The big question is: Can Shell keep riding this tiger? What prevents PetroChina’s parent, CNPC, from exploiting the Western producer for what it wants and then tossing it aside or perhaps even taking it over?

Updated: 2011-11-09

By Peter Voser (China Daily)

Coordinated global response is needed to meet challenge of providing more energy for more people and cutting CO2

Our world reached a significant milestone on Oct 31 when a mother gave birth to the Earth’s 7 billionth inhabitant. At this rate, the Earth will be home to more than 9 billion people by 2050 a number with an enormous potential impact on the global demand for energy, water and food.

Planning wisely for the future energy needs of this huge population is one of the most important challenges our generation faces, in part because it is far more than just an energy issue. Our future energy challenge is also a global security issue, an environmental issue, an economic issue and a jobs issue.

The global energy system is already in the early stages of a fundamental transformation. The future will see expanded use of renewable energy and cleaner fossil fuels. We will have more energy choices, but those choices will be more costly, so we will all have to become smarter about using energy efficiently.

Despite the scale of the challenge, I’m confident human ingenuity and technological innovation can make it happen. But what is lacking today is the common will to act. Getting where we need to go will require a new level of leadership and global collaboration on multiple fronts.

But the leadership triangle of government, business and society is increasingly ineffective. We need to rekindle the spirit of global cooperation and leadership that helped us deal with past challenges.

Simply put, our challenge is to produce far more energy for a world with far more people. At the same time, we need to reduce CO2 emissions and get smarter about how we extract and use our resources. And we will need to do this against a backdrop of almost constant volatility and change.

A big part of a broader global energy mix will be the rapidly expanding contribution of renewable energy resources. Up to 30 percent of the world’s energy mix could come from renewables by 2050. But that target assumes a very rapid growth rate that will require significant effort and sustained investment.

Even if the world achieves this target, all forms of energy will need to be developed to meet the future demand.

Among fossil fuels, natural gas will play an increasingly important role. It is the cleanest burning and the best ally of wind and solar power, which need a highly flexible backup.

Natural gas is also an ideal alternative to coal-fired power plants, emitting 50 to 70 percent less CO2. Replacing coal with gas to produce electricity is, by far, the fastest and least expensive way for the world to reduce CO2 emissions in the energy sector. Gas is affordable, its resource base is vast and widely dispersed, and it can help diversify energy supplies all of which enhance energy security.

It is also important that we focus on the ways in which water, energy and food are interconnected. Water is used to produce nearly all forms of energy energy is used to move and treat water, and energy and water are used to produce food. There is a growing awareness that the path to a more sustainable energy future will require society to balance the needs of these systems, while at the same time, keeping sight of carbon emissions and other resource stresses.

At Shell we have brought together specialists from various fields to map the links and better understand the trade-offs. Our early findings have identified two important factors that could help avoid a future water-energy-food crisis: smart urban development and greenhouse gas regulation and pricing.

Cities today hold half of the world’s population and generate up to 80 percent of its CO2 emissions. The global urban proportion is expected to grow to 75 percent by 2050. So the way in which our cities develop will greatly affect energy and water demand.

Through more efficient public transport, energy-efficient buildings and designs that utilize waste heat as an efficient energy source, and through investing heavily to upgrade our infrastructure, we can offset some of the growth in energy demand while creating new jobs.

But what is still urgently needed is a global consensus on greenhouse gas regulation and pricing. Widespread adoption of the most cost-effective CO2 reduction measures will only occur when governments promote frameworks to price CO2.

It brings us back to the need for leadership and global collaboration.

The absence of coherent energy policies among some of our largest energy-consuming nations and regions is a direct result of the lack of leadership and, more broadly, a troubling lack of basic trust between business, government and society.

Rather than choosing winners and losers, governments should set the goals and then provide appropriate incentives that let the market determine the most effective solutions.

I’m optimistic we will meet this challenge, as there are past examples of global leadership that offer hope. The coordinated response to the 2008 financial crisis is one. The international agreement to ban substances blamed for depleting the ozone layer is another.

Today we have a major opportunity to address the energy challenge in a way that avoids unnecessary pain in the future. Let’s not waste it.

