Of the $317 billion worth of oil and gas deals struck in 2011, $66 billion were shale-related transactions, up from $55 billion the year before. That trend is set to continue, and at the expense of investment in traditional renewables, says Ernst & Young’s Asia-Pacific Oil & Gas Leader Sanjeev Gupta.

The 2012 year has already started off strongly for shale, with China Petrochemical Corp. or Sinopec, making its first entry into the U.S. shale market through a $2.5 billion deal with Devon Energy Corp.

France’s Total SA also paid $2.3 billion for a stake in Chesapeake Energy Corp.’s shale fields in Ohio. On Friday, a unit of China National Petroleum Corp., PetroChina Co., said it had bought a 20% stake in Royal Dutch Shell PLC’s shale asset in Canada for undisclosed terms.

Despite all the attention surrounding the shale craze in North America, it’s China that has the world’s largest shale reserves, or 19% of global resources, according to Ernst & Young. The U.S. Energy Information Administration estimate China’s shale reserves to be as much as 1,275 trillion cubic feet, more than the agency’s combined estimates for the volumes in the U.S. and Canada.

“If the potential in this asset base can be unlocked, this could transform the oil and gas landscape in years to come,” said Ernst & Young. That could be many years away as China doesn’t have the technology to exploit its own reserves yet, particularly as much of China’s deposits are located on hostile terrain. But every foreign deal China does brings it closer to acquiring that technology and using it at home, so that it becomes less dependent on foreign energy sources.

This post by Isabella Steger originally appeared in the WSJ

Never mind that hydraulic fracturing was once again linked to an earthquake, this time a 4.0 tremor in Ohio on New Year’s Eve, the year 2012 kicked off in impressive fashion for the shale industry, which has been revolutionized by the controversial drilling practice.

Undaunted by the environmental and geological challenges, two oil giants signed shale deals in the United States for a combined US$4.5-billion ($4.58-billion) in one day. On January 3, France’s Total SA bought a 25% interest in Chesapeake Energy’s Utica shale play worth US$2.3-billion, while China Petroleum & Chemical Corp., or Sinopec, took up a one-third interest in Devon Energy’s shale projects for US$2.2-billion.

It’s a trend that’s set to continue and go beyond North American borders, says Moody’s Investor Services, as majors catch up with independent developers.

“Independent E&Ps have led the way in shale drilling, developing expertise in natural gas,” Moody’s said in a note. “The majors came late to the game in North America, but have begun pursuing E&Ps for their expertise in the new development techniques.”

Shale activity took off in earnest in 2011: ExxonMobil Corp. bought two companies in the Marcellus basin in Pennsylvania, and Marathon Oil Co. acquired Eagle Ford properties in south Texas from Hilcorp Resources Holdings LP. Mining giant BHP Billiton Ltd. acquired Petrohawk Energy Corp., a major player in the Haynesville and Eagle Ford, plus some Fayetteville shale properties, for US$15.1-billion. Norway’s Statoil ASA spent US$4.7-billion to buy Brigham Exploration Co. with operations concentrated in North Dakota’s Bakken Shale and Three Forks in Montana. Overall, shale acquisitions helped push overseas offers for U.S. oil and gas fields to US$51-billion last year, the most in at least 12 years, according to data compiled by Bloomberg.

“In Canada, the Montney Shale — a large natural gas basin in British Columbia and Alberta — has sparked interest for its proximity to a number of proposed projects to export LNG to Asia, and for potential gas-to-liquids (GTL) plants,” Moody’s says. “Sasol has two JVs with Talisman Energy and has begun studying a future GTL plant in western Canada that would use its proprietary technology. Petronas, Malaysia’s state oil company, created its first Montney JV with Progress Energy Resources — possibly with an eye on exporting LNG to Asia.”

GOING GLOBAL

Despite the ban in promising jurisdictions such as France, major companies are looking outside North America for growth. “These companies will strive to apply their expertise and mature cash flows toward other basins— particularly in Argentina, Brazil, China, Mexico, Poland and South Africa. The NOCs also hope shale development will help them improve energy security and self-sufficiency,” Moody’s says.

On Wednesday, China approved shale gas as an independent mining resource, a legal status that it hopes will encourage smaller Chinese energy firms to develop the unconventional energy source. The energy-hungry giant is expected to announce a new round of shale-gas tenders in early 2012, and although foreign companies can’t participate directly, they can team up with local firms.

