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Many emerging US fields now commonly considered part of the “shale” boom are not really shale at all, but rather tight oil such as in the Permian Basin or even conventional fields made un-conventional by modern techniques such as horizontal drilling, multistage fracturing that helps draw more oil from rocks and long laterals—the horizontal leg of a well—to enhance their economics.

“Shale is very fine grained…rock,” containing silica, Peng Li, petroleum geologist at the Arkansas Geological Survey, said. According to other sources, it also contains clay and even quartz. On the other hand, other plays being developed unconventionally are carbonates (such as the Permian Basin), sandstone, siltstones, limestone or even mudstone. “The difference is in the type of rock,” Li said.

While the Eagle Ford Shale in South Texas and Bakken Shale in North Dakota/Montana are two of the biggest shale oil plays, wildcatters continue trying to smoke out the next big oil find. There, shale hasn’t been the draw, but rather conventional fields some of which have produced modestly for years.

Company managers are now talking up older fields such as the Woodbine in East Texas, the Brown Dense in Louisiana/Arkansas and the Tuscaloosa Marine Shale in Louisiana/Mississippi as potential up-and-comers.

The Woodbine consists of sandstone and siltstone rocks, located at about 7,400-9,400 foot depths across several counties north of Houston. The formation sits below the Eagle Ford horizon, which some operators say is also potentially productive in that area. For that reason, many operators call it the Eaglebine play.

But according to oil companies, the Eagle Ford zone there is shallower than in south Texas where production is galloping. Eaglebine wells have approached initial production rates of a solid 1,000 b/d of equivalent oil in some cases; small operator Crimson Exploration, for instance, has seen rates above 1,200 boe/d. The company has said other zones may also be productive.

Global Hunter Securities cited a Devon Energy well that debuted at 936 boe/d from the Georgetown formation, while tiny Navidad Resources has vertically commingled the Buda, Georgetown and Glen Rose formations and “has produced 135,000 boe in a year,” or about 370 boe/d.

The Woodbine also has favorable well costs around $5.5 million versus $6-$7 million in the South Texas Eagle Ford, companies have said.

- The Brown Dense play is an old play made up of carbonate mudstone found at roughly 8,000-12,000 feet depths. Southwestern Energy, which pioneered the Fayetteville Shale, is a leader in this play also. It has drilled six wells, all but one in Louisiana.

One of the wells came in at over 1,000 boe/d of output that included 421 b/d of oil. The company is targeting sections 300-500 feet thick.

CEO Steve Mueller said in an August company call that its Brown Dense wells could cost $10-$12 million, topping initial $8 million estimates due to higher-than-expected well pressures. “When you start looking at how that works out on the economics, I think [a] 500-barrel-a-day range on the oil-only side still makes that work,” Mueller said.

- The Tuscaloosa Marine Shale is a shale, found between 10,000 to more than 16,000 foot depths with thickness varying from between 500 feet in Louisiana to over 800 feet in Mississippi, according to a report released earlier this year by David Dismukes, associate executive director of the Center for Energy Studies at Louisiana State University.

Tuscaloosa operator Devon Energy so far has drilled three wells in the play; the first averaged just shy of 300 b/d and the second, 670 b/d—an improvement, which company officials say they hope to sustain. Because of the depth, wells are costly at $12 million to the mid-teens. “Reducing costs and improving well performance over time are keys to making this play economic,” said David Hager, Devon executive vice president of E&P.

- Then there is an apparent one-man shop in an acreage spread west of Houston called the Navarro/Midway field. Said GHS in a recent report, “nobody else is leasing here, but [Halcon Resources CEO Floyd Wilson] liked this play so much he leased it personally” after selling his former company, Petrohawk Energy, last year. Petrohawk in 2008 pioneered the Eagle Ford Shale; BHP Billiton gobbled up the company for $15 billion.

The Navarro/Midway are two formations; Halcon has targeted both in vertical wells which require multistage fracturing to make them economic, Wilson said at a recent energy conference. The company has drilled two wells there; both should unearth a mix of oil, natural gas and gas liquids, he said.

Navarro is the deeper zone that may hold more gas and less oil; Midway has “a lot more oil and a little less gas,” said Wilson. “I’m expecting big numbers.”

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Big Oil knows where the money is, and its buried with the shale gas. The latest such foray into that arena is ExxonMobil’s agreement to buy Denbury’s shale assets in North Dakota’s Bakken field, which is awash in oil and gas.

