coal in Asia started in late 2008 and, triggered by the global economic crisis, sharply increased the price competitiveness of Australian and Indonesian thermal coal relative to that from China. Th ermal coal prices basis 6,080 kcal/kg net as received at the Newcastle trading hub in eastern Australia slumped as low as $57/mt FOB in March 2009 from a high of $180/mt in July 2008, as drastically slower economic growth in Japan, South Korea and Taiwan led to an unraveling of demand for Australian thermal coal.

Australian coal producers seized on the Chinese market as a potential new demand center for their material, and embarked on an aggressive sales and marketing drive in China to lure and retain new customers. In February 2009, China’s imports of Australian coking coal rocketed to 2 million mt from barely a few hundred thousand in the months before. Th is trend continued, and spread to thermal coal, as Australian producers began selling cargoes to power plants located in China’s coastal areas. Th ese power plants, some equipped with their own vessel unloading facilities that were used for domestic thermal coal, had easy access to the seaborne market and could nimbly respond to arbitrage opportunities because of the diff erence between the price of domestic and imported material.


CHINA COAL

Gradually, Chinese end-users and power plants extended their purchasing activity to take in a wide range of diff erent qualities of thermal coal of varied origin. New trade routes sprang up to service China’s nascent thermal coal demand including Richards Bay Coal Terminal in South Africa to South China ports, Colombia to China via the Atlantic Ocean, and the US to South China via America’s Atlantic and Pacifi c seaboards.

A sustained depression in freight rates following the global fi nancial crisis facilitated the development of these trade fl ows for thermal coal, which previously had traded within two almost hermetically sealed markets centered on the Atlantic and Pacifi c Basins. After peaking in May 2008 at 11,793 points, the Baltic Exchange Dry Index, a barometer of vessel freight costs for bulk commodities such as coal and iron ore collapsed 94% to only 663 points in December that year and traded below 1,000 points from January 2012 to March 2013.

Th e index hit a low of 647 points on February 1, 2013, only rising back to 1,000 points on June 18. It hovered around 1,150 points for most of the summer before iron ore and grain fi xtures boosted it signifi cantly higher. In late August, it began to show daily gains and as of mid-September, it has broken through 1,500 points to trade at 1,651 points on September 17 – the highest since December 2011. However, until very recently the low freight rates, also the product of a glut of available vessels from overbuilding by shipyards, has enabled Chinese traders to continue to purchase coal cargoes from far-fl ung destinations

making competition for buyers in the Chinese market very intense.

Price crash Seaborne prices for Australian and Indonesian thermal coal in the Asian market have traded in a wide range since the global fi nancial crisis. Some prices went on to soar to new records, most notably so in the case of Japanese longer-term supply deals. Japan’s power utilities agreed to pay a new record high price of $129.85/mt FOB for term Newcastle thermal coal with a calorifi c value of 6,080 kcal/kg on a net as received basis for the year ended March 2012.

Prices in these April-March yearly supply contracts only retraced to $115/mt FOB Newcastle for the Japanese fi nancial year from April 2012 to March 2013. In April 2013, in what is an illustration of how the market has shifted and who holds the upper hand in the talks, mining major Xstrata and Japan’s Tohoku Electric settled negotiations at $95/mt.

Market participants said, however, that the July-June yearly contract price appeared favorable to Australian thermal coal producers. Japan’s Tokyo Electric Power Company is said to have agreed on $89.95/mt FOB Newcastle basis 6,322 kcal/kg GAR with its Australian suppliers for shipments over the year starting July 1.

“Th e producers appear to have done well,” said one trader, noting that producers are struggling with spot prices that had fallen into the $70s/mt FOB for Australian 6,300 kcal/kg GAR thermal coal in late June before settling around $76/mt in September.


CHINA COAL

Asian seaborne spot prices for Australian and Indonesian thermal coal went into decline in February 2012 shortly after Japanese power companies settled their term contract price – the second highest on record – with their Australian coal suppliers. Prices for 6,300 kcal/kg GAR thermal coal fell to $83.80/mt in June and to a year-to-date low of $78.45/mt on October 15, 2012, a level more popularly associated with Australia’s production breakeven point.

Producers hit hardSpot prices crashed spectacularly throughout the second and third quarters of 2012 as Chinese buyers decided en masse that they wanted to negotiate lower prices with their Australian, Indonesian and South African coal suppliers.

Th e most physically liquid Newcastle product, 5,500 kcal/kg NAR thermal coal with a typical ash content of 20% slumped from $95/mt in mid-February 2012 to the low $70s/mt FOB. In early July 2013 the $70/mt mark was breached and it is wallowing just below the $65/mt level in mid-September.

Oversupply added to the bearish demand in the Asian seaborne market. Coal producers had ramped up their production faster than the market could absorb and now found fewer buyers for their product. In the US energy market, cheaper supplies of shale gas fl ooded the market, elbowing coal to the fringes of the country’s energy mix and forcing US producers to embark on frantic eff orts to export to overseas markets including Asia.

China’s imports of thermal coal ran at an average of 10 million mt/month through

2009 and 2010, and volumes soared to a high of 20 million mt in some months of 2011. In the fi rst 11 months of 2012, Chinese buyers bought 129 million mt of thermal coal on the seaborne market, and imports for the 2012 calendar year were around 147 million mt, according to Chinese customs data.

Data for the fi rst fi ve months of 2013 show total imports of all coal types including coking coal at 140.6 million mt, up from 112.7 million mt a year earlier. Steam coal imports have grown to 44.3 million mt from 34.9 million mt year on year. Th ese mainly consist of higher calorifi c value coals and are annualizing at over 100 million mt in 2013.

Lignite imports grew to 25.8 million mt in the period from 21.9 million mt the previous year while anthracite imports were up to 17.5 million mt from 15.7 million mt. Only “other coal” imports fell, to 18 million mt from 19 million mt over January-May.

China’s thermal coal imports are forecast to increase to 179 million mt in 2013, according to the Australian government’s Bureau of Resources and Energy Economics. Th e Canberra-based agency gave this forecast in its report for the fourth quarter of 2012.

Even if China’s net imports of thermal coal total 157 million mt in 2013, as UBS bank forecast in January, the country is increasingly becoming enmeshed in international coal markets. Its buyers have stretched to buying coal from as far away as Colombia and the US, in addition to sourcing coal from traditional suppliers closer to home. For now, in the thermal coal market at least, the only story in town is China.


SPECIAL SECTION

Sheikh KhalidSheikh Khalid Bin Khalifa Bin Jassim Al-Th ani is the Chief Executive Offi cer of Qatargas. He was appointed to his role as CEO in 2010 and has been credited with transforming the state-owned Qatargas into the world’s largest LNG producing company. Today Qatargas has a production capacity of 42 million tonnes per annum (Mtpa). It delivered the commissioning LNG cargo to the new Singapore LNG Terminal in March 2013.

Prior to Qatargas, Sheikh Khalid was the Director of Ras Laff an Industrial City (RLIC), Qatar’s main industrial hub for production of LNG and gas-to-liquids

Sheikh Khalid will deliver the keynote opening address at this year’s Singapore International Energy Week.

1. As more LNG supply projects come online around the world, what are your views on the global LNG supply/demand landscape from now till 2020?Global demand for energy has been increasing at a steady pace, whereas natural gas demand growth in the

non-OECD region has in fact been quite remarkable. While overall global energy demand has grown by 2.5% per annum during the past decade, natural gas demand in non-OECD countries has increased at yearly growth rates of over 4%. Th e favorable characteristics of LNG in that it is an aff ordable, clean burning and reliable fuel that can be used effi ciently in power generation and by industrial, commercial and domestic consumers, have led to the rapid growth in LNG deliveries to all four corners of the world. In fact, LNG demand growth has been phenomenal. During the past ten years alone, LNG demand has risen by almost 150%.

Looking ahead, the prospects for the LNG industry continue to be healthy, with many industry observers forecasting a doubling of demand during the next 15 years. Several factors are underpinning this robust growth forecast. Th ese include the environmental benefi ts of increased natural gas usage and LNG’s ability to help alleviate countries’ security of gas supply concerns, which have often been exacerbated by falling output from

FIVE QUESTIONS

Five questions with industry leaders

appearing at the Singapore International

Energy Week 2013 (SIEW). SIEW

is an annual event bringing together

top government and industry leaders

to share expertise and discuss key

developments and trends across the

global energy value chain. SIEW 2013

takes place from Oct 28 to Nov 1 and

will address topics such as the impact

of fossil fuels continued dominance,

the game-changing influence of natural

gas on global markets, as well as low

carbon growth and Asia’s energy future.

Associated events at SIEW 2013

include eight Roundtables hosted by

renowned Singapore and international

think tanks, and a half-day Public

Private Partnership (PPP) conference

on power markets and interconnectivity,

hosted in support of the US-Asia Pacific

Comprehensive Energy Partnership

(USACEP)

SHEIKH KHALID Chief Executive Offi cer Qatargas

DR. FATIH BIROLChief Economist,International Energy Agency


SPECIAL SECTION

legacy gas production areas. Technological advances have also helped LNG to compete more eff ectively with other fuel supplies.

2. How will Qatargas’ production output and position as an energy exporter evolve with the changing supply/demand landscape?In addition to deepening our relationships with our existing buyers, Qatargas is fi rmly committed to helping more countries benefi t from our clean energy resource.

Strong demand, the need for clean energy and declining legacy gas production are opening new LNG markets in Asia. Concerns over security of gas supply are helping facilitate our further penetration into European and Latin American markets. Meanwhile rising demand, partly due to growing populations, and the challenges with developing domestic gas reserves are driving robust LNG imports into the Middle East region. Qatargas aims to be the global LNG supplier of choice for each of these regions as well as for others that develop in the future.

3. How is Qatargas planning to tap into the growing LNG market in Asia? Given the varying gas prices across markets and increasing production of shale gas, how do you see this aff ecting gas prices in Asia?Asia continues to be one of our main markets. Japan was the founding importer of LNG from Qatar. Qatargas commenced long-term deliveries of LNG to Japan in 1996 and has since delivered well over 1,600 cargoes to

Japan. Th is included helping Japan cope with the additional short-term demand for energy in the aftermath of the Great East Japan Earthquake in 2011 and the signing of several SPAs with Japanese customers in 2012. We have also entered into long-term agreements for the supply of LNG into China and Th ailand.

In addition, Qatargas is doing what it can to support its Chinese partners, CNOOC and PetroChina, to expand their infrastructure. We have delivered commissioning cargoes to PetroChina’s Rudong and Jiangsu terminals and CNOOC’s terminal at Ningbo. In March this year, Qatargas also delivered the fi rst ever LNG cargo to Singapore to commission Singapore LNG Corporation Pte Ltd.’s (SLNG) LNG Terminal.

Recent technological innovations have made shale gas production in certain parts of the world economically feasible. For example, the United States appears to be on track to becoming a net LNG exporter through shale gas development. Such exports of LNG through upstream shale gas development will help grow new markets for natural gas. Nevertheless large scale production of shale gas seems some way off commercialization in other parts of the world where various considerable technical and regulatory hurdles still exist. LNG is produced and delivered today and is meeting energy needs all over the world, consistently and reliably. As a matter of fact Qatar has delivered cargoes to China, USA, Canada and the UK; and has concluded an agreement to deliver LNG to Poland. It is worth mentioning that all of these countries have potential reserves of shale gas.

It is in the interest of all LNG industry participants that projects along the entire

value chain will be developed. Th e LNG business requires participants to make very large capital investments in projects with signifi cant project risks. We believe that the nature of the LNG industry requires long term partnerships through long-term contracts. In order to incentivize participants such as end users, producers, fi nanciers and governments to invest in the new build of much needed replacements and additions of capacity in the entire LNG value chain, long term contracts underpinned by oil index pricing continues to be the norm.

4. Does Qatar envisage that natural gas will eventually replace other fuels in areas where it is traditionally not a major fuel, such as land, sea or air transportation?Many industry experts have forecasted that the demand for energy will continue to grow robustly. Th erefore, now and certainly in the future all forms of energy will be needed to meet energy needs, including the need for transportation fuels. Natural gas is expected to be a preferred fuel in that mix because of its availability, aff ordability and as an environmentally acceptable fuel and is thus expected to generally outstrip growth rates vis-à-vis competing fuels. Increasingly stringent environmental regulations, combined with gas’ competitiveness compared to other fuels, will help incentivize the necessary development of new infrastructure to grow natural gas’ penetration in the transportation sector. We are already seeing numerous initiatives for LNG ship bunkering for sea and river vessels and barges as well as the use of LNG in trucks and buses in various countries such as the United States and


SPECIAL SECTION

China. Th e potential is there for this market to grow and reach a signifi cant scale.

5. While Qatar is the world’s largest supplier of LNG, it is also advocating responsible energy exploration and working to diversify its international energy reach. What other new horizons do you see in Qatargas’ future in the energy sector?As a premier LNG company, Qatargas is very conscious of its responsibilities. We are committed to continuing the safe and reliable operation of our facilities and providing reliable energy supplies to our customers globally. As we look into the future, we in Qatargas will continue to demonstrate our ability as a reliable and safe global supplier of LNG adding to the energy diversity of countries in Asia, Europe and the Americas.

