But there are challenges to get the gas out of the ground. First, Argentina’s shortage of water may stand in the way of accessing natural gas reserves. Each well drilled to extract shale gas uses up to 6 million gallons of water per day, and experts say it will take 38 billion gallons of water to capture natural gas trapped underneath the Vaca Muerta, or “Dead Cow” basin.

Another challenge is the government’s oil and gas pricing regime, which has been a major disincentive to investment in recent years. Heavy regulations hold prices down to $2.00-$2.50 per cubic foot of regulated gas — nowhere near the breakeven price needed to make development worthwhile. Argentina has set up a two-tier system under its “Gas Plus” program — allowing gas produced by new investment to be sold at much higher prices – in some cases more than double the rate in the domestic market. This has brought in more than a billion dollars from the likes of Exxon, AES and Apache. But these differential prices show how transitory Argentine rules can be. To attract the huge amounts of capital needed to truly develop these gas finds in the coming years, the Argentine government will have to convince investors that the rules won’t change with the political winds.

If this happens, it will transform regional gas markets. Bolivia will be the biggest loser. As the region’s current top energy provider, its economy today depends on fueling neighboring Argentina and Brazil. By developing its own gas reserves, Argentina takes away not just a vital customer but also potential foreign direct investment – leaving Bolivia’s economic development model in jeopardy.

Another — much more indirect — loser is Mexico. The fact that investors are more interested in Argentina — known for playing fast and loose with property rights and contracts — than in Mexico, which is ranked Latin America’s most business friendly economy, shows how hamstrung Mexico’s energy sector remains. Without further changes to the system to open up outside funding for exploration and production projects, Mexico risks becoming a spectator on the energy sidelines, with huge ramifications for its overall economy as a result.

This post by Shannon K. O’Neil originally appeared on The Council on Foreign Relations

“We think the market dynamics are set up to where you can potentially get good value, so we will continue to look,” XTO Energy President Jack Williams said. He was talking at the Reuters Global Energy and Climate Summit.

Exxon acquired XTO Energy for $30 billion by assuming that natural gas demand will rise in coming years as electricity consumption increases. Exxon also made an acquisition of Phillips Resources and TWP Inc. for a purchase price of $1.69 billion.

In addition, Williams said the company owns some drilling rigs for oil and NGLs in the Eagle Ford Shale and the Permian Basin. “We’ll continue to look at liquids plays but we’re not running from gas plays either,” Williams noted.

Source: Reuters

ExxonMobil, Royal Dutch Shell and now BG Group have been arguing that significant changes are afoot in the unglamorous world of natural gas that could have a big impact on patterns of energy consumption, carbon dioxide emissions and the balance of power in volatile energy markets.

The big driver of this shift is supply. Energy companies have done a remarkable job in recent years of finding vast quantities of natural gas, possibly adding more than a hundred years of supply of the fuel.

To read the entire article, visit The Wall Street Journal Online.

“We will continue to evaluate acquisitions,” Mark Albers, senior vice president for Exxon, told the Goldman Sachs Global Energy Conference.

Since its purcase of XTO, Exxon has added more unconventional acreage — or acreage where technology like hydraulic fracturing is required to extract oil and gas — to its portfolio.

Last month, Exxon paid $650 million to buy natural gas assets in the Fayetteville shale in Arkansas from Petrohawk Energy Corp. (HK.N:Quote)

Shares of Exxon were up 69 cents, or nearly 1 percent, at $76.38 in afternoon trading on the New York Stock Exchange.

Source: Reporting by Anna Driver in Houston, editing by Matthew Lewis, Reuters

Petrohawk shares were down 2 percent at $18.26 in midday trade on Thursday on the New York Stock Exchange, having touched a low of $18.02 earlier in the day.

This is the last of the four asset-packet divestitures that Houston-based Petrohawk had planned for the year.

The company had sold its stake in its Haynesville midstream operations to Kinder Morgan Energy Partners (KMP.N) for $875 million in April and said it would reduce its rig count in the “gassy” Haynesville and double it in the liquid-focused Eagle Ford shale in Texas.

And in March it had sold assets in Louisiana and Oklahoma for combined proceeds of about $475 million.

Oil prices are up over 23 percent year-to-date but gas prices are down about 30 percent, pushing U.S. exploration and production firms to shift dollars to acreage with crude oil or natural gas with a high liquids content.

The company said it will sell its Fayetteville upstream assets for $575 million and midstream assets for $75 million.

Jefferies and Co analyst Subash Chandra said in a note that the Fayetteville sale was below his expectations, adding he expected $650 million for the upstream assets and $300 million for midstream.

Chandra, however, said the company will not face problems with funding its capital needs till the end of 2011. In November, Petrohawk set its 2011 capital budget at about $2.3 billion.

Wells Fargo Securities analyst Michael Hall said the deal value was below his expectations, but viewed it as a positive in terms of funding.

