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Proposed federal regulations on emissions from oil and gas production could cause unconventional drilling operations such as fracking to drop over the next several years, the American Petroleum Institute said.

The Washington-based trade group cited insufficient emission-cutting equipment and said that, unless the industry is given more time and more flexibility to meet the rules, drilling involving hydraulic fracturing could be reduced by 31 percent to 52 percent between 2012 and 2015.

The regulations would represent the first federal air standards for wells that are hydraulically fractured by injecting water, sand and some chemicals deep underground to release natural gas and oil from dense rock. The practice has been linked to increased smog in some Western states, including Texas. The process is being used in the Eagle Ford Shale in South Texas.

A report prepared for API by the research firm Advanced Resources International said companies would have to cut the number of wells they drill to meet the proposed Environmental Protection Agency regulations.

Obtaining and installing the equipment also would impose additional costs on drilling, the report says. While some companies already are cutting emissions, API said, a “one-size-fits-all” approach could cause problems for some companies.

However, the report expects drilling to recover to “business-as-usual” levels from 2017 onward.

The EPA, which delayed the rules last fall, submitted them to the White House for review early this month and plans to finalize them early next month.

API plans to suggest rule changes in a meeting with White House officials next week, said Howard Feldman, API director of scientific and regulatory affairs.

The EPA’s proposal would cut ozone-forming volatile organic compounds, or VOCs, emitted from oil and gas sites by one-fourth, with a 95 percent drop in the VOCs released from new and updated gas wells that are hydraulically fractured.

The proposal addresses air pollution problems reported in places such as Texas, Wyoming, Pennsylvania and Colorado.

In Dish, a rural town northwest of Dallas, the state’s environmental regulators have detected levels of cancer-causing benzene, sometimes at levels dangerous to human health, and likely coming from the industry’s 60 drilling wells, gas production pads and rigs, a treating facility and a compressor station.

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Chinese, French, and Japanese companies were among recent investors making long-term financial commitments to US unconventional oil and gas plays in a trend that is expected to continue despite economic uncertainty.

State-run Oil India Ltd. (OIL) has indicated an interest in acquiring shale assets in the US and Australia. Oil India Finance Director T.K. Ananth Kumar told reporters Oil India hopes to buy shale assets worth up to $200 million. Reliance Industries Ltd. and Gas Authority of India Ltd. already have US shale gas acreage.

Kumar said Oil India prefers a joint venture partnership rather than fully owning the asset. “This is our strategy for acquisition of shale gas,” he said.

Rick Roberge, PwC US principal for energy mergers and acquisitions, said international investment in US shale is well under way and likely to continue.

IHS Herold Inc. statistics showed international transactions involving US shale plays accounted for 40 deals totaling $60 billion during 2008-11 of which 33 transactions were announced within the last 2 years.

Roberge said 22 transactions involved drill-and-carry arrangements, and Chesapeake Energy Corp. was the most active player, participating in 8 deals.

“Every major global oil company is looking at US shale,” Roberge said. “They desperately want a position and will pay up for it.”

Roberge noted Russian investors are the lone exception, adding that Russia has a large conventional oil and gas reserve base.

Meanwhile, Asian companies have been very prominent investors in the US shale market. Roberge said Asian companies invest in US shale to acquire both financial reward and technical knowledge about unconventional oil and natural gas development.

China is very keen on acquiring shale expertise given its hope to tap into its own unconventional resources. Andy Brogan, Ernst & Young global oil and gas transactions leader, said China holds the largest estimated shale gas resources worldwide.

“If the potential in this asset base can be unlocked, this could transform the oil and gas landscape in years to come,” Brogan said.

The US Energy Information Administration estimates China has 1,275 tcf of technically recoverable shale gas compared with 862 tcf in the US. The estimate was part of an analysis of world shale gas that EIA released in April 2011.

Jim Dillavou, US leader of Deloitte’s energy M&A practice, said some Chinese companies have made multiple investments.

These partnerships provide US operators with capital to continue development while the drill-and-carry joint venture partners gain unconventional technical expertise.

Relationships continue evolving, he said. Recent low gas prices are unlikely to discourage international investors who already expect to wait several years for a financial return from their shale investments, he said, adding that unconventional liquids assets currently attract the keenest interest from buyers.

