News Base NRG Issue 20

For analysis and commentary on these and other stories, plus the latest oil and gas developments, see inside…

Copyright © 2011 NewsBase Ltd.

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NRG

November 2011

Issue 20 ! News

! Analysis ! Intelligence

Published by

! NewsBase

AFROIL 2 ! IEA warns of under-investment in MENA 2 ASIAELEC 4 ! CCS in the balance 4 ASIANOIL 5 ! Opportunity knocks for Beach Energy 5 CHINAOIL 7 ! Chinese shale leads to stalemate with

Russia 7 ENERGO 9 ! Pot calling the kettle black? 9 EUROIL 11 ! Italy’s energy future uncertain under

new leadership 11 FSU OGM 12 ! Botas, SOCAR plan gas pipeline

across Turkey 12 GCEM 13 ! China’s emissions conflict 13 GLNG 15 ! Offshore Australian project nears

FID moment 15 LATAMOIL 17 ! US dilemma over Cuba’s oil 17 DOWNSTREAM MENA 18 ! Sadara financing gains momentum 18 MEOG 20 ! IMF report flags up GCC revenue

bonanza in 2011 20 NORTHAMOIL 22 ! Alberta, Europe and the oil sands fight 22 REM 24 ! North African solar can create an

Arab summer 24 UNCONVENTIONAL OGM 26 ! Australian CBM sector faces

growing opposition 26

NEWSBASE ROUND-UP GLOBAL

NRG This is the twentieth issue of the NewsBase Round-up of Global energy issues.

NRG comes to you entirely at our expense, which we hope will further increase the value you derive from subscribing to NewsBase.

NRG covers developments from all global energy regions and sectors, and brings you the “best of the best” (as selected by our editors) from each of the previous month’s weekly Monitors.

The global nature of the energy industry means that no episode happens in isolation and we hope that NRG will help to tie up events around the world in one single issue.

This month, AfrOil assesses an IEA warning about under-investment in MENA, while EurOil assesses Italy’s energy landscape with Berlusconi out of the picture.

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

NRG NEWSBASE ROUND-UP

–– GLOBAL ––

NRG November 2011, Issue 20 page 2




Potential causes of reduced investment: !" Deliberate government policies to develop production capacity more slowly in order to hold back resources for

future generations or to support the oil price in the near term !" Constraints on capital flows to upstream development because priority is given to spending on other public

programmes !" Restricted, or higher-cost, access to loans or other forms of capital !" Delays owing to legal changes or renegotiation of existing agreements !" Increased political instability and conflicts !" Economic sanctions imposed by the international community !" Higher perceived investment risks, whether political or stemming from uncertainties in demand !" Constraints on inward investment as a result of stronger resource nationalism, particularly in regimes seeking to

pre-empt popular uprisings !" Delays because of physical damage to infrastructure during conflicts

Source: IEA WEO 2011

Much of the world’s additional energy requirements up to 2035 will come from the Middle East and North Africa, but it may not be plain sailing and investments are at risk of being sidetracked. In particular, the International Energy Agency (IEA) has said efforts to preserve stability by diverting cash from energy spending into social projects could store up trouble further out.

Big bucks Investment in global upstream spending will rise in 2011 to US$550 billion, according to predictions set out in the IEA’s World Energy Outlook (WEO). However, the report went on to warn that changes in the MENA region could fall below expectations in the medium term, jeopardising the region’s future.

The MENA region is to provide 90% of the world’s growth in oil production until 2035, under the IEA’s baseline plan, called the New Policies Scenario.

In order to meet this objective, spending in the area needs to average US$100 billion per year from 2011 to 2020 and climb to US$115 billion per year from 2021 to 2035. All figures are in 2010 US dollars.

The IEA report, though, launched in London last week, said it was “far from certain that all of this investment will be forthcoming, for many different reasons affecting some or all of the countries in the region.” The WEO’s Deferred Investment Case did not focus on any specific countries in the region.

A country may choose to slow development in its energy industry for a number of reasons, the OECD’s energy watchdog said. (See text box.)

The IEA’s head economist, Fatih Birol, said the agency had been “very careful not to put in probabilities on such alternative scenarios but the fact that we have made this Deferred Investment Scenario, in itself, is a signal that we see

a possibility that production growth from the MENA region may not come as much as consumers would like.”

Such a slowing of investment, Birol continued, would be a “pity for the global economy, a pity for the oil sector and, in the long term, a pity for those [MENA] countries. There is a likelihood that this could happen but we hope it does not.”

Under the slower spending case, the IEA suggested investments in oil and gas would be one third below that set out under the New Policies Scenario in 2011-15. Then, from 2015-20, spending would get back on track, matching up with the baseline projection by 2020.

Shaking it up The shortfall in oil production by 2020 would be around 6 million barrels per day, which would have a “significant impact” on global oil balances and therefore prices."

AfrOil

IEA warns of under- investment in MENA There are a host of reasons why investments in the MENA region may fall below the necessary levels, which poses serious risks to the world’s economy By Ed Reed # Reduced investment in MENA’s upstream would increase price volatility # An oil price of US$150 per barrel in 2016-17 would put the world’s economy in the danger zone # MENA countries’ revenue and total global investment would be around the same under either outlook





There would be an impact on gas, but the major shortfall would be a reduction in available oil for the world’s consumers.

Higher-priced oil would spur the development of resources in other countries but would not cover the shortfall. In addition, demand would fall.

Producers in the MENA region would see greater returns from their output in the short term, though they would not be far off gains made under the New Policies Scenario. However, looking over the entire period revenues would be marginally down, at US$16.7 trillion rather than US$17 trillion.

Total upstream investment would be around the same under either scenario, at around US$15.3 trillion. While production would be lower under the deferred case, the price of extracting the energy would be “significantly higher” than output from MENA.

The deferred case would spark a short-term surge in the oil price, peaking at US$150 per barrel in 2016-17, when the shortfall starts to bite owing to the long lead times of energy projects. Prices would then fall back into line with the New Policies Scenario by around 2020, at around US$120 per barrel. Importantly, though, the Deferred Investment Case would be “accompanied by significantly increased price volatility.”

Birol said the IEA had not calculated the expected impact on the global economy should prices rise as high as it has been suggested they will go. However, as a benchmark, he noted that oil prices in 2008 had averaged US$100 per barrel, which was 5% of global GDP.

“We believe the high prices played a crucial role in the run-up to the financial

crisis. They were not the main driver but they did play a role in weakening the trade balance of the consuming countries,” Birol said. This year, he continued, the average oil price has been US$102 per barrel, “which means that global economic recovery is at risk, we are in the danger zone at present levels.”

Should prices rise to US$150 per barrel, “this is definitely a very risky scenario” for the world’s economy and will have “major consequences.”

Demand destruction As a result of the reduced investment, primary oil demand would reach only 88 million bpd in 2015, the WEO said, only marginally higher than 2010 and about 3.2 million bpd lower than the New Policies Scenario. The peak of the demand reduction would be in 2017 – when the price would also peak – at 3.9 million bpd lower than the figure in the New Policies Scenario.

However, the reduction would have a long-term impact and demand would be 1.5 million bpd below the New Policies Scenario number in 2035.

The most significant impact would be seen in the near term, as prices rise and the market reacts to the shortfall through energy conservation, mostly through reduced driving. In the longer term, the higher price would encourage switching to alternatives for transportation – such as biofuels – and increasing efficiency. Coal would also benefit, as coal-to-

liquids (CTL) production would increase.

Importers of energy would be hit by higher prices in both the medium and long term, with the total passing US$46 trillion – around 10% higher – but supply would be more diversified.

China and the US – the two top oil-dependent countries – would play the greatest part in changes. In the US, fuel

is only lightly taxed, making pump prices extremely sensitive to changes in oil supply. China, meanwhile, would focus on large-scale production of electric vehicles and greater efficiency.

Overall, though, oil still accounts for 86% of total transport fuel in 2035, close to the level under the New Policies Scenario. The greatest winner would be biofuels, which would expand from 1.3 million bpd in 2010 to 5.5 million bpd by the end of the period.

Compensating for the shortfall in MENA production would be Russia, Canada and Brazil. However, increasing the pace of exploitation in non-MENA states runs down these resources faster and their share of output would be lower in 2035.

The deferred case set out by the IEA is a concern, given the part that high energy prices can play in spurring economic woes.

Investment decisions must be taken by the countries holding resources – and they have a duty to meet the needs of their citizens. However, contributing to a global slowdown, such as that which emerged from the surge in energy prices in 2008, will not benefit any party involved, including rulers throughout the region.

However, countries – especially those with autocratic rulers – are likely to choose between meeting actual short-term difficulties over nebulous long-term global economic woes."

AfrOil





With the Australian coal and electricity industries still smarting from a new carbon trading law, a taxpayer-backed project to develop the country’s first commercially viable carbon capture and storage (CCS) thermal power plant (TPP) has gone bankrupt.

The Zerogen project, funded by the federal and Queensland governments, was seen as a possible salvation for a power industry still largely dependent on coal and facing a swinging tax under a carbon law going into force next July.

Now Zerogen has ended amid recriminations of misspent taxpayers’ money, while the country’s growing anti-fossil fuel lobby is calling for the abandonment of further CCS research, at least with taxpayers’ money.

Too costly Zerogen was established by the Queensland government in 2006 and invested over US$100 million. The federal government added about US$50 million. The coal industry had also contributed over US$50 million.

The objective had been to build and operate a 530-MW coal-fired commercial TPP by 2015 using CCS technology, which would remove 90% of CO2. The operators of the Zerogen project had earlier this year sought but failed to secure financial backing from the Japanese giant Mitsubishi Corporation, although in a separate area Australia and Japan are co-operating in CCS technology.

It appears that Zerogen, located near Rockhampton on the central Queensland coast north of Brisbane,

found its coal gasification plans too costly and also suffered from CO2 storage problems. Meanwhile, political opponents to the federal and Queensland governments, both Labor Party controlled, are calling for an inquiry into the loss of taxpayers’ money, while the Green Party and other environmental groups said this should spell the end of fossil-fuelled power in Australia. “There should be an immediate independent inquiry as to how this [Zerogen] money has been lost and where it has gone,” said federal parliamentary opposition climate change spokesman Greg Hunt.

Zerogen was a speculative project like the government’s planned Clean Energy Finance Corporation, Hunt said.

The federal government is in the process of setting up the corporation with

an A$10 billion (US$10.18 billion) fund to finance renewable energy and low emissions power plant technologies.

“The collapse of the Zerogen coal emissions storage project in Queensland shows the commercial world is starting the transition away from fossil fuels and towards a clean energy economy,” the Australian Conservation Foundation (ACF) said.

“Despite [Zerogen] receiving government subsidies of almost A$160 million [US$164 million], we still have no commercial-scale proof that carbon capture and storage actually works,” ACF economic adviser Simon O’Connor said in a statement last week."

CCS projects in Australia Source: CO2CRC

AsiaElec

CCS in the balance As Australia’s first commercially viable CCS project goes bankrupt the technology is still provoking serious argument about the future of energy in the country By Graham Lees # The federal- and state-backed Zerogen CCS project failed to find enough private funding # The project lost US$150 million of public funding as it cost and technical problems # Green supporters say that commercial energy is moving away from coal towards renewables





The foundation is an independent agency made up of academics and scientists concerned about climate change and global warming. It calls for greater government support for renewable energy projects via the establishment of a Clean Energy Finance Corporation.

Some proponents believe the Zerogen collapse is a mere technical setback and work on CCS should continue elsewhere. In fact, the federal government continues to fund to the tune of about US$100 million per year the public Global CCS Institute in Canberra. The Zerogen operators say they will hand over all their research to the institute, with which the firm had loose links.

The institute, financed by the federal government until the end of 2013, collates research on CCS technology and has links with other CCS developers in

Europe, the United States and Japan. The institute has declined to comment

on the collapse of Zerogen.

