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December 1, 2011

Anadarko Petroleum Corp. (APC), the largest U.S. independent oil and natural-gas producer by market value, found more gas than expected at its Cheyenne East project in the Gulf of Mexico.

The company found more than 50 feet of gas-bearing rock at the prospect, topping expectations, Chuck Meloy, senior vice president of worldwide operations, said at a Jefferies & Co. conference in Houston today.

The find is the first announced by Anadarko in the Gulf since then end of a drilling moratorium that followed last year’s record offshore U.S. oil spill at BP Plc’s Macondo well in the Gulf. Anadarko had a stake in Macondo.

Anadarko is completing Cheyenne East and plans to tie it to Independence Hub, a platform that handles flow from several Gulf fields, Meloy said, with production expected next year. Anadarko is also drilling at the Heidelberg and Nansen projects, Meloy said. The company plans an extensive program next year, assuming it can get U.S. permits, he said.

The company owns 100 percent of Cheyenne East, John Christiansen, an Anadarko spokesman, said in a telephone interview today.

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By Katarzyna Klimasinska – Dec 1, 2011 4:02 PM CT

Air-pollution limits proposed by the Environmental Protection Agency for U.S. oil and gas production, including hydraulic fracturing, will be costly and waste time, the American Petroleum Institute said.

The EPA’s plan to cut emissions of smog-forming volatile organic compounds by about a quarter, with an almost 95 percent reduction from new and updated gas wells using fracturing, or fracking, will require too many tests and reports, said Howard Feldman, API director of regulatory and scientific affairs.

“These requirements will be overly burdensome,” Feldman said today on a conference call from Washington. “They will waste time and resources of the industry and the EPA.”

Fracking is a technique used by companies such as Exxon Mobil Corp. (XOM), Chesapeake Energy Corp. and Southwestern Energy Co. that injects chemicals and water into rock formations to free trapped gas. It has been tied to an increase in smog pollution in rural areas such as western Wyoming.

The emission limits, incorporating four air regulations issued on Oct. 28, will trigger too much monitoring, and performance testing, and might cause a shortage of equipment necessary to abide by the rules, according to the industry group.

The EPA under President Barack Obama also is working on rules regarding water discharges from drilling operations, which are scheduled to take effect in 2014, and the use of diesel in hydraulic fracturing.

Fracking Study

A comprehensive study of fracking and its effect on drinking water, ordered by Congress, will produce two reports, to be released in 2012 and 2014, Cynthia Dougherty, a director at the EPA, told the Senate Natural Resources Committee on Oct. 20. The Interior Department plans to require the disclosure of chemicals used to fracture shale formations on public lands.

The American Petroleum Institute expects a final rule on emissions from production in April.

“EPA’s schedule will not allow adequate time to review and analyze all stakeholder comments, develop necessary revisions to the rules, and complete internal and interagency reviews,” API said in comments filed to the agency yesterday.

The EPA works to ensure that U.S. shale resources are developed without harming the public’s health and the environment, according to an agency statement today.

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By Nick Snow

OGJ Washington Editor

Michael R. Bromwich prepares to finish 17 months at the US Department of the Interior satisfied that necessary reforms were beginning to be made at a troubled agency there, but concerned that their permanence may be threatened by funding cuts, he said 2 days before stepping down as head of what formerly was the US Minerals Management Service.

“I never thought I’d do anything like this. It’s been the biggest challenge of my career,” he told reporters during a Nov. 28 briefing at Interior’s headquarters. “It’s a huge accomplishment that’s a tribute to the hard-working and dedicated employees of an agency that was vilified as immoral and corrupt, particularly since we began reorganizing it in a crisis environment.”

But Bromwich also expressed deep concern that members of Congress and the White House might slash DOI’s offshore resources management budget to reduce the federal budget deficit. “People have short memories,” he observed. “We’ve tried to institutionalize these reforms, but there are people who believe that this spill was an anomaly and the changes are too onerous. This agency fought a losing battle for resources over 28 years, and I think these budget gains need to be sustained. I’m worried that the larger budget climate, particularly after the congressional super-committee failed to reach an agreement, may undermine the progress we’ve made.”

He said the change he made in MMS’s relationship with the industry it was supposed to regulate to one where “we are expecting more and yielding less” was necessary to implement badly needed safety and environmental reforms. “The amount I knew about offshore oil and gas issues you could fit in a thimble,” Bromwich said. Despite a steep learning curve, he said he quickly recognized that stronger safety rules would be needed. “These couldn’t just be paper standards,” he maintained. “Fairly quickly, we set the tone with industry that this was not the same agency it had been dealing with.”