Oil companies, which are constrained in the United States as to where they can drill, expect their investments in shale gas to pay off. It’s a way to diversify their holdings in a complementary fashion. In other words, natural gas is often found alongside oil deposits. And while developers have been forced to “flare” the fuel because they have been unable to monetize it, high electric utility demand for it is now providing the push to build the required infrastructure.

“This agreement provides a strategic addition to ExxonMobil’s North American unconventional resource base,” says Andrew Swiger, senior vice president of ExxonMobil. “ExxonMobil’s financial and technical strength will support continued development of America’s natural resources, which strengthens U.S. energy security while creating jobs.”

For its part, Exxon will get 196,000 acres, increasing its total land in the Bakken to 600,000 acres. Texas and North Dakota lead the United States in oil and gas production. The acquisition is considered small for Exxon but it is in keeping with its economic strategy, which is to acquire more such assets. Two years ago, it bought XTO Corp. for $31 billion. Since then, it has spent about $3 billion to collect shale gas leases throughout the United States.

In exchange for its Bakken shale assets, Denbury will receive $1.6 billion in cash and acquire ExxonMobil’s interests in the Hartzog Draw field in Wyoming and Webster field in Texas, which currently produce about 3,600 net oil equivalent barrels per day of natural gas and liquids.

Denbury said in a formal statement it is focusing on fields where it can leverage its know-how of enhanced oil recovery mechanisms using carbon dioxide. By capturing such releases from power plants, they can then be funneled into oil wells to ease the production process. To that end, the company’s Chief Executive Phil Rykhoek said that this ability “offers one of the most compelling rates of return in the oil and gas industry today.”

Potential Problems

The Potential Gas Committee, a research arm of the natural gas and petroleum industries, has said that this country has a natural gas resource base of nearly 2,000 trillion cubic feet — more than in the last 46 years. Most of the increase since the last 2009 study is the result of re-evaluating shale gas plays along the Gulf Coast Mid-Continent and Rocky Mountain areas.

Eric Potter of the University of Texas has given further estimates that 5,500 wells in the Barnett Shale region in Dallas will generate $100 billion for the Texas economy over several years.

All that is why the oil giants are interested in shale. ExxonMobil, in fact, has previously said in its annual energy outlook that it anticipates natural gas to grow faster over the next 20 years than either oil or coal.

Beside ExxonMobil, Chevron bought Atlas Corp. in February 2011 for $3.2 billion. RoyalDutch Shell, meantime, acquired East Resources for $4.7 billion in cash. 

As for ExxonMobil, it now possesses the resource equivalent of 45 trillion cubic feet of shale gas, shale oil and coal-bed methane. By betting on natural gas, all of the oil firms are expecting tighter air quality restrictions; natural gas emits far fewer emissions than either oil or coal.

“As the outlook shows, the world will still rely on oil and natural gas to meet much of its energy demand for years to come …,” says the American Petroleum Institute. But it goes on to say that the progression toward carbon constraints will force a move toward natural gas and other less carbon-intensive fuels to meet electricity demand.

But potential problems loom. For starters, flaring remains an issue and especially in the Bakken fields. But the industry is insistent that it will make the necessary investments to transport the natural gas.

Furthermore, shale is mined by pumping water, sand and chemicals deep underground to break it free from the rocks where it is embedded. Many communities and environmental groups say the process contaminates the groundwater. The issue, though, is getting a lot of attention and a recent high-profile panel appointed by the U.S. Department of Energy has concluded that through proper stakeholder involvement, the drilling processes in question could be safely done.

It’s a natural extension for Big Oil to reach out to shale gas producers. And it’s also beneficial for those smaller gas developers, which need access to capital. That’s why similar deals such as the one Exxon just entered into will continue.

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During America’s Age of Imperialism, Henry Cabot Lodge famously said that “commerce follows the flag.” Send over U.S. gunships, and U.S. business will be right behind.

These days it may be the reverse. America’s shale oil and gas revolution—one of the biggest commercial bonanzas in generations—is itself shaking up the world order.

As oil and gas flood into U.S. pipelines, relationships that defined how energy moved around the globe are shifting. How far that will go is open to debate. A U.S. that no longer defends Saudi Arabia? A China with dominion over the Middle East?

“It’s already had an impact,” says Ed Morse, an energy expert at Citigroup C -1.09% . “In the geopolitics of energy, there are always winners and losers. The U.S. is going to win big, and someone else is going to lose big.”

The U.S. is already getting a lift. In 2005, it imported 60% of its oil. That’s down to roughly 42% now. The losers: the Middle East, Africa and Venezuela, sometimes unpredictable suppliers that over the years brought us oil shocks and price spikes. Though the oil market is global and an oil-field strike abroad can still raise prices here, America’s vulnerability to shaky regimes and despots is declining.