Opposing views Peter Cook, the chief executive of the Australian Co-operative Research Centre for Greenhouse Gases, also known as CO2CRC, was less reticent. He told the Australian broadcaster ABC recently that he believed work on a viable commercial CCS system would continue because the world was not about to stop using coal.

“As long as society chooses to use coal and other fossil fuels there’s no alternative other than to use carbon capture and storage as the way of mitigating the consequences of that use,” said Cook, whose centre also studies CCS technologies and receives funding from both the state and the Australian coal industry.

But ACF president and university science professor Ian Lowe argues that CCS is not the future.

“It’s long overdue that we had an overall look at the issue of funding research and development into carbon capture and storage, given that it’s a speculative technology that can’t possibly extend to all coal-fired power and that, even if it worked, would probably be at least as expensive as renewable energy,” Lowe told the ABC.

“I think it’s entirely reasonable for the coal industry to do research in this area, but I think probably too much public money has been spent in this area, given that it’s likely at best only ever to be a niche application.”

The battle between Australia’s coal-fuelled power industry and renewable energy advocates looks set to continue."

With an abundance of natural gas and a string of liquefied natural gas (LNG) projects in the works, Australia is rapidly becoming one of the world’s most important natural gas export players.

According to a recent note by investment bank Jefferies, an estimated US$180 billion will have been invested in the current crop of Australian LNG projects by 2017, the end result of which should see national output rise by 250%, with the country tipped to become the largest producer of LNG by 2020. It

produced 19.8 million tonnes of LNG in 2010.

Yet Australia’s current crop of coal-bed methane (CBM)-to-LNG projects has drawn stinging criticism from environmental groups. This has led to increased environmental oversight that could well slow development of the sector, raising questions of feedstock supply for several world-class CBM-LNG projects that are currently in the pipeline in Queensland.

However, for Adelaide-based Beach

Energy, which is sitting on an estimated 300 trillion cubic feet (8.5 trillion cubic metres) of gas-in-place within a portion of unconventional acreage, the CBM sector’s problems could be to its advantage.

Speaking to AsianOil, Beach’s manager for investor relations, Chris Jamieson, explained how the company’s shale and basin-centred gas play could prove to be a game-changer in 2012."

AsiaElec

AsianOil

Opportunity knocks for Beach Energy The problems facing coal-bed methane (CBM) projects in Australia could provide an opportunity for Adelaide-based Beach Energy to exploit By Andrew Kemp # Beach is sitting on 8.5 trillion cubic metres of gas-in-place within a portion of unconventional acreage # The company’s unconventional potential lies within the Nappamerri Trough in the Cooper Basin # Growing environmental criticism of CBM projects could be a boon to Beach





Digging deep The company’s unconventional potential rests within the Nappamerri Trough in the Cooper Basin, sitting at a depth of around 3,500 metres.

It was by targeting the deeper areas of the basin, Jamieson noted, that the company had been able to unearth such a large find, with Beach looking at a target section that significantly exceeded initial expectations.

Jamieson described the size of the target as “quite extraordinary,” adding: “Initially we were chasing gas within the shale only; however, after coring and fracture stimulation of the Holdfast-1 well we discovered that we had a gas saturated section of around 700 metres that could extend to 1,300 metres, assuming the deeper Patchawarra section is also gas saturated. Even in the best shale acreages in the US, the target areas can be around 200 metres.”

He said the sheer size of the target area had transformed the potential of the acreage. Yet while upbeat about the discovery, the executive said next year would prove tremendously important for the company as it sought to prove the commercial viability of its resources.

To that end Beach plans to invest A$46 million (US$46.06 million) in the 2012 financial year in exploring Cooper’s unconventional potential.

It has already booked 2 tcf (56.64 billion cubic metres) of contingent resources from the PEL218 acreage, in which it holds a 90% stake and Adelaide Energy holds the remaining 10%. Beach is in the final stages of a takeover of Adelaide Energy, in which it currently holds a stake of around 87.3%.

“After fracture stimulating Holdfast-1 we had gas flowing at a rate of up to 2 million cubic feet [56,640 cubic metres] per day [of gas] and we were expecting 100,000-500,000 cubic feet [2,830-14,160 cubic metres],” Jamieson said.

All hail shale The size of the resources, if the company’s efforts in 2012 prove fruitful, will likely transform it into a major gas supplier.

“If we can prove that the

unconventional play can be economic, and we still have some work to do over the course of the next calendar year to do that, it will be Beach’s biggest asset and biggest cash generator by a long shot,” he said, adding: “The shale and basin-centred gas will dwarf the rest of the portfolio.” Beach is expecting to extract around 10-20% of the estimated gas-in-place in PEL218, with Jamieson pointing out that in its 40-year lifespan the Cooper Basin had only produced 6 tcf (169.92 bcm) of gas.

“If we can pull 30 tcf [850 bcm] of sales gas, then that would be more gas than all of the CBM reserves in Queensland.”

This should prove good news for Queensland’s raft of CBM-LNG projects, which are facing increased difficulties in tapping into enough raw gas to keep their projects at full capacity.

Only last week, the federal government, in a bid to secure support for its Minerals Resource Rent Tax Bill, bowed to pressure from two independent parliamentary representatives over introducing greater environmental oversight of CBM and large coal projects.

The regulations have drawn complaints from the extractive sector, however, which fears they could dampen development of the country’s fledgling CBM industry. It is under this scenario that Beach finds itself well placed to capitalise on the CBM industry’s difficulties.

CBM woes Speaking to AsianOil recently, partner and co-head of King & Spalding’s LNG practice, Dan Rogers, noted that the Australian CBM sector had struggled to counter effectively the opposition’s message.

“The [CBM] industry has just not done a good job of responding; either through putting industry-based facts into circulation or pushing people within the government to hire independent scientists to rebut the misinformation being used by opposition groups,” he said.

It is a sentiment Jamieson echoed, saying: “There’s a lot of misinformation

out there and, unfortunately for the CBM players, they were caught off guard and could have been more pro-active in educating the communities in which they operate.”

The opposition to CBM has gained enough momentum to prompt LNG project developers to seek out new supplies of gas in case they are unable to secure enough from coal tenements.

Jamieson said: “Initially the Gladstone LNG facilities were planned on gas being supplied from CBM acreage. There are, however, a lot of new challenges being faced from both an environmental and social perspective.”

He pointed to BG Group teaming up with Drillsearch to explore for and develop the Cooper Basin’s unconventional resources, while Santos has approached Beach in relation to supplying conventional gas to the Gladstone facility.

“What we’re seeing is certain LNG firms are likely [to be] short [of] gas, which could be primarily driven by the challenges faced by CBM,” Jamieson added.

Open markets Beyond the LNG market, however, Beach is also upbeat about Australia’s rising domestic demand, with Jamieson noting that around 80% of gas from the Queensland CBM projects is linked to the offshore LNG market even as demand on Australia’s eastern seaboard grows.

“We see ourselves as possibly being an integral part of future gas supply both for LNG and the domestic market driven by our Cooper Basin reserves and resources,” he said. “The stars are aligning for us because there’s now upward pressure on pricing – a lot of commentators are talking about A$6-9 [US$6.08-9.01] per gigajoule for gas. If prices reach that point it makes all projects more viable from a commercial standpoint.”

Beach’s gas resources could completely transform the company’s fortunes, potentially turning it into a major supplier to both the domestic and international gas markets."

AsianOil





Despite its enthusiasm for shale, however, the company is not prepared to put all of its “eggs into one basket.”

According to Jamieson, while the Cooper Basin’s unconventional reserves are set to dominate the company’s focus going forward, Beach has also spread its risk.

Diverse portfolio The company will continue to focus on conventional gas production from its joint venture with Santos in the Cooper Basin, as well as its oil production from the basin’s Western Flank.

Jamieson described these operations as fantastic cash generators and the “engine room” of the company and said its shale gas efforts in the Cooper would not completely replace conventional operations and the company would “remain in conventional oil and gas for

some time to come.” Aside from the Cooper shale, the

company has a range of shale gas interests across Australia, in the Bonaparte, Otway and Gippsland Basins, where it is hoping to enjoy similar success to that seen in the Cooper Basin.

Beach’s international presence, meanwhile, also gives the company access to some promising upstream oil assets. In Egypt, Beach has a spread of operations ranging from wildcat exploration to near-term production. In Tanzania, it holds a 100% stake in the Tanganyika South Block, which lies along the promising East African Rift, sharing characteristics with Lake Albert acreage in Uganda that has seen major oil discoveries. In the US, the firm’s operations in North Dakota produce minimal net production but have paid dividends in terms of learning to tap

shale gas deposits. Jamieson described the company’s

global footprint as “areas which don’t cost a lot and don’t take a lot of management time,” but add a good deal of upside for the company.

Opportunity knocks Beach’s exposure to conventional and unconventional, foreign and domestic energy plays gives the company a balanced portfolio to continue the development of the Cooper Basin’s shale and basin-centred gas potential.

If the recent upsets in the CBM industry are any indication, then tapping into coal seam gas could prove to be a tricky prospect going forward, opening the door to rich rewards if Beach can harness the Cooper Basin’s huge potential."

The International Energy Agency (IEA) said recently that it expected global natural gas demand to grow by 1.7% per year until 2035, when it will reach 4.75 trillion cubic metres. By this point, it is estimated that China will be consuming more than 500 billion cubic metres per year of gas, up from 110 bcm in 2010.

That prospect should have Russia rubbing its hands, but all signs seem to indicate that country’s gas empire may be losing its grip. Indeed, much of Russia’s future in the Asian market could

rely on the success, or lack thereof, of efforts to develop China’s enormous shale gas reserves.

Talked to death In 2006, Moscow and Beijing entered discussions over a long-term supply deal. The two sides have been discussing a plan that would see Russia send 68 bcm per year of gas to China by pipeline over a period of 30 years. For five years, however, the talks have made little progress.

On the surface, the sticking point is simple. Most of the Russian gas giant Gazprom’s supply contracts are linked to crude oil prices, which have soared on the back of increased demand and unrest in the Middle East. For this quarter, some of the company’s European gas contracts are being carried out at a price of US$500 per 1,000 cubic metres – around US$100 more than current forward prices."

AsianOil

ChinaOil

Chinese shale leads to stalemate with Russia Sino-Russian gas talks have stalled in part because of pricing issues but also because Beijing wants to determine the full potential of domestic shale gas reserves By Sam Wright # The IEA predicts that global gas demand will hit 4.75 tcm by 2035, while China’s will top 500 bcm # Gas supply talks with Russia have been prolonged and far from fruitful # Gazprom has set its sights on supplying Asian LNG demand, but that future is also looking murky





Despite protests from its customers, the company has refused to budge. “Gazprom should not cover the mistakes in marketing and trading of our counterparties,” has been the unambiguous official line.

Unsurprisingly, Gazprom’s stance has provoked rebellion. Poland, which has a famously turbulent relationship with its neighbour and chief gas supplier, has filed an arbitration suit in a bid to force the company to cut prices under its import contract. There are whispers that others may follow.

Wisely, China has outright rejected Gazprom’s insistence on using the oil-linked mechanism. In the face of these objections, the Russian firm, despite a string of comments to the contrary, has yet to suggest a viable alternative.

Facing the figures It is unlikely that this is for a lack of effort. After all, Gazprom is in a near impossible position.

Recently, the state-owned China Daily, which is widely regarded as a mouthpiece for the central government on policy issues, speculated that even if the price of gas was set at US$350 per 1,000 cubic metres, the deal with Russia would cost the country US$714 billion over 30 years.

“If you use [this] as a guide [to] the long-term agreed purchase price that China gets in the current international liquefied natural gas (LNG) market and the cost of China’s unconventional natural gas exploration, buying gas from Russia even at just US$250 per 1,000 cubic metres makes no sense,” it added. “If Russia gives China a lower price, how can it face consumers in Europe?”