“Most development plans are 6-10 years at least,” Dillavou said. “We see a lot of big pockets coming into this space. We haven’t seen any signs of it slowing. We think it will continue for awhile.”

Trend continues

The M&A trend from investors abroad into US shale continued robustly going into 2012 with three transactions announced in early January.

Total E&P USA Inc. signed a joint venture agreement with Chesapeake Exploration LLC and affiliates of EnerVest Ltd. in which Total acquires a 25% stake in Chesapeake-EnerVest holdings in the Utica shale in Ohio (OGJ Online, Jan. 3, 2012). Total paid $700 million upfront and agreed to pay up to $1.63 billion during 7 years in the form of a 60% carry of Chesapeake-EnerVest’s future drilling and completion expenditures.

Devon Energy Corp. agreed to sell one third of its interest in five plays to China Petrochemical Corp. (Sinopec) for $2.2 billion (OGJ Online, Jan. 3, 2012).

Terms call for Sinopec International Petroleum Exploration & Production Corp. (SIPC) to reimburse Devon for drilling costs. Previously, Devon assembled 1.2 million net acres in the Tuscaloosa Marine shale, Niobrara, Mississippian, Ohio Utica shale, and the Michigan basin.

The Eagle Ford JV results in SIPC paying 80% of the overall development costs during the carry period, Devon said.

Marubeni Corp. subsidiary Marubeni Eagle Ford Ltd. agreed to buy a 35% stake in Hunt Oil Co.’s holdings in South Texas. Terms call for Marubeni to pay future drilling expenses (OGJ Online, Jan. 9, 2012).

The Japanese trading house said the JV with the Dallas-based Hunt plans to drill several hundred wells during 5-10 years across 52,000 acres. Marubeni and Hunt plan to jointly acquire additional Eagle Ford acreage.

Other Japanese companies also are investing in US shale plays. Corporate conglomerate Itochu Corp. was part of an investor group led by Kohlberg Kravis Roberts & Co. LP that acquired Samson Investment Co., Tulsa, Okla., one of the largest private US exploration and production companies, for $7.2 billion.

Samson has positions in oil and liquids-rich plays such as the Bakken, Powder River, Green River, Granite Wash, Cana Woodford, and Cotton Valley as well as in the Haynesville and Bossier gas shales.

Previously, Itochu became the first Japanese company to participate in a US shale oil project upon buying a 25% stake in the Niobrara shale oil play in Wyoming from MDU Resources Group.

Separately, a subsidiary of Mitsui & Co. Ltd. acquired 12.5% working interest in the nonoperated Eagle Ford shale position of SM Energy Co., Denver. Mitsui agreed to carry 90% of SM Energy’s drilling and completion costs on its nonoperated acreage until it has spent $680 million for the benefit of SM Energy (OGJ Online, June 29, 2011).

Norway’s Statoil ASA announced plans to acquire independent Brigham Exploration Co. for $4.4 billion in a transaction marking Statoil’s entry into the Bakken and Three Forks unconventional oil plays in the Williston basin in North Dakota and Montana (OGJ Online, Oct. 17, 2011).

SandRidge Energy Inc. of Oklahoma City struck a $1 billion deal with Spain’s Repsol YPF last year involving SandRidge’s Mississippian oil fields.

Repsol agreed to pay SandRidge $250 million and to finance $750 million in drilling expenses over 3 years for a nonoperated stake in two areas, one straddling the Oklahoma-Kansas line and another in southern Kansas. While not shale, the Mississippian formation requires horizontal drilling and multistage fracturing. In a separate joint venture, South Korean firm Atinum Partners Co. Ltd. acquired a nonoperated working interest in SandRidge’s Mississippian fields for $500 million. Atinum will pay $250 million in cash at closing. Atinum has also committed to a drilling carry obligation to pay 13.2% of SandRidge’s share of drilling and completion cost for wells up to a total amount of $250 million during a 3-year period.

BHP Billiton Petroleum of Australia agreed to buy all of Chesapeake Energy Corp.’s interests in the Fayetteville shale in Arkansas for $4.75 billion (OGJ Online, Feb. 22, 2011).

J. Michael Yeager, BHP Billiton chief executive, said his company obtained an operated position in 487,000 net acres in the Fayetteville to “immediately make BHP Billiton a major North American shale gas producer. Longer term, the expertise we gain here will be usable elsewhere as we continue to grow our business.”

