The study predicts that domestic Chinese unconventional production will account for over a quarter of total gas supply by 2030. However, unconventional gas resources will take a significant time to develop. Therefore, meeting its gas demand will require China to import significant additional volumes of LNG and piped gas, particularly up to 2020.

“Development of indigenous unconventional gas is currently slow but we forecast significant volumes of coalbed methane, coal-based synthetic gas and shale gas to enter the market, reaching over 11 billion cubic feet per day by 2030. This will meet much of China’s incremental demand by this time. In total, unconventionals will account for over a quarter of total gas supply,” said Gavin Thompson, China gas study director for Wood Mackenzie.

Shale gas is the major growth story in China gas, he added. As China’s national oil companies increase their unconventional gas activity, they will look for partnership and technology in the initial phase of development, creating a window of opportunity for qualified foreign players. This is a near-term window of opportunity for international oil companies to gain access to China’s onshore acreage and to leverage skills honed in North America.

During the second quarter Encana Corporation announced it had signed a memorandum of understanding with China National Petroleum Corporation that outlines a framework for the two companies to negotiate a potential joint-venture investment in the development of certain lands in Encana’s natural gas plays in Horn River, Greater Sierra and Cutbank Ridge in northeast British Columbia.

While domestic Chinese conventional gas supply will continue to grow, Wood Mackenzie says it cannot keep pace with future demand in the current decade and China will need to secure significant additional volumes of imported gas in the form of both LNG and piped gas.

“China’s demand for LNG is driving Pacific LNG market growth. We now forecast China LNG demand in 2020 to be 46 million tons per annum, up from our previous forecast of 31 million tons per year. This will expand the opportunity for LNG suppliers seeking to secure markets, particularly those in Australasia. However, China’s LNG import growth will be mitigated by the emergence of indigenous unconventional gas. Consequently there will be a limited opportunity for some LNG suppliers to secure long term supply or risk seeing China disappear as a potential foundation buyer for their projects,” Thompson said.

China’s gas demand is forecast to rise from nine bcf per day in 2009 to 43 bcf a day in 2030, a compound annual growth rate of 7.5%, with strongest growth pre-2020. This strong demand growth, says Wood Mackenzie, will not purely be driven by gross domestic product (GDP).

“Demand is driven by a combination of factors, including policies to reduce the country’s growing reliance on oil imports. This is important as the gas demand story is about displacing oil products, not coal, in the industrial and residential sectors. Coal continues to dominate in power, although gas will increase its market share in wealthier coastal provinces as local government supports a cleaner fuel mix. As such, we think that industry will remain the largest gas consumer in China through to 2030,” Thompson said.

The study concludes that potential suppliers of gas to China need to rapidly engage with domestic buyers and secure contracts while the market is still available as longer term unconventional gas will constrain requirements for new LNG imports.

You probably have never heard of oilman George Mitchell, but more than anyone else, he has changed the global energy outlook.

In 1981, Mitchell’s small petroleum company faced dwindling natural-gas reserves. He proposed a radical idea: drill deeper in the company’s Texas fields to reach gas-bearing shale rock more than a mile down. Because the gas was tightly packed, most engineers believed it was too costly to extract profitably. But after nearly two decades of trying, Mitchell proved doubters wrong. The result: The world has far more available natural gas than anyone suspected.

The BP oil spill cast a cloud over almost all energy news. Well, shale gas is good news.

Until recently, scarce U.S. natural-gas reserves suggested increasing dependence on expensive foreign supplies of liquefied natural gas. No more. Next, natural gas emits about 50 percent less carbon dioxide, the major greenhouse gas, than coal. Substituting gas for coal in electricity plants could temper emissions. Finally, shale gas in Europe and Asia has huge geopolitical implications. It could reduce dependence on Russian natural gas and frustrate any gas cartel mimicking OPEC.

The Potential Gas Committee is a group of geologists who regularly estimate future U.S. gas supplies. In 2000, the group’s estimate equaled about 54 years of present annual consumption; by 2008, it was almost 90 years. “This isn’t the end,” says Colorado School of Mines geologist John Curtis. Globally, one study estimated the recoverable supply at 16,200 trillion cubic feet, more than 150 times today’s annual world gas use.

Natural gas provides about a quarter of U.S. energy use: for home heating, electricity generation and factories. This will probably increase, but the emerging shale boom faces two problems. The first is hype.

Shale gas has many virtues, but gains will come at the margin. It isn’t a panacea for every ailment.

Consider the impact on oil imports. In theory, natural gas – compressed or converted into a liquid – could replace oil in some vehicles. But natural gas now fuels only about 120,000 of roughly 250 million U.S. cars, vans, trucks and buses. At today’s prices, natural gas is competitive with oil, but there’s a chicken-and-egg problem: Drivers won’t use it without filling stations; companies won’t build stations without drivers.