It is a fair point, and one that seems to have hit home. On November 13, Gazprom chief Alexei Miller, seemed to acknowledge that the deal had finally hit a dead end. Instead of the pipeline, he said during a visit to Honolulu, LNG shipments are to be the new focus.

An unconventional future China is estimated to have 36 tcm of shale gas, which would give it the world’s largest reserves. This is also

vastly more than the 2.8 tcm of conventional gas reserves that BP’s Statistical Review of World Energy estimates the country had at the end of 2010.

The US trails significantly behind China with 24 tcm of shale gas. However, it has seen its energy market transformed in recent years as a result of unconventional development projects, with gas output soaring and investment piling in.

As China’s leaders view it, domestic shale gas could be enough to protect the country from Russia’s penchant for using its pipelines as a political tool. This practice has in the past led Gazprom to cut supplies to both Ukraine and Belarus.

“If the strategic goal is energy security and you’re now 55% dependent on foreign crude, that undermines the goal of domestic energy security,” Eurasia Group analyst Damien Ma told the New York Times. “A lot of companies want to do more gas.”

Unluckily for Russia, the proposed alternative of LNG could well fall by the wayside, too. Earlier this year, consultants McKinsey and Company warned Australian firms – a major source of LNG shipments to Asia – that local projects worth US$200 billion could be at risk if shale gas production in China took off as it has in the US. In total, it said, domestic shale production could provide as much as a quarter of the country’s total gas demand within four years.

Yet despite this seemingly strong position, Beijing has been reluctant to dismiss the Russian pipeline project out of hand. Just two weeks ago, Chinese Vice Foreign Minister Cheng Guoping described the negotiations as “in their final stages,” adding that they were proceeding well.

Building the future Part of this may be down to the challenges that China faces in bringing its shale gas to market. The first – unsurprisingly, given the country’s vast scale – is infrastructure.

In the US, a large number of shale plays were discovered near conventional gas fields, providing a ready-made pipeline network that drastically cut costs and sped up development. China’s reserves, on the other hand, are located in areas ranging from Sichuan Province to Inner Mongolia and the Xinjiang autonomous region, none of which have the level of established infrastructure needed to facilitate the rapid development of shale gas reserves.

For a country of China’s vast resources, this might not usually be a problem. Huge development projects have come to be the norm, made faster by cheap labour and the smoothing of regulations by state-owned firms.

Yet shale gas is different from a high-speed rail or bridge-building project. The country’s level of expertise in hydraulic fracturing, or fracking, is well below that of the US."

ChinaOil





In March, PetroChina, which operates the majority of domestic shale licences, completed its first horizontal shale gas well after 11 months of drilling. Outside China, this has been achieved in less than 20 days.

This comparison may be slightly unfair. The well, drilled in Sichuan, was much deeper than those typically found in the US. Joint ventures, both domestic and foreign, are likely to provide know-how and technology that can reduce drilling times drastically in the future. A number of major names are already on board, including ExxonMobil and US shale giant Chesapeake Energy.

Meanwhile, much responsibility rests with PetroChina. Yet the company seems strangely divided.

On one hand, it has pledged to drill 220 shale wells in Sichuan over the next four years. On the other, it has complained that domestic gas prices are too low and that it will only push forward with unconventional gas exploration if

prices reach US$350 per 1,000 cubic metres. The company’s focus, for the time being at least, is thought to firmly be on finding more conventional oil.

Looking forward Oil and coal still reign supreme in China. Natural gas currently accounts for just 4% of energy demand, and while the government is aiming to increase this to 10-12% by 2020, it is a long way from a complete transformation of the country’s energy mix.

Despite this, China still needs to import large quantities of gas in the short term. But the short term is precisely that. Most estimates place the time needed for China to begin producing from its shale reserves at 10 years, despite all the technical challenges. Once the ball is rolling, the timeline may well be much quicker.

China may be coy on the subject, but for this reason the Russian pipeline looks dead in the water. The turnaround is

simply too long, and the expected 30-year contract unrealistic. China, with nothing to lose, appears to be holding out to see what it can get. A ridiculously low offer from Russia – say, US$250 per 1,000 cubic metres – may be tempting, but is extremely unlikely.

Instead, the next decade could mark a reversal in Russia’s fortunes. Alongside China’s plays, huge reserves could begin production in Poland and France, while exploration is rife in other key Gazprom markets such as Ukraine. Poland in particular has repeatedly said that shale will free it from Russian influence, an idea that has been seized on by the Polish public.

On November 13, the ever-optimistic Russian president, Dmitry Medvedev, told journalists that his country expected to supply as much gas to China in the future as it currently supplies to Europe. He could well be right, but there is a good chance that delivery volumes may be nothing to brag about."

The Belarusian government has expressed serious reservations about Lithuania’s plans for building a 3,400-MW nuclear power plant (NPP) at Visaginas to replace the Soviet-built Ignalina facility.

Mikhail Mikhadyuk, the deputy energy minister of Belarus, said to reporters in the middle of October that Vilnius had thus far failed to address Minsk’s concerns about the projects.

He claimed that Lithuania had not answered questions about the

environmental impact assessment (EIA) for the Visaginas project, despite Belarus’ efforts to respond fully and transparently to questions about its own EIA for a planned 2,400-MW NPP near Astravets.

“Lithuania still has not given answers to Belarus about results of the environmental impact assessment of its future NPP,” Mikhadyuk was quoted as saying by the Itar-Tass news agency.

An official in the Belarusian Ministry of Nature and Environmental Protection

has voiced similar complaints. A ministry representative told Itar-Tass

in mid-October that he believed Lithuania’s critical remarks about the Astravets project were motivated more by politics than by substantive concerns about safety and security.

He complained that Lithuania’s efforts to drum up support for its project in the European Union and to highlight concerns about the Belarusian scheme were evidence of “double standards.”"

ChinaOil

Energo

Pot calling the kettle black? Belarusian criticism of Lithuania’s Visaginas NPP mirrors almost exactly the concerns voiced by Vilnius over plans for the Astravets plant By Jennifer Delay # Minsk’s complaints appear to be largely political in nature # EU support for the Lithuanian project is likely to remain strong # If Belarus steps up its campaign, work on the Visaginas station may face more delays





The official, who was not named, said that Vilnius’ hypocrisy was evident in its expressions of concern about the Astravets plant’s proximity to the border. “Lithuania protests against the site [in the Astravets district], which is only 30 km from the Belarusian-Lithuanian border. However, Vilnius plans to build its NPP at the distance of 2.3 km from the border with Belarus and believes that it’s OK,” Itar-Tass quoted him as saying.

Mirror image Not surprisingly, the complaints aired by Mikhadyuk and the unnamed ministry official mirror almost exactly concerns voiced earlier by Lithuanian officials.

As noted above, Lithuania was the first to express anxiety about the Belarusian plant’s proximity to the border between the two states.

Officials in Vilnius have also gone on record as saying that Minsk has been slow to answer their questions about the EIA for the Astravets plant – and that their own efforts have been designed to ensure full disclosure and transparency.

Moreover, they have speculated about the political component of Belarus’ decision to build the NPP in co-operation with Russia. Atomstroyexport, a subsidiary of Russia’s state atomic energy concern Rosatom, has been awarded a contract for the construction of the Belarusian station.

Politics Minsk’s decision to follow virtually the same line of argument against the Visaginas NPP that Vilnius has already employed against the Astravets station indicates that the Belarusian position is being driven more by politics than by substantive concerns. Indeed, given the symmetry between other points, the unnamed ministry official’s mention of Vilnius’ political considerations is probably evidence of this.

That politics would be a factor is hardly surprising. After all, one of the

Lithuanian government’s main foreign policy concerns is to safeguard the country’s independence against the possibility of Russian recidivism, and Belarus has on occasion acted zealously to promote the interests of Russia, which has often (though not always) served as its main patron.

The Kremlin, in turn, has its own reasons for keeping a close eye on the Baltic States. On one hand, Estonia, Latvia and Lithuania are home to substantial minority populations of ethnic Russians. On the other hand, they also have turned decisively away from Moscow, having gained membership in both the North Atlantic Treaty Organisation (NATO) and the European Union, and they have generally been cool to suggestions for expanding co-operation with Russia.

Lithuania was the first to express anxiety about the Belarusian plant’s proximity to the border between the two states

The EU, meanwhile, also has political interests at stake. It is bound to be more sympathetic to Lithuania, as a member state, than to Belarus, which is the target of sanctions imposed by Brussels.

Its regulations also call for Lithuania to cut its carbon emissions and to reduce its reliance on fossil fuels, and the Visaginas project is in line with these aims.

This raises the question of whether these political considerations will have any practical impact on the Visaginas project.

Support from Brussels In all likelihood, they will not affect the level of EU support for the project.

Indeed, European energy commissioner Guenther Oettinger offered words of support for the Visaginas NPP at a recent energy conference in Krakow.

After receiving information on Vilnius’ plan for the construction of the Visaginas NPP from Lithuanian Energy Minister Arvydas Sekmokas, Oettinger congratulated Lithuania and the three neighbouring states that had signed on to the project – Estonia, Latvia and Poland.

The partners have “[achieved] a significant milestone in the project implementation and selection of a strategic investor,” he said, according to a statement issued by the Ministry of Energy.

Now that the plan has been submitted to Oettinger according to Article 41 of the European Atomic Energy Community (Euratom) treaty, Lithuania is in a position to begin co-ordinating implementation of the project with EU institutions, the ministry added.

Even so, it may take time for Vilnius to respond to the Belarusian complaints, particularly if they gain in intensity. If so, it runs the risk of seeing work on the Visaginas station fall behind schedule yet again. Lithuania had said initially that it hoped to bring the NPP on line in 2015 but pushed its target date back to 2020 after encountering difficulties in finding funding and a strategic investor.

Rokas Zilinskas, the chairman of the Lithuanian parliament’s nuclear energy commission, alleged in late 2010 that Russian interference been a factor in these delays.

He claimed that pressure from Moscow had led South Korea’s KEPCO to

withdraw from the first tender for the Visaginas construction contract, even though it was viewed as the most likely winner of the contest. Japan’s Hitachi won the second tender earlier this year."

Location of Lithuania’s Visaginas NPP

Energo





Following weeks of political upheaval and roller-coaster market instability, Italy now finds itself with new national leadership. With it comes the promise of a technical approach to governance and the introduction of new financial measures aimed at calming global worries about the country’s ability to deal with its overwhelming debt.

The exit of controversial Prime Minister Silvio Berslusconi and the appointment of Mario Monti to lead the government to implement a host of new regulations promoted by the European Union (EU) and the International Monetary Fund (IMF) were welcomed by political and market leaders across the globe. But it is far from clear how this new technocratic leadership will work in practice, including how it will shape Italy’s precarious energy standing.

Although the news of Bersluconi’s exit was enough to drive up oil and gas prices across the globe – further allowing local companies such as Eni the spike in profits necessary to weather current challenges – it is far less clear how his departure will affect the country’s broader energy future.

Challenges The last 18 months have left Italy with a collection of energy challenges, including issues pertaining to its domestic operations and production as well as overseas exploration and production. The country’s most prominent energy trading partner, Libya,

saw its long-standing government collapse as pro-democracy movements led to an armed conflict lasting months, resulting in a complete halt in production.

Despite international pressure, Italy had spent the last decade cultivating trade and diplomatic relations with Libya’s former leader, Muammar Ghadaffi, through heavy investment in aid and development, establishing Libya as one of its three main providers of oil and natural gas alongside Algeria and Russia. The armed conflict saw Italy’s energy imports under threat, as companies such as Eni were forced to remove expatriate staff from the North African country.