Designing and continually improving the Company’s facilities and operations so that we minimize our environmental footprint remains a top priority. We are fully committed to meeting or exceeding the most stringent government regulatory and industry standards through sound operating practices and innovation. We work proactively, within our industry, to promote environmentally responsible operating practices.

We have various projects in this area and I would like to highlight the environmental excellence project named Jetty Boil-Off Gas Recovery Project (JBOG). Th is project will make productive use of the gas that boils off during the loading of LNG carriers at the Ras Laff an Port and thus eff ectively reduces product-related emissions by over 90%. Also Qatargas is currently

undertaking an operational excellence project named the Plateau Maintenance Project (PMP). Th e PMP will ensure that the production capacity of Qatargas 1 is maintained at 10 million tonnes per annum (MTA) of LNG. Th is will be accomplished by drilling additional off shore wells, modifying associated off shore facilities, modifying the existing Qatargas Trains 1, 2 and 3, and building additional onshore facilities.

Dr. Fatih BirolDr. Fatih Birol is the Chief Economist at the International Energy Agency in Paris. He is responsible for the IEA’s fl agship World Energy Outlook publication, which is recognized as the most authoritative source of strategic analysis of global energy markets. He is also the founder and chair of the IEA Energy Business Council, which provides a forum to enhance cooperation between the energy industry and energy policymakers.

Dr. Birol will discuss how Asia can power its future energy needs during the Singapore Energy Summit, a high-level dialogue at SIEW.

1. You have mentioned the foundations of the global energy system are shifting; can you elaborate? What is your view of these “new horizons in energy”?Th e global energy map is changing. It is notably being redrawn by the resurgence in oil and gas production in the United States, the retreat from nuclear power in some countries, continued rapid growth in the use of wind and solar technologies, an increasing policy focus on energy effi ciency and by the global spread of unconventional gas production. Th ese shifts will have far-reaching consequences for energy

markets and trade, but they don’t change the fact that current global trends in energy supply and consumption are patently unsustainable — environmentally, economically and socially. Th e path that we are currently on is more likely to result in a temperature increase of between 3.6 °C and 5.3 °C. Hence, intensive action is needed and energy is at the heart of this challenge: the energy sector accounts for around two-thirds of greenhouse-gas emissions, as more than 80% of global energy consumption is based on fossil fuels. Our new World Energy Outlook Special Report “Redrawing the energy-climate map”, which was released in June 2013, identifi es four measures that can keep the door open to the 2 degrees Celsius climate goal at no net economic cost, an important concern for many governments. Th e report can be downloaded for free at http://www.worldenergyoutlook.org/

2. We’ve heard a lot about the North American shale gas revolution. To what extent will it aff ect and change other regional gas markets including Asian markets?Th e boom in shale gas production in the United States has boosted overall gas supplies substantially, removing the anticipated need to import LNG and driving down US prices. As a result, the North American gas market is moving to a diff erent rhythm from the rest of the world. Th is disconnect is refl ected in large price diff erentials with other markets: at its lowest level in 2012, natural gas in the United States traded at around one-eight of import prices in Asia. In these market conditions, interest in exporting gas from North America has, unsurprisingly, grown. Just how


SPECIAL SECTION

much LNG export is eventually exported hinges on how the regulatory approvals process proceeds and whether the regional price diff erentials are maintained. But I certainly expect that rising supplies of unconventional gas – from North America as well as other countries such as Australia and eventually China – will play an important role in diversifying trade fl ows, putting pressure on conventional gas suppliers and on traditional oil-linked pricing mechanisms for gas. Liquefaction will remain a capital intensive process, so we will continue to see a persistent gap between gas prices in the US and Asia, but at a smaller level than today.

3. What will the impact of US energy independence be on the rest of the world?With a continued fall in US oil imports, North America as a whole is set to become a net oil exporter around 2030. Th is will accelerate the switch in direction of international oil trade towards Asia, putting a focus on the security of the strategic routes that bring Middle East oil to Asian markets.

Th e resurgence in US oil and gas production is also spurring economic activity in upstream oil and gas and among energy-intensive industries that are gaining a competitive edge. Moreover, it has contributed to wide diff erences in electricity prices in diff erent parts of the world, which are now putting a signifi cant burden on industry in Europe and in parts of Asia. In our upcoming World Energy Outlook 2013, to be released in November, we will examine in detail the implications for economic competitiveness of this changing energy map and off er insights on options policy makers could adopt to

improve their competitiveness, taking account of the need to curb fossil energy use and greenhouse-gas emissions.

4. You have dubbed energy effi ciency as a huge opportunity unrealized – how can we unlock the untapped potential of energy effi ciency? Which countries in Asia have been most successful in the adoption of renewable energy and alternative energy policies?Energy effi ciency has been an “epic failure” of energy policy making in most parts of the world, but there are increasing signs that it is rising up the agenda. Th is could well represent a game-changer in the same way the boom in US oil and gas production is redefi ning the global energy map. After all, energy effi ciency is just as important as energy supply – perhaps more so – in determining the nature of our economies.

But actions need to be taken to trigger this potential. First there needs to be government leadership. For too long, energy effi ciency has been considered the low-hanging fruit that is ripe to be picked. And yet, it is not. Barriers need to be overcome. Governments are often in the best position to make this happen. One of the ways they can act is with accurate information – helping us measure and understand the costs and benefi ts. Another way is to help make it aff ordable. Often the reason blocking energy effi ciency is that the costs and benefi ts fall on diff erent people. We need fi nancing instruments that improve aff ordability and align incentives. And we need to make energy effi ciency the norm. Th ere are soft ways of doing this, through information and communication campaigns to change

behaviour. And there are harder ways, such as building codes and standards for household appliances and vehicles.

In Asia, Japan has been the standout in terms of improving energy effi ciency. However, in recent years, China and countries in Southeast Asia have also been placing increased emphasis on improving the effi ciency of energy use, in recognition of the need to curb demand growth, reduce energy imports and mitigate pollution. But there remains much scope for eff orts to be stepped up.

5. Focusing specifi cally on ASEAN, what do you think are the region’s energy challenges? What impact will ASEAN integration have on the region’s energy landscape?Together with China and India, the ten ASEAN member states really are shifting the centre of gravity of the global energy system toward Asia. Since the Asian Financial Crisis, an economic revival coupled with ongoing urbanisation and industrialisation has driven brisk growth in energy use. Th ere remains great scope for energy demand in the region to rise as its energy use on a per capita basis remains very low and it is home to almost 600 million people. But there are a number of challenges the region will have to overcome if it is to meet its energy needs. Th ese include phasing out fossil-fuel subsidies, increasing access to modern forms of energy and improving energy effi ciency. Given the growing importance of the region, we are currently preparing a major study on energy in Southeast Asia, which will be released as a Special Report in our World Energy Outlook series at the East Asian Summit Energy Minister’s Meeting in Indonesia in late September.


TOP 250 ENERGY COMPANIES

Asia’s resource hungry giants and regional energy players have consolidated their impressive growth in recent years, creeping up Platts Top 250 rankings and populating the lion’s share of the world’s premier energy companies.

Led by the demand powerhouses of China and India, Asia’s emerging economies remained the sole source of net energy consumption growth again in 2012, as demand in the West languished.

But early signs of a slowdown in China’s growth phenomenon appear to be showing and the relative performance of its shining stars is now beginning to wane.

In fact, this year’s rankings show a remarkable swing in the fortunes of Asian energy sector companies compared to their rivals in North America. While the outright number of leading Asian energy players rose last year, their growth rates did not match that of the shale-led success stories of North America.

Without a doubt, the impact of US’ unconventional production boom from

shale and tight oil formations is now clearly apparent. US light, tight oil has fi rmly taken the baton from shale gas to power the ongoing US energy revolution and this year’s rankings refl ect the transformation that the shale industry is having domestically and further afi eld.

Th e latest Platts rankings show winners and losers in the US’ fast-changing energy landscape and highlight the knock-on impact to mid-stream companies, power producers, and gas utilities alike.

Shale is not the only story. Th is year’s list also underscores the persistent rise of ever-more integrated and diverse National Oil Companies challenging the role of traditional oil and gas producers.

Chinese and Russian NOCs made up four of the top ten biggest energy companies last year, up from three in 2011. When the rankings were launched in 2002, only one NOC sat in the top-ten list.

Price driversIt’s no coincidence that integrated oil and gas companies continue populate

US ENERGY BOOM TAKES

CENTER STAGEPlatts Top 250 Global Energy

Company Rankings™ Reviewed

ROBERT PERKINSEditor,EMEA Oil News

HENRYEDWARDES-EVANSAssociate Editorial Director,Power in Europe



FASTEST GROWING ASIA COMPANIES3-year CGR %

Platts RankRank Company Country Industry

1 Cairn India Ltd India E&P 121 109

2 Kunlun Energy Co Ltd Hong Kong E&P 74.9 123

3 China Resources Gas Group Ltd Hong Kong GU 68.3 232

4 Inner Mongolia Yitai Coal Co Ltd China C&CF 42.1 125

5 Yanzhou Coal Mining Co Ltd China C&CF 41.1 86

6 YTL Power International Berhad Malaysia DU 37.6 169

7 Shanxi Xishan Coal & Electricity Power Co Ltd China C&CF 36.3 180

8 Guangdong Electric Power Development Co Ltd China IPP 34.1 203

9 CNOOC Ltd Hong Kong E&P 33 12

10 China Yangtze Power Co Ltd China IPP 32.8 95

11 YTL Corp Berhad Malaysia DU 31.4 166

12 PetroChina Co Ltd China IOG 29.1 8

13 ENN Energy Holdings Ltd China GU 28.9 226

14 China Petroleum & Chemical Corp China IOG 27.5 10

15 CLP Holdings Ltd Hong Kong EU 27.4 84

16 China Shenhua Energy Co Ltd China C&CF 27.3 14

17 Banpu Pcl Thailand C&CF 26.6 201

18 The Hong Kong & China Gas Co Ltd Hong Kong GU 26.4 124

19 SDIC Power Holdings Co, Ltd China IPP 26 223

20 S-Oil Corp South Korea R&M 25.5 98

Fastest Growing is based on a three year compound growth rate (CGR) for revenues. The compound growth rate (CGR) is

based on the companies revenue numbers for the past four years (current year included). If only three years of data was

available then it is a two year CGR. All rankings are computed from data assessed on June 6, 2013.

Source: S&P Capital IQ/Platts

the entire top ten leader board for 2013, as they have done for many years.

Sales of oil and gas are the cash-fl ow engine for all the integrateds and robust commodity prices infl ate a company’s revenues, assets values, and net profi ts alike.

Th e average price of Dated Brent crude hit a fresh record of $111.68/b in 2012, up 3.5% on the year, as geopolitical threats to production largely off set concerns over fl agging oil demand.

Th e beat over the $110.91/b average for 2011, the previous all-time nominal high for oil prices, was slim, however, at less than 80 cents/b.

Despite ever creeping costs, the fresh record average oil price in 2012 proved a further windfall for many producers, with many integrated oil companies and oil and gas producers posting record upstream earnings.

Global gas market prices continued to diverge in 2012, demonstrating a growing disconnect with oil price markers and between the three distinct gas markets regions.

Natural gas prices rose in Europe and Asia, but fell in North America, where soaring shale natural gas output pushed gas prices to record discounts against both crude and international gas prices.

Natural gas in the US traded at its lowest ever level in 2012, averaging just $2.77/ MMBtu at Henry Hub, around one-fi fth of import prices in Europe and one-eighth of those in Japan.

European long-term contract prices hovered around $12/MMBtu last year

and spot Asian LNG prices breached $18/MMBtu level in May as Japanese buyers bought cargoes to hedge for summer demand.

European utilities continued to renegotiate costly long-term, oil-indexed supply contract with Russia, which supplies a quarter of Europe’s gas.

In Asia, gas demand continued to grow in 2012 led by China and India and with most of Japan’s 50 nuclear reactors still offl ine in the wake of the 2011 Fukushima earthquake. Japan’s average LNG import price grew 12% in 2012, to average $16.62/ MMBtu.