If the U.S. begins exporting its gas in earnest, Europe too may taste a bit more energy freedom. It’s currently shackled to the whims of Russia’s Gazprom, OGZPY -0.10% the dominant gas supplier to the region. Moscow loves that leverage: In January 2009, during a spat with Ukraine, it cut gas to a large chunk of Europe, leaving industry to ration energy and households to shiver.

Gas exports could also give the U.S. a new card to play in trade talks.

“The value of a free-trade agreement with the U.S. just went up a heck of a lot for some countries,” says Karan Bhatia, a former deputy U.S. trade representative who is now a General Electric GE +0.76% executive. Nations wanting access to gas through a free-trade agreement may now cede greater market access to U.S. business.

When the U.S. consumes its own oil, it drains less from global markets, leaving more for others. That can also have a big political payoff.

“Had it not been for this growth in U.S. production, the sanctions on Iran could not have been as successful,” says Daniel Yergin, author of “The Quest: Energy, Security and the Remaking of the Modern World.” The increase in U.S. production since 2008, he says, is equal to roughly 80% of what Iran was exporting before the sanctions. Countries that normally bought from Iran can find oil elsewhere. “It’s an example of the geopolitical impact of this renaissance in energy production.”

Other nations are trying to catch up. China is exploring its own shale reserves through a partnership between Sinopec and Chevron CVX +1.07% . But Rex Tillerson, CEO of Exxon, has said shale-gas development in China will take more time. In Central Europe, too, exploration is sluggish because of the geology of the region, the cost, and environmental concerns.

“There is a huge difference between the U.S. and the rest of the world,” George Kirkland, vice chairman of Chevron, told The Wall Street Journal in June. “You know a lot more about the actual geology” in the U.S.

Mr. Morse says the U.S. leads for other reasons, too. Along with Canada, Australia and the U.K., it has what many other countries don’t: fast-moving independent oil drillers willing to take risks, and capital markets willing to finance them. The resulting speed and innovation are tough for other countries to match.

That said, world order doesn’t trend in a straight line.

The U.S. will still be the cop on the beat protecting sea lanes, allies and the global economy, military experts say. But there are other kinds of influence.

“So the ships coming out of the Persian Gulf will turn left instead of right,” says John Hofmeister, former head of Shell’s operations in the U.S. “China will suck up the Mideast production the U.S. doesn’t need. That may reduce the leverage the U.S. thinks it ought to have in the Mideast if China becomes a bigger customer.”

Frank Verrastro, of the Center for Strategic and International Studies, similarly feels it is “premature” to herald a new U.S.-centric energy world. Countries like Russia have vast reserves and will help shape the global energy market for years to come, he says.

The politics at home are also a wild card. The U.S. must still address the laws prohibiting or heavily regulating the export of oil and gas. Some businesses, such as Dow Chemical, DOW -0.26% want to keep the gas at home to cheaply fuel manufacturing here. And environmental groups, worried about climate change, fear that more gas and oil production would take the nation’s eye off critical goals, such as expanding the use of solar and other renewable energy.

This week, the Department of Energy demonstrated why the new balance of power in energy remains in flux. Several companies have requested permission to export liquefied natural gas from the U.S. The DOE has been studying the matter and now says its report is delayed until the end of the year—likely after the presidential election.

But these problems seem like luxuries compared with the oil shocks America has endured over the years. The U.S. is clearly empowered by its new energy bonanza. Commerce just got a big tailwind. And that will give the flag a lift, too.

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ConocoPhillips is considering expanding its China portfolio to include shale gas. This was revealed by Mark Nelson, ConocoPhillips’ vice president of commercial and sustainable development, on the sidelines of the U.S.-China Oil & Gas Industry Forum in San Antonio, where Chinese government officials and energy executives met with their U.S. counterparts to discuss energy policy and attempt to form partnerships.

China is expected to put up 17 shale gas blocks for auction in the coming weeks in a bid to develop a robust shale gas industry. It is hoping to attract American energy firms to invest in the industry and form partnerships with domestic companies. It wants to see the success of the American shale gas industry replicated in China. China had no commercial shale gas production in 2011, but has set itself an ambitious target of producing 229.5 billion cubic feet of shale gas a year by 2015.

Importance Of Shale Gas

Shale gas is natural gas that is trapped inside shale rock and is extracted by using a technology called hydraulic fracturing, where highly pressurized water mixed with sand and chemicals is used to crack open rocks. It has completely altered the energy calculus for the U.S., resulting in a natural gas supply glut which has sent prices crashing down.