Poland, which holds the most active and best areas geologically for shale in Europe, where governments want to diversify their natural-gas supplies away from Russia, is another promising play. The country has drawn investment from JVs involving ExxonMobil/Total, Marathon/Nexen, ConocoPhillips and OMV Petrom, among others.

But Moody’s says the development of these shale resources will not be quick or straightforward, and will face numerous obstacles similar to those seen in North America.

“Hydraulic fracturing has led to widespread environmental concerns over such issues as water contamination, wastewater disposal, land subsidence, earthquakes, and noise pollution. Areas more densely populated than sparsely inhabited North Dakota will present further challenges — particularly in Europe, where resistance to shale development has emerged,” the ratings agency says.

Source: Financial Post

Total agreed to pay $700m for a 25 per cent stake in shale assets totalling 619,000 acres rich in liquids as well as natural gas, held by Chesapeake and EnerVest in Ohio’s Utica formation.

It has also committed to pay an additional sum of up to $1.63bn to cover future capital expenditure on drilling and well completion in the area for up to seven years.

In 2010, Total bought a 25% stake in Chesapeake’s Barnett Shale field in Texas  at a deal valued at up to $2.25bn.

Speaking at the World Shale Gas conference in Houston, John Bannerman, chief executive officer of Total E&P USA, said that the company was exploring new joint ventures or becoming an operator.

“We’re very clearly on the lookout,” said Bannerman.

Total is targeting basins that have crude oil or natural gas with a high liquids content. ”In this current climate, liquids have an added advantage,” Bannerman told reporters.

“It will be a natural progression” for Total to focus its shale expansion on shale liquids areas such as Texas’s Eagle Ford Shale and Ohio’s Utica Shale, the Total executive said.

Bannerman declined to say whether Total was Chesapeake Energy’s partner in the Utica Shale in Ohio, Earlier this month, Chesapeake announced a joint venture deal with an undisclosed international major.

Last year, Total signed a $2.25 billion joint venture agreement to buy a 25% stake in Chesapeake Barnett Shale in Texas.

Apache Argentina country manager Michael Bose said the drilling and extraction technologies that gave rise to the unconventional gas boom in the U.S. could do the same for Argentina.

“It’s a very good model for Argentina to follow. We have the opportunity to turn the curves around both on production and reserves growth,” he said at an oil and gas conference.

Argentina accounted for 7% of Apache’s total oil and gas production and 4% of its estimated proved reserves last year and the company has committed increasing resources to its operations in the South American country.

Apache Argentina will invest about $340 million this year, up from $253 million in 2010, Bose said.

According to the U.S. Energy Information Administration, Argentina ranks No. 3 in the world in terms of technically recoverable shale gas resources with 774 trillion cubic feet of gas. Unconventional gas refers to gas locked up in tight sands and shale formations.

That potential has attracted a number of major players in the global oil and gas industry, including France’s Total SA and Exxon Mobil Corp.

Argentina’s nascent unconventional gas industry faces a number of hurdles, including rising wage costs and a lack of pipeline and related infrastructure to handle large volumes of gas.

But price caps that have discouraged investment in gas production are an important reason why Argentina’s natural gas reserves have plunged 40% during the last 10 years.

Last year, local producer YPF SA sold natural gas in the domestic market for an average price of $1.96 per million British thermal units — about 1,000 cubic feet — compared with the $7.33/MMBtu that Argentina paid for Bolivian gas.

At the same time gas demand has surged owing to those low prices and a fast growing economy.

The government has imported growing volumes of much more expensive gas from Bolivia and Trinidad & Tobago, while the supply situation has become so precarious that in the cold winter months it rations gas to industrial users to make sure residential demand is met.

To attract shale gas investment, President Cristina Kirchner launched the Gas Plus program in 2008 that allows producers of unconventional gas to charge significantly higher prices than is the case with natural gas from conventional sources that are subject to price caps.

During 2010, Apache signed a Gas Plus contract for $4.10/MMBtu and two contracts for $5.00/MMBtu.

Bose declined to mention an ideal price level that would allow the unconventional gas industry to reach its full potential in Argentina.