So fuel switching will likely focus on heavy-duty trucks with regular routes that require few stations. If 500,000 heavy-duty trucks changed to natural gas, oil consumption would drop almost half a million barrels a day, estimates Michael Eaves of Clean Energy, a builder of natural-gas filling stations. That’s about 5 percent of U.S. imports. The impact is large because trucks travel about 100,000 miles a year and get only about 5 miles to a gallon, says Eaves.

Similar qualifications apply to the substitution of natural gas for coal in electricity generation.

The potential seems enormous, because many gas-generating units are underutilized. But practical problems intrude. Coal is the low-cost fuel; coal-fired and gas-fired plants often serve different markets. On balance, present gas-fired plants might reduce coal-fired electricity by 5 percent to 9 percent, a Congressional Research Service study estimated. Future gas plants might expand this.

The second threat is overregulation. Environmentalists are split. Some favor shale gas as a “bridge fuel” until non-carbon energy expands. Others argue gas drilling will threaten drinking water supplies; that was a theme of Gasland, a film shown on HBO. The charges seem overblown. As the BP spill reaffirmed, all drilling requires regulation. There are environmental issues. But onshore drilling has proceeded for decades without polluting water supplies. In shale gas, thousands of feet typically separate shale deposits from water tables.

George Mitchell’s persistence made shale gas a huge geological gift. Only fools would discard it.

Robert J. Samuelson writes for Newsweek and the Washington Post Writers Group.

Source: Columbus Dispatch

“We plan to further increase activity in the Haynesville, Fayetteville, Marcellus, Eagle Ford, and Bakken shale plays,” said ExxonMobil’s Vice President of Investors Relations David Rosenthal, who was speaking to analysts in a conference call.

ExxonMobil completed its acquisition of natural gas producer XTO Energy Inc. in June, becoming the largest natural gas producer in the U.S.

Apache will acquire assets in Alberta and British Columbia producing 240 million cubic feet of gas and 6,500 barrels of gas liquids a day.

Earlier in the day, BP said it would sell $1.7 billion worth of assets in Vietnam and Pakistan.

Apache increases it Canadian presence: it is partners with Encana Corp in the Horn River shale gas play in northern British Columbia and has an interest in a planned LNG liquefaction project on the Pacific Coast.

Earlier this year Apache acquired Mariner Energy Inc. and Devon Energy Corp’s shallow water drilling assets in the Gulf of Mexico

Once complete, the coal and natural gas company said it will take a leading position in the strategic Marcellus Shale, a rock bed the size of Greece that lies about 6,000 feet beneath New York, Pennsylvania, West Virginia and Ohio. It is potentially the country’s most productive natural gas source.

Consol, which is based in Canonsburg, Pa., near Pittsburgh, also said its natural gas business is expected to account for as much as 35 percent of the company’s total revenue. It needs to raise about $4 billion to fund the acquisition and is targeting a mix of equity and debt, the company said.

The transaction, subject to regulatory approvals, is expected to close by April 30.

Consol shares fell $4.21, or 7.8 percent, to $50.13 in morning trading. Dominion shares rose 25 cents to $30.94 after touching a 52-week high of $40.29 earlier in the session.

Dominion’s exploration and production business is one of the oldest and most active drillers in Pennsylvania and West Virginia. Dominion is based in Richmond, Va.

Consol will acquire a total of 1.46 million oil and gas acres from Dominion along with over 9,000 producing wells, the company said.

The acquisition is a “strategically compelling transaction” that will transform Consol into a “leading diversified energy company with a strong position in natural gas as well as coal,” CEO J. Brett Harvey said in a news release.

Consol, which has operations in West Virginia, Virginia, Kentucky, Pennsylvania and Utah, has responded to tougher environmental regulations of coal mining by expanding its gas business. At the start of the year, Harvey told Wall Street that he considered mining a cash cow that would be tapped to fund increased production from CNX Gas. Consol owns more than 83 percent of CNX, which already has a sizable stake in the Marcellus shale as well as coalbed methane wells in Virginia.

“The investments in coal operations are primarily in the efficiency area to maintain our position as a low cost producer,” Chief Financial Officer Bill Lyons said during the company’s earnings conference call in January. “The investments in the gas company are focused on growth with emphasis on expanding our Marcellus Shale acreage position, increasing drilling, and increasing production.”

By The Associated Press. March 16, 2010

SOURCE:
Don At Dawn: Consol Energy Buys Into Northeastern Shale Gas Play For $3.5B”

Virtually every deal that big oil has cut in recent months focused on resources of this type. ExxonMobil agreed in December to pay around $30 billion for XTO Energy, which specializes in extracting gas trapped in shale rock in the U.S. France’s Total agreed in January to acquire a quarter of Chesapeake Energy’s huge shale gas resource in Texas for $2.25 billion. Last week, BP cut a much smaller deal with Lewis Energy for half of its Texas shale territory.