A few months later, BHP Billiton announced an agreement to acquire Petrohawk Energy Corp., Houston, for $12.1 billion, giving BHP operated positions in the Eagle Ford and Haynesville shale resource plays and the Permian basin (OGJ Online, July 25, 2011).

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Just how much natural gas is trapped underground in the United States?

The difficulty and uncertainty in predicting natural gas resources was underscored last week when the Energy Information Administration released a report containing sharply lower estimates.

The agency estimated that there are 482 trillion cubic feet of shale gas in the United States, down from the 2011 estimate of 827 trillion cubic feet – a drop of more than 40 percent. The report also said the Marcellus region, a rock formation under parts of New York, Ohio, Pennsylvania and West Virginia, contained 141 trillion cubic feet of gas. That represents a 66 percent drop from the 410 trillion cubic feet estimate offered in the agency’s last report.

The Energy Information Administration said the sharp downward revisions to its estimates were informed by more data. “Drilling in the Marcellus accelerated rapidly in 2010 and 2011, so that there is far more information available today than a year ago,” its report said. Jonathan Cogan, a spokesman for the agency, added that Pennsylvania had made far more data available than in previous years.

Under the agency’s new estimates, the Marcellus shale, which was previously thought to hold enough gas to meet the entire nation’s demand for 17 years at current consumption rates, contains instead a six-year supply. The report comes just five months after the U.S. Geological Survey released its own estimate of 84 trillion cubic feet for the Marcellus shale.

The estimates are important because they underpin policy decisions on energy subsidies and exports. Market analysts look to these estimates in making investment decisions. Historically, they have varied widely based on assumptions about the future of technology, coming regulations on drilling and the long-term price of gas.

Previously inaccessible, shale gas has been unlocked in recent years by advances in a drilling technology known as hydraulic fracturing, or hydrofracking. These advances have prompted a drilling frenzy in states like Louisiana, Pennsylvania and Texas, which has helped create tens of thousands of jobs, lowered energy prices for consumers and offered the promise of lessening U.S. dependence on foreign energy.

Despite the lower estimates, the agency’s report noted that shale gas would continue to have a growing impact on the broader energy market. The share of natural gas produced by drilling in shale formations is projected to more than double, from 23 percent in 2010 to 49 percent in 2035, the report said. The United States will also become a net exporter of liquefied natural gas by 2016, while natural gas prices are expected to remain low for more than a decade, according to the report.

Energy companies are also likely to be undaunted by the new lower estimates because they are confident that whatever the total amount of available gas, technology will improve over time so that they can access the gas more efficiently and profitably. This assumption depends on the price of gas rising soon from the rock-bottom levels, where it has lingered since late 2008.

In his State of the Union address last week, President Barack Obama said the United States had a nearly 100-year supply of natural gas.

That prediction includes gas from shale wells, offshore

wells and Alaska’s North Slope. But many energy experts question these types of projections because they include substantial amounts of natural gas that many scientists and engineers say may never be tapped.

Drilling proponents, including investors and many politicians, tend to embrace optimistic projections, even though estimating resources is an inexact science.

Some of the earliest and most optimistic estimates of gas resources have come from academia. In 2009, Terry Engelder, a geosciences professor at Penn State, helped accelerate the rush to drill for natural gas in Pennsylvania and surrounding states by projecting that more than 500 trillion cubic feet of natural gas could be produced from the Marcellus.

This estimate is more than three times as high as the estimate for the Marcellus region from Energy Information Administration, and it is higher than what federal energy officials now say can be found in the entire country.

Engelder said last week that he stood by his estimates, citing assumptions that he believed remained reasonable, and he questioned whether federal officials were being too conservative.

“I don’t know what EIA did other than cave into peer pressure from the USGS,” he said, referring to the U.S. Geological Survey, which released its new estimates in August.

Energy companies, which use different formulas for calculating their numbers, tend to present even higher estimates.

For example, more than three dozen companies have leased land in the Marcellus region, and each company provides its own estimates to investors for how much gas it believes can be found under the acreage they possess. The combined resource estimates of just two of those companies, Range Resources and Chesapeake Energy, whose acreage holdings represent a small fraction of the Marcellus shale, is roughly equal to the amount federal energy officials now say can be found in the entire region.

Many experts note that it is difficult to predict how difficult or easy it will be to extract gas in different parts of the country because the geology varies drastically.