The author is chief executive officer of Royal Dutch Shell. The article is based on a speech he delivered on Oct 31 to the Singapore Energy Summit.

(China Daily 11/09/2011 page8)

SOURCE ARTICLE

Thu Oct 13, 2011 12:47am EDT

* Planned JV won initial approval, pending final green light

* Imported condensate eyed as feedstock for petchem

BEIJING, Oct 13 (Reuters) – A proposed refinery, a petrochemical joint venture between China’s CNPC, Royal Dutch Shell Plc and Qatar, this week signed a framework deal with local authorities in eastern China’s Zhejiang province where the mega project will be built.

The project, to include a 400,000-barrel-per-day oil refining and 1.2 million tonnes-per-year ethylene plant, won initial approval from the National Development and Reform Commission, the country’s macro planner, in June, industry officials have said.

Pending final government approval, which also includes an environmental clearance, the greenfield refinery would give Shell and Qatar their first solid foothold in the world’s No.2 oil consumer, which is embarking on a refinery building boom.

The Taizhou venture, in coastal Zhejiang province, will use imported condensate and other raw materials to produce ethylene and other petrochemicals, CNPC said in a company newspaper.

“The agreement further clarifies work scope and targets for each side, reflecting sincere intentions to cooperate,” it said.

In January, Qatar Oil Minister Abdullah al-Attiyah and Wang Yong, head of the state-owned Assets Supervision and Administration Commission (SASAC), which is both a regulator and shareholder in most of China’s big state-owned companies, pledged to strengthen cooperation in the oil and gas sector and discussed the Taizhou project.

Industry experts told Reuters that the project, likely to cost close to $10 billion, would be led by Shell on the foreign partners’ side. Such an alliance follows a giant supply agreement between Qatar and China.

“The project looks promising to win Chinese government’s final blessing, as China may see Qatar quite a stabilising factor among the Middle East resource nations,” said an industry veteran.

CNPC is parent of PetroChina , Asia’s top oil and gas firm.

In May 2010, CNPC and Qatar Petroleum signed a 30-year deal for gas exploration and production in Qatar, holder of the world’s third-largest gas reserves. Shell, as operator, will hold a 75 percent equity stake, with CNPC holding the remainder.

SOURCE ARTICLE

COLUMN-Is fracking set to transform the oil market? John Kemp

(John Kemp is a Reuters market analyst. The views expressed are his own)

By John Kemp

Oct 12 (Reuters) – Hydraulic fracturing and horizontal drilling revolutionised the natural gas market, unlocking huge quantities of previous unrecoverable reserves trapped in tight rock formations.

The question is whether they are about to do the same for oil — unlocking billions of barrels of crude trapped in similar rock forms, and thereby upending forecasts about increasing oil scarcity and steeply rising prices.

WHY MALTHUS WAS WRONG

In the short term, prices for commodities are determined by the usual forces of supply and demand. In the medium and long term, however, technology is the main determinant of price and availability.

Fracking and horizontal wells are classic examples of transformational or disruptive technologies which completely alter their industries by upsetting long-held assumptions about the feasibility and cost of production.

New technology has proved a blind spot for market analysts and forecasters. In many instances, forecasts implicitly assume technology remains unchanged or evolves only incrementally, even over years or decades.

Yet past experience suggests disruptive and transformational technologies are more common than this static framework assumes. Given sufficient incentives in the form of high prices or threatened shortages technology has proved extraordinarily resourceful, wringing extra raw materials from the planet.

Failure to account for technical change that has repeatedly tripped up forecasters — from Thomas Malthus in the 18th century (food shortages) and William Jevons in the 19th (peak coal) to U.S. geologists in the early 1900s (peak domestic oil), M King Hubbert in the 1950s (peak oil), the authors of “Limits to Growth” in the 1970s (worldwide food and energy shortages), and Robert Hirsch in 2005 (peak gas).

In most cases, transformational technologies were already being employed when these gloomy forecasts were made, but the authors failed to appreciate their significance. Jevons, for example, considered the potential for petroleum to displace coal in a chapter on “supposed substitutes” but dismissed it.

In his 1866 bestseller “The Coal Question: An Inquiry Concerning the Progress of the Nation, and of the Probable Exhaustion of our Coal Mines”, Jevons was more concerned to knock down suggestions that wind and water power could replace diminishing coal supplies when domestic production peaked.