In the latest deal, announced yesterday, Royal Dutch Shell and Petrochina have jointly offered A$3.26 billion for Arrow Energy, a producer of natural gas from coal seams in Australia.

There are several good reasons for this to be happening.

A big increase in unconventional gas production is likely to be a “game-changer”, according to BP Chief Executive Tony Hayward. The U.S. shale gas boom has already dramatically altered the energy supply picture for North America, cutting the need for domestic gas imports, driving a surplus of sea borne liquefied natural gas cargoes to Europe and weakening the dominance of Europe’s largest gas supplier, Russia’s Gazprom. The major oil companies don’t want to be sitting on the sidelines as this dramatic change sweeps through energy markets creating new opportunities.

Secondly, a big increase in natural gas supplies, which are less carbon intensive than oil and coal, could provide big oil a vital bridge to a low carbon future. The growing likelihood of ever-tighter emissions caps in the developed world will make carbon-intensive parts of their businesses, such as oil refining or tar sands, less competitive. This threat could be offset by increasing their gas output. Natural gas already makes up just over half the hydrocarbon production of Shell and other companies are moving in the same direction.

Third, the method of producing these reserves plays to the strengths of major oil companies. Releasing gas trapped in shale rock or coal seams requires the drilling of thousands of wells, the management of large water resources and constant incremental improvements in technology and economies of scale to maintain competitiveness. This is the kind of thing that modern oil companies excel at.

Finally, unconventional gas is one of the few new resources that is actually open to the major oil companies. They are largely shut out of the greatest prizes in the Middle East and have missed the boat in up and coming oil provinces like offshore Brazil or Ghana. The largest unconventional gas resources are located in areas that are open for business–North America, Australia and possibly Latin American and Europe. They may be less profitable than a big new oil discovery, but nevertheless are tempting targets for companies struggling to maintain their resource base.

This shopping spree may just be getting going.

By James Herron for The Wall Street Journal. March 9, 2010.

SOURCE:
The Wall Street Journal: “The Natural Gas Shopping Spree Quickens”

Recent changes in reserve reporting rules mandated by the Securities and Exchange Commission enabled Carrizo to book an additional 47.4 Bcfe of proved reserves in the Barnett Shale at year-end 2009, most of which were proved undeveloped.

Carrizo’s Barnett Shale reserves were 137.6 Bcfe at year-end 2009, up 32% from year-end 2008. Proved developed reserves increased 39% to 86.2 Bcfe.

Carrizo holds 56,000 net acres in the Barnett Shale, and had 33 net horizontal wells drilled and awaiting completion or pipeline connection there at year-end 2009. The independent also recently entered a $16 million joint venture in the play with Japan’s Sumitomo.

“We view Sumitomo as a strong partner that will permit us to opportunistically accelerate drilling in our core Barnett Shale development area,” Chip Johnson, chief executive of Carrizo said in December (OD Dec.16,p6).

Carrizo also has a two-year old partnership in place with private equity firm Avista Capital Partners in the emerging Marcellus Shale, where it has yet to see first production. Carrizo holds 108,000 net acres in the Marcellus.

The Houston-based independent also holds acreage in the Fayetteville Shale in Arkansas, and the Texas and Louisiana Gulf Coast regions, along with prospective positions in the Marfa Basin and the Floyd and New Albany shales.

Carrizo said it replaced 400% of its production in 2009 and ended the year with total proved reserves of 601.9 Bcfe, 20% higher than year-earlier levels.

“We had an excellent operational year in net reserve additions despite our reduced drilling program and the impact of lower prices,” said Chief Operating Officer Brad Fisher.

Fourth-quarter production rose 20% from the year-earlier period to 8.7 Bcfe (94.4 MMcfe/d), while full-year production increased 28.9% to 33.0 Bcfe (90.5 MMcfe/d). Natural gas made up about 97% of production volumes.

Carrizo has also set a 2010 capital spending budget of $170 million. Of this, $130 million (76%) will fund drilling and completion activities in the Barnett Shale, $31 million will be spent on the Marcellus Shale, and the remaining $9 million will be invested in other areas.

By Rachael Seeley for Energy Intelligence. March 4, 2010.

SOURCE:
Energy Intel

The oilfield services industry is a difficult one in which to strategize. The usual business cycle follows oil prices, with high prices encouraging investment in exploration and production (E&P), which in turn stimulates demand for services. The rise was so sharp leading up to July 2008′s record prices that demand tested supply capacity and exposed a skill shortage in the industry. Conversely, the low prices witnessed at the beginning of 2009 discouraged E&P activity, leading to service cost discounts of 65-80% on 2008 levels.