The natural gas output in the U.S. rose to 66 billion cubic feet a day in 2011, up from 56 billion cubic feet a day in 2001, according to the U.S. Energy Information Administration. Shale gas accounts for about 40% of U.S.’s domestic natural gas output. Without the contribution made by shale gas, the production of natural gas would have declined and the U.S. would have had to import massive quantities of liquefied natural gas. Natural gas is considered to be a bridge fuel between crude oil and the clean hydrogen-based energy sources of the future. Without it, the demand for crude oil would have risen beyond the current demand figures, thus driving up on prices as well as straining broader geopolitical relations.

Why China Also Wants A Piece Of The Action

China’s demand for energy is huge even though its economy is slowing. It imports vast quantities of crude oil besides using humongous quantities of coal to keep its economic engine humming. However, given the current discourse surrounding climate change and its own residents’ constant complaints about the heavily polluted air and water, China is keen to move to cleaner fuels.

Natural gas is one such option. The country already imports vast quantities of the same from countries like Australia, but it would like to unlock the potential of its own domestic reserves. It is estimated that recoverable shale gas reserves in China stand at 1.28 trillion cubic feet while total reserves may stand at 26 trillion cubic meters. According to the EIA, Chinese consumers used 39 billion cubic feet a day of natural gas in the first quarter of 2012. This demonstrates the ample market demand for gas. Developing domestic reserves would also reduce China’s energy imports bill, diversify its energy mix by reducing dependence on crude oil, and make it self-reliant to some extent.

Why Invite Western Companies Like ConocoPhillips

The shale gas extraction technology is largely a preserve of Western oil and gas companies as they have developed this expertise in-house over time. China is keen that its own companies learn these technological and engineering aspects, which is quickened if they form joint ventures with Western firms. Prior to this, China had been focusing on persuading other countries to share this technology, arguing that a better use of its own energy resources would ease pressure on tight global markets.

We believe that this argument hasn’t gained much traction with foreign governments that see no reason to give away proprietary technology free-of-cost. Hence, for all its reluctance to share a resource that could become a major growth area for output and profits, we believe that China doesn’t have a choice but to make commercial deals.

Why ConocoPhillips Might Be Interested

ConocoPhillips already has large shale gas operations in the U.S. However, low gas prices in the U.S. due to a supply glut have forced Conoco to announce cuts in its plans to develop shale assets in the U.S. We think that it is now more keen to focus on international markets, particularly in Asia, where demand is robust and gas prices are higher. Hence, it has taken a step towards exploration of shale reserves in Australia. Gas from here would feed into the LNG plants Conoco is developing with Chevron to cater to markets such as Japan and China. We feel that nothing could be better than the opportunity to produce in the targeted consumer market itself, in this case China. This would reduce costs and boost margins for its natural gas business which accounts for 15% of the Trefis price estimate for ConocoPhillips.

Also, we believe that environmental regulations in China are much more relaxed than in other countries, which would reduce risk of liabilities and penalties. Considering that Conoco’s presence would most likely be as a part of some joint venture with a Chinese company, this risk would be further reduced.

We recently revised the Trefis price estimate for ConocoPhillips to $60 which is in line with its market price.

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Oil and gas investment is flooding into the region in amounts not seen since the fall of the Berlin Wall. Anglo-Dutch giant Royal Dutch Shell RDSB.LN -0.62% PLC, France’s Total SA TOT +1.53% and ConocoPhillips COP +0.97% of the U.S. have acquired exploration rights in Poland, where current estimated reserves equal 35 to 65 years of the country’s demand for natural gas, according to the Polish Geological Institute.

Ukraine is heating up as well. TNK-BP Holding, a joint venture of BP BP.LN +0.32% PLC and a group of Russian investors, plans to invest $1.8 billion in shale projects at a half-dozen sites around Ukraine. In June, Italy’s Eni SpA E +2.92% paid an undisclosed amount for a stake in Ukraine-based LLC Westgasinvest, which holds about 1,500 square miles of land with potential shale-gas reserves. And Chevron Corp., CVX +0.59% which has acquired more than 6,250 square miles of potential shale gas leases in Central Europe since 2009, says it is working with Ukraine to negotiate a production-sharing agreement.

Welcome Alternative

At least part of the region’s motivation in embracing these partners is obvious: to get out from under Russia’s thumb. According to a May study by consultancy KPMG, 69% of the gas consumed in Central and Eastern Europe is imported, nearly all of it from Russia. A string of disputes over transit fees between Russia and Ukraine—the main gas corridor to Eastern Europe—has pushed some countries to seek other sources of supply.