Since the hydrofracking boom is fairly recent, there is also a shortage of data to indicate how much gas wells will produce over the long term.

In private discussions, some federal energy officials have raised questions about the way oil and gas companies may be inflating estimates of the amount of recoverable gas.

“The variability of shale gas well performance is crucial to any assessment of the resource potential of a shale play,” Philip Budzik, an Energy Information Administration research analyst, wrote in an email to an industry analyst last April.

The email was released this month in response to open records requests, and it echoes comments made previously in other publicly released emails.

“Companies highlight their highly productive and profitable wells,” Budzik wrote, “while ignoring their ‘dogs,’ thereby giving the public the impression that every well is a ‘gold mine.”’ The information administration declined to comment about the email.

Last summer, the New York attorney general and the Securities and Exchange Commission sent subpoenas to several companies to see whether they were accurately portraying the amount of recoverable gas to investors. The offices declined to comment about the subpoenas.

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COASTAL BEND — Soaring drilling permit figures, sales tax revenues and wages, and sinking unemployment rates are hard evidence of how the Eagle Ford Shale formation has transformed rural South Texas.

Just as interesting is what will happen in “secondary” counties — including Jim Wells, Kleberg, Nueces and San Patricio — especially if Eagle Ford production lives out projections of active drilling for the next 15 to 20 years, said Tom Kennelly, project manager for the South-West Texas Border Small Business Development Center Network at the University of Texas at San Antonio.

Those areas likely will attract more projects and industries related to drilling, he said.

Kennelly and Larry Ellis, rural program manager for Del Mar College’s Small Business Development Center, told a Corpus Christi Chamber of Commerce lunch gathering that while the area is feeling the benefits it must keep an eye on the future to stay ahead of the boom.

The formation continues to outpace projections.

As of early December, more than 3,100 drilling permits had been issued. There were more than 500 oil wells and 500 gas wellson schedule for construction.

At that pace, Eagle Ford could produce more than 67,000 full-time direct and indirect jobs by 2020, and that pace will continue as long as oil prices remain well above about $60 per barrel, Kennelly said.

Since the rush started strong in 2008, shale production has represented 6 percent of the 24-county drilling area’s gross domestic product, he said.

“So think of all the activity we’re having, yet we’re really only at the surface,” Kennelly said.

There are drawbacks, as well, though none have shown any signs of denting the surge.

Housing continues to be a major issue, and even new hotels in cities such as Three Rivers and George West aren’t enough to ease the problem, Ellis said.

Companies have used the available labor in the oil patch towns and are beginning to look toward the Rio Grande Valley and beyond for workers.

“The real truth is anyone who wants to work can work,” Ellis said.

But the surge in the oil patch has drained the labor pool for small business owners, who find themselves forced to pay higher wages to compete and attract with oil and gas jobs, Ellis said.

On the upside, many businesses are getting an upswing in business, including restaurants which have full dining areas and long waits.

“I don’t hear any of them complaining,” Ellis said. “They just need a little help with employees.”

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By David Mildenberg – Dec 19, 2011 11:01 PM CT

While the Eagle Ford shale boom in Texas isn’t the first that Daryl Fowler has seen, the DeWitt County judge is working to ensure that his community will be left with new roads and housing when the oil and gas are gone.

Fowler, whose non-judicial post gives him administrative control over the county 70 miles (112 kilometers) southeast of San Antonio, has negotiated an $8,000-per-well fee from drilling companies to pay for roads. The county was able to reduce its property-tax rate by 18 percent this year while total assessed value jumped 27 percent as producers, including BHP Billiton Ltd. (BHP), and Pioneer Natural Resources Co. (PXD), sought permits to drill more than 340 wells.

“It takes 270 loads of gravel just to build a pad used for drilling a well, which means a lot of truck traffic on a lot of roads that nobody except Grandpa Schultz and some deer hunters may have used in the past,” Fowler, 55, said in a telephone interview.

From Pennsylvania to North Dakota, production of natural gas locked in shale formations is on a tear. The output will support 870,000 U.S. jobs and add $118 billion to economic growth in the next four years, plus $57 billion in federal, state and local taxes by 2035, according to a Dec. 6 report from IHS Global Insight, a forecaster based in Englewood, Colorado. By early 2012, Texas will become the third state to gain back all of the jobs lost during the last recession, following oil and gas-rich North Dakota and Alaska, according to the firm.