With rising natural gas output driving prices lower in the US, natural gas continued to displace coal in



PLATTS RANK 2013

STATE OR COUNTRY

ASSETS REVENUES PROFITSRETURN ON

INVESTED CAPITAL 3-YEAR CGR%

INDUSTRY CODECOMPANY REGION $ MILLION RANK $ MILLION RANK $ MILLION RANK ROIC% RANK

1 Exxon Mobil Corp Texas Americas 333795 4 428376 3 44880 1 24 4 15.8 IOG

2 Chevron Corp California Americas 232982 9 222580 7 26179 4 17 9 11.8 IOG

3 Royal Dutch Shell plc Netherlands EMEA 360325 2 467153 1 26592 3 12 26 18.9 IOG

4 OJSC Gazprom Russia EMEA 375275 1 145084 11 36775 2 12 28 16 IOG

5 Statoil ASA Norway EMEA 134925 16 121388 16 11852 7 16 14 15.1 IOG

6 Total SA France EMEA 224804 10 238502 6 13991 6 10 38 17.6 IOG

7 LUKOIL Oil Co Russia EMEA 98961 23 139171 12 11004 9 14 22 19.7 IOG

8 PetroChina Co Ltd China Asia/Pacifi c Rim 353759 3 358065 5 18810 5 7 64 29.1 IOG

9 OJSC Rosneft Oil Co Russia EMEA 119970 19 92294 20 10604 10 10 34 27.1 IOG

10 China Petroleum & Chemical Corp China Asia/Pacifi c Rim 206605 12 454336 2 10419 11 8 60 27.5 IOG

11 BP plc United Kingdom EMEA 300193 7 375580 4 11580 8 7 70 16.1 IOG

12 CNOOC Ltd Hong Kong Asia/Pacifi c Rim 74388 30 40389 38 10388 12 17 11 33 E&P

13 ConocoPhillips Texas Americas 117144 20 60347 28 7411 17 10 36 -24.3 E&P

14 China Shenhua Energy Co Ltd China Asia/Pacifi c Rim 74599 29 40819 37 7969 14 13 23 27.3 C&CF

15 Phillips 66 Texas Americas 48073 55 166169 10 4122 24 15 18 18.7 R&M

16 Ecopetrol SA Colombia Americas 59908 44 36221 47 7775 16 18 8 31.3 IOG

17 OAO TNK-BP Holding Russia EMEA 35978 80 38591 39 7961 15 28 2 9.7 IOG

18 PTT Plc Thailand Asia/Pacifi c Rim 53442 49 91526 21 3429 28 9 47 20.8 IOG

19 Reliance Industries Ltd India Asia/Pacifi c Rim 63734 38 69838 25 3663 26 7 62 24.9 R&M

20 OJSC Surgutneftegas Russia EMEA 64399 36 25976 60 5246 20 9 42 18.4 IOG

21 Eni SpA Italy EMEA 182692 14 166442 9 5492 19 5 120 15.2 IOG

22 Oil & Natural Gas Corp Ltd India Asia/Pacifi c Rim 44580 62 28397 56 4260 23 14 21 16.3 E&P

23 OAO AK Transneft Russia EMEA 62099 41 22774 69 5613 18 10 35 27.8 S&T

24 Occidental Petroleum Corp California Americas 64210 37 24172 67 4627 21 10 39 17.7 IOG

25 Marathon Petroleum Corp Ohio Americas 27223 106 76580 24 3383 29 22 5 23.5 R&M

26 Valero Energy Corp Texas Americas 44477 63 138286 13 2081 45 8 52 29.5 R&M

27 Petróleo Brasileiro SA - Petrobras Brazil Americas 318700 6 132320 14 9961 13 4 155 15.5 IOG

28 Enterprise Products Partners LP Texas Americas 35934 81 42583 35 2420 36 8 53 18.6 S&T

29 Electricite de France SA France EMEA 327230 5 95151 19 4338 22 4 162 7.1 EU

30 Centrica plc United Kingdom EMEA 33775 85 36837 45 1959 49 11 29 2.9 DU

31 Iberdrola SA Spain EMEA 126665 18 44745 31 3716 25 4 139 9.7 EU

32 Suncor Energy Inc Canada Americas 73863 31 36916 44 2689 34 6 104 16.1 IOG

33 National Grid plc United Kingdom EMEA 84168 25 22092 72 3531 27 6 99 0.8 DU

34 BG Group plc United Kingdom EMEA 65247 34 18933 82 3215 30 7 80 7 IOG

35 Hess Corp New York Americas 43441 66 37691 43 2025 47 7 70 8.4 IOG

36 E.ON SE Germany EMEA 183720 13 173316 8 2852 33 3 175 18.1 DU

37 OMV Aktiengesellschaft Austria EMEA 39928 75 55798 30 1784 57 7 68 33.5 IOG

38 Repsol, SA Spain EMEA 84936 24 77090 23 2473 35 4 159 13.4 IOG

39 Husky Energy Inc Canada Americas 33951 84 21676 74 1941 50 9 49 14.2 IOG

40 Sasol Ltd South Africa EMEA 20358 127 16931 87 2356 38 16 13 7.1 IOG

41 Southern Co Georgia Americas 63149 40 16537 89 2350 39 6 102 1.7 EU

42 RWE AG Germany EMEA 115395 21 66701 26 1709 60 4 168 3.3 DU

43 Coal India Ltd India Asia/Pacifi c Rim 21382 124 12014 122 3053 31 35 1 13.4 C&CF

44 Anadarko Petroleum Corp Texas Americas 52589 50 13307 111 2376 37 6 81 17.5 E&P

45 JX Holdings, Inc Japan Asia/Pacifi c Rim 73332 32 113094 17 1608 62 3 177 R&M

46 Gas Natural SDG SA Spain EMEA 61342 42 32582 48 1885 53 4 148 18.7 GU

47 OAO Tatneft Russia EMEA 19610 133 13810 107 2285 40 14 20 5.3 E&P

48 CEZ, a.s. Czech Republic EMEA 32282 88 10684 128 2103 44 9 42 3.6 EU

49 NTPC Ltd India Asia/Pacifi c Rim 31433 92 11952 123 2215 41 9 50 12 IPP

50 Apache Corp Texas Americas 60737 43 16834 88 1925 51 4 132 25.5 E&P

Notes: C&CF = coal and consumable fuels, DNR = data not reported, DU = diversifi ed utility, E&P = exploration and production, EU = electric utility, GU = gas utility, IOG = integrated oil and gas,

IPP = independent power producer and energy trader, R&M = refi ning and marketing, S&T = storage and transfer. All rankings are computed from data assessed on June 6, 2013.