Meanwhile at home, Italy has seen two domestic efforts to step up energy independence curtailed by local protest movements. Offshore drilling projects were restricted after the Deepwater Horizon spill in the Gulf of Mexico inspired calls for new project rules in the Mediterranean, leading to a ban on efforts within 5 nautical miles (9.3 km) of the Italian coastline. While the new regulations have mostly hindered smaller operators, such as Mediterranean Oil and Gas, new proposals from the EU on offshore drilling could have a further impact on projects in the region. Finally, the government’s push to revive Italy’s long-dormant nuclear power programme after the events surrounding the tsunami in Japan this year and its impact on nuclear plants sparked a wave of protest

from EU and local political leaders. After being set aside until political pressure had subsided, the campaign has now lost its strongest proponent in Berlusconi, causing further uncertainty about a nuclear future in Italy.

Foreign relations These events have left Italy and the country’s largest energy firms increasingly isolated when it comes to their immediate opportunities not only for growth but also for the country’s immediate oil and gas needs. This situation may be further exacerbated by the absence of Bersluconi, who demonstrated a willingness to seek out energy partnerships beyond and sometimes against wider regional sentiment.

This approach – leading to close working and diplomatic relationships with Ghadaffi and Russia’s Prime Minister Vladimir Putin, will not likely be continued under the stewardship of Monti, a much stronger proponent of EU market integration and member state partnerships. Having announced his campaign to return to Russia’s highest office, Putin echoed this sentiment in a speech last week where he derided EU energy policies while praising the outgoing Berlusconi as a friend and “one of the last of the Mohicans of European politics”, according to the Wall Street Journal."

EurOil

Italy’s energy future uncertain under new leadership A shift in focus could come with the exit of Silvio Berlusconi and the arrival of a new government but right now a great deal of uncertainty surrounds Italy’s energy future By Christopher Coats # Events over the past 18 months have left Italy with a variety of energy challenges at home and abroad # The dynamics of Italy’s foreign relations stand to change in the absence of Berlusconi # Italy is looking to expand its energy presence in North Africa and elsewhere overseas





Although Putin is favoured to return to office, the change in leadership in Libya may offer Italy some relief, as Eni has returned to production efforts in the country after embracing the Libyan Transitional National Government (TNG) despite earlier reservations. Eni has revived production efforts in Libya, including its work in the Elephant field south of Tripoli, but levels remain modest. Fully supported by the EU, the TNG will provide a greater opportunity for Italy to expand its presence in North Africa in the months ahead, though infrastructure deficiencies and lingering worries concerning regional stability

have slowed a return to pre-conflict production levels.

Elsewhere in North Africa, Italy has sought more exposure to the region’s energy potential, recently moving forward on a long-delayed pipeline project linking Algeria, one of its largest energy providers, with the island of Sicily.

The move would increase imports into Italy, as well as side-step potentially unstable transport systems in the transitional political environments of Tunisia and Libya. However, faced with likely spending cuts and a significant tightening of the belt, Italy may not be

willing or able to pursue such costly infrastructure projects in the coming year.

For now, the country’s energy future remains vague, with little allotted for traditional or novel approaches to meeting domestic energy needs or expanding its hydrocarbon presence abroad.

Having announced that it has little to contribute to Europe’s expanding shale extraction marketplace and that it has done little to build a government support system for renewables, the country again is looking to its traditional providers for an energy answer."

Elshad Nasirov, the vice president of the State Oil Company of Azerbaijan (SOCAR), stated last week that his firm would team up with Botas, Turkey’s state pipeline operator, to form a consortium to build a new pipeline to pump Azerbaijani natural gas across Turkey to Europe.

The pipeline is to have a capacity of no less than 16 billion cubic metres per year, Nasirov said. That is the volume of gas that Shah Deniz Stage 2 (SD2) is expected to produce when it comes on stream in 2017.

Some 6 bcm per year of the total has already been promised to Turkey, while the remaining 10 bcm per year will be contracted to shippers using one of several proposed pipeline projects: the 31

bcm per year Nabucco gas pipeline, the 10 bcm per year Interconnector-Turkey-Greece-Italy (ITGI) pipeline or the 10-20 bcm per year Trans Adriatic Pipeline (TAP).

Complications Nasirov’s announcement appears to have made a situation that was already complicated even more so.

This is partly because it follows a move by BP, the operator of the Shah Deniz field, to unveil a proposal for putting a consortium together to carry 10 bcm per year of SD2 gas from Turkey’s western border into Central Europe. BP calls its plan the South-East Europe Pipeline (SEEP).

The multinational is believed to have

mooted the SEEP pipeline plan because it views the Nabucco, ITGI and TAP consortia as unreliable partners for a variety of reasons. The plan cannot succeed, though, without help.

As such, the move by SOCAR and Botas is seen as a necessary preliminary, in that it is designed to establish infrastructure that can reliably move 10 bcm per year of gas through Turkey.

This cannot be done with Turkey’s existing gas pipeline network, which is considered to be too disjointed to provide a clear transit route across the country.

It is not clear whether BP will participate in the construction of this new pipeline across Turkey."

EurOil

FSU OGM

Botas, SOCAR plan gas pipeline across Turkey The unveiling of a new scheme to move Shah Deniz Stage 2 production to Europe appears to have made a situation that was already complicated even more so By Charles Coe # SOCAR is already considering delivery proposals from Nabucco, ITGI and TAP # However, it appears to have doubts about all three pipelines # The proposed link across Turkey could feed gas into BP’s proposed South-East Europe pipeline





According to press reports, though, the consortium that SOCAR and Botas intend to put together is expected to include other Shah Deniz partners.

Gas deal SOCAR’s move also coincides with a new gas deal between Turkey and Azerbaijan.

After years of haggling, Ankara and Baku inked several agreements in late October. The documents not only set the price for delivery of SD2 gas to Turkey for domestic consumption and for shipment to Europe but also provided for the upgrade of Botas’ existing network or for the construction of a new pipeline.

This may have far-reaching consequences, as it appears to pave the way for SOCAR and Botas to cut the Nabucco project out of the picture.

Like ITGI and TAP, Nabucco submitted to Shah Deniz shareholders its bid to transport the gas to Europe by the October 1 deadline. While the contracts are probably months away from being awarded, the Nabucco group hopes to win, despite the fact that the 10 bcm per year of SD2 gas would account for less than half of its full capacity. (The consortium is looking to also transport gas from northern Iraq and from

Turkmenistan, with which the European Union is discussing the construction of a gas pipeline across the Caspian Sea.)

In an attempt to make itself more attractive to Caspian gas producers, Nabucco has proposed extending its pipeline from eastern Turkey to Baku, where it could theoretically connect with the long-discussed Trans-Caspian Gas Pipeline (TCGP).

Speaking in Baku on November 5, SOCAR’s president, Rovnag Abdullayev, said the Shah Deniz consortium would decide within a year on which route to choose for the export of gas to Europe. He also asserted that the unveiling of a different pipeline project would not prevent the implementation of the Southern Corridor pipeline projects, those being Nabucco, ITGI and TAP.

Abdullayev was quoted by Trend news agency as saying that Turkey’s existing pipeline infrastructure was complex. For that reason, he said, SOCAR has decided to explore the prospects for constructing a new gas pipeline across the country.

Complex decision The SOCAR chief’s words were echoed by Nasirov, who said during a conference in Baku on November 5 that a decision

on how to transit SD2 gas through Turkey would be taken in mid-2012.

“The gas transportation system from Baku to European markets consists not only of one pipeline, but of the whole combination of several pipelines,” Nasirov was quoted by Azerbaijan Business Centre as saying. These, he said, include routes “from Baku to the Turkish border, from eastern Turkey to western Turkey and further to the European markets or in the southwest or northwards direction.”

He added: “The transit agreement [between Baku and Ankara] was signed for the option of [expanding] the existing infrastructure in Turkey. In this connection, a consortium will be set up to consider a new pipeline construction option.”

Nasirov further remarked that the decision on how to award the contract for deliveries of SD2 gas was a complex one.

“The route from the western border of Turkey and sales of gas to Europe is one part of the project; passage through Turkey is another project, and delivery of gas from Baku to Turkey is one more project,” he said."

Rising coal consumption in China threatens to undermine central government targets for reducing CO2 emissions by 2015. That is the verdict of a study by a leading Chinese university

published as the central government trumpeted that the country’s carbon intensity levels – emissions per unit of economic growth – had fallen in 2010.

The study was published as Beijing

also made a number of confusing announcements about plans to tackle greenhouse gas (GHG) emissions nationally."

FSU OGM

GCEM

China’s emissions conflict While the Chinese government hails falling carbon intensity levels, new research predicts rising coal consumption as economic growth continues By Graham Lees # Research from Tsinghua University says annual coal consumption will reach 4.6 billion tonnes by 2015 # Beijing wants provincial authorities to take the lead in promoting low-carbon energy and cutting emissions # Beijing has announced tentative plans for voluntary emissions cuts and a carbon trading system # Provincial governments’ desire to expand their economies limits their ability to cut emissions





They appeared to underline the university study’s misgivings of a clear line of progress to CO2 cuts by 2015.

Carbon intensity levels dropped in 2010 because of Beijing’s push to close down inefficient coal-burning power plants, the use of more gas in place of coal and an expansion of renewable energy systems. However, the overall electricity generating capacity produced from coal has actually gone up in the last five years from 68% to 70%, said the study by the Climate Policy initiative of Tsinghua University.

“[The] central authorities’ goal of controlling coal use in the next five years will be unattainable so long as local governments remain reluctant to use less energy while they pursue economic growth,” the official China Daily newspaper quoted the study as saying.

“Local authorities still have a strong desire for economic expansion,” the study’s chief editor Qi Ye told the newspaper last week.

Reducing carbon intensity Based on the targeted growth plans published by provincial governments across the country, China will be burning 4.6 billion tonnes of coal per year by 2015, said Qi. That is 500 million tonnes a year more than Beijing would like.

The gloomy predictions by Tsinghua University coincide with an announcement by Beijing of plans to curb GHG emissions to achieve a 17% drop in CO2 emissions per unit of GDP by 2015. But state media in the past week have quoted national officials giving

differing thoughts on tackling climate change-linked pollution. Some seem to be in favour of voluntary emissions controls at a provincial level, while others talk of a nationally led coercive programme, including a compulsory carbon trading regime.

“China should actively develop and promote low-carbon energy, while accelerating the establishment of a calculation system for greenhouse gas emissions,” a State Council statement on November 9 said.

It called on local governments to take steps to reduce CO2 emissions, but gave no indication that there would be any clampdown on expanded coal use.

“Positively coping with climate change should be regarded as an important strategy for China’s economic and social development, as well as a great opportunity for economic restructuring and promoting a new industrial revolution,” said the State Council.

Voluntary schemes These are laudable words but the Tsinghua study makes clear that many provincial authorities are not heeding directives from the centre, especially those provinces in central and western regions which are still economically far below the wealth and standard of living now being enjoyed in coastal provinces.

Perhaps in an attempt to coax recalcitrant provincial governments into a cleaner future, the National Development and Reform Commission (NDRC) on November 11 named four large cities under the central

government’s direct control which had “volunteered” to join a test programme on CO2 emissions.

The test, which will not begin until 2013, will involve Beijing,

Tianjin, Shanghai and Chongqing, plus the provinces of Guangdong and Hubei, said China Daily, quoting “sources with knowledge of the matter”

“These regions have submitted detailed plans that cover emissions caps, quota allocations, third-party verifiers of emissions cuts, enforcement of trading emissions consumption quotas and excess emissions penalties,” said the state newspaper.

China will begin with voluntary emissions cuts but also “explore market-oriented measures to realise reduction targets,” the director-general of the NDRC’s climate change department Su Wei told the official news agency Xinhua last week.

Coal demand China will need to balance continuing strong economic growth with controlled energy consumption, the president of the China Beijing Environment Exchange, Mei Dewen, said.

“China can adopt both an absolute carbon cap and voluntary carbon trading in the beginning to test the waters, then gradually consolidate the two measures,” Mei told the China Daily.