In retrospect, his dismissal of petroleum is almost comically brief: “Petroleum has of late years become the matter of a most extensive trade, and has even been proposed by American inventors for use in marine steam-engine boilers. It is undoubtedly superior to coal for many purposes, and is capable of replacing it. But what is petroleum but the essence of coal, distilled from it by terrestrial or artificial heat. Its natural supply is far more limited than that of coal.”

In a modern example, Hirsch and his co-authors warned about peaking U.S. gas supplies in a 2005 report for the Department of Energy, predicted worse to come when global oil supplies peaked sometime between 2008 and 2014.

Even as Hirsch was writing, hydraulic fracturing and horizontal drilling tech had been around for decades and were starting to be deployed extensively across the Barnett shale in Texas, heralding the start of the shale gas boom (here).

Disruptive technologies may remain at the experimental and development stage for many years, but once they take off and reach commercial deployment the impact is usually rapid. Production of shale gas has risen from virtually nothing in the late 1990s to 23 percent of all U.S. output by 2010.

WHAT ARE WE MISSING?

Any forecast for oil supply-demand balances and prices over the medium-to-long term (five years or more) must start by asking the question: what is the market missing?

Projections of rising demand from China and other emerging markets are well known, as is depletion of existing fields and the failure to find new ones on a scale to replace the ageing super-giants discovered between the 1930s and the 1960s.

The question is whether there are any disruptive technologies that would significantly alter these supply and demand trends, and if so over what timescale?

There are a number of candidates for the role. Technologies to make liquid transport fuels from abundant gas and coal; increase the use of biofuels; or promote the use of electric vehicles. But none is as promising over the short to medium term as using hydraulic fracturing and horizontal drilling to produce crude from tight rock formations.

Technologies to extract oil from tight formations are mature (having been extensively used in the natural gas industry); capital costs are comparatively low; and they utilise existing energy infrastructure and pathways rather than requiring construction of new distribution and processing systems and new vehicles.

WHERE BAKKEN LEADS …

Crude production in the state of North Dakota has nearly quadrupled to around 110 million barrels a year since 2002 as a result of applying these technologies to the Bakken formation, which covers much of the state as well as parts of neighbouring Montana, South Dakota, Manitoba and Saskatchewan.

Soaring output from Bakken coupled with increased deepwater output from the Gulf of Mexico has pushed up U.S. domestic production 600,000 barrels per day (12 percent) since 2008, the first increase since 1985, confounding predictions domestic output was set on an inexorable downtrend (here&GAS.pdf).

The industry has known about the Bakken formation since the early 1950s. But until the last decade the oil was thought to be essentially unrecoverable. Unlike a conventional resource in which oil or gas accumulates in a discrete, permeable reservoir rock over a relatively small area, oil and gas deposits across the Bakken are distributed over a huge area in formations with low permeability.

The U.S. Geological Survey refers to formations like Bakken as a “continuous-type” oil or natural gas resource. Prior to the application of fracking and horizontal drilling, there was no way to get these extensive but unconcentrated gas and oil resources held in relatively impermeable formations to flow to the foot of traditional vertical wells in sufficient volume to make them economically recoverable.

Continuous-type oil and gas resources are more common than concentrated reservoirs. Geological surveys show extensive formations suitable for shale gas extraction across North and South America, northern Europe, north Africa, India, China and Australia. Many of these regions may have formations suitable for oil production as well, though research has so far concentrated on gas rather than liquids.

If the technologies that have revolutionised gas can be rolled out for oil there is potential for a significant increase in output, much of it located away from traditional producing areas in the Middle East, the North Sea and West Africa.

Chief Executive Peter Voser of Royal Dutch Shell, which has been an oil industry leader in adopting new technology, told the Financial Times newspaper last month that it aimed to start producing from tight oil reserves in North America.

Voser told the Financial Times that having built a large position in North American tight gas, Shell planned to apply the same model to tight oil (“Shell targets North American tight oil”, Sep 22).

Tight oil production faces formidable problems. Unlike concentrated conventional oil and gas reservoirs, production from tight rock formations is far more extensive, and its footprint on communities and the environment is consequently much larger.