Encouraging Fracking

Under Governor Rick Perry, a Republican seeking his party’s presidential nomination, Texas communities have encouraged the process known as hydraulic fracturing, or fracking. The technique, used in as much as 90 percent of new gas wells drilled in the U.S. each year, forces a mixture of water, chemicals and sand into underground shale formations, breaking open the rock and freeing the natural gas it contains.

Shale development is also surging in North Dakota’s Bakken formation and in the mid-Atlantic’s Marcellus and Utica deposits. West Virginia passed a law Dec. 14 regulating fracking, and New York is studying drilling rules that suspended development of similar geologic structures that contain trapped oil and gas. New Jersey lawmakers sought to ban drilling before Governor Chris Christie vetoed the measure.

“There are some places that are totally anti- development,” David Porter, one of three Texas commissioners who oversee oil and gas extraction, said Dec. 15 by telephone. “We are very pro-development.”

‘Generally Positive’

“It’s an understatement to say that Texas leaders have generally positive views toward oil and gas development,” said Scott Anderson, a senior policy analyst with the nonprofit Environmental Defense Fund in Austin. Permits for drilling cost a few hundred dollars in Texas, compared with a few thousand in West Virginia and Pennsylvania, he said.

Fracking’s environmental impact has become a key issue in local political elections in parts of Texas’ Dallas-Fort Worth metropolitan area where wells abut residential neighborhoods, Anderson said. “There’s been a definite shift in attitude among elected officials and the industry does face closer scrutiny,” he said.

In states including New York, New Jersey and Delaware, opponents say they are concerned that contaminated water can leak from wells. New York is considering rules to prevent drilling near aquifer boundaries and water wells, and to force developers to store waste in tanks to contain contamination from fracking. Pennsylvania also restricts well locations to keep them away from water supplies. Texas has no such limits.

Regulatory Culture

“Texas has more than 100 years of experience in regulating oil and gas,” said Ed Ireland, executive director of the Barnett Shale Energy Education Council, an industry-supported group based in Fort Worth. “In New York you have a whole regulatory culture that is totally unfamiliar with oil and gas. They aren’t welcoming because they don’t understand it.”

States now regulate fracking, although the U.S. Environmental Protection Agency is reviewing the effects of the process and may issue rules on waste handling in 2014. Among concerns are leakage of the slurry from wells into water supplies and disposing of tainted fluids. An EPA investigation found evidence of fracking chemicals in an aquifer in Wyoming, the agency said Dec. 8.

“I don’t understand the current administration — they just seem to be throwing anything out there to try to hinder” domestic energy production from Washington, said Porter, a member of the industry-regulating Texas Railroad Commission.

Tax Windfall

Energy development in the Eagle Ford is expected to produce a windfall for government coffers. Tax revenue tied to the formation may reach $1.65 billion a year by 2020, up from $108.5 million this year, according to a University of Texas at San Antonio study commissioned by America’s Natural Gas Alliance, a Washington-based group supported by 30 oil and gas companies.

Oil and gas development has brought as many as 15,000 workers into the mostly rural Eagle Ford area, with another 40,000 expected to arrive by 2022, said Bob Zacariah, an Austin developer. He is building a 70-unit hotel in Cotulla, in La Salle County southwest of San Antonio.

Most Eagle Ford wells are located in rural areas well away from cities, so housing is scarce, said Jenny Savage, president of Remote Logistics International, which has built two lodges for a combined 600 workers in Carrizo Springs, in Dimmit County, and Three Rivers, in Live Oak County.

In Carrizo Springs, southwest of San Antonio near the Mexican border, “there’s nowhere to rent right now, so if you are coming here, you better be ready to live in your car,” said Estanislado Martinez, the county treasurer.

Sales-Tax Growth

Dimmit County’s sales-tax receipts have grown eight-fold over the past four years and it issued $4.6 million in debt to renovate municipal buildings, Auditor Carlos Pereda said. “We’re seeing a lot more activity, so we need improvements.”

In DeWitt County, the donations Fowler negotiated from drilling companies should add up to $1.8 million during this fiscal year, he said. With a population of about 20,000, including 1,300 prison inmates, the county was the Eagle Ford region’s second-biggest oil producer and third-largest for gas through August, according to industry newsletter Powell Shale Digest. The shale formation crosses under 24 counties from east Texas to Mexico.