PLATTS RANK 2013

STATE OR COUNTRY




51 Canadian Natural Resources Ltd Canada Americas 47323 56 14096 104 1828 56 6 99 12.9 E&P

52 Edison International California Americas 44394 64 11862 124 1503 65 7 62 -1.4 EU

53 NextEra Energy, Inc Florida Americas 64439 35 14256 101 1911 52 4 132 -3 EU

54 GDF Suez SA France EMEA 268853 8 126955 15 2028 46 1 252 6.7 DU

55 Marathon Oil Corp Texas Americas 35306 82 15724 93 1582 63 6 87 22.2 E&P

56 SK Innovation Co, Ltd South Korea Asia/Pacifi c Rim 30182 97 65421 27 1043 82 5 120 18.9 R&M

57 Woodside Petroleum Ltd Australia Asia/Pacifi c Rim 24810 113 6348 172 2983 32 15 19 22.1 E&P

58 Murphy Oil Corp Arkansas Americas 17523 142 28616 55 964 89 9 50 19.4 IOG

59 Inpex Corp Japan Asia/Pacifi c Rim 36451 78 12263 119 1844 54 6 97 13.1 E&P

60 Cia Energetica de Minas Gerais Brazil Americas 19174 135 8681 149 2009 48 15 17 14.9 EU

61 HollyFrontier Corp Texas Americas 10329 209 20091 77 1727 58 22 6 60.8 R&M

62 JSOC Bashneft Russia EMEA 14413 166 15452 97 1336 68 12 24 33.9 E&P

63 China Coal Energy Co Ltd China Asia/Pacifi c Rim 30287 95 14238 102 1442 66 6 93 18 C&CF

64 Fortum Oyj Finland EMEA 32221 89 8058 153 1843 55 7 64 4.3 EU

65 PPL Corp Pennsylvania Americas 43634 65 12286 118 1518 64 5 115 18.2 EU

66 Tenaga Nasional Berhad Malaysia Asia/Pacifi c Rim 28691 102 11626 125 1361 67 7 70 7.6 EU

67 Public Service Enterprise Group Inc New Jersey Americas 31725 90 9781 136 1275 70 7 78 -6.7 DU

68 Tokyo Gas Co Ltd Japan Asia/Pacifi c Rim 20084 128 19310 80 1025 83 6 83 10.6 GU

69 Enel SpA Italy EMEA 224578 11 109616 18 1132 77 1 269 9.8 EU

70 EDP-Energias de Portugal, SA Portugal EMEA 55770 47 21377 76 1325 69 3 184 10.2 EU

71 Exelon Corp Illinois Americas 78554 27 23489 68 1160 75 3 207 10.7 EU

72 American Electric Power Co, Inc Ohio Americas 54367 48 14945 99 1259 71 4 162 3.5 EU

73 Plains All American Pipeline, LP Texas Americas 19235 134 37797 42 784 102 5 106 26.8 S&T

74 Consolidated Edison Inc New York Americas 41209 74 12188 120 1138 76 5 115 -2.2 DU

75 Tesoro Corp Texas Americas 10702 205 32484 49 743 108 12 26 25.1 R&M

76 Cenovus Energy Inc Canada Americas 23397 116 16272 91 959 91 6 91 13.5 IOG

77 OAO Novatek Russia EMEA 14402 167 6560 169 2160 42 16 12 32.9 E&P

78 Duke Energy Corp North Carolina Americas 113856 22 19158 81 1727 59 2 230 15.4 EU

79 Polski Koncern Naftowy Orlen Spolka Akcyjna Poland EMEA 16114 152 36771 46 718 112 6 87 20.9 R&M

80 Indian Oil Corporation Ltd India Asia/Pacifi c Rim 41808 72 81039 22 783 103 3 202 22.6 R&M

81 SSE plc United Kingdom EMEA 31689 91 43549 34 655 119 4 162 9.5 EU

82 TonenGeneral Sekiyu KK Japan Asia/Pacifi c Rim 13961 175 28274 57 552 128 9 47 9.9 R&M

83 EnBW Energie Baden-Wuerttemberg AG Germany EMEA 48106 54 25258 62 619 122 3 175 7.3 EU

84 CLP Holdings Ltd Hong Kong Asia/Pacifi c Rim 29475 100 13511 110 1071 79 4 130 27.4 EU

85 Turkiye Petrol Rafi nerileri AS Turkey EMEA 9058 236 24928 63 773 104 15 16 32.2 R&M

86 Yanzhou Coal Mining Co Ltd China Asia/Pacifi c Rim 20013 129 9484 139 1014 85 7 70 41.1 C&CF

87 Polska Grupa Energetyczna SA Poland EMEA 17835 138 9355 140 983 87 8 61 12.2 EU

88 MOL Hungarian Oil & Gas Co Hungary EMEA 21007 126 24339 65 668 115 4 130 19.3 IOG

89 YPF SA Argentina Americas 15108 161 12694 113 737 110 8 56 25.1 IOG

90 Origin Energy Ltd Australia Asia/Pacifi c Rim 26668 108 12328 116 934 94 5 123 17.2 IOG

91 PG&E Corp California Americas 52449 51 15040 98 816 100 3 193 3.9 DU

92 Xcel Energy Inc Minnesota Americas 31141 93 10128 132 905 95 5 127 1.6 EU

93 Entergy Corp Louisiana Americas 43202 68 10302 129 847 98 4 162 -1.4 EU

94 Idemitsu Kosan Co Ltd Japan Asia/Pacifi c Rim 27503 104 44098 32 506 137 3 184 12 R&M

95 China Yangtze Power Co Ltd China Asia/Pacifi c Rim 25833 112 4211 208 1691 61 7 78 32.8 IPP

96 Huaneng Power International, Inc China Asia/Pacifi c Rim 42261 70 21741 73 899 96 2 221 20.2 IPP

97 TransCanada Corp Canada Americas 46698 58 7736 156 1255 72 3 184 -0.7 S&T

98 S-Oil Corp South Korea Asia/Pacifi c Rim 11149 198 30978 52 505 138 6 83 25.5 R&M

99 Saudi Electricity Co Saudi Arabia EMEA 63620 39 8972 143 683 114 3 177 12.2 EU

100 China Resources Power Holdings Co Ltd Hong Kong Asia/Pacifi c Rim 22908 117 8045 154 964 90 5 115 23.4 IPP





PLATTS RANK 2013

STATE OR COUNTRY




101 FirstEnergy Corp Ohio Americas 50406 52 14848 100 770 105 2 221 5.7 EU

102 Kinder Morgan, Inc Texas Americas 68185 33 9973 134 1092 78 2 234 11.5 S&T

103 Sempra Energy California Americas 36499 77 9647 137 859 97 4 168 6 DU

104 Enbridge Inc Canada Americas 45576 60 24450 64 589 124 2 238 12.7 S&T

105 GAIL (India) Ltd India Asia/Pacifi c Rim 10516 207 8951 144 769 106 10 40 23.5 GU

106 JSC KazMunaiGas Exploration Production Kazakhstan EMEA 10336 208 5268 186 1063 80 12 24 18 E&P

107 Noble Energy, Inc Texas Americas 17554 141 4037 213 965 88 8 58 21.9 E&P

108 DTE Energy Co Michigan Americas 26339 110 8791 147 666 116 4 136 3.1 DU

109 Cairn India Ltd India Asia/Pacifi c Rim 9498 225 3082 238 2121 43 25 3 121 E&P

110 Polskie Gornictwo Naftowe I Gazownictwo Spolka Akcyjna Poland EMEA 14671 162 8796 146 685 113 6 93 14.1 IOG

111 ONEOK Partners, LP Oklahoma Americas 10959 202 10182 130 660 118 7 64 16.3 S&T

112 Snam S.p.A. Italy EMEA 29547 99 4991 196 1019 84 4 139 15.8 GU

113 Ultrapar Holdings Inc Brazil Americas 7195 266 25356 61 475 141 8 53 14.3 S&T

114 Spectra Energy Corp Texas Americas 30587 94 5075 193 938 93 4 144 3.7 S&T

115 Galp Energia SGPS SA Portugal EMEA 18197 137 24323 66 449 144 3 177 15.5 IOG

116 Datang International Power Generation Co Ltd China Asia/Pacifi c Rim 44899 61 12657 114 663 117 2 238 17.4 IPP

117 Williams Companies, Inc Oklahoma Americas 24327 114 7486 159 723 111 4 148 12.4 S&T

118 JSC Russian Grids Russia EMEA 30249 96 19331 79 517 135 2 223 10.4 EU

119 Bharat Petroleum Corp. Ltd India Asia/Pacifi c Rim 13686 177 42572 36 331 174 4 148 25 R&M

120 Osaka Gas Co, Ltd Japan Asia/Pacifi c Rim 15795 156 13911 106 529 131 4 148 8 GU

121 Energy Transfer Equity, LP Texas Americas 48904 53 16964 86 413 152 1 255 46.3 S&T

122 GD Power Development Co, Ltd China Asia/Pacifi c Rim 29715 98 9198 141 795 101 3 207 18.4 IPP

123 Kunlun Energy Co Ltd Hong Kong Asia/Pacifi c Rim 13985 173 4246 205 840 99 7 70 74.9 E&P

124 The Hong Kong & China Gas Co LtdHong Kong Asia/Pacifi c Rim 12759 184 3211 235 996 86 9 42 26.4 GU

125 Inner Mongolia Yitai Coal Co Ltd China Asia/Pacifi c Rim 6747 271 5151 189 1053 81 20 7 42.1 C&CF

126 Canadian Oil Sands Ltd Canada Americas 9827 216 3578 227 948 92 16 15 10 E&P

127 EOG Resources, Inc Texas Americas 27337 105 11096 126 570 127 3 202 42.7 E&P

128 Korea Gas Corp South Korea Asia/Pacifi c Rim 36240 79 31253 51 327 176 1 259 21.7 GU

129 Empresas Copec SA Chile Americas 22010 119 22761 70 407 155 2 223 31.8 R&M

130 CPFL Energia SA Brazil Americas 14614 164 7080 163 576 126 5 115 9.8 EU

131 Power Assets Holdings Ltd Hong Kong Asia/Pacifi c Rim 13097 180 1342 297 1254 73 11 30 0.1 EU

132 NRG Energy, Inc New Jersey Americas 35128 83 8422 150 550 129 2 230 -2 IPP

133 Wisconsin Energy Corp Wisconsin Americas 14285 168 4246 204 546 130 6 97 1.2 DU

134 Dominion Resources, Inc Virginia Americas 46838 57 13093 112 324 178 1 259 -4 DU

135 Tauron Polska Energia SA Poland EMEA 9575 224 7575 157 449 145 6 81 21.8 EU

136 Thai Oil Pcl Thailand Asia/Pacifi c Rim 5591 300 14010 105 404 156 9 46 18.6 R&M

137 Northeast Utilities Massachusetts Americas 28303 103 6274 173 526 133 3 207 4.9 EU

138 CenterPoint Energy, Inc Texas Americas 22871 118 7452 160 417 150 3 193 -3.5 DU

139 Power Grid Corp of India Ltd India Asia/Pacifi c Rim 19943 130 2307 261 759 107 5 123 22.5 EU

140 GS Holdings Corp South Korea Asia/Pacifi c Rim 11341 197 8777 148 432 146 4 132 -33.6 R&M

141 Cheung Kong Infrastructure Holdings Ltd Hong Kong Asia/Pacifi c Rim 11408 195 581 325 1215 74 11 30 20.8 EU

142 Continental Resources, Inc Oklahoma Americas 9140 232 2418 255 739 109 11 33 56.8 E&P

143 OJSOC Slavneft Russia EMEA 8381 244 6178 175 450 143 7 70 21.1 E&P

144 ONEOK Inc Oklahoma Americas 15855 154 12633 115 346 172 3 193 5.3 GU

145 Red Eléctrica Corporación S A. Spain EMEA 12056 189 2321 259 644 120 7 68 13.4 EU

146 VERBUND AG Austria EMEA 16206 151 4155 210 509 136 4 144 -3 EU

147 Tullow Oil plc United Kingdom EMEA 9382 228 2344 257 624 121 10 40 36.8 E&P

148 CONSOL Energy Inc Pennsylvania Americas 12671 186 5046 194 388 161 5 106 3.6 C&CF

149 Manila Electric Co Philippines Asia/Pacifi c Rim 5168 314 6792 165 382 165 17 9 16.4 EU

150 CMS Energy Corp Michigan Americas 17131 144 6253 174 375 166 4 171 0.3 DU





PLATTS RANK 2013

STATE OR COUNTRY




151 Veolia Environnement SA France EMEA 58366 46 38514 40 10 285 0 285 1.9 DU

152 Pacifi c Rubiales Energy Corp Canada Americas 7087 268 3885 219 528 132 10 37 82.5 E&P

153 SCANA Corp South Carolina Americas 14616 163 4176 209 420 148 4 139 -0.5 DU

154 NiSource Inc Indiana Americas 21845 122 5034 195 411 153 3 193 -8.1 DU

155 Delek Group Ltd Israel EMEA 33678 86 19531 78 122 250 1 255 24.6 R&M

156 Korea Electric Power Corp South Korea Asia/Pacifi c Rim 130389 17 43822 33 -2825 325 -3 295 13.1 EU

157 Denbury Resources Inc Texas Americas 11139 199 2436 254 525 134 6 83 40.4 E&P

158 TERNA SpA Italy EMEA 19819 131 2270 262 607 123 4 155 8.7 EU

159 Santos Ltd Australia Asia/Pacifi c Rim 16235 149 3069 239 495 140 4 148 13.9 E&P

160 A2A S.p.A. Italy EMEA 15628 160 8217 151 340 173 3 193 6.1 DU

161 Pinnacle West Capital Corp Arizona Americas 13380 179 3302 233 387 162 5 109 1.5 EU

162 Tokyo Electric Power Co, Incorporated Japan Asia/Pacifi c Rim 151092 15 60241 29 -6908 328 -8 315 6 EU

163 Reliance Infrastructure Ltd India Asia/Pacifi c Rim 11696 193 3910 217 395 159 5 120 15 EU

164 Neste Oil Corp Finland EMEA 9662 221 21465 75 205 210 3 184 24.5 R&M

165 Acciona, SA Spain EMEA 25930 111 9834 135 248 197 1 249 -0.4 EU

166 YTL Corp Berhad Malaysia Asia/Pacifi c Rim 16742 146 6550 170 383 164 3 213 31.4 DU

167 Shanxi Lu'an Environmental Energy Development Co, Ltd China Asia/Pacifi c Rim 6461 280 3273 234 419 149 11 30 3.2 C&CF