Came at critical time

Bromwich became director of the US Bureau of Ocean Energy Management, Regulation, and Enforcement—the former MMS—on June 21, 2010, as federal, state, local and oil and gas industry responders tried to contain a massive oil spill from BP PLC’s deepwater Macondo well. He arrived after US Interior Sec. Ken Salazar announced he was moving MMS’s royalty and revenue responsibilities to a new Office of Natural Resources Revenue under Asst. Interior Sec. for Policy, Management, and Budget Rhea Suh.

The move ended one of MMS’s mission conflicts, but Salazar and Bromwich concluded that BOEMRE itself would need to be divided to separate leasing and resource management from enforcement of safety and environmental regulations. The separation occurred on Oct. 1 with the creation of the Bureau of Ocean Energy Management, with Tommy L. Beaudreau as director, and the Bureau of Safety and Environmental Enforcement, which Bromwich agreed to lead on an interim basis until a permanent director could take over.

US Coast Guard Rear Adm. James A. Watson IV, who coordinated the joint response to the spill, will take BSEE’s helm on Dec. 1, and Bromwich will stay on for 30 days as a counselor to Salazar, to assist in the transition, and to attend to other matters including continuing to build an international offshore regulatory alliance. “I can’t count the number of foreign regulators who have come to us asking what we have learned and how to implement it,” he said.

He said that the next critical phase for BSEE will be reviewing safety and environmental management systems in December which offshore operators and contractors are supposed to have developed and implemented. “We will initially put our composites of our most common findings,” he said. “Ultimately, we will want to specifically identify violators, but in the short term publicly identifying the most prevalent problems while providing immediate feedback to specific operators is the best approach.”

Shuns revolving door

After Dec. 31, Bromwich said he would like to continue working on offshore resource issues, but not as a representative of any group having dealings with BOEM or BSEE. “There’s been too much of a revolving door with former directors returning in new capacities with outside organizations. I refuse to do this,” he declared, adding that he might join a law firm or start one of his own.

Bromwich said that he thought his relationships with individual oil and gas producers were better than those he had with trade associations which represented them and some members of Congress. “The operators knew who they were dealing with from the beginning,” he said. “I wasn’t a member of their team…I didn’t have any conceptions, let alone preconceptions, of the issues. I made the industry and environmental groups unhappy, but I called matters as I saw them.”

He suggested that his lack of oil and gas experience may have worked to his advantage by making him question long-standing practices, such as MMS’s limiting its regulation and penalties to offshore well operators and letting producers sort out penalties with drilling contractors and service and supply companies. Referring to his effort to begin citing other well drilling participants, Bromwich said: “I didn’t believe we should give across-the-board immunity to a contractor who had committed a major violation.”

He said that he was more successful recruiting new inspectors and environmental engineers to come work at BOEM and BSEE than he was at hiring senior petroleum engineers. “We need to pay them more, and recruit them more,” he said. “I’ve heard from some industry executives that they’re having trouble too, and it’s more urgent for them because they need to design the kind of wells that meet our new requirements.”

Retraining engineers from other specialties may be one way to address this problem, and Bromwich noted that the Colorado School of Mines has such a program under way. “Every option needs to be explored so neither industry nor the agencies that regulate it experience a bottleneck,” he said.

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By Newsroom America Staff at 1 Dec 11:36

(Newsroom America) — Despite aggressive demand-management policies announced in recent years, China’s oil use could easily reach levels comparable to today’s U.S. levels by 2040, according to a new energy study by the Baker Institute.

The study’s authors said this finding has timely significance because China’s growing energy use could continue to pose a major challenge for global climate deliberations in South Africa this week.

The study, “The Rise of China and Its Energy Implications,” finds that China’s recent efforts at centralizing energy policy do not appear to be significantly more successful than the makeshift patchwork of energy initiatives devised by the United States. In fact, the study said, the U.S. system of open and competitive private sector investment is stimulating more innovation in the American energy sector than in the Chinese energy industry, especially in the area of unconventional oil and gas.

That, ironically, is attracting Chinese state investment to U.S. shores and prompting Beijing to consider further opening of its oil and gas exploration activities to partnerships with U.S. firms, the study said.

China, like the United States, has substantial potential shale gas resources but faces technical, regulatory and market infrastructure challenges that are likely to delay rapid development. Were China to mobilize investments in shale gas more quickly, the study said, it could greatly reduce the country’s expected large import needs for liquefied natural gas (LNG) from Australia and the Middle East and contribute to a future glut in global natural gas markets.