“There is no doubt that the opportunities are here to be competitive with the import gas with the LNG cargoes. We have the opportunity to develop the shale gas here,” he told reporters at the sidelines of the event.

Are we surprised? The answer is no — students of hydrocarbon bonanzas know that, going back to the 19th-century frenzies of Baku and Pennsylvania, reserve assertions in the heat of the boom are not reliable. Such outbreaks of exuberance, regardless of whether fundamentally legitimate, include con artists (hence suckers), cooked books (more suckers), and out-and-out fraud (ditto). In the Caspian era of the 1990s, for instance, the Clinton administration, relying on lobbying reports from Amoco, justified a supercharged policy effort with estimates of 200 billion barrels of oil; the actual figure as of today is closer to 50 billion barrels. Yet companies and individual investors proceed anyway because they do not want to potentially miss out.

Which is what makes one puzzled by the war-like reaction to two long, ambitious, but fairly run-of-the-mill pieces in the New York Times (“Insiders Sound an Alarm Amid a Natural Gas Rush” and “Behind Veneer, Doubt on Future of Natural Gas“) by Ian Urbina. In 5,300 words, plus a splash of leaked memos and emails, Urbina reports that U.S. natural gas prices are too low to justify much of the drilling and that companies have been possibly permitted by the Securities and Exchange Commission to overstate their gas reserves (the latter by far the best of the three pieces). Today, Urbina adds a piece with federal lawmakers calling for an investigation.

I have weighed in on how the very real volumes of shale gas being extracted from Texas, Oklahoma, and elsewhere are already transforming geopolitics, weakening Russia’s hold on Europe, for instance. Yet we also know about the nightmare (for drillers) of low natural gas prices (this piece by Jack Smith at the Fort Worth Star-Telegram is excellent). The industry’s full potential is being put in jeopardy by the interesting PR policies of industry hands like Chesapeake Energy CEO Aubrey McClendon. In addition, as noted above, wise hands have understood they must discount promotional estimates and characterizations by the shale gas marching band.

Yet Urbina seemed to strike a sensitive nerve. McClendon issued a special statement in which he said Urbina is “obviously motivated by an anti-natural gas agenda,” and “chose not to interview a single reliable source.” Similarly, the ultra-sober Michael Levi at the Council on Foreign Relations dismissed the pieces as just another salvo in the Times’ “war on shale gas.” The Energy Information Administration released an explanatory letter it had written to Urbina in advance of publication. Over at Forbes, Christopher Helman, calling Urbina’s reporting “absurd on its face,” posed the question, “Would drillers be investing billions a year in new wells if they weren’t getting some return out of it?” (Answer: yes. The reason is that many of the leases require drilling in order to keep possession of the fields).

So what is going on with this storm? Is it a slow news cycle? Do we have a Shakespearean denial? Parenthetically, one observes that the much-reported demise of the impact of mainstream newspapers is premature. More to the point, shale gas may be exaggerated, but it is being produced in substantial volumes. And it is shaking up the status quo.

Ultimately, we get a fairly mundane conclusion. Which is that, with much at stake, booms tend to make people hot under the collar.

With our thanks to Steve LeVine

Steve LeVine is the author of The Oil and the Glory and a longtime foreign correspondent.

In this past Sunday’s edition, the Times accused the Chesapeake of exaggerating the productivity of shale gas wells and industry reserve estimates of future well performance.

Aubrey K. McClendon, Chesapeake’s Chief Executive Officer, commented, “Chesapeake stands behind all of its statements to shareholders, partners and the public regarding our natural gas discoveries and production.”

McClendon claimed the story was motivated by an anti-natural gas agenda.

“It is telling that the reporter chose not to interview a single reliable source and instead selectively quoted emails from unnamed sources or well-known industry critics dating back to as early as 2007 to invent a series of inaccurate and misleading allegations,” said McClendon

“If the Times was interested in reporting the facts and advancing the debate about the prospective benefits of natural gas usage to energy consumers, it could easily have contacted respected independent reservoir evaluation and consulting firms that annually provide reserve certifications to the U.S. Securities and Exchange Commission or contacted experts at the U.S. Energy Information Administration, the Colorado School of Mines’ Potential Gas Committee, the Massachusetts Institute of Technology, Navigant Consulting and others who would gladly have gone on record to confirm the abundant resources that have been made available thanks to the horizontal drilling and hydraulic fracturing techniques that Chesapeake and other industry peers have pioneered in deep shale formations across the U.S.”