168 Chubu Electric Power Co, Incorporated Japan Asia/Pacifi c Rim 59299 45 26702 58 -324 301 -1 292 5.8 EU

169 YTL Power International Berhad Malaysia Asia/Pacifi c Rim 12638 187 5147 190 400 157 4 162 37.6 DU

170 Grupa LOTOS Spólka Akcyjna Poland EMEA 6141 286 10137 131 283 187 6 95 32.2 R&M

171 Enbridge Energy Partners LP Texas Americas 12797 183 6706 166 369 167 3 184 5.4 S&T

172 Huadian Power International Corp Ltd China Asia/Pacifi c Rim 26948 107 9636 138 236 200 1 259 17.5 IPP

173 OGE Energy Corp Oklahoma Americas 9922 215 3671 224 355 170 6 102 8.6 EU

174 The Kansai Electric Power Co, Incorporated Japan Asia/Pacifi c Rim 76963 28 28820 54 -2454 323 -4 307 3.1 EU

175 Electric Power Development Co, Ltd Japan Asia/Pacifi c Rim 21873 120 6613 168 300 182 2 243 3.9 IPP

176 Integrys Energy Group, Inc Illinois Americas 10327 210 4212 207 291 185 5 112 -17.5 DU

177 Hindustan Petroleum Corp Ltd India Asia/Pacifi c Rim 16230 150 38018 41 88 263 1 263 24.7 R&M

178 ATCO Ltd Canada Americas 13831 176 4214 206 362 169 4 171 12 DU

179 PT Adaro Energy Tbk Indonesia Asia/Pacifi c Rim 6692 274 3722 223 385 163 7 64 10 C&CF

180 Shanxi Xishan Coal & Electricity Power Co Ltd China Asia/Pacifi c Rim 7360 259 5094 191 295 184 6 95 36.3 C&CF

181 Alliant Energy Corp Wisconsin Americas 10786 203 3094 237 325 177 5 115 -3.3 DU

182 Companhia Paranaense de Energia Brazil Americas 9975 214 4012 214 330 175 4 132 10.9 EU

183 El Paso Pipeline Partners, LP Texas Americas 6581 277 1515 289 579 125 9 45 10.6 S&T

184 Pepco Holdings, Inc District of Columbia Americas 15776 157 5081 192 285 186 3 202 -11.8 EU

185 Alliance Oil Co Ltd Russia EMEA 5992 292 3445 229 397 158 8 58 25.9 R&M

186 Enagás, SA Spain EMEA 10576 206 1544 287 497 139 5 108 9.6 GU

187 Whiting Petroleum Corp Colorado Americas 7272 264 2138 269 413 151 8 57 32.6 E&P

188 Abu Dhabi National Energy Co PJSC United Arab Emirates EMEA 33375 87 7564 158 177 224 1 273 18.1 DU

189 China Longyuan Power Group Corp Ltd China Asia/Pacifi c Rim 17589 139 2820 245 423 147 3 213 21.1 IPP

190 Formosa Petrochemical Corp Taiwan Asia/Pacifi c Rim 15680 159 30029 53 91 259 1 273 12.1 R&M

191 OJSC Federal Grid Co of Unifi ed Energy System Russia EMEA 39189 76 4363 202 221 202 1 273 17 EU

192 Centrais Elétricas Brasileiras SA - Eletrobras Brazil Americas 80976 26 16019 92 -3235 326 -6 311 13.8 EU

193 AGL Resources Inc Georgia Americas 14141 169 3922 216 271 190 3 184 19.2 GU

194 Rabigh Refi ning & Petrochemical Co Saudi Arabia EMEA 12739 185 16535 90 130 246 2 238 28.2 R&M

195 Concho Resources, Inc Texas Americas 8589 242 1820 274 408 154 6 89 52.7 E&P

196 ERG SpA Italy EMEA 6229 282 10828 127 198 217 4 136 11.4 R&M

197 NHPC Ltd India Asia/Pacifi c Rim 10964 201 1078 310 460 142 5 110 5.8 IPP

198 The AES Corp Virginia Americas 41830 71 18141 83 -915 314 -3 298 11.4 IPP

199 Tohoku Electric Power Co Inc Japan Asia/Pacifi c Rim 43187 69 18070 84 -1045 317 -3 298 2.5 EU

200 NV Energy, Inc Nevada Americas 11984 190 2979 241 322 179 4 159 -6 EU





PLATTS RANK 2013

STATE OR COUNTRY




201 Banpu Pcl Thailand Asia/Pacifi c Rim 7274 262 3844 220 304 180 5 112 26.6 C&CF

202 Cosan Ltd Brazil Americas 15893 153 14115 103 102 257 1 263 25.1 R&M

203 Guangdong Electric Power Development Co Ltd China Asia/Pacifi c Rim 10717 204 4810 198 277 188 3 193 34.1 IPP

204 Cimarex Energy Co Colorado Americas 6305 281 1624 281 347 171 8 53 17.2 E&P

205 Fortis Inc Canada Americas 14444 165 3530 228 304 181 3 216 0.1 EU

206 Talisman Energy Inc Canada Americas 21858 121 7303 161 123 249 1 263 6.4 E&P

207 Calpine Corp Texas Americas 16549 148 5430 184 199 215 1 249 -5.6 IPP

208 Devon Energy Corp Oklahoma Americas 43326 67 8809 145 -188 295 -1 291 4.9 E&P

209 Kyushu Electric Power Co, Incorporated Japan Asia/Pacifi c Rim 45628 59 15583 94 -3351 327 -10 320 2.3 EU

210 Chesapeake Energy Corp Oklahoma Americas 41611 73 12316 117 -940 315 -3 297 16.9 E&P

211 EVN AG Austria EMEA 8979 237 3745 222 255 194 4 155 1.6 EU

212 UGI Corp Pennsylvania Americas 9710 218 6519 171 199 213 3 207 4.3 GU

213 Iren SpA Italy EMEA 9201 230 5493 183 200 212 3 184 23.8 DU

214 Showa Shell Sekiyu KK Japan Asia/Pacifi c Rim 12431 188 26503 59 10 284 0 281 9.1 R&M

215 The Chugoku Electric Power Co, Inc Japan Asia/Pacifi c Rim 29226 101 12093 121 -221 298 -1 293 4.9 EU

216 Hellenic Petroleum SA Greece EMEA 9687 219 13696 108 110 251 2 238 15.7 R&M

217 Westar Energy, Inc Kansas Americas 9265 229 2261 264 273 189 4 136 6.8 EU

218 Cosmo Oil Co, Ltd Japan Asia/Pacifi c Rim 17575 140 31921 50 -866 313 -8 316 6.6 R&M

219 TECO Energy, Inc Florida Americas 7356 260 2997 240 245 198 5 123 -3.3 DU

220 Qatar Electricity & Water Co Q.S.C Qatar EMEA 6114 289 1242 302 395 160 7 70 19.5 DU

221 Hawaiian Electric Industries Inc Hawaii Americas 10149 211 3375 231 139 242 4 139 13.5 EU

222 Shenergy Co Ltd China Asia/Pacifi c Rim 6135 287 3934 215 254 195 5 127 16.1 IPP

223 SDIC Power Holdings Co, Ltd China Asia/Pacifi c Rim 23796 115 3893 218 172 226 1 268 26 IPP

224 Public Power Corp SA Greece EMEA 21010 125 7830 155 40 275 0 280 -0.3 EU

225 Buckeye Partners, LP Texas Americas 5981 293 4357 203 226 201 4 144 35 S&T

226 ENN Energy Holdings Ltd China Asia/Pacifi c Rim 5039 325 2940 242 242 199 7 77 28.9 GU

227 AGL Energy Ltd Australia Asia/Pacifi c Rim 14047 171 7106 162 110 253 1 259 7.7 DU

228 Light SA Brazil Americas 5514 302 3580 226 199 214 6 104 7 EU

229 Essar Energy plc Mauritius EMEA 17408 143 17637 85 -778 312 -7 312 27.8 R&M

230 Cameco Corp Canada Americas 7937 250 2243 265 257 193 4 144 0.1 C&CF

231 Empresa de Energia de Bogotá SA ESP Colombia Americas 7728 256 834 318 363 168 5 110 19.4 GU

232 China Resources Gas Group Ltd Hong Kong Asia/Pacifi c Rim 5463 303 2524 251 213 207 6 91 68.3 GU

233 OJSC Federal Hydro-Generating Co - RusHydro Russia EMEA 26580 109 9173 142 -642 308 -3 295 -4.5 EU

234 BKW Inc Switzerland EMEA 7908 252 2933 243 141 241 5 123 -4.5 EU

235 Energen Corp Alabama Americas 6176 284 1617 282 254 196 6 99 4.7 E&P

236 Pembina Pipeline Corp Canada Americas 7997 248 3311 232 217 205 3 177 61.6 S&T

237 Atmos Energy Corp Texas Americas 7496 258 3438 230 191 219 4 155 -10.9 GU

238 National Fuel Gas Co New York Americas 5935 294 1627 280 220 203 6 89 -7.4 GU

239 Hera S.p.A. Italy EMEA 8765 240 6093 176 155 235 2 217 2.2 DU

240 Inter Pipeline Fund Canada Americas 5401 305 1147 308 297 183 6 83 8.7 S&T

241 The SP AusNet group Australia Asia/Pacifi c Rim 9611 223 1563 286 266 192 3 191 7.1 EU

242 China Power International Development Ltd Hong Kong Asia/Pacifi c Rim 11403 196 2863 244 193 218 2 236 16.9 IPP

243 Penn West Petroleum Ltd Canada Americas 14001 172 2551 250 168 230 2 243 3.7 E&P

244 Caltex Australia Ltd Australia Asia/Pacifi c Rim 5133 318 22170 71 54 270 2 236 9.5 R&M

245 Emera Inc Canada Americas 7273 263 1989 272 213 206 4 162 11.5 EU

246 Great Plains Energy Incorporated Missouri Americas 9647 222 2310 260 198 216 3 207 5.5 EU

247 Alpiq Holding AG Switzerland EMEA 15685 158 13613 109 -1109 318 -10 321 -4.9 EU

248 Crescent Point Energy Corp Canada Americas 11721 192 2151 268 184 221 2 234 39.4 E&P

249 Boardwalk Pipeline Partners, LP Texas Americas 7862 253 1185 304 271 191 4 168 9.2 S&T

250 Peabody Energy Corp Missouri Americas 15809 155 8078 152 -482 305 -4 305 11.4 C&CF





FASTEST GROWING AMERICAS COMPANIESState or Country

3-year CGR %

Platts RankRank Company Industry

1 Pacifi c Rubiales Energy Corp Canada E&P 82.5 152

2 Pembina Pipeline Corp Canada S&T 61.6 236

3 HollyFrontier Corp Texas R&M 60.8 61

4 Continental Resources, Inc Oklahoma E&P 56.8 142

5 Concho Resources, Inc Texas E&P 52.7 195

6 Energy Transfer Equity, LP Texas S&T 46.3 121

7 EOG Resources, Inc Texas E&P 42.7 127

8 Denbury Resources Inc Texas E&P 40.4 157

9 Crescent Point Energy Corp Canada E&P 39.4 248

10 Buckeye Partners, LP Texas S&T 35.0 225





power generation, causing the US to experience the largest decline of coal consumption in the world.

Top 10Th e world’s top 10 energy companies generated combined profi ts of $211 billion on revenues of $2.67 trillion, down 11% but up 2.6% respectively from the year-ago leaderboard total, suggesting earnings – while still buoyant – were hit by rising costs.

Taken together, asset values of the top ten rose marginally to $2.44 trillion up from $2.4 trillion in last year.

ExxonMobil continues to hold court at the number one spot for the ninth consecutive year, keeping its oil major rivals outmuscled with a world-class asset portfolio.

Below it, Shell and Chevron traded places for second and third spots respectively as Russian giants Gazprom, Lukoil and Rosneft continue to advance on the top of the pack.

Th e three Russian companies moved up by a combined six places in this year’s list, with Gazprom now 4th, Lukoil 7th, and Rosneft in 9th overall.

Sinopec, or the China Petroleum & Chemical Corp, returns to the top 10 this year after a brief absence last year. PetroChina has risen to eighth spot from ninth place overall in last year, but is down from fourth position in 2011, currently the high watermark for the company.

Norway’s Statoil has consolidated its rise to take 5th spot, up one position from last year and a signifi cant gain from the 11th place it held in the prior year.

But Statoil’s gain refl ects the loss of two notable exceptions to this year’s top 10; BP and ConocoPhillips.

Typically amongst the world’s top fi ve energy players, BP dived to 118th in 2011 from 2nd in 2010, refl ecting the huge losses it suff ered as a result of the Deepwater Horizon disaster in the Gulf of Mexico, the world’s biggest off shore oil spill.

Although the company rebounded to take 4th position in last year’s global Top 250, its unresolved settlement with claimants and other fi nes continues to crimp its earnings.

Last year, BP’s reported profi ts more than halved to $11.58 billion, hit by $5 billion in Gulf spill charges, including a settlement for US federal criminal charges. BP’s ranking also suff ered as a result of its shrinking asset base.

BP has sold over $38 billion worth of assets since 2010 to help pay for the disaster, most of which it completed by the end of 2012. As a result, although BP’s asset value grew marginally last



ASIAN COMPANIES IN 2013 TOP 250

TOP ASIA

PLATTS RANK 2013 STATE OR COUNTRY


INVESTED CAPITAL INDUSTRY CODECOMPANY $ MILLION RANK $ MILLION RANK $ MILLION RANK ROIC% RANK

1 8 PetroChina Co Ltd China 353759 3 358065 5 18810 5 7 64 IOG

2 10 China Petroleum & Chemical Corp China 206605 12 454336 2 10419 11 8 60 IOG

3 12 CNOOC Ltd Hong Kong 74388 30 40389 38 10388 12 17 11 E&P

4 14 China Shenhua Energy Co Ltd China 74599 29 40819 37 7969 14 13 23 C&CF

5 18 PTT Plc Thailand 53442 49 91526 21 3429 28 9 47 IOG

6 19 Reliance Industries Ltd India 63734 38 69838 25 3663 26 7 62 R&M

7 22 Oil & Natural Gas Corp Ltd India 44580 62 28397 56 4260 23 14 21 E&P

8 43 Coal India Ltd India 21382 124 12014 122 3053 31 35 1 C&CF

9 45 JX Holdings, Inc Japan 73332 32 113094 17 1608 62 3 177 R&M

10 49 NTPC Ltd India 31433 92 11952 123 2215 41 9 50 IPP

11 56 SK Innovation Co, Ltd South Korea 30182 97 65421 27 1043 82 5 120 R&M

12 57 Woodside Petroleum Ltd Australia 24810 113 6348 172 2983 32 15 19 E&P

13 59 Inpex Corp Japan 36451 78 12263 119 1844 54 6 97 E&P

14 63 China Coal Energy Co Ltd China 30287 95 14238 102 1442 66 6 93 C&CF

15 66 Tenaga Nasional Berhad Malaysia 28691 102 11626 125 1361 67 7 70 EU

16 68 Tokyo Gas Co Ltd Japan 20084 128 19310 80 1025 83 6 83 GU

17 80 Indian Oil Corporation Ltd India 41808 72 81039 22 783 103 3 202 R&M

18 82 TonenGeneral Sekiyu KK Japan 13961 175 28274 57 552 128 9 47 R&M

19 84 CLP Holdings Ltd Hong Kong 29475 100 13511 110 1071 79 4 130 EU

20 86 Yanzhou Coal Mining Co Ltd China 20013 129 9484 139 1014 85 7 70 C&CF

21 90 Origin Energy Ltd Australia 26668 108 12328 116 934 94 5 123 IOG

22 94 Idemitsu Kosan Co Ltd Japan 27503 104 44098 32 506 137 3 184 R&M

23 95 China Yangtze Power Co Ltd China 25833 112 4211 208 1691 61 7 78 IPP

24 96 Huaneng Power International, Inc China 42261 70 21741 73 899 96 2 221 IPP

25 98 S-Oil Corp South Korea 11149 198 30978 52 505 138 6 83 R&M

26 100 China Resources Power Holdings Co Ltd Hong Kong 22908 117 8045 154 964 90 5 115 IPP

27 105 GAIL (India) Ltd India 10516 207 8951 144 769 106 10 40 GU

28 109 Cairn India Ltd India 9498 225 3082 238 2121 43 25 3 E&P

29 116 Datang International Power Generation Co Ltd China 44899 61 12657 114 663 117 2 238 IPP

30 119 Bharat Petroleum Corp. Ltd India 13686 177 42572 36 331 174 4 148 R&M

31 120 Osaka Gas Co, Ltd Japan 15795 156 13911 106 529 131 4 148 GU

32 122 GD Power Development Co, Ltd China 29715 98 9198 141 795 101 3 207 IPP

33 123 Kunlun Energy Co Ltd Hong Kong 13985 173 4246 205 840 99 7 70 E&P

34 124 The Hong Kong & China Gas Co Ltd Hong Kong 12759 184 3211 235 996 86 9 42 GU

35 125 Inner Mongolia Yitai Coal Co Ltd China 6747 271 5151 189 1053 81 20 7 C&CF

36 128 Korea Gas Corp South Korea 36240 79 31253 51 327 176 1 259 GU

37 131 Power Assets Holdings Ltd Hong Kong 13097 180 1342 297 1254 73 11 30 EU



year, the major’s s asset rank has slipped from 5th spot last year to 7th overall.

ConocoPhillips, still treated in last year’s rankings as one company, has dropped to 13th place from 8th refl ecting its ground-breaking downstream spin off in the form of refi ner Phillips66.

Th e new downstream company checks in for the fi rst time at 15th place overall in the rankings, and fl ies to straight to the top spot of the list of global refi ners ahead of India’s Reliance Industries.