The Tsinghua study’s findings are backed up by a senior national policymaking figure, Zhang Guobao, the former chief of the National Energy Administration (NEA).

“The growing demand for coal will put China under pressure in terms of coal mining, transportation and controlling carbon emissions,” Zhang told China Daily.

China is importing more coal than ever, the NDRC has conceded. A record 19.1 million tonnes were shipped in during September, 25% more than the same month one year ago.

It looks like China’s central government faces an uphill task in bringing first the provinces, and then their CO2 output, under control.

The one thing that may help them more than anything else, however, is the global slump, which has reduced demand for Chinese products, and therefore energy."

GCEM





A final investment decision (FID) on the huge Ichthys LNG project in northwest Australia is due by the end of the year, but the project will cost more than expected, according to the scheme’s two shareholders, Japan’s Inpex Corporation and France’s Total.

Adding to the raft of Australian LNG projects on the drawing board, Inpex and its 24% partner Total have been targeting a late-2011 sign-off for construction of an export terminal in Darwin capable of producing 8.4 million tonnes a year of LNG, with the first cargo scheduled to be shipped from late 2016.

“We are working to make the decision within this quarter as planned, and the work is proceeding without any big problem,” said Masahiro Murayama, Managing Executive Officer of Inpex’s Finance & Accounting Division, quoted by Dow Jones on November 4.

The project will now cost more than US$30 billion, according to Total. “It will cost a little more than expected for environmental reasons ... We had originally said US$30 billion,” Total Chief Executive Christophe de Margerie told Reuters on the sidelines of a G20 meeting of business leaders in southern France.

Project details The technical complexities and scale of the project, led by the massive size of a semi-submersible central processing facility to be based 200 km offshore,

have previously prompted many analysts to ponder whether Inpex and Total would be able to mount a viable business case for the venture.

While the news of the cost increase bodes poorly for the sponsors of other key LNG projects in Australia, the imminence of the FID, after which work on the project will commence immediately, will be welcomed as a massive financial boost in Darwin, where a gas liquefaction plant will be built on the Blaydin Point industrial site.

This would take feedstock from the Ichthys gas field in the Browse Basin off the Western Australian coast, via an 885-km undersea pipeline from the offshore natural gas and condensate processing facility.

The project has been described as a “game-changer” for Darwin by federal Resources Minister Martin Ferguson, and will require thousands of construction personnel, some of whom will be housed in a 2,700-bed workers’ village in Howard Springs.

Inpex, Japan’s top oil and gas explorer, is expected to pump hundreds of millions of dollars into the Northern Territory economy during the four-year building programme.

Soaring costs Inpex estimated in 2008 that the Ichthys project would cost US$20 billion, but de Margerie said that the Japanese company had in recent months been citing the

figure of US$30 billion at road shows. The strict environmental conditions

imposed by the Australian government to develop the project explain the upward revision in the project’s cost, de Margerie said, noting that environmental approvals for the scheme were already in place.

Recent green lights for several rival energy developments in Australia have significantly increased the demand for labour, sparking analysts’ warnings of potential delays and cost overruns, but de Margerie did not cite this factor.

De Margerie also indicated that Total wished to raise its 24% stake in the Ichthys scheme, which is also slated to produce 1.6 million tonnes of liquefied petroleum gas per annum. “We would like to have more than that,” he said, but provided no details on whether Inpex would agree to let Total up its stake.

Reuters said that he did not comment on the outcome of reported meetings by bankers in Tokyo and Sydney that were aimed at putting together the financing needed for the development.

“In Ichthys, like for every big project we have been in, the FID will be made before the financing is in place,” de Margerie was quoted as saying.

Inpex has said previously that much of the scheme’s massive costs will be met by project financing, in which Japan’s biggest development and commercial banks are expected to play a major role."

GLNG

Offshore Australian project nears FID moment The Ichthys LNG will cost more than the expected US$30 billion, although a final investment decision is expected to be taken by the end of 2011 as planned By Kevin Godier # Total blames the Australian government’s strict environmental conditions for soaring costs # Inpex and Total have awarded engineering contracts to the Clough DORIS Joint Venture JV # Offtake contracts with Japanese buyers are already in place. # Inpex is looking to offload some equity to share the financial burden more broadly





Contract awarded Inpex’s determination to push ahead with the project was seen in mid-September, when the Japanese company said construction of its Naoetsu LNG receiving terminal, in the Niigata region, was on schedule to be completed by 2014, with the facility’s two LNG tanks both 70% complete.

The terminal is a key strategic plank for Inpex, and will boost the company’s ability to feed its sizeable gas distribution network in Japan.

In August, a joint venture between Australia’s Clough and France’s DORIS Engineering received a letter of intent (LoI) to provide offshore integrated project management support services for the Ichthys project.

The contract to be awarded to the Clough DORIS Joint Venture (CDJV), which is equally owned by the two firms, is valued at more than A$250 million (US$253.3 million).

Under the contract, CDJV is to oversee the detailed engineering design, procurement, fabrication, at-shore commissioning, tow to site and offshore hook-up of the central processing facility and the floating production, storage and offloading (FPSO) vessel for the project, Clough said.

More Japanese equity? Another major Japanese gas player, the Osaka Gas Company, has been in discussions with Inpex on the acquisition of a stake in the Ichthys LNG project.

Kenji Kawamoto, Osaka Gas’ executive officer in charge of overseas business development, said in early September that his company would also buy LNG from the project as part of any deal.

Such a move would fit well with comments by Inpex in July and August that it plans to sell an equity stake of around 10% in the Ichthys LNG project to the customers it has lined up to lift

output from the development. Osaka Gas Co. is Japan’s second

biggest gas utility after Tokyo Gas Company, and has said it intends to raise its total LNG imports, both via contracts and stake holdings, to 10 million tonnes per year by 2020, compared with around 6.8 million tonnes per year in fiscal 2009.

Inpex said in June that sales agreements that would cover the entire 8.4 million tonnes per year of LNG to be produced at Ichthys were nearing completion.

Inpex and Total will each lift 900,000 tonnes per year from the project, although Total has agreed to provide 200,000 tonnes per year of its volume to its Japanese partner.

Inpex has also reached a heads of agreement (HoA) with Taiwan’s CPC Corporation for the sale of 1.75 million tonnes per year, and with Japanese utilities Chubu Electric and Toho Gas for 490,000 million tonnes per year and 280,000 million tonnes per year respectively, according to Platts.

Another potential buyer of the Ichthys gas, according to media reports, is TEPCO, Japan’s largest LNG buyer, which accounts for about 30% of the

country’s LNG imports. TEPCO and another key Japanese gas

purchaser, Chubu Electric Power, have become more aggressive in taking upstream stakes in LNG projects, as they look to gain first-hand knowledge of projects and to secure stable supplies.

In a separate deal with South Korea’s KOGAS, the largest single buyer of LNG in the world, Total is to sell 2 million tonnes per year of LNG from Ichthys and other fields in Nigeria, Norway and Egypt from 2014 to 2031.

While all of these contracts depend upon the approaching FID, there is now sufficient evidence in place to suggest that the Ichthys development is poised to add itself to the cluster of Australian LNG schemes that are poised to propel the country into the very top tier of LNG exporters.

As the end of the year approaches, market observers will be looking for further news of equity acquisitions that will downsize Inpex’s huge financial commitment to the scheme and share the fiscal burden more broadly."

Ichthys field location Source: Inpex

GLNG





After half a century of being ostracised and subjected to swingeing sanctions, Cuba is rich – at least in terms of resources. While the citizens of the pariah state may be impoverished monetarily, they appear to have been sitting on impressive oil reserves all along.

Cuba already has an oil industry in place which produces about 53,000 barrels per day, meeting approximately one-third of the socialist island’s domestic needs. The majority of Cuba’s oil demand is supplied by Venezuela, at an estimated cost of US$3.5 billion per year to its ideological bedfellow and benefactor.

However, Cuba’s current production is just a taste of what could lie untouched, with the Cubans claiming that 20 billion barrels lie beneath their territorial waters, a figure the US Geologically Survey more conservatively puts at 4.6 billion barrels.

Resource rich Should the Cubans be correct, it would mean their reserves would be the 14th largest in the world, knocking the US into 15th place, according to a report by Global Research.

Whatever the reality, Cuba could well become a net exporter of oil, and potentially wealthy in its own right. The promise of Cuba’s untapped riches has brought interest from all over the world to the socialist state, with North America represented in the form of Canada.

The new international reality is represented by the US$750 million, 53,000 tonne Scarabeo 9 oilrig heading to Cuba: the Chinese-built advanced

mobile drilling platform – owned by Italian-outfit Saipem – should arrive from Singapore next month, when it will be operated by Spanish energy major Repsol.

Repsol is to begin exploratory drilling in January and is backed by a wave of local optimism.

On November 15, the BBC quoted the head of exploration for Cuban state oil company Cupet, Rafael Tenreiro, as saying: “It is not a matter of if we have oil, it is a matter of when we are going to start producing.”

This will not be Repsol’s first exploratory drilling in Cuba, as it found oil in 2004 but said it was not economically viable to exploit. The test is whether exploration can now be made to pay when faced with the expense of drilling at more than 1,600 metres amid the constraints of the US’ decades-old sanctions.

Downstream limitations Refining capacity could also be a problem. If the oil found offshore is particularly heavy there may be few downstream options open for island state; even Venezuela’s PDVSA and Mexico’s Pemex refine a substantial amount of their heavy crude in the US – not an option for blockade-bound Cuba.

Venezuela is engaged in updating the island’s long neglected refineries with the expansion of the Cienfuegos and Santiago de Cuba facilities, as well as the creation of a new refinery in Matanzas.

At present, Cuba leans heavily on Venezuela for support but Venezuelan President Hugo Chavez’s ill health, or the ballot box, could end the close

relationship. As such, Havana has sought to build

close ties with China, seeking to tap into the Asian giant’s deep pockets. However, China’s investments, while often carrying some geopolitical motive, tend to be more business orientated that ideology driven. China and Cuba may share socialist ideals on paper, but whether China can be counted on could well depend on the level of financial return Beijing sees in the relationship.

Without Chavez, Cuba would be exposed and, as such, might feel that it needed to derive income from its offshore depths.

Involvement in socialist Cuba, however, is a dangerous occupation for all but the most powerful. With the US mortgaged to the hilt to China, Beijing can act with impunity. Spain’s Repsol, however, has no such leverage and, with interests in the US Gulf of Mexico, it needs to tread carefully.

Big stick Ileana Ros-Lehtinen and 33 fellow members of the US Congress have written to Repsol to warn the firm that its operations in Cuba could incur “criminal and civil liability in US courts.”

Anxious not to make enemies across the Florida Straits, Repsol emphasised that it had complied with all US safety and embargo legislation. Additionally, it offered to allow US officials to check the safety standards of the Scarabeo rig.

There is considerable US anxiety about the risks of Cuban exploration, which would take place in waters even deeper than BP’s disastrous Macondo prospect."

LatAmOil

US dilemma over Cuba’s oil Cuba’s offshore resources may turn the country into an oil exporter, but they could also lead to a major environmental accident By Jon Stibbs # Cuba could hold as much as 20 billion barrels of reserves # Repsol is start exploration in January with a Chinese-built rig # The US is exposed to environmental risk by its blockade of Cuba





If there were a spill, models suggest the slick would be borne along the Florida Keys’s coral reef and mangroves.

At present, however, the US’ own draconian laws threaten its coastline in the event of a spill because US citizens need a licence to enter Cuban waters and a special export licence to send clean-up equipment there. Therefore, the US would have to wait for the oil to sweep towards its shores before it could intercede.

This fear has led Cuban-American groups to renew the mantra of ever-stronger sanctions to prevent any drilling going ahead. By strengthening the present Cold War blockade policies, they want to push up the costs and risks of oil production to uneconomic levels.