SOURCE ARTICLE

BUSINESS CHINA

11 Oct 2011

By James Paton

Sept. 26 (Bloomberg) — Arrow Energy Ltd., owned by Royal Dutch Shell Plc and PetroChina Co., agreed to buy Bow Energy Ltd. after sweetening its offer to A$535 million ($516 million), gaining resources for a natural gas project in Australia.

The coal-seam gas explorer and producer in Queensland state increased its cash offer to A$1.52 a share from A$1.48, Brisbane-based Bow said in a statement today. That’s 72 percent more than the stock’s price of 88.5 cents in Sydney trading before Arrow made its initial offer on Aug. 22.

Arrow plans the fourth liquefied natural gas venture in Queensland to meet rising Asian demand for the fuel, following approvals for more than $50 billion in developments led by BG Group Plc, Santos Ltd. and ConocoPhillips. The acquisition may allow Arrow to expand output at the venture’s first two units, or trains, by as much as 15 percent, the company said today.

“These big LNG project developers will need more gas” to underpin additional processing units, Ivor Ries, an analyst at E.L. & C. Baillieu Stockbroking Ltd., said by telephone today from Melbourne. “We’ll see more consolidation.”

Bow rose 0.3 percent to A$1.465 at 4:10 p.m. in Sydney. Bow has gained 66 percent since Aug. 19 on the Australian stock exchange, before Brisbane-based Arrow made its initial offer.

‘Good Deal’

The Arrow accord values Bow at about 16 cents a gigajoule of proven, probable and possible reserves, compared with an average of about 50 cents a gigajoule for Australian coal-seam gas transactions over the past two years, Andrew Williams, an analyst at RBC Capital Markets in Melbourne, said by phone.

“This is a very good deal for Arrow,” Williams said.

The Arrow LNG venture may cost more than $20 billion to develop, Deutsche Bank AG estimated in a Sept. 23 report. Bow had been the subject of takeover speculation since Santos, Australia’s third-largest oil and gas producer, agreed in July to pay about A$730 million to buy the shares in coal-seam gas explorer Eastern Star Gas Ltd. it didn’t already own.

“Our project is proceeding quite nicely on our existing reserves,” Andrew Faulkner, Arrow’s chief executive officer, said in a phone interview today. The transaction provides “the opportunity to take that project to the next level, to expand the train size and to strengthen our reserves base,” he said.

The Bow deal may allow Arrow to expand the size of each of the first two LNG processing units on Curtis Island to as much as 4.6 million metric tons of the fuel a year from the current plan of 4 million tons a year, Faulkner said. Arrow is on track to make a final investment decision in late 2013, he said.

‘Superior Bid’

Bow’s board recommends that shareholders vote in favor of the proposal in the absence of a “superior” bid, according to the statement. The accord is subject to regulatory approvals in Australia and China, and Bow shareholders are due to vote on the deal in December, the companies said in separate statements.

Bow said it is being advised by Bank of America Corp. and Wilson HTM Investment Group, while Arrow said it named JPMorgan Chase & Co. as a financial adviser.

The offer “absolutely reflects the underlying value of Bow’s assets and resources,” Arrow’s Faulkner said in the interview. “The price acknowledges the volatility and the technical and commercial uncertainties that are out there.”

The coal-seam gas industry on the east coast of Australia “must repair damage and rebuild the trust” of communities amid criticism from environmental groups who say the drilling of wells may contaminate water supplies, Elaine Prior, a Citigroup Inc. analyst in Sydney, said in a Sept. 21 report.

–Editors: Keith Gosman, Amit Prakash

To contact the reporter on this story: James Paton in Sydney jpaton4@bloomberg.net.

To contact the editor responsible for this story: Amit Prakash at aprakash1@bloomberg.net.

SOURCE ARTICLE

In Sakhalin… Exxon has fared much better than rival Royal Dutch Shell, which has led the development of Sakhalin-2. In 2005 Shell disclosed $10 billion in cost overruns on the $20 billion project, and in 2007 it was forced by the Kremlin to sell half of its Sakhalin stake to Gazprom. Though Shell and Rosneft signed a “strategic alliance” in 2007, it has proven to be all show, no go. In May, Rosneft and Shell were reportedly in talks over a deal to explore the Arctic. The Exxon announcement indicates that those talks have ended.