“The Times questioned the economic merits of shale gas production in complete disregard and/or ignorance of supply and demand fundamentals as well as recent and forward market natural gas prices,” Chesapeake’s CEO continued.

McClendon listed companies active in shale gas development in the U.S. including Anadarko, BG, BHP, BP, Chevron, CNOOC, Conoco Phillips, Devon, EnCana, ENI, EOG, ExxonMobil, KNOC, Marathon, Mitsubishi, Mitsui, PetroChina, Reliance, Shell, Statoil, Talisman, and Total.

“Consider whether it could really be possible that all of these well-respected energy leaders, with a combined market cap of almost $2 trillion, know less about the economics of shale gas production than a single New York Times reporter, a few environmental activists and a handful of shale gas doubters?”

McClendon said that the industry continues to have learning-curve benefits that make U.S. shale gas projects attractive to the global energy industry.

Read the Full Statement from Chesapeake HERE

Read: The New York Times Is All Hot Air On Shale Gas from Forbes HERE

Planning Minister Julio De Vido told reporter that even if the gas reserves are found to be very large, they will be targeted for local consumption, especially by industry.

The U.S. Energy Information Administration said that Argentina could be home to the largest technically recoverable shale gas resources in South America, with an estimated 774 trillion cubic feet. Brazil trailed as a distant No.2 with 226 trillion cubic feet.

Last December, Argentina’s largest oil and gas producer, YPF SA, said that it uncovered a massive shale gas discovery in the southern province of Neuquén.

Total SA, Exxon Mobil Corp.and Apache Corp.are also exploring for shale gas in Neuquén Province.

Argentina used to be a major supplier of natural gas to Chile until 2004, when it essentially cut shipments to its neighbor to ensure sufficient supplies at home.

Argentina’s proven natural gas reserves fell 51% to 13.3 trillion cubic feet between 2000 and 2009 because of rapid economic growth and government price caps that have spurred demand while providing little incentive to search for more gas.

As a result, Argentina has become a net importer of gas.

It has a contract with Bolivia to import 7 million cubic meters of natural gas a day, with that amount scheduled to increase to 11 million cubic meters next year. Liquefied natural gas is also brought in from Trinidad & Tobago.

Even so, supplies are so tight that in the coldest periods of the southern hemisphere winter, usually July, the government is forced to cut gas to industry to satisfy residential demand.

To attract investment, the government in 2008 unveiled a program known as Gas Plus that allows producers of unconventional gas to charge significantly higher prices than is the case with natural gas from conventional sources.

Source: Dow Jones

Further readings:

Americas Petrogas Increases Interests in Argentina

Argentina: Major Shale Oil Strike for YPF

The amalgamation of hydraulic fracturing and horizontal drilling technologies in the 1980s enabled the US to become the pioneers of commercial shale gas production. Although the first shale gas well was drilled in 1821, the technical and economic feasibility of producing from deep-lying horizontally planed shale formations has inhibited their development. These two fundamental technologies have provided the key to unlocking this troublesome hydrocarbon, and the US has quietly gone about expanding the industry from the late 1980s onwards.

US shale gas production had crept up to 300 billion ft³ by 1996 and then more than tripled to 1.1 trillion ft³ by 2006. In 2010, according to the US Energy Information Administration, production of shale gas in 2010 stood at 4.9 trillion ft³. This expeditious expansion in US shale gas production in the 21^st Century has sparked enormous attraction from overseas nations looking to see whether they too have the resources and capabilities of producing shale gas on home soil.

The attractions of doing so are multifarious, but most importantly it reduces energy dependency on a resource that is expected to play an ever increasing role in the energy mix of nations. The recent turbulence in the Middle East, ongoing terrorist concerns post 2001, and political disputes with key producing nations have led to more concerted efforts by the US government to increase national oil & gas production.

For natural gas, there is also a growing fear that the Gas Exporting Countries Forum (GECF) will create a cartel similar to OPEC, allowing them to dictate future production levels and prices. The prospect of a gas cartel may put a dampener on the natural gas sector and projected growth in natural gas consumption over the coming years. Shale gas is thus a very real opportunity to circumnavigate any unfavourable future dependencies. And while a cartel in the short-term may be unlikely, simply the prospect of one will drive shale gas development.