The sale values the assets’ proved reserves at $1.92 per thousand cubic feet equivalent, according to brokerage firms Global Hunter Securities and Tudor Pickering Holt.

This is about 32 percent lower than what Exxon Mobil was estimated to have paid for XTO, which it acquired in December last year.

Petrohawk estimates Fayetteville upstream proved reserves of about 299 billion cubic feet equivalent as of December 31, 2009, and current production of 98 million cubic feet equivalent per day.

Bank of America Merrill Lynch acted as financial adviser to Petrohawk for both transactions.

Source: Reuters

This follows the announcement of the commencement of drilling of the country’s first shale gas well.

Profit petroleum is a part of the revenue earned by the exploration company when it sells oil or gas. Proposed to be called shale gas payment as opposed to profit petroleum, this revenue will be shared between the centre and the state.

This new policy is being scripted to get proactive support from state governments in this new field of energy that is set to be a game changer. The profit share will be over and above the royalty that state government would earn from the oil company, a senior official at the Director General of Hydrocarbon’s office said.

DGH, a technical arm of the oil ministry, is directly involved with the policies on oil and gas exploration. It would be essential to get the state governments as a partner in the development of shale gas as this new unconventional gas involves exploration over large areas.

The profit share for the state would incentivise states to help with the land acquisition as it is under the direct jurisdiction of the state governments. It is expected that the resource-rich states would invest these revenues in the development of the region to avoid conflicts with local populace such as agitation against bauxite mining in Niyamgiri, the official who is working on the policy said.

Shale gas is non-conventional natural gas found in non-porous rock and requires fracing technology to extract gas from shale. Global majors like Exxon, Chesapeake, Devon and Pioneer are the market leaders in shale gas. India’s Reliance Industries has taken a lead in this new source of energy by acquiring stakes and forming joint ventures with shale gas companies in the US.

Petroleum secretary S Sundareshan confirmed that the government is framing new profit-sharing rules for shale gas production.“Quality of investments in shale gas (exploration and production) is different. We will consider international practices before framing profit sharing mechanism for it,” Mr Sundareshan told ET.

The government plans to invite bids for shale gas exploration by 2011-12, he said. India has huge shale deposits in Assam, Gujarat, Rajasthan, the Gangetic plain, the Cambay basin and the Gondwana basin.

This comes at a time when the first well for producing shale gas has been drilled by the national oil company ONGC. “The first (shale gas) well was drilled at Ichapur near Durgapur in Damodar valley on Tuesday,” ONGC chairman & managing director RS Sharma said.

The well is targeted to a depth of 2,000 mts and will be assessing the shale gas potential of about 700 mts thick shale. The contract has been awarded to Schlumberger and the results of this well is expected by October 30, 2010. ONGC has undertaken a Rs 128-crore pilot project for exploration of shale gas in the Damodar basin in Jharkhand and plans to drill three wells by March 31, 2012.

The new profit sharing norms is particularly being designed for shale gas exploration companies as this unconventional gas production requires wells to be drilled over large acerages in a much quicker time frame. In the US and Canada, where shale gas production has emerged as a game changer accounting for almost 17% of the gas consumption in the US, energy companies have acquired large tracts of land to take up shale gas production.

Unlike the conventional natural gas production process, where fewer wells are drilled and the volume of gas from each is much higher, shale gas wells have small volumes where almost 80% of the production of gas is done within the first year. “Its a volume game and the developer has to have a mindset of a manufacturer, “ R S Butola, managing director of ONGC Videsh said.

Source: Economic Times

Range Resources CEO John Pinkerton said in an interview yesterday his company may be a partner or target for oil companies, like Apache Corp. and Occidental Petroleum Corp., seeking to expand shale holdings in North America.

Exxon said last month it would buy XTO Energy Inc., a Fort Worth, Texas-based gas producer, for about $37 billion in stock and debt. Petroleum companies are “clearly sniffing around,” said Pinkerton, who declined to identify companies that have approached him.
Oil companies, previously focused overseas, are now “seeing that natural gas is half the carbon footprint of coal, it’s a third cleaner than oil, and now you’ve got these gigantic shale plays in the U.S.,” said Pinkerton.

Natural gas produces less carbon dioxide, the heat-trapping gas blamed for accelerating global warming, than crude oil or coal, according to the U.S. Environmental Protection Agency. Shale gas is produced from rock formations using water, sand and chemicals.
Range Resources, based in Fort Worth, Texas, holds 1.4 million acres of leases for the Marcellus Shale, a formation that may hold 20 years’ worth of U.S. gas supplies. Improvements in shale-gas extraction technologies have helped U.S. gas reserves reach a record 1,836 trillion cubic feet, according to the Potential Gas Committee.
Shell, based in The Hague, wants Marcellus Shale acreage, said David Todd, onshore asset manager for the company’s U.S. unit.