Exploratory drilling for shale gas by Chevron in Poland.

The majors are bringing with them key technologies successfully tested in North America, such as horizontal drilling and hydraulic fracturing—unlocking the gas by blasting rock with sand, chemicals and water.

But a host of obstacles stand in the way. For a start, it isn’t clear that the potential supplies are as great as was initially hoped. In June, Exxon Mobil Corp. XOM +1.17% said it would halt exploration efforts in Poland after two early wells proved commercially unviable.

The Long Haul

Most companies, however, have vowed to stay.

“We have no plans to scale back our activities,” says Ian MacDonald, a Chevron vice president in charge of its exploration and production strategy for Europe, Eurasia and Middle East. Mr. MacDonald estimates it will take three to five years to know whether gas wells in Eastern Europe are viable.

Seismic imaging work in search of shale gas by Chevron in Poland.

As in the U.S., local environmentalists have also vigorously opposed hydraulic fracturing, or fracking. The technique uses lots of water, raising fears that it will tap into scarce drinking water in some communities. The water is also mixed with chemicals, sparking fears of contaminating groundwater.

In January, Bulgaria canceled a decision to award a license to Chevron—which says its technologies are designed to prevent contamination—and implemented a moratorium on shale drilling. Romania also has put shale-gas exploration on hold, and the Czech Republic is considering a similar move.

When exploration is allowed, oil majors also have to deal with both governments and private land ownership, unlike in the U.S. where mineral rights are the sole property of the latter.

Locked In

Another challenge will be loosening Russia’s grip over supplies. Moscow controls the region’s pipelines. Many buyers in Eastern Europe are also locked into supply contracts of as long as 25 years with Russian gas giant OAO Gazprom—making it uneconomical in some cases to seek a new supplier.

Some estimates put the cost of exploring for shale gas much higher in Eastern Europe than in the U.S. According to Schlumberger Ltd., the oil-field-services supplier, drilling a shale-gas well in Poland costs almost three times as much as in the U.S.—or $11 million for a depth of 2,000 meters. And shale depths in Europe are on average 1.5 times greater than in the U.S., translating into the need for powerful rigs, more powerful pumps and more fracturing fluids, according to the Oxford Institute for Energy Studies.

John Avaldsnes, an oil and gas manager for Ernst & Young’s European operation, warns that no one should expect shale gas to surge overnight in Eastern Europe. “It’s not going to take place as a revolution, like in the U.S.,” he says, “but as an evolution, slowly building up.”

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U.S. oil company ConocoPhillips COP +0.34% is looking into expanding its China operations to include shale gas, a company executive said Tuesday.

A move by ConocoPhillips would help China—a country with no commercial shale gas production in 2011—along on its ambitious target to produce 229.5 billion cubic feet a year of shale gas by 2015. ConocoPhillips, which currently holds stakes in Chinese offshore drilling projects, is “looking into expanding into shale” in the country, Mark Nelson, ConocoPhillips’s vice president of commercial and sustainable development, said.

Mr. Nelson spoke on the sidelines of the U.S.-China Oil & Gas Industry Forum in San Antonio, where Chinese government officials and energy executives met with their U.S. counterparts to discuss energy policy and attempt to form partnerships. During the forum, ConocoPhillips took three buses of Chinese delegates on a tour of the Eagle Ford shale region south of San Antonio, where oil rigs and hydraulic-fracturing work crews dot the drought-stricken landscape. The area’s booming oil patch has been instrumental in bringing U.S. oil production to its highest level in more than a decade.

China is expected to put 17 domestic shale-gas blocks up for auction in the coming weeks, hoping to entice U.S. energy firms to form partnerships with domestic companies and kickstart the sort of shale-gas revolution that the U.S. has undergone in the past decade. ConocoPhillips, Chesapeake Energy Corp., CHK +2.64% EOG Resources EOG +0.03% and others have used advances in drilling technology to unlock natural gas from shale formations throughout the U.S., sending the country’s natural-gas output to 66 billion cubic feet a day in 2011, up from 56 billion cubic feet a day in 2001, according to the U.S. Energy Information Administration. Without shale gas, which accounts for about 40% of domestic natural-gas output, production of the commodity would have declined and the U.S. would have had to import massive quantities of liquefied natural gas, experts say.

The energy needs in the world’s second-largest economy continue to grow, with Chinese consumers using 39 billion cubic feet a day of natural gas in the first quarter according to the EIA.