According to the World Energy Council (WEC), there is approximately 16,110 trillion ft³ of global shale gas resources, of which around 40% is thought to be recoverable. These figures are, however, preliminary and with more extensive investment in exploration activity the recoverable reserve estimate is likely to expand.

Countries outside of North America that have already carried out exploratory activity into viable shale gas reserves include Australia, China, South Africa, New Zealand, the UK, France, Sweden, Germany, Poland, Hungary, Argentina, Ukraine, Algeria, Indonesia and India.

As it currently stands only the US and to a lesser extent Canada have managed to produce commercial levels of shale gas. But the mounting interest from nations and international companies, as well as mushrooming investment in exploratory drilling, is now palpable. All of the supermajors and many of the world’s largest oil & gas companies have made their first steps into large-scale shale gas projects – most of the US and Canadian production being conducted by local independent energy firms to date.

In China, the three largest energy companies – China National Petroleum Corporation (CNPC), Sinopec and China National Offshore Oil Corporation (CNOOC) – have all invested billions of dollars in North American shale gas projects, including CNPC’s $5.4bn joint venture deal with Canada’s Encana Corporation. Australian mining giant BHP Billiton also invested approximately $4.75bn in a deal with Chesapeake Energy for shale gas interests in the US, while France’s Total spent $2.25bn for 25% of Chesapeake’s shale plays.

The shale gas market has also seen the largest acquisition made by an energy company since the 2008 recession, with ExxonMobil acquiring shale gas specialists XTO Energy in a deal worth approximately $41bn. In a time when major acquisitions and investments have fallen across the oil & gas industry, shale gas projects have bucked the trend.

According to Visiongain, the global shale gas market is expected to grow at a strong rate from 2011-2021, with a gathering momentum towards the end of this time-frame. The US and Canada are both expected to increase production over the next decade, with the former looking to supply 26% of domestic gas consumption from shale gas by 2035. But it is in the fledgling national shale gas markets where the most significant growth will take place.

China is one nation which is looking to develop shale gas from national resources estimated to be around 1,000 trillion ft³. China’s Ministry of Land and Resources (MLR) has set a target for the country to locate 35 trillion ft³ of recoverable shale gas and to build 500 billion ft³ to 1.1 trillion ft³ of production capacity by 2020.

As previously noted, the three largest Chinese energy companies have made substantial investments in the US shale gas market, in the perceived interest of acquiring skills, experience and technical know-how to develop resources in China. IOCs such as Shell, Chevron Corp. and Statoil ASA have all either signed or have been linked with shale gas projects in China. Indeed, Shell’s Peter Voser recently claiming the company would invest $1bn per year over the next five years should appraisal wells prove to be producers.

Countries in the EU have also been attracted to developing untapped shale gas resources, with dwindling reserves in the North Sea and a growing reliance on natural gas imports from Russia and the Middle East. Drilling has begun in nations such as Poland, the Netherlands, the UK, Germany, France, Hungary, Sweden and Austria. The consensus among many experts is that it is too early to know with any certainty whether commercial shale gas production will be achieved within the coming ten years. However, Visiongain forecasts a significant increase in investment in exploratory and appraisal drilling in this time-frame, with commercial production achieved in Poland and to a lesser degree in the other EU states mentioned above.

Other national shale gas markets that are forecasted to expand rapidly over the next ten years are the Indian, Australian and Argentinean markets. In India there have been talks by government members with the US Geological Survey (USGS) over the development of Indian shale gas, while the largest energy firm, Reliance Industries Limited, has invested over $3bn on acquisitions in the US shale gas market. Shale gas acreages are expected to be auctioned in India in August 2011.

Australia is on the cusp of realising shale gas production from the highly prospective Cooper Basin, where companies have recorded positive appraisal tests – local firm Beach Energy declaring commercial production would commence in 2015. The country is also keen to develop its LNG industry to enable it to export natural gas to the vast and expanding Asian market.