Christopher Helman, Forbes Staff

From Houston 8/31/2011 @ 12:46PM

More than a black eye for BP, the Rosneft deal is a gold star for ExxonMobil, one that illustrates that the company is not only the world’s biggest international supermajor, but the only one that can claim any lasting success in Russia.

Contrary to the conventional wisdom that Exxon is stepping into dance shoes that had been knocked off BP’s feet — the Exxon/Rosneft venture has been a long time in coming. What’s more, the lovey-dovey deal increases the likelihood that Exxon and the Kremlin might soon be able to come to terms on the development of massive untapped natural gas reserves held by Exxon’s Sakhalin Island development.

Sure it embarrasses BP, considering that back in January new Chief Executive Robert Dudley was heralding his $16 billion share swap with Rosneft as marking the start of BP’s comeback — only to see it waylaid by lawsuits from BP’s oligarch partners at Russian joint venture TNK-BP.

But remember that half of this “new” deal–the $1 billion exploration of Black Sea prospects — had already been signed by Exxon and Rosneft back in January.

Exxon and Rosneft have been partners in Russia for more than 15 years in development of the Sakhalin-1 project, which started up in 2005 and now produces more than 250,000 bpd. “Today’s agreement with Rosneft builds on our 15-year successful relationship in the Sakhalin-1 project,” said ExxonMobil Development Co. President Neil Duffin in a statement yesterday.

In Sakhalin (where current Chief Executive Rex Tillerson cut his teeth) Exxon has fared much better than rival Royal Dutch Shell, which has led the development of Sakhalin-2. In 2005 Shell disclosed $10 billion in cost overruns on the $20 billion project, and in 2007 it was forced by the Kremlin to sell half of its Sakhalin stake to Gazprom. Though Shell and Rosneft signed a “strategic alliance” in 2007, it has proven to be all show, no go. In May, Rosneft and Shell were reportedly in talks over a deal to explore the Arctic. The Exxon announcement indicates that those talks have ended.

What of the other supermajors? In June Chevron backed out of its JV with Rosneft to explore in the Black Sea, reportedly because geologists at the two companies couldn’t agree on the size of the resource. We’ll see if Chevron gets another chance to make inroads in Russia any time soon. Same goes for ConocoPhillips, which last year sold its stake in Russian giant Lukoil and exited the country.

As for France’s oil giant Total, it is a partner with Gazprom in developing the giant Shtokman gas field in the iceberg-strewn Barents sea — but it’s a big question mark whether that $15 billion-plus project will happen any time soon given Russia’s trove of more easily accessible riches.

Such as the 17 trillion cubic feet of as yet untapped gas reserves that Exxon’s Sakhalin consortium is sitting on in the Chayvo field. Exxon has for years wanted to sell the gas from Sakhalin-1 directly to China. But that conflicts with Gazprom’s desire to control all the gas from Sakhalin, and merge Exxon’s flow into that from Sakhalin-2 in order to fill a new pipeline to Vladivostok. In 2008, Rosneft said it would help convince Exxon to sell its gas to Gazprom — which is a funny concept considering that a majority of each company is held by the Kremlin.

This June, Gazprom said it expected to reach an agreement with Exxon on Sakhalin-1 gas by the end of the year. You can be sure that Exxon ironed out those details in advance of this week’s Rosneft deal. All that’s left is the official announcement that Exxon will put Sakhalin gas development into overdrive.

SOURCE ARTICLE

By Alexis Flynn, Of DOW JONES NEWSWIRES

LONDON -(Dow Jones)- When Europe’s major oil companies reported quarterly earnings last week, headlines across national capitals once again excoriated the petroleum giants for soaring profits in the face of consumers anger at high fuel prices.

Yet the profits couldn’t mask a trend that continues to trouble Wall Street and corporate boardrooms: Nearly every major oil company reported year-on-year oil and gas output declines, often in the double-digits.

Big Oil is throwing huge resources at the problem with more open embrace of unconventional petroleum developments, high-risk exploration in frontier areas and corporate restructuring. But even if these strategies work in some cases, there is little doubt that anemic petroleum output signals a long-term challenge confronting the sector.