But even if ConocoPhillips and other U.S. firms decide to partner with Cnooc Ltd. and other Chinese national oil companies to develop the country’s estimated 1.28 trillion cubic feet of recoverable shale gas, China still may not hit its 2015 production target, which some executives at U.S. energy producers working in China have called too ambitious for the country’s current capability.

“The shale gas target is too aggressive,” said one executive for a U.S.-based oil-and-gas firm doing business in China. “They won’t get that far.”

China has little experience in drilling for shale, and its workforce lacks the technology and engineering know-how needed, said Julio Friedmann, chief energy technologist at the Lawrence Livermore National Laboratory in Livermore, Calif., who has visited China to conduct technical analysis on the country’s shale potential.

“Chinese companies, including Cnooc, are finding it challenging to quickly learn about shale-gas and tight hydrocarbon tech,” Mr. Friedmann said. “The transfer of knowledge and know-how is limited by language, culture and different commercial goals.”

Despite the skepticism, a Chinese official on Tuesday reaffirmed the government’s target.

“This goal can be attained,” said Zhang Yuqing, deputy administrator of China’s National Energy Administration. “We would like to utilize U.S. technology to increase our development. We would like to learn from you and establish a good framework for shale gas development.”

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Over the last 10 years, the U.S. has emerged as a leading producer of shale gas. Thanks to innovative extraction techniques spearheaded by Texas entrepreneur George P. Mitchell, natural gas trapped in shale formations, previously too difficult and costly to recover, now provides a burgeoning domestic energy supply. By drilling horizontally underground to reach shale formations and then flushing those tunnels with water, sand and chemicals to break open the rock and force out the gas — a process called hydraulic fracturing (fracking) – U.S. companies have sparked a shale gas revolution: U.S. shale gas production climbed from virtually zero in 2000 to a level where it is contributing a quarter of U.S. natural gas today and is expected to comprise half of total U.S. natural gas by 2030, according to the James A. Baker III Institute for Public Policy at Rice University in Houston, Texas.

Blessed with the world’s second-largest reserves (behind China), according to the U.S. Energy Information Administration (EIA), the U.S. suddenly has a vast new energy source that could help it reduce its reliance on foreign oil. “The real positives from shale gas are what it does for U.S. energy independence,” says Gary Survis, a fellow at the University of Pennsylvania/Wharton School’s Initiative for Global Environment Leadership (IGEL). “It’s a huge paradigm shift.”

What’s more, natural gas, made up mostly of methane, produces half the carbon emissions that coal does. Fracking itself raises environmental concerns — such as groundwater contamination if the tunnels are not lined correctly and the chemicals used to keep the rock pores open are able to seep out. Not accounting for the environmental impacts of producing shale gas, however, “natural gas is the better hydrocarbon fuel,” notes Robert Giegengack, professor of earth and environmental Science at Penn. “It produces less sulfur dioxide and other contaminants, is easier to handle and manage, and is produced closer to the market” in places such as the Marcellus shale formation underlying New York, Pennsylvania and neighboring states.

Yet for all the virtues of shale gas, U.S. producers now are discovering that there can be too much of a good thing. Rocketing production, coupled with the economic slowdown, drove U.S. natural gas prices from about $7-$8 per million cubic feet in 2008 down to less than $3 per million cubic feet today. With oil at about $100 a barrel, gas drilling is leveling off, as the number of oil rigs in the field rise. In 2010, for the first time in 16 years, the number of oil rigs exceeded the number of gas rigs in the continental U.S., according to a UBS Securities report.

Today, operators are pulling back from more mature shale gas fields, such as the Barnett in Texas and the Haynesville in Arkansas, Louisiana, and Texas, and deploying to newer fields with the potential of producing gas along with oil — including the Utica in Ohio and Bone Spring in Texas and New Mexico, says Drew Koecher, KPMG’s U.S. energy leader in transactions and restructuring. With low gas prices, many shale gas developers are facing financial challenges. Chesapeake Energy, based in Oklahoma City and the nation’s second largest shale gas company after Exxon Mobil, needs to raise cash through asset sales, while managing a U.S. Securities and Exchange Commission investigation into CEO Aubrey McClendon’s alleged conflicts of interest, which involve taking loans against his personal stake in the company’s wells, according to news reports.