An American revolutionDriven by fracking, the rebound in US oil and gas production has unlocked



ASIAN COMPANIES IN 2013 TOP 250

TOP ASIA

PLATTS RANK 2013 STATE OR COUNTRY


INVESTED CAPITAL INDUSTRY CODECOMPANY $ MILLION RANK $ MILLION RANK $ MILLION RANK ROIC% RANK

38 136 Thai Oil Pcl Thailand 5591 300 14010 105 404 156 9 46 R&M

39 139 Power Grid Corp of India Ltd India 19943 130 2307 261 759 107 5 123 EU

40 140 GS Holdings Corp South Korea 11341 197 8777 148 432 146 4 132 R&M

41 141 Cheung Kong Infrastructure Holdings Ltd Hong Kong 11408 195 581 325 1215 74 11 30 EU

42 149 Manila Electric Co Philippines 5168 314 6792 165 382 165 17 9 EU

43 156 Korea Electric Power Corp South Korea 130389 17 43822 33 -2825 325 -3 295 EU

44 159 Santos Ltd Australia 16235 149 3069 239 495 140 4 148 E&P

45 162 Tokyo Electric Power Co, Incorporated Japan 151092 15 60241 29 -6908 328 -8 315 EU

46 163 Reliance Infrastructure Ltd India 11696 193 3910 217 395 159 5 120 EU

47 166 YTL Corp Berhad Malaysia 16742 146 6550 170 383 164 3 213 DU

48 167 Shanxi Lu'an Environmental Energy Development Co, Ltd China 6461 280 3273 234 419 149 11 30 C&CF

49 168 Chubu Electric Power Co, Incorporated Japan 59299 45 26702 58 -324 301 -1 292 EU

50 169 YTL Power International Berhad Malaysia 12638 187 5147 190 400 157 4 162 DU

51 172 Huadian Power International Corp Ltd China 26948 107 9636 138 236 200 1 259 IPP

52 174 The Kansai Electric Power Co, Incorporated Japan 76963 28 28820 54 -2454 323 -4 307 EU

53 175 Electric Power Development Co, Ltd Japan 21873 120 6613 168 300 182 2 243 IPP

54 177 Hindustan Petroleum Corp Ltd India 16230 150 38018 41 88 263 1 263 R&M

55 179 PT Adaro Energy Tbk Indonesia 6692 274 3722 223 385 163 7 64 C&CF

56 180 Shanxi Xishan Coal & Electricity Power Co Ltd China 7360 259 5094 191 295 184 6 95 C&CF

57 189 China Longyuan Power Group Corp Ltd China 17589 139 2820 245 423 147 3 213 IPP

58 190 Formosa Petrochemical Corp Taiwan 15680 159 30029 53 91 259 1 273 R&M

59 197 NHPC Ltd India 10964 201 1078 310 460 142 5 110 IPP

60 199 Tohoku Electric Power Co Inc Japan 43187 69 18070 84 -1045 317 -3 298 EU

61 201 Banpu Pcl Thailand 7274 262 3844 220 304 180 5 112 C&CF

62 203 Guangdong Electric Power Development Co Ltd China 10717 204 4810 198 277 188 3 193 IPP

63 209 Kyushu Electric Power Co, Incorporated Japan 45628 59 15583 94 -3351 327 -10 320 EU

64 214 Showa Shell Sekiyu KK Japan 12431 188 26503 59 10 284 0 281 R&M

65 215 The Chugoku Electric Power Co,Inc Japan 29226 101 12093 121 -221 298 -1 293 EU

66 218 Cosmo Oil Co, Ltd Japan 17575 140 31921 50 -866 313 -8 316 R&M

67 222 Shenergy Co Ltd China 6135 287 3934 215 254 195 5 127 IPP

68 223 SDIC Power Holdings Co, Ltd China 23796 115 3893 218 172 226 1 268 IPP

69 226 ENN Energy Holdings Ltd China 5039 325 2940 242 242 199 7 77 GU

70 227 AGL Energy Ltd Australia 14047 171 7106 162 110 253 1 259 DU

71 232 China Resources Gas Group Ltd Hong Kong 5463 303 2524 251 213 207 6 91 GU

72 241 The SP AusNet group Australia 9611 223 1563 286 266 192 3 191 EU

73 242 China Power International Development Ltd Hong Kong 11403 196 2863 244 193 218 2 236 IPP

74 244 Caltex Australia Ltd Australia 5133 318 22170 71 54 270 2 236 R&M

Notes: C&CF = coal and consumable fuels, DNR = data not reported, DU = diversifi ed utility, E&P = exploration and production, EU = electric utility, GU = gas utility, IOG = integrated oil and gas, IPP =

independent power producer and energy trader, R&M = refi ning and marketing, S&T = storage and transfer. All rankings are computed from data assessed on June 6, 2013.

previously inaccessible oil and gas from shale resources and is spurring economic activity and transforming the role of North America in global energy trade.

US oil output grew by 1 million b/d last year, the largest increase in the world and in the country’s own history, according to BP’s latest annual statistical review.

Staggeringly, the US is now projected to briefl y overtake Saudi Arabia in 2020 to become the largest global oil producer.

Th e US will also overtake Russia as the world’s biggest gas producer by 2015 and will become almost self-suffi cient in its energy needs by about 2035, according to the International Energy Agency.



#1 IN ASIA BY INDUSTRY

Industry Company Country Platts RankIOG PetroChina Co Ltd China 8

E&P CNOOC Ltd Hong Kong 12

C&CF China Shenhua Energy Co Ltd China 14

R&M Reliance Industries Ltd India 19

IPP NTPC Ltd India 49

EU Tenaga Nasional Berhad Malaysia 66

GU Tokyo Gas Co Ltd Japan 68

DU YTL Corp Berhad Malaysia 166

FASTEST GROWING ASIAN COMPANIES BY INDUSTRY

Industry Company Country3-year CGR % Platts Rank

E&P Cairn India Ltd India 121.0 109

GU China Resources Gas Group Ltd Hong Kong 68.3 232

C&CF Inner Mongolia Yitai Coal Co Ltd China 42.1 125

DU YTL Power International Berhad Malaysia 37.6 169

IPP Guangdong Electric Power Development Co Ltd China 34.1 203

IOG PetroChina Co Ltd China 29.1 8

EU CLP Holdings Ltd Hong Kong 27.4 84

R&M S-Oil Corp South Korea 25.5 98

All rankings are computed from data assessed on June 6, 2013.


Fastest Growing is based on a 3 year compound growth rate (CGR) for revenues. All rankings are computed from data

assessed on June 6, 2013.


Last year, North American companies saw their presence grow with total numbers of US and Canadian energy fi rms in the top 250 climbing from 84 to 102 in 2011.

In 2013, this actually reversed and North American companies slipped to hold 94 placings overall in the Top 250 due to mergers and acquisitions of a number of US and Canadian players.

Th e America’s region also took a smaller slice of the rankings pie, fi lling 106 places in 2013 compared to 113 positions last year. Asia and Pacifi c Rim companies took up some of the slack occupying 74 places, up from 70 in 2012.

But the outright number of companies in the list does not tell the whole story. While the overall numbers of American players fell, the latest rankings show the region’s energy companies were growing at a faster pace.

A total of 15 of the 50 top best performing energy companies on a 3-year CGR basis are now in North America, up from just six last year.

And it seems North America’s gain is now Asia’s loss. Last year, it was Chinese and other Asian energy companies that dominated the fast growers list taking 30 of the top 50 places. Th is year, 20 Asian players remained on the list.

In terms of growth rates, the America’s region has now picked up pace with an average three-year compound growth of 52% for the region’s top 10 fastest growers, a sharp jump from the 30% average 3-year CGR last year.

Th e America’s top performers are now growing at a pace on par with their Asian rivals, the data shows, with both region’s 10 fastest growing energy fi rms averaging 52% 3-year CGR.

By contrast, the success stories in the EMEA region which -with the exception of the UK’s African-focused Tullow Oil- is dominated by Russian players, saw average 3-year CGR of 31%, down from 32% last year.

In South America, Pacifi c Rubiales, the Toronto-based independent led by former PDVSA executives which has made good fi nding and developing oil fi elds in Colombia, continued to shine last year. Pacifi c Rubiales remains the world’s second fastest growing energy



FASTEST GROWING EMEA COMPANIES

Country3-year CGR %

Platts RankRank Company Industry

1 Tullow Oil plc United Kingdom E&P 36.8 147

2 JSOC Bashneft Russia E&P 33.9 62

3 OMV Aktiengesellschaft Austria IOG 33.5 37

4 OAO Novatek Russia E&P 32.9 77

5 Turkiye Petrol Rafi nerileri AS Turkey R&M 32.2 85

6 Grupa LOTOS Spólka Akcyjna Poland R&M 32.2 170

7 Rabigh Refi ning & Petrochemical Co Saudi Arabia R&M 28.2 194

8 OAO AK Transneft Russia S&T 27.8 23

9 Essar Energy plc Mauritius R&M 27.8 229

10 OJSC Rosneft Oil Co Russia IOG 27.1 9





company for a second year with an 82.5% 3-year CGR giving it an overall ranking of 152.

Argentina’s surprise takeover of Repsol’s 51% in YPF last year has yet to signifi cantly aff ect the Spanish major with its own ranking at 38, down from 34 last year.

YPF on the other hand has appeared unable to overcome domestic politics and pricing despite the takeover, as its ranking slipped from 70th to 89th.

Brazil’s state-backed giant Petrobras slipped places from 18th to 27th position overall as soaring production costs, a downstream domestic pricing dilemma and high debts holds back its transformation into key oil exporter.

Shale winners and losersBooming US shale gas output soon led to oversupplies, and US gas prices plunged to a 10-year low in 2012, forcing many US-focused companies to write-down the value of some of shale gas assets.

But weak US gas prices have dented not crippled the US-focused oil majors, even though some such as Exxon and Shell now produce more gas than oil.

With the US pumping record amounts of oil, earnings from US players refl ect those which have been largely successful in shutting in less valuable gas production in favor of liquids.

EOG Resources, a US oil and gas shale producer, is a case in point. Th e independent was absent from last year’s 50 fastest growing list, but jumped in this year in tenth place with a 3-year CGR of 42.7%.

Th e US’ biggest horizontal driller, EOG is present in all three key US shale oil plays; Texas’s Eagle Ford, North Dakota’s Bakken/Th ree Forks, and the Permian Basin of south-western Texas and south-eastern New Mexico. Th e company increased its crude and condensate output by 39% last year.

But EOG’s soaring revenue stream from the shale plays did not save it from slipping down the rankings. EOG’s placing fell from 87th to 127th overall as the company was forced to take a large writedown on the value of its Canadian assets due to low gas prices.

Concho resources, a small US independent focused on the Permian Basin of Southeast New Mexico and West Texas, was the world’s 8th fastest growing energy company with a 3-year CCG of 53%.

Concho, which ranked 200th when it debuted in last year’s Top 250 list, has delivered market leading growth rates from its shale assets and have moved up 5 spots to 195th place.



TOP 50 FASTEST GROWING COMPANIESCompany 3-year CGR% Platts Rank

1 Cairn India Ltd 121.0 109

2 Pacifi c Rubiales Energy Corp 82.5 152

3 Kunlun Energy Co Ltd 74.9 123

4 China Resources Gas Group Ltd 68.3 232

5 Pembina Pipeline Corp 61.6 236

6 HollyFrontier Corp 60.8 61

7 Continental Resources, Inc 56.8 142

8 Concho Resources, Inc 52.7 195

9 Energy Transfer Equity, LP 46.3 121

10 EOG Resources, Inc 42.7 127

11 Inner Mongolia Yitai Coal Co Ltd 42.1 125

12 Yanzhou Coal Mining Co Ltd 41.1 86

13 Denbury Resources Inc 40.4 157

14 Crescent Point Energy Corp 39.4 248

15 YTL Power International Berhad 37.6 169

16 Tullow Oil plc 36.8 147

17 Shanxi Xishan Coal & Electricity Power Co Ltd 36.3 180

18 Buckeye Partners, LP 35.0 225

19 Guangdong Electric Power Development Co Ltd 34.1 203

20 JSOC Bashneft 33.9 62

21 OMV Aktiengesellschaft 33.5 37

22 CNOOC Ltd 33.0 12

23 OAO Novatek 32.9 77

24 China Yangtze Power Co Ltd 32.8 95

25 Whiting Petroleum Corp 32.6 187

26 Turkiye Petrol Rafi nerileri AS 32.2 85

27 Grupa LOTOS Spólka Akcyjna 32.2 170

28 Empresas Copec SA 31.8 129

29 YTL Corp Berhad 31.4 166

30 Ecopetrol SA 31.3 16

31 Valero Energy Corp 29.5 26

32 PetroChina Co Ltd 29.1 8

33 ENN Energy Holdings Ltd 28.9 226

34 Rabigh Refi ning & Petrochemical Co 28.2 194

35 OAO AK Transneft 27.8 23

36 Essar Energy plc 27.8 229

37 China Petroleum & Chemical Corp 27.5 10

38 CLP Holdings Ltd 27.4 84

39 China Shenhua Energy Co Ltd 27.3 14

40 OJSC Rosneft Oil Co 27.1 9

41 Plains All American Pipeline, LP 26.8 73

42 Banpu Pcl 26.6 201

43 The Hong Kong & China Gas Co Ltd 26.4 124

44 SDIC Power Holdings Co, Ltd 26.0 223

45 Alliance Oil Co Ltd 25.9 185

46 Apache Corp 25.5 50

47 S-Oil Corp 25.5 98

48 Cosan Ltd 25.1 202

49 YPF SA 25.1 89

50 Tesoro Corp 25.1 75

Fastest Growing is based on a 3 year compound growth rate (CGR) for revenues. All rankings are computed from data

assessed on June 6, 2013.


Oklahoma-based Continental Resources, a leading Bakken shale oil producer, is another shale winner. Th e company has risen to the world’s 7th fastest growing company with a 3-year CGR of 56.8%. Last year it placed 42nd in the list with a 20.2% CGR.

Continental, which plans to triple its production to 300,000 boe/d by the end of 2017, now sits in 142nd place overall after climbing 66 positions.

Although not shale related, US independent Anadarko was a notable mover in the Top 250. Th e producer jumped from 218 to 44 as its bounced back from the impact of a $4 billion Macondo payout to BP in 2011 to settle its share of oil spill claims.

Of notable absence in this year’s rankings, is Canada’s Nexen which, formerly at 163th, was swallowed up by CNOOC last year.

Producers with more gas-focused assets in North America have not fared so well. Savage asset value writedowns due to low gas prices have hit some North American producers much harder than others. Th e main US shale casualties last year were Talisman Energy, Devon Energy, and Chesapeake Energy.