‘Very Interested’

“We currently are very interested in the Marcellus and are looking for an entry,” Todd said in June at the Bentek Energy Market Fundamentals Symposium in Houston. “We do not have a sizeable position.”

Total SA, Europe’s third-largest oil company, agreed this month to pay as much as $2.25 billion for a 25 percent stake in Chesapeake Energy Corp.’s Marcellus fields. Chesapeake Energy, based in Oklahoma City, has raised $10.8 billion in the past two years by selling joint-venture interests in its shale-gas properties.
Partnerships may be more common than takeovers because they cost less, Range Resources’ Pinkerton said.

“The idea that you’re going to have a rash of these is a little bit naïve,” Pinkerton said. “There aren’t many Exxons and there aren’t many XTOs.”
Range Resources, which increased gas output for 27 straight quarters, has its most promising holdings in the Marcellus Shale with its leases in Pennsylvania, Pinkerton said.

Breaking Even

Wells in the Marcellus Shale break even with gas prices at $3.19 per million British thermal units, the third-cheapest break-even rate among the most productive U.S. gas fields, Bentek Energy LLC Chief Executive Officer Porter Bennett said at an investor conference in New York this month.

The Marcellus probably will yield 489.2 trillion cubic feet of gas, equivalent to a 20-year supply for the U.S., Terry Engelder, a Pennsylvania State University geologist, said in an Oct. 21 interview. Chesapeake Energy, holder of 1.5 million Marcellus acres, predicted last year it will be the largest U.S. gas field.
Gas stocks are less expensive because the price of crude oil on commodities markets is 58 percent higher than natural gas based on the amount of energy each can produce, Pinkerton said.

Oil, Gas Prices

Crude oil futures fell 3 cents to $73.64 a barrel yesterday on the New York Mercantile Exchange. An energy-equivalent price for gas would be $12.27 per million British thermal units. Natural gas fell yesterday 14 cents to $5.14 per million British thermal units.

Exxon affirmed the economy and productivity of shale-gas wells by paying a 25 percent premium to XTO’s previous closing price, Pinkerton said. Devon, based in Oklahoma City, is selling as much as $7.5 billion of offshore and overseas assets this year to cut debt and focus on U.S. shale-gas production. “We had an opportunity to get into the Marcellus in a big way a couple of years ago,” Devon President John Richels said in response to a question during in a Nov. 18 conference call. “Maybe it was a mistake, but we chose not to.”

Devon spokesman Chip Minty and Occidental spokesman Richard Kline said yesterday the companies don’t comment on merger speculation.

By Jim Polson BUSINESS WEEK

Of DOW JONES NEWSWIRES

HOUSTON (Dow Jones)–Exxon Mobil Corp.’s (XOM) $31 billion bid for XTO Energy Inc. (XTO) marks the biggest endorsement yet for the exploitation of unconventional natural gas resources–and signals a growing will to carry the expertise that has revolutionized gas production beyond the North American gas market.

In a statement released Monday, Exxon Chief Executive Rex Tillerson said that the deal would benefit consumers “here and around the world,” and help the company develop natural gas and oil resources globally. Exxon, the world’s largest publicly traded oil company, has recently scooped up unconventional gas assets in Poland, Germany, Hungary and Argentina. If brought online, these resources could help feed major markets that currently face unsteady supplies.

Exxon plans to manage its global development of unconventional gas resources from XTO’s Fort Worth offices. But overseas exploitation of shale reserves face challenges not found in Texas, Oklahoma or Louisiana, where an extensive network of service companies has helped small independent natural-gas producers drill intensively in the hard-to-crack rock formations that trap the unconventional gas. Also, the geology of overseas shale plays isn’t understood as well as the U.S. rock formations, and obtaining mineral rights in foreign countries can be more difficult, said Robert Clarke, manager of unconventional gas services for the energy consultancy Wood Mackenzie.

Still, overseas markets present opportunities for potential new gas supplies. “There is vast resource potential abroad and those resources would serve undersupplied local markets,” Clarke said.

Big Oil is having an easier time accessing shale and other unconventional plays than conventional oil resources–where they have to fight off zealous governments and national oil companies.

Until recently, major oil companies have been reluctant to take big bets on shales because they are relatively new areas of exploration that require intensive drilling. It was mostly aggressive, independent natural-gas producers that learned to drill horizontal wells into tight rock formations and crack them with a high pressure solution of water and sand, releasing the gas trapped within.

But in the past two years several international oil companies have been kicking the technology’s tires. Statoil ASA (STO, STL.OS), BP PLC (BP, BP.LN) and ENI SpA (E, ENI.MI) have struck deals that give them a foothold in U.S. shale plays.

“Every major oil company is thinking about getting into these shale plays both in the U.S. and globally, the question is how,” said David Rockecharlie, co-head of the energy investment banking group for Jefferies & Co Inc. Barclays Capital and Jefferies advised XTO on the transaction.