Still, the recent shale gas boom is far from over, and a full realization of the U.S. shale gas revolution is yet to come, say experts. For starters, the U.S. has significantly more resources to recover. “The U.S. has a long way to go before it depletes shale gas,” says Brandon Beard, KPMG’s managing director for U.S. energy transactions and restructuring. “It will take 10 to 20 years to play through.” Moreover, as new demand for gas develops, gas prices will recover and buck up the industry. “The glut of gas is somewhat temporary,” states Noam Lior, a Penn mechanical engineering and applied mechanics professor who is also on the graduate faculty of Penn/Wharton’s Lauder Institute. “As long as oil prices are holding above $100 a barrel or so, gas will be very competitive.” Jonathan Banks, senior climate policy advisor at the Clean Air Task Force in Boston, agrees. “Nothing cures low prices like low prices,” he says. Spurred by these low prices, demand from electric utilities, chemical manufacturers, natural gas vehicles and overseas markets will restore health to the shale gas industry, and relatively low natural gas energy prices could help buoy the U.S. economy, experts predict. “It’s a game changer,” notes A.J. Scamuffa, U.S. chemicals leader at PwC in Philadelphia.

In the short term, the biggest increase in demand for natural gas comes from power generation, says KPMG’s Beard. So many utilities have switched from coal to cheaper natural gas that U.S. carbon emissions in the first four months of this year fell to their lowest level in two decades, according to the EIA. Coal now powers only 34% of U.S. electricity, down from half in 2005, the EIA reported. In one of the largest announced coal-fired generator closures, the Tennessee Valley Authority said last year it would shutter 18 generators at three plants by 2020 to help settle a Clean Air Act complaint from the U.S. Environmental Protection Agency. It plans to replace those generators with ones powered by natural gas and biomass. In August, the TVA dedicated its fifth and largest gas powered plant, the 986-megawatt Magnolia plant near Ashland, Miss.

A Coming Renaissance?

Meanwhile, over the next few years, low gas prices could spark a renaissance in U.S. manufacturing, say experts. PwC predicts the shale gas revolution could add one million U.S. manufacturing jobs by 2025 and reduce manufacturing expenses by $11.6 billion a year through that time. “We’re seeing a shift in offshore chemical manufacturing back to the U.S.” to take advantage of low-priced natural gas feedstocks here, says PwC’s Scamuffa.

Today, many chemical manufacturers are switching from using oil-based to natural gas-based chemicals to make propane, butane and other basic ingredients in manufactured products from paints to semiconductors. Major companies are investing more than $15 billion in capital to upgrade existing facilities and to build new facilities in North America due to the abundance of natural gas here, notes Garrett Gee, PwC’s director of chemical advisory services in Philadelphia. According to a PwC report, such companies include Dow Chemical, Bayer and Westlake Chemical. ”Over the next three to four years, as this infrastructure is built out in North America, we are hopeful that the lower cost of feedstock will translate into lower costs for everyday goods and consumer durables.”

Over time, cheap natural gas could even transform the U.S. transportation sector, which is responsible for about 30% of the nation’s carbon emissions. Worldwide, 14 million natural gas vehicles are on the road, 10 times more than a decade ago, according to an August 2012 National Petroleum Council report. But, the U.S., with only 130,000 natural gas vehicles, ranks eighth in the world after countries such as Pakistan, Argentina, Brazil, India and China. Most U.S. natural gas vehicles are energy-hogging trucks, buses and trash haulers. With only 1,200 natural gas filling stations around the country, compared to about 160,000 gas stations, widespread natural gas-powered family cars are still a long way off, notes Richard Kolodziej, president of the Natural Gas Vehicle Association in Washington, D.C. “For the mom and pop market to gain traction, you probably need 10% penetration in filling stations, or 16,000 stations,” he says.

One of the most controversial potential new sources of demand for U.S. shale gas is overseas markets. Historically, gas prices in each region of the world are “set differently for no rational reason other than tradition,” states Penn professor Lior, who is writing a paper on the subject. In the U.S., prices are set by demand and supply, but in Europe and Asia, they are indexed to the price of oil and other factors, he says.

With gas prices in Asia two to three times higher than in the U.S., gas exports seem a logical next step. Yet, many experts think large-scale exports are not in the cards. For example, political opposition is surfacing from those who want to keep gas at home to promote U.S. energy independence and the domestic economy, KPMG’s Koecher points out. Moreover, adds Michael Levi, senior fellow of energy and the environment at the Council on Foreign Relations, “The U.S. is likely to become a small exporter but unlikely to become a large one, because of the cost of moving natural gas from the U.S. to overseas markets.”