However, in acquiring a new portfolio of skills, Schlumberger and Baker Hughes may have found an alternative to this routine. The natural gas market is seeing major growth, driven by environmental concerns over coal and low gas extraction costs. These lower costs have come as hydraulic fracturing technology or ‘fracking’ has matured and opened up shale reserves to exploitation.

The rapid growth in shale gas extraction in the US is likely to alter the country’s energy profile entirely. Crucially, large oil and gas companies are investing heavily in shale gas E&P and in companies with knowledge of the sector, evidenced by ExxonMobil‘s acquisition of XTO. The potential demand for service companies qualified to operate in this market is vast and may offer a way to hedge their exposure to weak demand in the oil sector.

Schlumberger’s $11 billion bid for Smith International and Baker Hughes’ $5.5 billion acquisition of BJ Services were driven by demand for turn-key contracts under which the service company provides every service required to develop a field. This is especially difficult in an industry as new as shale gas, as skilled engineers with knowledge about fracking are in short supply. Coupled with the industry’s aging workforce, other service companies may struggle to enter this market.

In light of these market conditions, both acquisitions make sense. Although it is the service market leader, Schlumberger lacks expertise in lubricants (which are important to shale gas extraction), making Smith, with its specialization in lubricants, a valuable asset. Smith also has drill bit technology, which is crucial for meeting Schlumberger’s ambition to serve the growing demand for other unconventional forms of extraction such as deepwater drilling.

Similarly, Baker Hughes now has a much stronger portfolio, having acquired BJ Services’ knowledge of ‘pressure pumping’, another critical technology in shale gas extraction. Through their respective acquisitions, both firms have made it clear that they expect unconventional gas to form an increasing share of the US energy mix.

SOURCE:
Trading Markets: “Schlumberger and Baker Hughes Prepare Shale Gas Boom”

In making the deal, Schlumberger is apparently hoping that Smith’s reputation and extensive domestic network will help position it as the top player in an increasingly hot sector of the oil patch, fending off the likes of Baker Hughes.

“There is I don’t think any doubt that long-term shale gas is going to be one of the big new energy sources both in the U.S. and overseas,” Andrew Gould, Schlumberger’s chief executive, said in a conference call with analysts on Monday. “Smith’s capacity to serve that market in North America is of great interest to me.”

With big oil companies like Exxon Mobil and Total, as well as a handful of private equity firms, spending billions to buy up unconventional leases around the country, the demand for more drilling is obvious. But the flood of new natural gas on the market could squeeze margins to unprofitable levels, making Schlumberger’s 18 percent premium for Smith look a bit rich.

“It may not be the best financial return in the oilfield at this point in time,” Mr. Gould said, “but long term, what we can learn in that market is extremely interesting”

A deal between Schlumberger and Smith had been rumored since last summer, when Baker Hughes acquired BJ Services for $5.5 billion. BJ derived about 81 percent of its 2008 revenue from an oil service technique known as pressure pumping, used in unconventional natural gas wells.

Both BJ and Smith also make use of a technique known as fracturing to obtain unconventional reservoirs, including “tight” or low-permeability sandstones, coal-bed methane and gas-bearing shale. Much of that production is focused in the United States in natural gas reservoirs in Texas, North Dakota and the Rocky Mountains.

Smith is a leader in drill bit technology needed to burrow down into shale, which could be highly valuable to Schlumberger.

“Schlumberger’s claims that Smith gives it greater exposure to the U.S. shale does make sense, at least to some degree,” Doug Sheridan of EnergyPoint Research, which conducts customer satisfaction surveys for oil field service companies, told DealBook. “Through its leadership position in bits and bits related technologies, Smith has considerable knowledge of what works and does not work when drilling shale wells.”

It seems like every other week there is another major shale field discovered which could bring billions of cubic feet of gas to the market. High natural gas prices first spurred this rush into shale earlier this decade and it has continued even as prices have dropped significantly, on the hopes that increased natural gas demand will justify more and more drilling.

But the expensive and crude fracturing technique is expensive and time-consuming. While it is still profitable to drill for unconventional gas at current prices of around $5 per one million British thermal units, there isn’t much room for error. Even a slight drop in gas prices would make shale fields unprofitable.

“I don’t think that the actual optimum technology set for producing shale gas has yet been defined — at the moment, we are doing it by brute force and ignorance.” Mr. Gould said. “As we get better at identifying the sweet spots in shale reservoirs, drilling will systematically become more important.”

The United States is expected to rely more on natural gas for its power needs, as it is cleaner than coal. But carbon-cap legislation has yet to take effect, raising questions about whether the anticipated rise in natural gas demand will materialize. Many producers that depend heavily on natural gas left the country after prices spiked in the middle part of the last decade, meaning that the new demand needs to come from the more fickle residential and commercial sectors.

By Cyrus Sanati for The New York Times. February 22, 2010.

SOURCE:
The New York Times: “Behind Schlumberger’s Smith Deal”

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