In Argentina, there are numerous basins believed to hold commercial levels of shale gas, with local energy company YPF (part of Repsol-YPF) claiming that a single deposit in the Loma de la Lata in the Neuquén Province of Patagonia may hold as much as 257 trillion ft³. The company has chalked up 11,412 exploratory wells for drilling over the forthcoming years, and has recently signed a $140m contract with Brazil’s Vale SA to develop 4.5 trillion ft³ of reserves encountered at a discovery in the Neuquén basin. France’s Total has also acquired four six-year shale licenses in partnership with YPF, as well as 85% of two additional Neuquén shale blocks.

Visiongain also forecasts strong growth in the Ukrainian shale gas market, which has been identified by US supermajor ExxonMobil as having high potential, with an MoU signed with local Naftogaz to explore for shale gas deposits in the nation. According to the Deputy Director of the Ukrainian Department of Technology Policy at the National Agency of Effective use of Energy Resources, Aleksandr Semchenko, Ukraine has between 2-32 trillion m³ (70-1,130 trillion ft³) of recoverable shale gas reserves.

In June 2010, Deputy Prime Minister Adrey Klyuyev stated that Ukraine planned to double natural gas production to 1.4 trillion ft³ per year, with a large percentage of this coming from unconventional coalbed methane and shale gas. According to the national bank company Nadra Ukraine, the nation has the largest shale gas reserves in Europe.

It is clear, therefore, that while the oil & gas industry has distanced itself from achieving large-scale production in nations outside of North America over the coming ten years, some in fact may achieve this inside this time-frame, and potentially within five years. The booming levels of investment in exploration and appraisal activity will ensure market growth over the next ten years is strong, and providing wellhead natural gas prices can climb to around the $6 per million Btu mark, production will be sought more rapidly than has been predicted.

There have also been fears raised in media over the safety of using hydraulic fracturing, despite over 50 years of the technology being used across the US. A recent report by Robert Howarth from Cornell University in the US has also suggested that shale gas has a far more harmful impact on the environment as methane is a considerably more powerful greenhouse gas, with a footprint of around 20% greater than coal. However, if the industry can, as it should, prove that both fears are overstated if not inaccurate, then shale gas development will abound unaffected.

Natural gas prices will of course play a major role in the direction of the shale gas market, as will natural gas consumption levels and public sector involvement. However, the signs all lead to first commercial shale gas production from nations outside of North America within ten years. To what degree is the only question.

The Shale Gas Market 2011-2021 report is published by Visiongain, an independent business intelligence provider for the Telecoms, Pharmaceutical, Defence, Aviation, Energy and Materials industries.

The Shale Gas Market 2011-2021 provides a comprehensive analysis of the global shale gas market and addresses evolving opportunities and risks. More information on The Shale Gas Market 2011-2021, including a download sample, can be found HERE

He noted that the Haynesville and Marcellus were also very significant.

“In 2013, shale gas will make up 34% of gas production,” he said.

The biggest deal activity, according to Rathan, was in the Fayetteville in 2008. He said the Marcellus had peaked from a deal perspective in 2009: “That’s when we entered the marketplace providing strategic advice. This year we feel there will be a lot of activity in the Niobrara.”

He added, “We prioritize them according to the peak level of interest for our clients.’

Rathan said that in developing production of shales, there were two parts: 1) the nature part, which concerned the quality of the shale, and 2) the nurture part, which was all about applying technology to make them produce, “In applying lessons, understanding the geology, interpreting the logs and understanding the surface aspects of developing the shale play.”

His slide told that it was about “Maximizing the right characteristics,” namely, depth, thickness, porosity, TOCs, the pressure regime, etc. “These describe the natural aspects of the play,” he explained “and ultimately you move to certain areas of that play.”

Mr. Rathan spoke about joint venture activity in the Marcellus, including players like Total SA, BG Group and Statoil ASA. “The Canadians came a little later,” he recalled, “and more recently there has been Japanese and Chinese interest. Following them are the BRIC countries.”

He said that in the last six months Tudor Pickering Holt & Co had been very involved in a transactions in the Niobrara and Eagle Ford shale plays involving top Chinese offshore oil producer CNOOC Ltd and Chesapeake Energy Corp.

“They asked us to help them with the technical analysis and the ultimate deal structuring,” he explained. “Working with the Chinese one has an expectation that working with Asian countries can be a lengthy process, but these moved extremely quickly and that’s a critical requirement. In the Niobrara we conducted it on the basis of only two wells in the Powder River basin.”