The particulars varied across the sector. BP PLC’s (BP) 11% output drop was fueled in part by the continued hit from its reduced activity in the U.S. Gulf of Mexico after last year’s disastrous spill. Italian giant Eni’s (ENI) production fell 15% due to its disproportionate exposure to war-ravaged Libya. Spain’sRepsol YPF SA (REP.MC), whose output fell 17%, was affected by both Libya and the U.S. Gulf, as well as by labor unrest in Argentina. Norway’sStatoil ASA (STO) saw a16% output decline largely on production outages and maintenance in its home market in the North Sea.

Oil giants are more vulnerable to operational problems in part because of their declining dominance over key resources. Whereas in 1973, independent oil firms controlled three-quarters of the world’s reserves, they hold as little as10% today, according to some estimates. That has forced oil majors to rely to a greater extent on costly unconventional plays such as shale gas, deepwater exploration, and Arctic exploration.

Investment in conventional assets accounted for 63% of the majors’ total capital expenditure between 2001 and 2005, research by Wood Mackenzie showed, with this proportion set to fall to 40% between 2011 and 2015.

Last week’s reports showed that the two biggest oil giants, Royal Dutch Shell PLC (RDSA) and Exxon Mobil Corp. (XOM), were somewhat better positioned than their smaller peers, in light of their capacity to progress capital-intensive projects. Another standout, Wall Street darling BG Group PLC (BG.LN), the only European oil major to report higher year-on-year output, has prospered from recent discoveries in the hot Brazil offshore region.

Yet there are problems even with these templates. Though demand for natural gas remains solid, natural gas prices could see further weakness in light of surging North American shale gas output and economic weakness in Europe and the U.S.

The push for more exploration has ignited interest in Africa following new seismic results and recent discoveries in Ghana and Uganda. But it’s a risky and capital-intensive game and one requiring a fleetness of foot to grasp opportunities and adapt quickly to contrary political circumstances. Industry anecdotes abound of how some of the most lucrative recent discoveries on the continent were once passed up by reluctant majors.

Consolidation offers another way forward, yet few expect large corporate mergers between integrated oil giants in light of antitrust concerns and today’s high oil prices. More likely is a deal akin to Exxon’s purchase of U.S. unconventional gas specialist XTO, a major factor in Exxon’s standout 10% rise in production in the quarter. Wood Mackenzie’s Simon Flowers predicts more such “infill acquisitions,” but says “large-scale acquisition is not likely in the near term.”

Another possibility is the flowering of deals between private oil giants and emerging state-controlled firms like Brazil’s Petrobras, Russia’sRosneft (ROSN.RS) and China’s CNPC. BP‘s failed share swap and Arctic exploration deal with Rosneft was an example and illustrates the lengths to which companies are prepared to go to gain access to their potentially lucrative reserves.

Wall Street will likely push harder for some sort of tangible action from Big Oil in the coming months. The sector trades at a significant discount to the oil price itself, a factor that could sharpen calls for share buybacks and more special dividends. The recent move by ConocoPhillips (COP) to hive off its downstream business lifted the Texas company’s share price and spawned questions for the rest of the sector. But so far, most of Conoco’s peers have dismissed the idea as impractical in light of the advantages of the conventional integrated model.

-By Alexis Flynn, Dow Jones Newswires; +44 207 8429471, alexis.flynn@ dowjones.com

(END) Dow Jones Newswires 07-31-111009ET

Copyright (c) 2011 Dow Jones & Company, Inc.

SOURCE ARTICLE

From pages 31 & 32 of “Royal Dutch Shell and its sustainability troubles” – Background report to the Erratum of Shell’s Annual Report 2010

The report is made on behalf of Milieudefensie (Friends of the Earth Netherlands)
Author: Albert ten Kate: May 2011.

Unconventional gas and high-volume fracking

Not only for oil, but also for gas Shell is resorting to unconventional production methods. In December 2010, Shell-CEO Peter Voser stated: “In recent years, Shell has increased investment in natural gas projects in countries like Qatar, Australia, Russia, the United States and Canada, with a special focus on tight gas, shale gas and coal-bed methane – together these are known as unconventional gas. We’re currently exploring the potential for unconventional gas outside North America in countries like China and South Africa, as well as some European countries.” The Shell-CEO proceeds: “I know by 2012 Shell will be producing more gas than oil, and, I know, when it comes to natural gas supplies, a revolution is under way. (…) Shell is set for strong growth in tight gas.”