Chesapeake Energy, one of the fi rst movers in the US shale game, dived from 64 to 210 place refl ecting its fall from grace as the US shale gas glut shrank its revenues and it suff ered a governance crisis.

Th e debt-laden independent has seen its share price devastated agreed to sell over $12 billion in assets since the beginning of 2012 to plug a cash-fl ow defi cit



aggravated by dire prices for gas, which accounts for some 80% of its output.

Part of those sales includes a $1 billion deal for 850,000 acres of shale to China’s Sinopec agreed earlier this year.

Oklahoma-based Devon Energy, another the natural-gas-focused producer, suff ered similarly with US gas price dragging down its value and forcing massive asset impairment charges. Devon dropped 151 places in the ranking from 57th to 208th.

Likewise, Canada’s Talisman was penalized in 2012 when cheap US gas and cost blowouts at overseas projects conspired to pushed its operating performance into the red. As a result, Talisman sank from 103th to 206th place overall.

Another shale loser is Peabody Energy Corp, the largest US coal producer, which has suff ered from US power producers ditching coal for cheaper to fuel their plants.

Peabody sank by 151 places to in this year’s rankings to just hang on in 250th place.

Asia In 2012, all of the net growth in global energy consumption was – once again – in emerging economies, with China and India alone accounting for nearly 90% of the total gains.

Th e world’s top 10 fastest growing energy companies is still led by Cairn India which has seen its Rajasthan oil development fuel a huge 121% CGR over three years.

Asia’s top ten growth companies scored 49% CGR in 2012, which rose to 52%

last year, with the stand-out growth of leader Cairn India continuing to pull up the average. Th e numbers confi rm that Asia remains the global engine of demand growth across the board.

Indeed, China’s energy players in the list of companies have now grown from 23 to 27, and now outnumber the US energy companies based in Texas for the fi rst time ever.

Chinese resource companies have continued to target foreign acquisitions as part of a global strategy to access the key commodities needed to fuel China’s economy.

Last year was no diff erent, and CNOOC’s $15.1-billion purchase of Canada’s Nexen, which closed in February this year, was China’s biggest-ever overseas energy acquisition.

Th e deal will likely push CNOOC into the top 10 next year, after years of slowly clambering above rafts of mid-sized oil majors to occupy 12th position overall in 2013.

CNOOC’s assent through the ranks of the world’s biggest energy fi rms has been meteoric by any yard pole. In just 10 years, the Chinese major has now jumped 64 places in the rankings from 76th in 2002.

With the split up of ConocoPhillips, China’s state-run CNOOC also now takes the top position as the world’s biggest exploration and production company, a testament to the giddy rise of the Asian resource tiger.

PetroChina, facing more stubborn competition from the big cats, has



gained just two places over the same period, up from 10th position to 8th.

But the modest progress in position belies the fact that PetroChina remains Asia’s fastest growing integrated oil fi rm, with a three-year compound growth rate of almost 30%.

China Petroleum & Chemical Corporation, or Sinopec, has fared similarly well rising 2 places to 10th overall and boosting the world’s second biggest energy generator of revenues behind Shell.

Oversees acquisitions is not the only source of growth for China’s top energy majors either. Closer to home, China new oil product pricing mechanism is widely expected to reduce the regulatory risk of refi ning losses, and boosting downstream earnings for the integrated players.

Kunlun Energy, the listed natural gas subsidiary of Chinese state-controlled company PetroChina, continues to outpace not only its global but regional rivals with its 75% 3-year CGR making it the world’s third fastest growing energy company last year.

India made another solid showing in this year’s Top 250, with its mix of 12 oil and gas producers, coal and power companies; though the pace of their growth has slowed.

In last year’s rankings, half of India’s 12 companies were among 50 fastest growing energy companies in the world with an average 3-year CGR of 40.6%. In this year’s list only one remains, Cairn India.

India energy conglomerate Reliance Industries, which operates the world’s

biggest refi ning complex at Jamnagar and earns 80% of its revenue from refi ning, has leaped from 57th spot a decade ago to 19th place over all this year, making it world’s number two refi ner behind Phillips 66.

South Korea’s S-Oil Corp and India’s Bharat Petroleum lead in Asia as the region’s fastest growing refi ners.

State-run monopoly miner Coal India, at 43 overall, continues to lead the table for return on invested capital with a remarkable 35% ROIC. Coal India has now posted sector-leading ROIC for the last three years despite the challenges it faces in meeting its production targets.

Indeed, its 3-year compound growth rates, a measure of revenue growth, are less impressive, however, growing 13.4% over the period.

South Korea’s SK Innovation, petrochemical and base oil producer, slipped from 26th place last year to 54th overall.

Russia Russia’s continued dominance as a key global resource and energy hub remains ever present in this year’s numbers, but their relative performance in the standings was eroded last year.

Th e combined ranking of the 14 Russian companies in this year’s Top 250 was 81, compared to 56 previously when the absence of Alliance Oil meant there was one fewer Russian player. Even excluding Alliance, Russia’s overall average standing slipped to 73th place last year.

Collectively, Russian’s seven energy companies in the overall top 50 have

improved their average rankings to 18.1 place, up from 19.4 in 2011.

Russian oil and gas giants Gazprom, Lukoil and Rosneft moved up by a combined six places in this year’s list, with Gazprom now 4th, Lukoil 7th, and Rosneft in 9th overall. Rosneft, which has risen from 16th in the rankings when its fi rst listed in 2006, could now well challenge the top three spots after buying TNK-BP, the country’s third-biggest oil producer.

After completing its $55 billion purchase of TNK-BP this year, Rosneft became the world’s biggest publicly traded company in terms of hydrocarbons production and reserves.

Th e enlarged Rosneft controls some 40% of Russia’s total crude output of more than 10 million b/d, and will also become a major refi ner in the country, with control of 11 plants totaling some 1.6 million b/d, nearly a third of Russia’s total capacity.

Alliance Oil, an independent oil and gas company with vertically integrated operations in Russia and Kazakhstan, jumped in at 185th place, the highest spot for a new entrant in this year’s rankings.

But this year’s list suggest the region’s growth is also slowing with Russian energy companies taking four out the top 10 spots for fastest growing fi rms in the EMEA region last year.

Th e previous growth burst by energy fi rms in the regional was arguable supported by the surge in energy prices on the back of stellar Chinese growth rates which are starting to slow.



Russian utilities fared worse with government-controlled RusHydro and Federal Grid Co of Unifi ed Energy falling by a combined 225 places. In the case of generators such as RusHydro, declining liberalized power prices and weaker demand growth played a part while transmission operators labored under regulated tariff s.

But Russia’s biggest energy players continue to climb up the rankings.

Gas giant Gazprom moves up to into fourth position, replacing BP, continuing its solid growth path over recent years.

Russia’s second-tier producers, Bashneft, Novatek, Tatneft all are still in the top ten fastest growing energy companies in the EMEA region but collectively they slipped six places in the overall rankings.

SECTORSRefi ning 2012 marked another year of large refi ning capacity additions in Asia Pacifi c and signifi cant capacity reductions in Europe and the Caribbean.

Despite overcapacity, global crude runs grew by 0.5 million b/d in 2012, with increases in China, India and the US more than off setting declines in Europe and South & Central America.

Global refi nery capacity utilization improved to over 82%, the highest since 2008 but, as in the recent past, there were large regional discrepancies in margins and earnings.

Th e trickledown benefi ts of the US shale phenomenon can now clearly be seen in the downstream sector.

Most US refi ners continue to benefi t from three key competitive advantages to their overseas rivals; cheap natural gas, low cost domestic crude, and upgrading capability. Not all US refi ners were winners though. Some of those with US East Coast assets importing crude from West Africa or the North Sea were, literally, killed by dire margins and weak demand.

Half of the world’s top 10 refi ners in the rankings, however, are now the US compared to the previous year when US players made up just three of the top 10 refi ning spots.

In 2011, the global refi ning success stories were dominated by Asian plant owners. Th is year, only four where based Asia and only one, Poland’s PKN Orlen, was from the oversupplied EMEA region.

Phillips66, Conoco’s downstream spinoff , checks in for the fi rst time at 15th place in the rankings, and fl ies to straight to the top spot of the global refi ners ahead of India’s Reliance Industries.

ConocoPhillips’s ground-breaking split in 2011 year appears to have paid off its terms of re-valuing the upstream and downstream components of the company, according to the data.

In 2011 prior to the split, ConocoPhillips combined assets of $153 billion ranked 16th in the asset class. A year later, ConocoPhillips asset slipped to 20th place at $117.14 billion but Phillips 66 held $48.1 billion giving a combined $165 billion asset score.

With most Mid West-focussed US refi ners exposed to discount shale oil, bumper margins over external crude benchmarks have infl ated their profi ts.

US independent refi ner HollyFrontier is the world’s sixth fastest growing energy company in this year’s rankings, up from 11th last year, with a 3-yr CGR of 60.8%.

HollyFrontier owns fi ve US refi neries with total crude capacity of 443,000 b/d. Its Midcontinent refi neries consist of the 135,000 b/d El Dorado, Kansas, refi nery, which can run a wide slate of crudes, and a 125,000 b/d Tulsa, Oklahoma, plant that runs mostly sweet crudes, although it can run sour crude when it is economical.

Tesoro was another US refi ning winner, climbing 23 slots overall to place 75th and jumping on the bottom rung of the world’s 50 fastest growing energy companies.

Top US refi ner by capacity Valero has also gained on its exposure to cheap US light, tight oil, rising to 4th for the refi ning sector 26th overall and

While US and Asian refi ner dominate the top 10 leaderboard for the sector, the only European refi ner, Poland’s PKN Orlen, made a return to the sector’s in this year top ten rankings.

Now in ninth place after falling out of the sector leaderboard last year, PKN Orlen’s recovery may refl ect a mild recovery in Europe’s refi ning margins despite the structurally weak outlook for downstream players the region.

Storage and pipelinesAt position 23 overall, Russia’s transport behemoth company Transneft still holds its own as the world’s biggest storage and transport company in the rankings despite slipping from third to ninth position in Europe’s fastest-growing category this year.



But the stand-out movements this year come again from one the key benefi ciaries of the North American energy boom; companies owning and expanding pipeline and storage capacity to deliver the new oil and gas wealth to customers.

Midstream operators have seen markets swell and earnings climb as the sector scrambles to move oil and oil-products in new directions around North America.

Excluding Transneft and Brazil’s Ultrapar Holdings, North American storage and pipeline companies made up eight of the top ten spots for the industry sector last year.

More importantly, US mid-stream players now score three positions on the list of 10 fastest growing energy companies in the Americas. Th e year before there were none.

Th e global relative importance of the mid-stream sector has also grown, improving its average ranking from 89.3 last year to 88.2.

In the US, Buckeye, AGL Resources and Boardwalk Pipelines are all new entries in this year’s rankings, a testament to the surging demand for oil and gas transport options such as trucks and trains across the country.

Th is year also saw the debut of Canadian transporter Pembina Pipeline in the rankings, which jumped into 236th place overall. It also sits in fi fth place at the top of the global fastest growers list with an impressive 61.6% 3-year CGR.

Pembina has grown strong on its NGL pipeline capacity in Alberta, Western

Canada and crude pipeline system in British Columbia and is riding high on the oil sands revolution as manages pipelines used to transport synthetic crude from upgrading facilities.

Another Canadian midstream player making an entry this year is Inter Pipeline Fund, which has seen its key role as biggest transporter of oil sands bitumen take it to 240th place overall.

In Brazil, Ultrapar Holdings, which distributes fuel and gas, produces chemicals, operates bulk logistics placed 133th overall and was the sector’s 8th ranked storage and pipelines player.

UtilitiesUtilities do not fi gure near the top of Platts’ 250 list, with the fi rst 28 places dominated by oil and gas concerns – no surprise, perhaps, given the global nature of the hydrocarbons business versus the predominantly national focus of power and gas utilities.

Th ereafter, however, some 32 electric, gas or multi-utilities fi gure in the top 100. In recent years these companies have represented an increasingly volatile group of risers and fallers in the rankings, a fact that many utility management boards are still coming to terms with after years of stolid dependability.

For the majority of diversifi ed and electric utilities in the top 100, 2012 represented another grim year of retrenchment. A handful of the largest companies in these two categories, predominantly European, have managed to claw their way up the list, but overall their standing remains down on recent years. While upstream oil and gas companies have benefi ted from the $100 barrel, many electricity supply companies

have been adapting to wholesale power prices uncomfortably close to or even below the cost of production.

Th e best utility performers in 2013 list, then, really have bucked a long-term trend. Th e largest, Electricite de France, has risen year-on-year from 40th to 29th. Centrica of the UK nips at EDF’s heals at 30th, up from 77th last year. And Iberdrola, whose core Spanish market is frankly ravaged by unpaid debt and huge overcapacity, completes a tight top three at 31st, up from 39th.

At face value these promotions up the list are hard to explain, given the extremely downbeat message across the sector, the drive to cut costs, close uncompetitive assets and seek growth in riskier, more distant markets.