According to Rathan, the attraction into the US shale plays was also from the perspective of the economics, not just from a learning perspective.

“We believe that the long term gas price will be $6 – the short term price ($4) is not realistic, for shale plays to provide attractive rates of return.”

He said activity was moving to more economic plays. “The sustainable gas price is about the midpoint of his chart,” Rathan showed. “That ultimately is where we expect the gas price to come back to. The shale plays is a good place for the operators to be.”

He noted the move into liquid rich plays. “In oily areas the rates of return are 50-100%. They are cropping up all over the country, signalling a big shift in activity.”

“The emerging plays, particularly the oily ones, have been rising with the rig count and companies are aggressively shifting their capital there. So the activity is shifting to the west, in places like the Niobrara and the Bakken. It’s just applying the same technologies,” he said.

Rathan discussed the value evolution of land acreage at places like Niobrara and emerging oil plays.

“You can’t sell these assets until you have plenty of science, plenty of logs of fracture stimulation,” he explained, “knowing how far out the fractures go. Seismic is extremely important information to build a position, and there’s constant evolution and learnings in this area.”

He explained that the Barnett shale provided a laboratory of sorts for learning. “We realized it wasn’t all equal,” he said of the shale. “A partner purchased the wrong acreage in the Barnett. We try to understand immediately where the sweet spots area.”

From an operational perspective, Rathan spoke of drilling in an urban environment. He showed a photograph of drilling being done right in a university at Fort Worth, saying it was doable via long laterals closely spaced, maximizing an area. He also spoke of stacked pad drilling.

He emphasized the importance of seismic for certain shale plays, like in the Barnett for avoiding the viola limestone in the Barnett, or skirting natural faults.

“Coupled with that is the application of microseismic to understand where we’re stimulating and where we’re not,” said Rathan. “It helps with the drainage area, therefore with spacing and completion optimization.”

He said that minimization of the surface footprint was receiving a lot of attention.

“Enormous quantities of proppant and water volume are required, he explained.

“You can gain a lot of resource out of one location, drilling 3000 foot laterals and achieving enormous quantities of resource from one location. The aim is stimulating as much rock volume as possible via the spacing of frack events.”

He continued: “Engineers are modifying the number of frack stages, and more proppant can lead to higher recovery. As we get longer laterals we get more stages and should get higher EURs. We think we can get a million barrels on a per well basis.”

Rathan posed the question whether too much money was being spent on completions. “It’s not a blind process doing more things,” he answered. “It’s doing things smarter.”

“The type of fluid you use can impact the kind of stimulation you have. We’re finding that a hybrid fluid treatment can give us the best of both worlds.”

Rathan offered up a “Top Ten List” of the factors that had made US shales a success.

“It began with identifying organic rich foreland sedimentary basins –understanding them was one of the first requirements,” he said. “It took decades of legacy vertical well drilling. Vertical well activity in the Barnett led to cracking the code.

Among others, he said that accessible and accommodating land owners were key, as well as a pragmatic and transparent regulatory environment, scientific advances in formation analysis, an investment climate attracted to energy, a declining domestic gas supply and high gas prices, advances in horizontal drilling, and isolated mult-stage fracking.

He said that so much had been learned in North America about this process.

In terms of land he offered advice: “Move early and gather both a contiguous and diverse position, to ensure you don’t miss a sweet spot.”

In terms of regulatory issues, he said: “Focus on areas with oil friendly regulatory regimes. Poland is going to be like the Oklahoma or Texas of the US. Once you’re there you should communicate, be transparent, having town halls and making the economic case.

“US O&Gs need to make their case much more forcefully,” added Rathan.

“Don’t skimp on science,” he said of technical issues. “Get cores, shale petrophysics, etc.”

“From a capital perspective, have a good balance sheet,” he encouraged. “Understand how to fund your company in an appropriate way through the debt markets, equity, non core asset sales, and through joint ventures to develop the plays and stay strong.”

In terms of operations, Rathan emphasized being flexible. “Rig mobility is important in the US, from the less competitive gas plays to the more, and now to the liquid rich plays. The ability of companies to move their operations around is important and we hope that in Europe there won’t be certification boundaries.”