Conventional natural gas is usually found trapped in the pore space of rock types like sandstone in underground geologic formations. Compared to unconventional gas, conventional gas flows rather easily to drilled wells. For unconventional gas, often high-volume fracking is used as a technique to get the gas to the surface. Fracking (or hydraulic fracturing) involves injection of water, mixed with sand and chemicals to ease production of natural gas and oil by breaking up rock formations. Fracking has been done around the world for many years. However, high- volume fracking is a rather new phenomenon and causes much more environmental damage and health risks. From this point of view, the revolution that is under way according to Shell-CEO Peter Voser, may in fact be a quite worrying revolution.

Tony Ingraffea, professor of Civil Engineering at the Cornell University in the U.S. State of New York, has conducted much research on fracking. During a radio interview in February 2011, he asked himself the question: “What is high-volume fracking, compared to the traditional historical kind that no one seems to be complaining too much about?” His answer was: “The difference is about a factor of hundred in just about everything, predominantly the amount of fluids that are necessary to do the fracking [including the amount of chemicals; the professor mentions this later in the interview], the amount of fluids and other waste products produced from a high- volume unconventional well that’s fracked, the amount of truck traffic, the amount of energy and power that needs to be brought to a well. (….) It’s not the issue of fracking, it’s the entire system of developing gas from an unconventional resource.”

Shell’s positions in unconventional gas

Shell is rapidly expanding its positions in unconventional gas (tight gas, shale gas and coal-bed methane). Below its main present positions around the world are listed:

− North America. Shell’s North American tight gas production amounted to some 140,000 barrels of oil equivalent per day in 2009, an increase of 62% from 2008 levels. Shell expects that its production could double from 2009 to 2015. Its activities in U.S. tight gas began in 2001, with purchases in the Pinedale Anticline in Wyoming State. More recently, Shell secured unconventional gas positions in the Haynesville play in Texas/Louisiana State and in Western Canada (Groundbirch, Deep Basin, Foothills, Klappan). Its 2010 acquisitions are mainly in the Marcellus shale, the biggest natural gas field in the United States, covering most of Pennsylvania state and parts of New York, Ohio and the Virginia states. Another 2010 acquisition was within the Eagle Ford shale play, in South Texas.

− South Africa. Shell wants to start shale gas exploration activities within the Karoo eco-region in South Africa. The exploration area would comprise 90,000 square kilometres, more than two times the surface of the Netherlands.190 Shell has applied for three exploration areas, each comprising 30,000 kilometres. In each area it wants to drill up to eight exploration wells. The formations in the Karoo that are believed to contain recoverable gas are located 1.5 to 4.5 kilometres below the surface.

− China. Shell and PetroChina operate Changbei, a tight gas field in the Shaanxi Province of China. Commercial production in Changbei began in March 2007, supplying 3 billion cubic metres of natural gas a year to Beijing and other cities in eastern China. Late 2007, Shell took over a 55% equity interest in a coal-bed methane venture in Shaanxi Province. In the Sichuan province, Shell works together with PetroChina on developing two tight/shale gas reservoirs of each 4,000 square kilometres.192 Shell provides little information about the environmental impacts of its Chinese operations.

− Australia. In August 2010, Shell and PetroChina (majority owned by the state company CNPC, China National Petroleum Corporation) completed their acquisition of the Australian company Arrow Energy. The 50/50 joint venture called CS CSG (Australia) Pty Ltd. now owns coal seam gas assets in Queensland state, domestic power businesses, and a site to build a liquefied natural gas (LNG) plant for export markets. Coal-bed methane is natural gas contained in coal seams. The new joint venture will be the operator of the coal seam gas assets. The gas production assets are in the Surat and Bowen basin. In the Surat basin, there is no fracking done. In the Bowen basin, there might be.

− Other. Shell also has unconventional gas positions in Sweden, Germany, Ukraine and Brazil.

A further extract from this section of the report will be published in the coming days.

THE COMPLETE 73 PAGE REPORT (with reference sources)