Many people are wary of putting money into multiyear build-outs of liquid natural gas (LNG) export terminals due to concerns that China, Australia and other countries will develop their own domestic shale gas production and wipe out the value of their investments. A liquefaction plant takes a lot of time to line up both money and building permits, says Levi. “If you are getting into that business, you have to be confident you can make money exporting five or more years after the facility comes into existence.” Levi notes that only a handful of companies seem serious about pursuing exports, including Golden Pass Products, a recently announced joint venture between Exxon Mobil and Qatar Petroleum, which plans to convert a Texas facility into an LNG terminal, and Houston-based Cheniere Energy, which is investing in a LNG terminal in Sabine Pass, La.

Environmental Questions

While the shale gas industry might boost the U.S. economy and energy independence, environmental advocates are concerned about its overall environmental impact. Complaints about groundwater contamination from fracking liquids are now making their way through the courts, and some anti-fracking advocates fear the practice can cause earthquakes. The jury is out even on air emissions, since methane is four times more harmful as a greenhouse gas than carbon dioxide.

“Natural gas can be burned more cleanly than coal, but not nearly clean enough for climate,” especially if affordable gas encourages greater consumption, says David McCabe, an atmospheric scientist at the Clean Air Task Force. “The best information we have now is that abundant, cheap shale gas will hasten warming.” While the EPA just passed rules to limit methane leakage at new shale gas wells built in 2015 and beyond, the U.S. has no regulations restricting methane leakage along other parts of the supply chain. “If we don’t have some effective regulations, we might have very difficult problems in the future [with regard to] contamination of air and water,” says Penn’s Lior.

Another major concern is the impact of shale gas on the emerging alternative energy sector, say experts. “The amount of carbon that natural gas puts out is significantly better than coal, but it’s not the same as wind or solar by any stretch,” notes IGEL fellow Survis. “Shale gas is only a bridging technology, not a sustainable technology. It’s not going to lead to long-term energy independence where we’re getting our energy from the sun or wind.” Unfortunately, the shale gas boom comes at a time when green energy is still struggling to lower its costs to be competitive with fossil fuels. “By bringing [gas] prices down, shale gas can absolutely crowd out and hobble alternative energy,” especially as the U.S. is phasing out many subsidies for this sector, says Survis.

For now, the shale gas revolution in the U.S. continues to gain ground and reach a more sustainable footing, remaking the U.S. energy landscape and economy in its wake.

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Natural-gas production from shale formations rose in May on increased supplies from the Marcellus deposit even after prices fell to a 10-year low, Energy Department data show.

Total output from shale formations in the continental U.S. averaged 25.58 billion cubic feet a day in May, 24 percent higher than a year earlier and up 1.7 percent from April, according to slides that accompany a presentation the department will make to Congress Aug. 1. Shale production has gained 5.7 percent this year.

Production from shale deposits with oil and other liquids has gained as dry-gas output has declined in response to decade- low prices, the department said in its Short-Term Energy Outlook on July 10. Gas futures on the New York Mercantile Exchange dropped to $1.902 per million British thermal units April 19.

May output from the Marcellus shale in the eastern U.S. averaged 6.85 bcf a day, up 6.4 percent from the previous month and gained 28 percent during the first five months of the year. May 2011 production averaged 3.37 bcf daily.

Haynesville shale output in Louisiana and Texas averaged 6.92 bcf a day, down from 6.93 billion in April. Production from the region has declined 2.4 percent this year. Output averaged 6.43 billion cubic feet a day in May 2011.

Barnett Output

Output at the Barnett shale in Texas was 4.67 bcf daily, from 4.66 billion in April, department data show. Production dropped 1.7 percent versus May 2011.

The average for Eagle Ford shale gas output in southern Texas was 1.52 billion cubic feet a day in May, up from 1.51 billion the previous month. Production has gained 6.3 percent this year. Output averaged 820 million cubic feet a day a year ago.

Woodford shale output in Oklahoma averaged 1.14 billion cubic feet a day in May, up from 1.13 billion both in April and during May 2011. Fayetteville production in Arkansas declined 1.1 percent this year to 2.68 billion cubic feet a day. Output averaged 2.69 billion in April and 2.54 billion in May 2011.

Bakken gas output in North Dakota held steady at 190 million cubic feet a day in May versus the previous month. Production is up 19 percent from a year earlier. Gas from the Antrim shale in Michigan, Indiana and Ohio averaged 290 million cubic feet a day in May, unchanged versus April and May 2011.

Gas for August delivery on the New York Mercantile Exchange climbed 3.6 cents, or 1.2 percent, today to $3.117 per million Btus, the highest settlement price since Dec. 22. Gas is up 4.3 percent this year on increased demand from power generators that switched from costlier coal.

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