“Some of these towns have gone through booms and busts before, and it’s extremely challenging when you have an invasion like this,” said Zacariah, the Austin developer. “It would be nice to see money used for roads, water pipes, sewers, trash services and schools, rather than just building nice offices for the city and county folks.”

‘Likely Sustainable’

The Eagle Ford formation was identified in 2008, when about 130,000 barrels of oil were extracted. Through August, the region has produced 38.2 million barrels of oil, according to the Powell newsletter.

“I’m hearing that this is likely sustainable for at least 20 or 30 years,” said Thomas Tunstall, director of the Center for Community and Business Research at the University of Texas at San Antonio.

The Eagle Ford formation is the latest source of mineral wealth for Texas, which will collect $4.8 billion from taxes on oil and natural gas production in the 24 months through August 2013, according to Comptroller Susan Combs. That makes up 6.7 percent of tax collections in a state that doesn’t have personal-income levies.

Public schools are benefiting from increasing property values, and the revenue that generates, while enrolling relatively few new students as most oil and gas workers are men who are single or have families living elsewhere, Porter said.

‘Fear Tactic’

Perry called environmental worries over fracking a “fear tactic that the left is using” during a Dec. 18 campaign stop in Decorah, Iowa. DeWitt County’s Fowler shares that worry.

“We don’t need any of that down here,” he said, referring to concerns that fracking could endanger some rare species. “This could become more of a political issue because for some people it’s name your bug. We fear that could unravel this thing overnight.”

Original Article

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By America’s Natural Gas Alliance

Published: Thursday, Jul. 28, 2011 – 4:02 pm

AUSTIN, Texas, July 28, 2011 — /PRNewswire/ –  Background: America’s Natural Gas Alliance (ANGA) Texas State Lead, David Blackmon, issued the following statement on the formation of the Eagle Ford Shale Task Force. The Task Force is comprised of a broad spectrum of diverse stakeholders and was formed to open lines of communication between all parties, establish best practices for Eagle Ford Shale development, and promote the significant economic benefits.

“ANGA is very encouraged by Texas Railroad Commissioner David Porter’s announcement of the Eagle Ford Task Force and the diversity of interests represented on the panel.  The forethought shown in the formation of such a pivotal group and its impressive level of community engagement clearly demonstrates a keen understanding of the Eagle Ford region itself.

“Addressing public concerns and operational issues that arise in a transparent and proactive manner is the best way to ensure the public and interested third parties that the tremendous resource potential of the Eagle Ford formation is being developed in a safe and responsible manner.

“We are very hopeful that the diversity of interests represented on the Task Force will lend a maximum level of credibility to the panel’s activities with the public at large and with the news media.  By creating a broad-based group and committing to conduct its activities in a transparent manner, we believe Commissioner Porter is doing a tremendous public service for the oil and natural gas industry, the Eagle Ford region, and the people of Texas.”

America’s Natural Gas Alliance (ANGA) represents 31 of North America’s leading independent natural gas exploration and production companies. ANGA members are dedicated to increasing the appreciation of the environmental, economic and national security benefits of clean, abundant, American natural gas. Learn more about ANGA at www.anga.us.

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The worst Texas drought since record-keeping began 116 years ago may crimp an oil and natural- gas drilling boom as government officials ration water supplies crucial to energy exploration.

In the hardest-hit areas, water-management districts are warning residents and businesses to curtail usage from rivers, lakes and aquifers. The shortage is forcing oil companies to go farther afield to buy water from farmers, irrigation districts and municipalities, said Erasmo Yarrito Jr., the state’s overseer of water supplies from the Rio Grande River.

Concern over water usage is especially acute in southern Texas’s Eagle Ford Shale area because drilling there is more water-intensive than other regions, said Robert Mace, a deputy executive administrator of the Texas Water Development Board.

“It’s pretty dry down here and a lot of oil companies are looking for water,” Mace said.

The water crisis in Texas, the biggest oil- and gas- producing state in the U.S., highlights a continuing debate in North America and Europe over the impact on water supplies of an oil and gas production technique called hydraulic fracturing. Environmental groups are concerned the so-called fracking method may pose a contamination threat, while farmers in arid regions like south Texas face growing competition for scarce water.