Less surprising, perhaps, is a solid retention of position by National Grid of the UK, albeit up two places to 33rd, in keeping with its fully-regulated transmission business model. Also unsurprising is Enel of Italy’s decline from 37th in 2012 to 69th this year, given its exposure to tough sector reforms in southern Europe. Th is is followed by an astonishing leap, the biggest of any utility in the list – E.ON’s move from 144th to 36th (it had been as high as 13th in 2011).

Was E.ON’s post-Fukishima nuclear closure bill in 2011 so much worse than German peer RWE’s, down from 33rd to 42nd? Certainly there is a cost-cutting, post-impairment ‘bounce’ behind a number of these utility improvements. Th e fundamentals remain challenging, but these companies are at least coming to terms with a new reality of uncertain demand, subdued wholesale prices and increasing regulatory intervention. A few,



like Iberdrola, have moved early to catch the renewables wave. Others, like Centrica, are evolving a new service-driven business model focused on its customers.

EDF’s huge nuclear and hydro asset base ensures a high standing in the ranking, augmented last year by sales growth of 11.4% and reduced one-off charges. In the last two years the French utility has made provisions for risks and impairments in the hundreds of million euros compared to the €2.7 billion hit recorded in 2010, when price declines in the US and Italy came home to roost. Th at year EDF ranked 65th in the Top 250.

Th e disconnect between global oil and local electricity prices leaves EDF relatively unscathed. As a country with scant gas-fi red capacity, France has been mercifully free from the oil-indexed gas supply contracts that have driven so many European power generators into the red. Th e growth in EDF’s power exports in recent times underlines the competitive nature of its generation mix when ranged against combined cycle gas turbine plants in neighboring markets.

Th ese mitigating circumstances for EDF hide a basic truth for many electric utilities – future earnings are far less assured than in previous years. A ten-year view shows the number of electric utilities in the top 50 down from 17 to four. In that time the sector has undergone a profound revolution as the green power agenda has evolved and ageing central generation assets have come under fi nancial and environmental pressure.

US utilities slipUS utilities may have faced less severe economic austerity, but still their standing has slipped over a longer view as

demand and prices have stagnated. In 2003 Edison International ranked 15th in the Top 250. By 2012 it had slipped to 188th, rising to 52nd this year. Southern Company, a solid performer in recent years and 41st in this year’s list, has slipped from a high point of 19th in 2004. Exelon has moved from 12th in 2004 to 26th in 2010 to 71st this year.

Southern Company’s success in its 100th year of operation had much to do with a $1 billion fuel bill saving in 2012 on 2011. Over the last fi ve years the utility has tripled the percentage of natural gas in its generation mix, using more gas than coal for the fi rst time in its history during 2012. Huge capital commitments to ensure its future were evident in progress on nuclear units 3 and 4 at Plant Vogtle, a coal gasifi cation plant in Mississippi and completion of installation of 4.4 million smart meters in Georgia, Alabama and Florida.

Th e theme of the most recent round of US power sector earnings reports in August, 2013 was of lower volumes sold at lower prices, prompting cost-cutting moves and, for some companies, fostering strategic shifts. Lower wholesale forward power prices were identifi ed in the Mid-Atlantic, California and Texas. Th e lower Mid-Atlantic forward prices are the result of increases in Marcellus shale gas production pushing regional gas prices below Henry Hub levels. Overall, forward power prices across the US are down 5% to 7% from 2014 to 2017.

Th e merger of Exelon and Constellation in March 2012 gives Exelon impressive new scale, but on an operating basis, the utility’s earnings in 2012 were $2.85 per diluted share compared to $4.16 in 2011.

While 2012 earnings cannot be directly compared to 2011 earnings due to the addition of Constellation and BGE to Exelon’s fi nancial results, the overall decrease in non-GAAP operating earnings refl ected a year driven by challenging power prices and reduced profi tability, only partially off set by post-merger synergies. In response, Exelon plans to shift its capital expenditures to its regulated utility businesses, including Commonwealth Edison and Baltimore Gas & Electric, over the next fi ve years. It is to allocate $13.5 billion of its planned $16 billion in capex to its utilities.

Asian utility growthWhile no European or US utility or generator makes the top 50 fastest growing companies in the 250, nine Asian utilities and IPPs do. Fourth in this list with a three-year CGR of 68.3% is China Resources Gas Group Ltd, which operates 151 city gas networks in 20 provinces across China. Driven by organic growth and acquisitions, the gas utility recorded a 45% increase in turnover for 2012 and registered a 38% increase in net profi t. Gross gas sales increased 28% to 9.3 billion cubic meters and total connected residential customers increased 34% to 14.03 million. Th is impressive growth rate is set to continue: the company is confi dent it can reach 20 billion cubic meters of gross gas sales volume and 20 million connected residential customers by 2015.

Of 15 Chinese concerns in the Top 50 fastest growing company list, six are electric power, gas or IPP companies, further proof if needed that industrial and urban expansion in China remains a potent driver of global commodity prices. Th ree of these are dedicated power



producers – Guangdong Electric Power Development Co, China Yangtze Power Co and SDIC Power Holdings Co.

While the rate of growth in Chinese electricity demand has been slowing (this is relative: fi ve-month consumption of 2,057 TWh to end-May 2013 was 4.9% higher than for the same period of 2012), the rate at which generating capacity is being added to the country’s grids remains high, boosting the asset values of these companies.

An astonishing 24,660 MW were added in the fi rst fi ve months of 2013, up almost 9% compared with the same time in 2012. Chinese additions during the fi ve-month period included 6,840 MW of hydroelectric plant – which now stands at 219,580 MW in all – and 12,270 MW of fossil fueled, meaning predominantly coal-fi red capacity, which now totals 830,410 MW. Th ere is also 13,670 MW of nuclear plant with the remaining 70,000 MW or so of capacity including wind and some solar facilities.

Th e slight cooling in demand growth may be drawing to a close. China State Grid Corporation, which serves 88% of China by area, has said that electricity demand in its service area was expected to increase by an average of 8.4% on year during the 2013 summer peak period.

India is Asia’s second power house in terms of demand growth and capacity additions. Up to 49th place in this year’s list from 62nd last year, government-controlled generator NTPC Ltd delivered a post-tax profi t of $2.21 billion for the fi nancial year ending March 2013, an

on-year increase of almost 37%. Th e utility commissioned 4,170 MW in the 12-month period, taking its total to 41,184 MW – or over 18% of Indian grid capacity.

Across India capacity additions slowed in 2012, with coal and gas shortages impacting on annual generation fi gures as reported by India’s Central Electricity Authority. Nevertheless coal-fi red generation increased by 13% to 659 TWh, mainly due to the commissioning of more than 15,000 MW, while gas-fi red generation dropped nearly 30% to 64.8 TWh. Th e CEA estimated that 106 TWh of potential generation was lost due to gas shortages and coal quantity and quality shortfalls. Transmission constraints and other issues caused the remaining loss of 21 TWh.

COALChina the driverCoal dominates Asia’s power mix – hence the presence high up in the 250 list of China Shenhua Energy Co (14th, up from 16th last year and the highest-placed non-oil and gas company), Coal India Ltd (43rd) and China Coal Energy Co (63rd). Other smaller Chinese coal companies rank highly in terms of growth, with Inner Mongolia Yitai Coal Co Ltd, Yanzhou Coal Mining Co Ltd and Shanxi Xishan Coal & Electricity Power Co Ltd all placing in the top 20 fastest-growing energy companies in the world.

Coal accounts for about 70% of all Chinese power generating capacity and 80% of output, and the fuel benefi ted from two power sales tariff increases from late 2011 and a reversal in the three-year upward trend in coal prices in 2012.

Th e price of Shanxi Premier Blend coal at the key Qinhuangdao trading hub fell by 23% during 2012, as rising coal output and imports outstripped demand. While falling coal costs assisted generator profi ts, declining coal prices in part refl ected the fact that coal-fi red generation grew only modestly in 2012. Th e limited – and in areas, negative – growth in coal-fi red output came as Chinese electricity demand grew by a relatively subdued 5.5% on 2011.

With an overhang of coal-fi red capacity emerging in 2012 as plant commissioning continued in line with previous double-digit growth expectations, the use of coal-fi red plants declined. Th e average utilization of coal-fi red plants fell to 4,965 hours in 2012, down 6.4% on year, as China’s stock of generating capacity rose by 8.2% on year to 1,144,000 megawatts at end-2012.

Th e total included 819,000 MW of fossil-fueled plant, more than 90% of which is coal-fi red. Th e plants produced about 3,900 TWh of the 4,980 TWh of total generation in 2012, up 0.3% on year compared with the 14.2% growth posted in 2011.

A switch in the fortunes of power and coal producers in 2012 compared with 2011 can be seen from the results of China Shenhua Energy Co. China’s largest listed coal producer, Shenhua Energy is also a substantial power generator as well as a rail and port operator. Shenhua Energy posted revenues of Yuan 250.26 billion, up 19.6% on year, while profi t attributable to shareholders was 6.6% up on year at Yuan 48.858 billion.



However, while the pre-tax profi t from its coal operations fell from Yuan 46.593 billion in 2011 to Yuan 45 billion in 2012, pre-tax profi t from Shenhua Energy’s generating operations rose by 30.1% from Yuan 8.329 billion in 2011 to Yuan 10.837 billion in 2012.

Th e company said its integrated coal mining, transportation and generating operations allowed “eff ective risk hedging, mutually complementary and coordinated development among these segments.” India has just one coal supplier high in the list, dominant state-run producer Coal India Ltd up to 43rd this year from 48th last year and 51st the year before that.

Th e company holds the coveted top spot in the Return on Invested Capital segment. With an ROIC of 35%, Coal India has outstripped the likes OAO TNK-BP Holding (28.3%), Cairn India (25.3%), Exxon Mobil (24.5%) and Marathon (21.9%). Also deserving of mention in this context is Inner Mongolia Yitai Coal Co Ltd, landing a creditable seventh spot in the ROIC list with a 20% return.

Despite production of 452 million tonnes of coal in 2012-13 (April-March), up 3.8% on the previous fi scal year, Coal India struggled to meet the country’s demand from indigenous sources – Indian power utilities imported 62.5 million mt of thermal coal for the fi scal year, up 37% year-on-year. Th e company is confi dent that it can meet demand from its own mines this year and is looking to develop its international profi le, notably in Australia, Mozambique and South Africa. It remains to be seen whether the extended bear run in oversupplied global

coal markets will blunt the growth of this vast organization.

Gas utilities Among energy utilities, those focused on gas generally improved or maintained their standings in the Top 250, with three-year Compound Growth Rates (CGRs) averaged across the 16 gas utilities in the 250 list of 16% compared to a 7% average for the 60-odd electric utilities in the list.

Spain’s Gas Natural Fenosa is the gas utility sub-sector’s highest placed company, having gained 12 places year-on-year to take 46th place overall in the Top 250 – testament to the company’s debt reduction eff orts and its highly successful drive to diversify earnings abroad, notably in Latin America and via an aggressive international LNG sales drive.

Today the company has a natural gas and LNG supply portfolio of around 30 billion cubic meters and a fl eet of 10 LNG tankers, making it a benchmark LNG operator in the Atlantic basin and the Mediterranean. It should be noted that Gas Natural Fenosa has also diversifi ed into conventional power generation, where performance has been mixed, and renewables, where growth is encouraging.

Meanwhile Tokyo Gas Company’s rise from 111th to 68th is the standout year-on-year promotion for a gas utility, driven by a 120.7% increase in net income for fi scal year 2012. Th e boost refl ects a 9% increase in sales coinciding with a hike in gas rates after a period of under-recovery – the so-called ‘slide time lag’ that sees Japanese gas rates lag behind raw material costs by around fi ve months. Managing this lag is a challenge

for Japanese gas companies, whose customers are faced with some of the highest prices in the world. Month-ahead gas as assessed by Platts’ Japan Korea Marker in August, 2013 exceeded $15/MMBtu compared to $10-12/MMBtu in Europe and $3-4/MMBtu in the US.

Since the Great East Japan earthquake that struck March 11, 2011, LNG-fi red power stations have helped address near-term shortages of electricity in the Tokyo metropolitan area. With a vision to take this trend into the long term, Tokyo Gas Company now imports over 12 million tons of LNG per year, has three LNG storage and production plants in Tokyo and 2,000-MW of gas-fi red power generating capacity, which it plans to increase to a maximum of 5,000-MW by 2020.

Th e third largest global gas utility in the Top 250 is GAIL (India) Ltd, edging up to 105th from 109th and posting a healthy three-year CGR of 23.5%. Th e company boosted 2012-13 net revenue by 18% and net profi t by 10%, securing a long-term LNG supply agreements with Gazprom, Gas Natural Fenosa and GDF Suez, a long-term liquefaction tolling capacity agreement with Dominion Resources of the US and commissioned an LNG terminal at Dabhol, Maharashtra, where it is to act as Commercial Operator for 25 years.

Rounding off a busy year, GAIL added 1,300-km of new gas lines to its network during 2012-13, taking its network to 10,700-km with a capacity of 210 million standard cubic meters of gas per day transmission. Th e company plans to expand its network to around 15,000-km within the next few years.

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*Platts 2012

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