Writing in the Huffington Post, Mauricio Claver Carobe, director of Cuba Democracy Advocates in Washington, called for “withholding US executive visas for the Castro regime’s foreign partners; stripping those partners of drilling rights and concessions in the [US] and our off-shore waters; multiplying their legal liabilities, and legally disqualifying use of the drilling rig Scarabeo 9.”

Operational options If sanctions fail, however, and Repsol pushes ahead in Cuba, calls will grow for co-operation with the Castro regime after around half a century of bellicose diplomatic silence.

This would require a brave move away

from deeply entrenched – albeit largely failed – policies and would incur the wrath of the US-Cuban lobby.

High prices and developing technology mean the international oil industry is likely to make a success of Cuba’s reserves. The US’ antiquated policies to protect it from communism mean it will be isolated from a natural supplier while also being exposed environmentally.

While Cuba is slowly liberalising, the glacial speed of ongoing Cold War politics in the Caribbean mean the prospect of the US buying Cuban crude seems an impossibly long way off, but limited co-operation may be within reach."

The financing process for the major Sadara Chemical Company project in Jubail Industrial City, Saudi Arabia, is beginning to unfold, presaging what may be the biggest ever financing for a project in the MENA region.

Sadara, originally known as the Ras Tanura Integrated Project (RTIP) – and once termed ‘The Beast’ by bankers awed by the scheme’s sheer size and expense – was moved to Jubail because of escalating costs. Its financing brunt will be borne by insurance and guarantees from export credit agencies (ECAs) from across the world, confirmed a source close to the development, which is being undertaken by affiliates of The Dow Chemical Company and Saudi Aramco. The two firms each hold a 50%

stake in the venture. “The nine ECAs backing Sadara had

their second meeting in early November – they have all committed to back exports to the project from their own countries,” said the source.

One of the ECAs, UK Export Finance – until recently known as ECGD, is set to insure project finance worth US$2 billion at the massive petrochemicals project, according to the agency’s head of business development, Ali Sherwani. Speaking to Downstream MENA on the sidelines of a recent seminar held in London, Sherwani said that the project would involve input from “multiple UK suppliers, including Jacobs Engineering’s UK subsidiary.” Two Korean agencies, Korea EximBank and K-Sure, will be

among the ECA group, said the first source, citing “very low Korean bids for contracts.”

Healthy competition Sadara awarded a US$920.3 million engineering, procurement and construction (EPC) contract for the project’s main mixed feed cracker to Daelim of South Korea in July 2011.

The flexible cracker will break the naphtha and ethane feedstock to produce around 3 million tonnes per year of chemical products and plastics – part of the overall 8 million tonnes per year of specialised chemicals production from the scheme, which will represent the largest plastics and chemicals production complex ever built in a single phase."

LatAmOil

Downstream MENA

Sadara financing gains momentum With Saudi Arabia being largely untouched by the political instability that has surged throughout the region, the market is optimistic about funding for the behemoth complex By Kevin Godier # Costs for the project are expected to total around US$20 billion # Sadara will represent the largest chemicals production complex ever built in a single phase # It will help make Saudi Arabia a major petrochemical production hub, with much of the output bound for Asia





It is also indicative of Saudi Arabia’s moves to diversify its petrochemicals industry.

Daelim is also reported to be the lowest bidder, against Samsung Engineering, for building parts of the other production units at the Sadara complex, which will consist of 26 chemical manufacturing units and be one of the largest fully integrated complexes of its kind in the world.

The other units include facilities to manufacture analine, methylene di-para phenylene isocyanate (MDI), mononitrobenzene (MNB), toluene diisocyanate (TDI) and dinitrotoluene (DNT).

“The Koreans have done really well, gaining some quite juicy contracts by undercutting everything else by as much as 30-40%,” said the source.

Covering costs He pointed additionally to ECAs from Japan, North America, France and Germany – as well as Saudi Arabia’s Public Investment Fund – that would be backing a financing package likely to cover between 60% and 70% of Sadara’s capital costs.

“The capital costs of the project are continuing to come down, which has been helped by the competitiveness of the contract award process, and will add to the cost savings made via the move from the project’s originally planned location at Ras Tanura. All of this will help with the financing process,” said the source.

He stipulated that there was still no final capital figure for the Sadara scheme, for which estimates of US$20 billion are still being bandied around. Dow and Aramco will fund around US$7 billion between them. An initial public offering (IPO) to raise this equity is planned to be held during 2013-14.8

COMMENTARY Market confidence The events of the Arab Spring appear

not to have dented the ability of major Saudi downstream projects to push ahead and raise financing.

“Saudi is the regional leader in this area – and the Arab Spring has not affected that,” said a lawyer specialising in Middle East projects. “There has been no mention of any potential popular discontent in the Kingdom during the discussions with financiers for the Sadara Chemical scheme or for the Saudi International Petrochemical Company [Sipchem] financing, which is continuing to raise money,” he added.

He continued: “You need three main factors in place for a project financing deal to go ahead – political stability, finance market liquidity and robust prices to prevail for the commodity in question.”

Elsewhere in the MENA region, “there has been some stepping back in Egypt, particularly for the Egyptian Refinery Company deal – but by and large, there has not been very much effect, even in Bahrain,” he added.

With regard to liquidity, “ECAs are now playing a major role, given that every country in the world currently wants to boost its exports,” said a Dubai-based banking source. “The Japanese banks are also very liquid, as are the [Gulf Co-operation Council’s (GCC)] regional banks. Saudi banks are a mainstay, because they are somewhat obliged to finance Saudi projects, but they are being supported by liquidity from other players such as Islamic financiers,” he added.

He pointed to the Saudi Aramco Total Refining and Petrochemical Company (SATORP) refinery complex in Jubail, which will supply ethane and naphtha derived from oil and natural gas liquids as feedstock for Sadara, and for which the sponsors issued a 3.75 billion riyal (US$1 billion) Islamic bond – or sukuk – in October.

This marked the first Shariah-compliant project sukuk instrument in Saudi Arabia. Significantly, it received significant demand from a wide range of investors, resulting in an oversubscription of around 3.5 fold, demonstrating that Islamic bonds will almost certainly have a greater role to play for Saudi project sponsors going forward.

Contract awards Construction work on Sadara has already started and is scheduled to be completed by early 2015.

Production from the first units is expected to begin in the second half of 2015, and all units should be up and running in 2016, after which annual revenues of roughly US$10 billion are anticipated within a few years of operation, with around 45% of exports targeted at Asia.

Progress with the financing is dependent to some extent on the steady progress that continues to be made with contract awards.

On November 10, Jacobs Engineering was announced as the winner of an engineering, procurement and construction management (EPCM) contract for the Chemicals 1 Envelope. Under the terms of the contact, Jacobs is providing front-end engineering design (FEED) and detailed engineering services, in addition to procurement, inspection and delivery of equipment and bulk materials, as well as the overall construction management.

Officials did not disclose the terms of the agreement, but noted that the work was being performed by Jacobs’ offices in Manchester, UK; Mumbai, India; and Al Khobar, Saudi Arabia.

Mid-October saw the award of another key contract, when ABB was awarded the main automation contract for the complex. As part of the contract, ABB will have to build process automation and safety systems for the factory and also provide project management, project engineering and commissioning assistance services."

Downstream MENA





Post-delivery site support, training the technicians for maintenance and operation are also part of the contract. In August, Fluor was awarded a US$2 billion EPCM contract for developing all the offsite work and utilities (O&Us) at the site. The scope of work will include development of associated infrastructure and pipework arrangements to allow the construction of the complex.

Another major milestone, the joint

venture (JV) shareholders’ agreement for Sadara, was signed by Aramco and Dow in early October, bringing nearer to fruition a scheme that will be instrumental in Saudi Arabia’s strategy to become not only a strategic chemicals and plastics producer but also a hub for future downstream manufacturing.

“Sadara will be a game-changer in the Kingdom’s petrochemical industry, as it has all the needed ingredients for

success,” said Saudi Aramco President and CEO, Khalid Al-Falih, at the JV signing ceremony.

With financing for the project beginning to assume an embryonic shape, Aramco and Dow will be hoping for the smoothest possible progress on every front over the next five years to ensure that the scheme finally leaves the launch pad."

Underpinned by high oil prices, the external current account surplus of the Gulf Co-operation Council (GCC) is expected to surge by a massive 71% this year, from US$163 billion to US$279 billion, with the region’s economy anticipated to record more than 7% growth by year-end, according to the International Monetary Fund (IMF).

An IMF report released on October 26 (Regional Economic Outlook for the Middle East and Central Asia) said at current projected oil prices and output levels, revenue gains would more than offset the high levels of public spending across the region.

“For the GCC, who have stepped up production temporarily in response to higher oil prices and shortfalls in production from Libya, growth continues to be projected at more than 7%,” said Masood Ahmed, Director of the IMF’s Middle East and Central Asia

Department.

Oil rules The region’s economies are dominated by the highly capital-intensive oil and gas sector and will continue to be so for the foreseeable future.

“The GCC has been largely shielded from the negative impact of social unrest in the region,” the IMF said, adding that it instead benefited from oil prices that were 31% higher than in 2010, and greater export volumes.

“Since the beginning of this year, the region has witnessed unparalleled uncertainty and economic pressures,” Ahmed told a press conference in Dubai.

The recent worsening of the global economy, he added, would likely add to these pressures.

“But we should not lose sight [of] the ongoing historical transformation holding the promise of improved living standards

and a more prosperous future for the people in the region,” he stressed.

Higher oil prices Economic activity in the region’s oil-exporting countries has clearly improved, bolstered by continued high energy prices, and the temporary stepping up by several countries – Saudi Arabia in particular – of oil output in response to higher prices and shortfalls in production from Libya.

“The decision to increase oil production in the wake of disruptions in Libya was an essential contribution toward global energy market stability and enhanced activity,” Ahmed noted.

The IMF said Kuwait’s economy was expected to expand by 5.7% in 2011, compared with 3.4% last year, while growth would be at 3.3% in the UAE compared with 3.2% in 2010."

Downstream MENA

MEOG

IMF report flags up GCC revenue bonanza in 2011 Higher oil prices this year have supported strong growth across the broad GCC region, though the economic outlook for 2012 looks less certain By Kevin Godier # Regional economic growth is forecast at more than 7% by the year-end, the IMF says # Qatar is the star performer as always, with 2011 growth projected to come in at 18.7% # Broader social and economic concerns could bring a halt to progress in the year ahead





The Saudi economy will expand by 6.5% in 2011, after growing 4.1% in 2010, and Qatar’s economy will continue to make major strides, expanding by 18.7%, even better than the massive 16.6% rise recorded last year, thanks to its growing gas industry.

Oman, which appears to have put behind it limited social unrest in the spring that resulted in the death of two protesters, is forecast to register a 4.4% growth in GDP, compared with 4.1% in 2010, the IMF said.

Although Bahrain is a member of the oil-rich GCC, its economic growth is expected to slow sharply following a heavy-handed crackdown on a nationwide protest earlier this year.

The economy is expected to grow by 1.5% in 2011, compared with 4.1% last year.

Ahmed pointed out that increased oil revenues had created additional room for government spending in the GCC.

Several countries announced spending programmes early in the year covering a wide spectrum of measures such as subsidies, wages and capital expenditure.

While hydrocarbon exporters will experience a pick up in growth in 2011 on the back of higher oil prices, the IMF cut its economic growth forecast for the wider Middle East’s oil importing countries – which include Djibouti, Jordan, Lebanon and Syria – to just 1.9%, down from an earlier forecast of 2.3%.

The Fund anticipates that the Syrian economy will shrink by 2% after years of robust growth, following months of deadly protests against President Bashar al-Assad.

Yemen’s economy is also expected to contract by 2.5% this year – after an 8% expansion in 2010 – following nine months of nationwide protests demanding the ouster of President Ali Abdullah Saleh.