Fracking-Led Boom

In fracking, drillers shoot high-pressure jets of sand- and chemical-infused water into the ground to crack rock and release trapped deposits of crude oil and gas. The technique has spurred a new onshore drilling boom from British Columbia to Poland as prospectors revisit geologic formations previously passed over, said Robert Ineson, senior director of global gas at IHS Inc. (IHS)’s Cambridge Energy Research Associates.

Along the Rio Grande River, where border towns such as Laredo supply workers and equipment for the drilling boom, most areas have received less than 2 inches (5 centimeters) of rain since Oct. 1, the National Weather Service said.

To compensate, Exxon Mobil Corp. (XOM) is recycling fracking fluids to reduce the amount of water needed for future drilling. Anadarko Petroleum Corp. (APC) is replacing dirt roads leading to its wells with limestone to preserve water that otherwise would be used to keep down the dust.

Farmers, landowners, environmental activists and state oil industry regulators gathered on June 10 at the University of Texas Health Center in Laredo to discuss the potential impact of fracking on water, air and public health, one of several such meetings that have been held across the state this year.

13 Million Gallons

The Eagle Ford’s peculiar geology means it takes three to four times as much water to fracture as the Barnett Shale near Fort Worth, said Mace, of the state water board. Fracking a single Eagle Ford well requires as much as 13 million gallons of water, enough to supply the cooking, washing and drinking needs of 40 adults for an entire year, he said.

“This is not the drilling your grandparents knew in west Texas,” said Sharon Wilson, an organizer for Earthworks’ Oil and Gas Accountability Project, which lobbies for tougher government regulation of oil drillers. “It’s a heavy industrial activity with massive amounts of water and chemicals.”

About 94 percent of Texas was in a state of severe, extreme or exceptional drought as of June 7, according to the U.S. Drought Monitor compiled by the U.S. Agriculture Department and the National Drought Mitigation Center. The October-through-May period was the state’s driest since record-keeping began in 1895, said Texas State Climatologist John Nielsen-Gammon.

Waiting For Rain

Municipal water departments, farmers, ranchers and oil drillers near Laredo are relying on water from two reservoirs and underground aquifers filled by last summer’s tropical storm season, said Yarrito, whose job title is Rio Grande Watermaster.

Unless storms bring more rain soon, “we’ll be in trouble,” said Sonny Hinojosa, general manager of Hidalgo Irrigation District No. 2 in San Juan, Texas. The drought has decimated crops, with about 79 percent of the state’s winter wheat, 72 percent of its oats and 36 percent of its corn classified as poor or very poor as of June 6, according to the Agriculture Department in Washington.

The Edwards Aquifer Authority, which oversees underground water supplies around San Antonio and along the northern edge of the Eagle Ford Shale, on June 2 declared a Stage 2 emergency requiring a 30 percent cut in water usage. Other water districts have imposed similar restrictions.

Water Demand Gusher

Water consumption by Eagle Ford Shale drillers is forecast to explode during the next 25 years, Mace said. A study to be released later this summer by the Texas Water Development Board and the University of Texas’s Bureau of Economic Geology estimates fracking-water demand in the area will jump 10-fold by 2020, and double again by 2030, he said.

Since Petrohawk Energy Corp. (HK) drilled the first discovery in the Eagle Ford Shale in 2008, oil explorers have sought to gain footholds in the 20,000 square-mile (51,800 square-kilometer) formation. Exxon spent $34.9 billion last year to buy XTO Energy Inc. to capture fracking expertise and U.S. assets including Eagle Ford leases. Marathon Oil Corp. (MRO) agreed on June 1 to pay KKR & Co.-based Hilcorp Resources Holding LP $3.5 billion for assets in the area.

Anadarko Petroleum Corp. and Houston-based Swift Energy Co. (SFY) are among the companies buying water for fracking from Hidalgo Irrigation District No. 2, which also supplies water to 400,000 acres of sugar cane, cotton, peppers and cantaloupe, Hinojosa said. If rain doesn’t arrive in the next four months to replenish the reservoirs, Hinojosa said he’ll have to reconsider whether to continue selling to the oil companies.

Anadarko Rigs

Anadarko, based in The Woodlands, Texas, near Houston, said it’s also buying water from the Wintergarden Groundwater Conservation District, which regulates the aquifer beneath three counties in the heart of the Eagle Ford Shale. The company has 10 rigs operating in the Eagle Ford and plans to drill 200 wells this year, R. Douglas Lawler, vice president of operations, said at a UBS Securities LLC energy conference on May 25.