Even for major oil exporters, fiscal vulnerability has increased, however, as break-even oil prices – the prices at which the fiscal balance is zero given the level of expenditure and non-oil revenues – have risen steadily and are now approaching observed oil prices.

For Iraq and Bahrain, this is now a worrying US$100 per barrel or higher, and stands at between US$80 to US$90 per barrel for Iran, UAE and Saudi Arabia, according to IMF data.

Oman’s break-even price is over US$70 a barrel, while the figure for Kuwait stands at around US$50 and at below US$40 for Qatar, the report indicated.

Qatar’s optimisation of its oil and gas revenues has long been the standout feature of the tiny emirate’s soaring growth path in the past two decades, and its break-even figure is helped hugely by its very small population, which provides a negligible demand on the yearly budget in comparison to other countries within the region.

2012 challenges While 2011 has been fiscally favourable for most Middle East countries, the prospects for 2012 are less benign, the IMF believes.

The Fund’s assessment foresees a significant moderation in growth for the region’s oil exporters to 3.9% in 2012, and notes that these countries also face some downside risks, with several factors holding the ability to trigger a less positive growth scenario for the region’s oil exporters.

The most immediate risk is a sharp slowdown in Europe and the United States.

Global oil demand would contract substantially, possibly leading to a sustained drop in oil prices, the Fund said. Evidence that this threat is being taken seriously has been observed in Qatar, which has rarely hedged crude oil for the past 20 years.

As part of its oil strategy for 2012, Qatar has begun hedging oil prices, according to the Financial Times, which reported that brokers estimated Doha had already hedged almost 200,000 bpd of oil, almost 25% of its annual output.

For oil importers, the prospects look more difficult, with political and economic transformations occurring in several of these markets expected to extend well into 2012.

Together with a worsening economic

outlook globally, and in the European Union, the region is seeing a sharp drop in investment and tourism activity.

“The recovery in 2012 is expected to be weaker than earlier anticipated, with growth projected at just over 3%,” the IMF said.

Moreover, in response to mounting social unrest, the economic downturn and higher commodity prices, oil-importing countries in the region have significantly expanded subsidies and transfers, the Fund emphasised.

The cost of this social spending is high, exceeding 10% of GDP in Egypt and more than 5% of GDP in most other countries.

As a result, the fiscal deficits of oil importers’ across the Middle East are widening, the IMF said.

“In the near term, such spending measures are appropriate to lessen the impact of the downturn. But from an efficiency and equity standpoint, it is better for governments gradually to replace universal subsidies with targeted social safety nets,” the IMF report stated.

Above all, it said, the conflict across the wider Middle East region – particularly in Libya, Syria, and Yemen – has taken a massive human toll in addition to its enormous economic costs.

“The immediate priority for these countries is to avoid further humanitarian crises and, once the conflict is over, to pursue an agenda of reconstruction and reform,” it recommended.

Job concerns Another challenge for the region’s oil exporting governments is employment, said a different IMF report, released on October 14 and entitled; Gulf Cooperation Council Countries (GCC): Enhancing Economic Outcomes in an Uncertain Global Economy.

This highlighted that the strong growth in the GCC countries over the past decade had not delivered all the expected results, particularly with respect to generating jobs for the region’s nationals and reducing dependence on oil and gas revenues."

MEOG





Despite accounting for almost half of GDP, the oil sector employs less than 3% of the region’s labour force.

As a result, a large part of the region’s growth has had a limited impact on employment, the study observed.

With more than 4 million new nationals expected to enter the GCC job market over the next five years, the

problem could worsen, the Fund predicted.

However events in the region pan out in the coming months and years, the Middle East’s oil and gas resources will continue to provide governments with some huge advantages in terms of revenue generation.

Oil price worries remain a valid

concern, and the IMF reports have flagged up several other areas worthy of scrutiny, but the reality remains that GCC governments, in particular, are better positioned than most other regions globally to withstand new global traumas."

The European Union’s Fuel Quality Directive (FQD) is intended to cut the use of Alberta’s oil sands by imposing a carbon surcharge. One of the oddest things about this plan – and one that those both for and against agree on – is that it will have little impact on current supply and demand patterns. The bigger question is one of how the world will view this resource.

Alberta is well established as an up-and-coming energy supplier with substantial resources, a situation reflected by international interest in the oil sands. However, most production from the province flows south, securing Canada the top spot in terms of US oil imports.

This state of affairs belies the fact that the fight has become increasingly heated and is being played out across the capitals of Europe.

Despite the lack of an immediate impact, Canada is concerned that regulations from the EU will have a “global reputational impact,” the head of

Alberta’s UK office, Jeffrey Sundquist, told NorthAmOil.

Passing the FQD, the Co-operative Group’s toxic fuels campaigns manager, Colin Baines, told NorthAmOil would be a “huge signal” that the oil sands had “no place in a low-carbon economy – and it’s important industry takes that onboard.”

Carbon emissions The EU’s plans to impose additional tariffs on the oil sands are part of its focus on reducing carbon dioxide emissions by 6% by 2020 from transportation fuels. In order to meet this target, the European Commission agreed in October of this year to back the FQD. The European member states are to vote on it on December 2 and it will then be sent to the European Parliament.

Neither side appears confident of how the vote will go, with Baines saying countries appeared to be evenly split.

Should the FQD be passed, those wishing to import from the oil sands

could, technically, do so by offsetting the carbon-intensive fuels with less-polluting products, such as biofuel. However, this is likely to be impractical because of the resulting higher prices.

Sundquist stated Alberta’s support for the reduction of carbon emissions but disagreed that targeting oil sands via the FQD was the most effective means to accomplish such a goal.

Under the plan, emissions from oil sands are classified as being 23% greater than those from conventional crude. The EU’s efforts to penalise oil sands are based on an assessment that have been criticised as being overly simplistic.

Numbers game Emissions from the oil sands are likely to be higher than some others, but Sundquist made the case that, in fact, production from all over the world would carry different amounts of emissions based on a number of factors, including the extraction process."

MEOG

NorthAmOil

Alberta, Europe and the oil sands fight Alberta has come out fighting against EU plans to impose carbon tariffs on its oil sands, based on worries that the world will follow the European lead By Ed Reed # The FQD will effectively close the EU to Alberta’s oil sands, although this will have little immediate impact # The EU’s life-cycle emissions figure have been criticised by IHS # Canada’s oil sands make up a large part of the world’s resources that are open to investment





Greenhouse gas values under the FQD Ordinary crude: 87.5 grams per megajoule Oil sands production: 107 grams per megajoule Oil shale, such as from Estonia: 131.3 grams per megajouleCoal-to-liquids (CTL): 172 grams per megajoule

A study provided by Alberta from IHS CERA picked out a number of issues with the EU’s emissions figures, based on a paper from a Stanford University by Adam Brandt. IHS noted that blending diluent with the bitumen cut life-cycle emissions to only 11% over the EU average.

The EU’s methods are “discriminatory” on differentiating oil sands from conventional crudes, IHS continued, and warned that there was a danger of “serious errors in policymaking.” A number of studies have come to varying conclusions on life-cycle emission question and Brandt was quoted by Friends of the Earth as saying the IHS study did “not include enough information to evaluate the approach used to model refining of oil sands-derived products.”

Baines also came out against studies backed by the Alberta government. “We absolutely take issue with those numbers,” he said, flagging concerns about a lack of peer review. Steam-assisted gravity drainage (SAGD), another means of extracting the resource, was even more carbon-intensive, the Co-op official said.

Sundquist, though, echoed IHS’ concerns of discrimination. The FQD, he said, fails to tackle the key aspect of curbing emissions and unduly penalises the oil sands industry.

By focusing on effectively one feedstock – oil sands – the EU neglects the complexity of the situation, he said.

Efforts to regulate the carbon impact of feedstocks, he maintained, should either examine each blend separately or treat all crudes the same. The oil sands are “not a separate category” of feedstock, Sundquist said.

The Alberta official cited a “wells-to-wheels” comparison graph from the Canadian Association of Petroleum

Producers (CAPP), showing Canada’s oil sands are less bad than Middle East heavy and part-upgraded Venezuelan crudes. Oil sands, according to the CAPP graph, are on a par with Angola and Nigerian light crudes.

Immoral part The EU’s efforts to tackle oil sands, if approved, will have little impact on global energy flows initially. However, it would have an impact on the longer-term outlook for oil sands – both from Alberta and Venezuela’s Orinoco resource – another issue on which both those for and against the FQD agree.

Sundquist commented that the EU tended to lead the world in terms of environmental legislation, although he disputed the suggestion that it had played a role in the US’ decision to delay the Keystone XL pipeline plan. Increasing the throughput of oil from Canada to the US Gulf Coast raises the possibility of more exports to the EU, particularly in terms of diesel supplies.

Alberta remains confident that the Keystone XL will be approved, but Sundquist did say the province was looking at alternative export markets, such as Asia, via Enbridge’s Northern Gateway link.

“Many jurisdictions look to the EU for global leadership” in terms of environmental legislation, the official said.

With the world’s oil reserves virtually monopolised by states that restrict foreign access, Canada’s oil sands are

one of the sole resources available to companies for development. Only 20% of the world’s oil is not controlled by states, Sundquist said, and 53% of that 20% comes from Alberta’s oil sands.

Baines, though, disputed whether the world would need the additional resources from the oil sands, predicting that global demand would peak by around 2020. As such, he said, those companies investing in the oil sands risk stranding funds in a resource that will not be needed. The Co-op official went on to say that conventional lower-carbon crudes would be sufficient to meet this demand.

The International Energy Agency’s (IEA) recent projections in the World Energy Outlook put Canada as one of the only non-OPEC sources of increased crude, putting growth from unconventional output from the country at 3 million barrels per day from 2010 to 2035.

Despite the hits Alberta’s resources have taken in recent weeks – the Keystone XL decision and the EU’s moves on the FQD – Sundquist was upbeat on the region’s potential. “There may be delays,” he said, “but ultimately the reserves will be developed” given the world’s increasing need for oil.

The development of the oil sands will depend on how the world meets future energy demand and whether this will continue to be through oil. In the shorter term, though, the fight over the FQD is set to be increasingly acrimonious."

NorthAmOil





When launched in January 2009, the Desertec project seemed like science fiction – covering the desert in solar plants to power an entire continent. Even now, the sheer size of the installations and investments being talked about dwarf any solar site in existence.

But now, as a 150-MW Desertec reference project moves into development in Morocco, with a 2,000-MW scheme from independent Nur Energie in the works in Tunisia, the fantasy seems a viable possibility. The concept has already survived a wave of revolutions in the Arab world, and its promise of jobs is a tempting pitch to many of the region’s rulers. Plans for other grand solar undertakings, such as Greece’s Project Helios and the Blythe Solar Power Project in California, now mean that a solar network stretching across the Sahara no longer seems quite so outlandish.

Steady as she goes The promising political atmosphere could evaporate if the region’s politics fail to stabilise

Still, many challenges remain. The promising political atmosphere could evaporate if the region’s politics fail to stabilise, and any solar power exports to Europe will have to compete with a wave of emerging energy sources such as offshore wind, domestic shale gas and liquefied natural gas (LNG) imports.

REM spoke to Till Stenzel, chief operating officer of Nur Energie, a

member of the Desertec Industrial Initiative (DII) consortium which has also agreed a joint venture with Tunisia’s Top Oilfield Services to build a US$14 billion, 2,000-MW solar plant independently of DII.

Asked about the impact of the Arab Spring on Nur’s project, Stenzel said: “It’s been a major positive influence for us in Tunisia. We’ve certainly seen a much more open approach by the new administration, a much more transparent approach in terms of what is required and what are the questions from their side. We didn’t own any physical assets in Tunisia beforehand; only one measuring station for capturing solar radiation and measuring solar radiation at our target site, but that was untouched and it’s continued to work well, so really overall we’ve seen this very positively.”