Anadarko’s Eagle Ford wells were producing the equivalent of 40,000 barrels of crude a day last month, Lawler said. The company is installing meters to monitor and help manage water usage on its wells, Brian Cain, an Anadarko spokesman, said.

Bruce Frasier, a farmer and rancher in Carrizo Springs, Texas, about 40 miles northeast of the Rio Grande, has lost more than half his cotton crop this year and reduced his cattle herd to 300 from 1,000 because it’s too dry for grass to grow.

Frasier, whose family has been farming and ranching in south Texas for 98 years, has refused to sell water to oil companies that are offering 40 cents to 70 cents a barrel, equivalent to 42 gallons. In 2008 before the first Eagle Ford well was drilled, there was no market for a farmer’s water in the area.

“I’ve got to have that water for my farming operation,” said Frasier, whose Dixondale Farms is the largest cantaloupe grower in Texas.

Original Article

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By Selam Gebrekidan

NEW YORK | Tue May 3, 2011 12:13am EDT

NEW YORK (Reuters) – A century after a gusher at the Spindletop field in Beaumont, Texas, ushered in the first U.S. oil boom, a quieter oil craze is underway 300 miles west in a chain of counties more famous for cattle than crude.

Over the past two years, some 30 companies have moved in to a shale prospect in South Texas called the Eagle Ford that could add 420,000 barrels per day (bpd) to U.S. crude oil production, nearly matching the output of OPEC member Ecuador.

The first phase of this latest boom has accelerated over the past year. Companies have hastened development of the estimated 3 billion barrels of shale oil across Eagle Ford by bringing in the horizontal drilling and hydraulic fracturing techniques that opened up North Dakota.

Where wildcatters and entrepreneurs pounced on the Spindletop boom at the start of the 20th century, engineers and business analysts are leading the charge to develop reserves under 20,000 square miles of cattle land in Eagle Ford.

Shale natural gas initially drew companies to the area, but as gas prices languished and crude surged, interest in the region’s crude potential grew.

To relieve a bottleneck producers say has begun to choke growth, pipeline companies in recent weeks committed more than $1 billion to add 940,000 barrels per day (bpd) of pipeline capacity by the end of 2012, according to Reuters estimates.

Texas, once the center of the oil world, fell on hard times as production declined and big energy companies looked overseas to expand and replenish reserves. After decades of decline, U.S. oil output is slowly rising again, largely due to shale reserves like the Bakken field in North Dakota and now Texas.

In April alone, top pipeline companies such as Enterprise Products, Nustar Energy and Koch pipelines announced five projects to build new crude and condensate lines or expand older ones, bringing the rising supply of high quality light, sweet oil to giant Gulf Coast refiners.

For now, truck drivers are working overtime to ferry oil from the region, which stretches across 22 counties in South Texas. Transport companies are retrofitting rigs, but often can’t find lodging for drivers as hotels and motels are booked a year in advance.

“The demand is really straining the trucking industry,” said John Esparza, president of the Texas Motor Transportation Association. “A lot of the capacity that existed a few years ago was cut during the recession. Now there is a spike in demand for a very specific type of truck.”

Explosive production growth will make the transportation infrastructure problem more glaring. Eagle Ford output has risen from nil two years ago to 71,000 barrels of oil per day, and will leap fivefold by 2015, according to energy consultancy Bentek.

“The growth …. clearly outpaces the capabilities of existing pipeline infrastructure,” says Joan Dunlap, spokesperson for Petrohawk Energy, one of the top four producers in Eagle Ford.

ConocoPhillips <COP.N,>, which aims to triple its current output of 20,000 barrels of oil equivalent per day in the next few years, expects pipeline problems to be solved by 2013, the company said last week in its first-quarter earnings report.

FROM TWO DOZEN TO 2,000

The pace of development has picked up quickly since the first successful horizontal well was drilled in Eagle Ford in late 2008, when the Texas Railroad Commission had only 26 permits on record for the area.

The number shot up to more than a thousand in 2010, and the commission issued 562 permits in the first quarter of 2011 alone.

“The Eagle Ford is going from a non-event to being extremely active. We’re expecting a four to five times increase in permits and production in four years,” said Commissioner David Porter of the Railroad Commission of Texas, which regulates exploration companies operating in the state.

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