While stable government contacts are always useful for major infrastructure projects, Stenzel played down the impact of changing faces, saying: “There wasn’t a terrible rate of attrition in the [transitional] administration.”

Changing times Elections on October 24 produced a victory for the moderate Islamist Ennahda party, although the composition of a new government remains uncertain.

Stenzel said: “The new Tunisian government is in formation as we speak and no major decisions will be taken in Tunisia before a new government is properly installed, so … we have to wait

and see what happens. Once that is in place, what we are doing from our side is engaging with the new energy minister in Tunisia regarding our project and obtaining authorisations to go forward. We’ve been active in discussing this already with the previous transition government in Tunisia and so there’s a dossier on the desk there regarding our project, which is in active discussion.”

While the region has changed substantially since the Desertec Foundation was established, so has the Desertec organisation itself.

The DII consortium, based in Munich, contains a host of Europe’s biggest energy companies, including E.ON, RWE and Abengoa, with several major banks signed up as partners. Nur Energie is a partner of DII rather than a member of the consortium, but Stenzel said this brought several advantages: “We exchange information regularly. The DII has its focus, priority projects, which are primarily in Morocco now, so we are kept informed broadly about what they’re doing in Morocco, [and] we keep them broadly informed about what we’re doing in Tunisia.”

He added: “There’s lots of scope to [affiliate] with other shareholders and partners in the DII for our project.”

Factors in the North African solar projects target market of Europe have also influenced the venture’s development."

REM

North African solar can create an Arab summer The Desertec initiative has had its fair share of detractors, but the prospect of major North African solar projects is closer than ever to becoming a reality By James Ellingworth # Desertec, launched in January 2009, aims to cover the desert in solar power generating capacity # Nur Energie is building a US$14 billion, 2,000-MW scheme in Tunisia independently of Desertec # Greece’s 10,000-MW Project Helios plan could pose a challenge to North African solar





Nuclear fallout Germany’s nuclear withdrawal, which will see all nuclear power plants (NPPs) switched off by 2022, has raised interest in Desertec there, according to Stenzel.

“I think the German nuclear withdrawal was a real impulse to say ‘this is a real opportunity.’ German companies have always been interested in these sorts of projects in general. But I think by now DII is pretty international. Certainly, its offices are in Munich and so on, but if you look at the list of partner companies and shareholders now, it’s becoming less and less German. I don’t think it’s such an exclusive German club as it might have been at the outset.”

Since 2009, there have also been wide-ranging changes in the development of other renewables projects and emerging energy sources that could challenge Desertec. The Polish government predicts that commercial shale gas development could begin in 2014, while cheap LNG has spawned a rash of infrastructure projects across the continent.

Meanwhile, offshore wind farms in the North and Baltic Seas are now much larger than Desertec’s 150-MW reference project in Morocco.

Renewables may also soon be able to play a much larger role in Europe’s energy development, if power-to-gas projects such as a 5 million euro (US$6.8 billion) pilot scheme from E.ON become commercially viable.

Stenzel has claimed in the past that Nur Energie’s Tunisian project will be able to compete on price with offshore wind owing to the level of technology involved, especially as the site reaches full capacity of 2,000 MW in 2020.

Solar competition While any of the above trends certainly seem to have the potential to compete with Desertec and other North African solar for investment or customers in the future, the most directly comparable

threat is from other large-scale solar projects.

Nur Energie’s Tunisian venture, being developed outside the DII, hints that North African solar could become a competitive marketplace, with independents seeking to undercut DII projects.

The most direct competitor comes in the shape of Greece’s 10,000-MW Project Helios plan, which has attracted considerable attention from European governments during the Greek debt crisis.

Leading European politicians such as German Finance Minister Wolfgang Schaeuble have suggested that Helios is the sort of indicator of potential Greek economic growth that could ease the burden of a bailout by making European taxpayers more confident about the future.

Asked whether Helios could shift Europe’s focus away from Desertec-style projects, Stenzel said: “No. The main reason for this is that I don’t think Project Helios will really become a big project. First of all, there are a lot of open questions. It’s not clear who’s in charge. Simply, the solar resource in Greece, in

the areas being talked about, is not particularly great. The export of solar electricity from such a location would not really be as economic as it would be from the high solar radiation areas in North Africa. Of course, it’s one of these things that’s being talked about now with the Greek crisis, but I don’t think this is really the answer.”

While Helios remains in its infancy, North African solar projects are becoming ever more concrete. Schedules have been set and work practices agreed, but DII and other developers still have some way to go before they install the first modules.

Assuming the projects come to fruition, it is difficult to say whether they will be competitive or what their rivals will be.

Various factors could still derail the projects, such as further instability in North Africa and the politics of laying the required power cables across the Mediterranean.

Regardless of the challenges, North African solar has made more progress than many commentators predicted in January 2009, and it remains a challenger."

REM





Australia’s wealth of coal and coal-bed methane (CBM) resources is creating friction at both a state and a federal level over development methods and practices.

The country has a string of CBM projects either under way or in the pipeline, with output destined for the domestic gas-fired power generation and the international liquefied natural gas (LNG) market.

The sheer abundance of Australian CBM has opened the door for a clutch of world-class LNG projects to take shape in Queensland, with a raft of smaller projects following in their wake.

The country’s US$50 billion CBM sector has drawn a growing crowd of opposition, however, with grassroots opposition movements springing up across investment hotspots. This new groundswell of public protest over CBM projects has pushed the sector on to the back foot and, while unlikely to halt its growth, has clearly hampered development.

Environmental oversight The government announced this week that, under a deal to secure support for its mining tax bill, all future CBM and large coal projects would come under increased environmental scrutiny.

The ruling Labor party made the concession to two independent MPs essential to the formation of the country’s coalition government. Independent parliamentary representatives Robert Oakeshott and Tony Windsor have reportedly faced

growing pressure over the expansion of gas projects in the areas they represent.

While the deal ensured a major political victory for embattled Australian Prime Minister Julia Gillard, with the Minerals Resource Rent Tax Bill passing through the Lower House with a thin margin of two votes, it will lead to creation of a US$150 million independent scientific committee that will evaluate all future coal and CBM projects prior to approval. The body will be tasked with ensuring such developments do not pose a risk to underground water sources.

In addition, states will be forced to confront concerns about damage from drilling to underground water supplies and, if they refuse to do so, legislation will be introduced giving the federal government the power to block new CBM projects not subject to proper environmental scrutiny, The Australian reported.

In a statement, Gillard said: “Coal seam gas and coal can bring huge opportunities, but to do so [we] must maintain community confidence, especially in regard to the impact on water.” (CBM is called coal seam gas in Australia)

“This can only be achieved by ensuring all environmental approvals and licensing decisions are made on the basis of transparent, objective scientific evidence,” Gillard added.

However, the announcement has elicited protest from the extractive sector, with complaints that the new regulations

will hamper the development of the country’s nascent CBM sector.

Politics not economics The move highlights existing concerns that a major impediment to Australia’s CBM-LNG sector is not project economics but an uncertain political landscape created by a government lacking popular support.

In an interview with Unconventional OGM, partner and co-head of King & Spalding’s LNG practice, Dan Rogers, said the hurdle for new LNG projects in Australia was the political environment and growing opposition movement.

“The likelihood of success in the next wave of projects may actually turn more on the political landscape than project economics,” he said.

Opposition to CBM projects has gained traction in Queensland, where four multi-billion dollar Gladstone projects are well under way, as well as in New South Wales.

Landowners and environmentalists have mounted increasingly effective campaigns against the development of CBM, with the New South Wales government having recently banned fracture stimulation (fracking) while it considers new industry regulations.

Rogers said: “The opposition has achieved really good traction thus far and part of that is because, once again, the industry has not done a very good job of getting correct information into public circulation.”"

Unconventional OGM

Australian CBM sector faces growing opposition Mounting opposition to Australia’s multi-billion dollar coal-bed methane (CBM) industry is slowing development By Andrew Kemp # The Australian government’s fragile hold on power bodes ill for the CBM industry # Few financial incentives for landowners mean there is little reason to embrace CBM projects # CBM developers have failed to maintain a unified front in presenting their case





He added that while there were risks involved in CBM development, as in any extractive operation, the level of opposition found in Australia was “shocking.”

He said: “When you look at [the evidence used by the opposition] and try to match it up with reality, then the dots just do not connect. And the industry has just not done a good job of responding; either through putting industry-based facts into circulation or pushing people within the government to hire independent scientists to rebut the misinformation being used by opposition groups.”

According to Rogers, however, there are other challenges at play that are also interfering with the sector’s development.

Surface deep Australian law stipulates that resources below the surface are the property of the state, which means there is little incentive for landowners to grant surface access to CBM projects.

Rogers said: “Someone is paid a fee, almost like a parking space, but it’s not the type of royalty structure that really incentivises landowners to co-operate with those trying to extract the resources.”

He added that these issues created friction and problems, but pointed to the

success of the CBM-LNG projects in Queensland in navigating the issue. However, he added: “It’s a harder job to get that done in an environment where the landowners don’t have any interest or right in the subsurface.”

While the task of negotiating land access is a tricky one, for larger projects the task has been less arduous given the amount manpower available to hold numerous negotiations. For smaller projects, however, their capacity to negotiate with hundreds of landowners and farmers is much smaller.

“It may be more of challenge for some of the new projects because they may not have the large staff [levels]. They don’t have the resources to send hundreds of people out to negotiate with landowners simultaneously the way an oil major would be able to do,” Rogers said.

Moreover, he pointed out that all future projects were likely to have to pay more because of the recent rise in opposition. “Projects may have to pay more to the landowners ultimately to get access and to me that’s probably what is driving the opposition,” he added.

Rocky road With Australia’s mineral resources ownership system denying landowners the benefits of subsurface resources the protest over CBM development may have grown more quickly than it perhaps

might have otherwise. “Surface owners are trying to figure

out a way to get a better deal for themselves,” said Rogers, adding: “If the landowners had more of a stake in the project, and saw more benefit to themselves, then you might find there were more of them willing to play ball.”

However, while noting that a change of system could take much of the steam out of the opposition movement, Rogers was sceptical that such a change would, or could, take place.

“It’s not likely to happen because it’s just such a fundamental part of the Australian mineral resources system,” he said, adding: “It would be such a fundamental change that it’s more than the Australian government would be willing to take on at this point. I suspect that [the government] feels like its system works, and has worked for a long time, and it may not be of the view that there is a need for a change.”

The government may not feel the need for change, but a lack of incentives for landowners has created fertile ground for those opposed to CBM development to spread their message. Coupled with an industry that seems unable to present a united front on the issue, Australia’s CBM industry looks set to endure further bumps on its path towards maturity."

Unconventional OGM

NRG November 2011, Issue 20 Back Page

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HEADLINES FROM A SELECTION OF NEWSBASE MONITORS THIS WEEK

Oil and Gas Sector

AfrOil Chariot has pushed back drilling plans offshore Namibia after failing to secure a rig.

AsianOil Several South Korean firms have teamed up to buy oil assets in the US valued at US$973 million.

EurOil Cairn Energy is still positive about its Greenland drilling programme, despite disappointing recent results.

FSU OGM The head of the White Stream project says Azerbaijan has enough gas to support two export pipelines.

LatAmOil Brazilian regulators have fined Petrobras US$47 million for misreporting production at the P-50 offshore platform.

MEOG The EU has blacklisted three Syrian oil companies as part of its sanctions regime.

NorthAmOil BP is selling its Canadian NGL assets to Plains Midstream Canada for US$1.67 billion.

Unconventional OGM Lithuania is to launch a tender for shale gas concessions in early 2012.

Downstream MENA Kuwait Petroleum Corp. has completed a feasibility study for a mix-feed cracker to be located near al-Zour.

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