Despite sporadic government policies to discourage private car ownership, the growth in the number of vehicles on the road in China has more than quadrupled in recent years to more than 50 million. The Baker Institute report projects that this number could increase to more than 200 million vehicles by 2020 and 770 million by 2040 under a scenario where China’s real gross domestic product growth averages 6 percent between now and 2030. Even under a scenario where the number of electric cars rises to 5 million a year by 2030, which is in line with ambitious targets announced by China’s National Development and Reform Commission, China’s oil use from the transportation sector will grow significantly, the Baker Institute study said.

“Given the scale of vehicle stock growth in China, it is going to be extremely difficult to move the needle of the country’s rising transport fuel outlook,” said Kenneth Medlock, a study author and the James A. Baker III and Susan G. Baker Fellow in Energy and Resource Economics at the Baker Institute.

The study noted that China’s “going abroad” strategy has also encountered recent difficulties in light of geopolitical events and rising global political risks in oil-producing regions.

“China is learning that owning equity oil in risky regions may not be as effective an energy security strategy as it had previously imagined,” said Amy Myers Jaffe, an author of the study and the Wallace S. Wilson Fellow for Energy Studies at the Baker Institute. “China is now finding itself mired in more energy-related foreign diplomacy than it bargained for.

“But this could be good news for the United States,” Jaffe said. “It may mean China will be more inclined to act in concert with other members of the international community in conflict-prone regions.”

The study noted that China has tried to offset some of this risk by increasing investments in the United States and Canada, which gives the U.S. more leverage in seeking China’s collaboration in international diplomatic matters.

More findings from the energy study will be publicly released ahead of a daylong conference at the Baker Institute Dec. 2. To view the study, go to www.bakerinstitute.org/riseofchina.

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By Andrew Restuccia and Ben Geman – 12/01/11 06:36 PM ET

State of play: House Republicans will step up their attacks Friday on the Obama administration’s decision to delay action on the proposed Keystone XL oil sands pipeline until after the 2012 elections.

A House Energy and Commerce Committee hearing on the proposed Alberta-to-Texas pipeline will cap several days of attacks on both sides of Capitol Hill.

Republicans, seeking to exploit a split in President Obama’s political base, have called several union officials that support the project to testify Friday.

Their support runs counter to green groups that bitterly oppose the pipeline, which would expand imports from Alberta’s massive oil sands projects.

The witness testimony is available here.

The hearing comes two days after dozens of Senate Republicans — including GOP leadership — introduced a new bill to require a State Department permitting decision within 60 days.

The Senate bill faces an uphill battle but has the support of powerful business groups including the U.S. Chamber of Commerce and the American Petroleum Institute.

“The Administration’s recent decision to put off a decision on the permit delays the project’s benefits for American job seekers, the economy, and domestic energy security,” the Chamber said in a letter to senators Thursday.

The Senate plan is currently a GOP affair, but conservative Democrats Mary Landrieu (D-La.) and Joe Manchin (D-W.Va.) told The Hill Thursday that they will consider signing on.

House Republicans are pressing their own bill to speed up action on the project. Rep. Lee Terry (R-Neb.) is rolling out legislation this week that would put the permitting decision in the hands of the Federal Energy Regulatory Commission.

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By Edward Klump and David Wethe

Dec. 2 (Bloomberg) — Chesapeake Energy Corp. said the oil and natural-gas industry isn’t likely to find another U.S. bonanza like the Eagle Ford and Utica shale formations.

Next year likely will bring a close to a period of big acreage purchases by Chesapeake and other companies, Chief Executive Officer Aubrey McClendon told reporters Nov. 30. He said more formations may be found under existing acreage.

McClendon’s comments at a Jefferies & Co. energy conference in Houston this week contrasted with views expressed by other executives at the gathering.

Chuck Meloy, a senior vice president for worldwide operations at Anadarko Petroleum Corp., told a Jefferies audience yesterday he expects surprises in the amount of oil and gas resources in coming years. He cited recent onshore discoveries and finds off the coast of Africa.

“There’s some very clever minds trying to unlock the keys and the bounty of this Earth to deliver those hydrocarbons,” he said. “I think we’ll still see positive surprises, particularly in the shales and particularly in deep water.”

“I would take a little bit different view than in perhaps what Aubrey articulated,” EOG Resources Inc. CEO Mark Papa said on a Jefferies panel. “I don’t believe all the plays, even in onshore North America — the horizontal resource plays — have been found.”

Still Exploring

The U.S. has many previously uneconomic, non-shale plays to which producers can apply technologies that have helped make shale finds productive, James Wicklund, portfolio manager at Carlson Capital, in Dallas, said yesterday in a telephone interview.

“Might those all be Haynesville or Barnett or Marcellus shales? Maybe not,” Wicklund said. “Would these be discoveries? Sure, I’d call them discoveries. We’re still doing exploration.”

U.S. oil and gas producers use horizontal drilling and hydraulic fracturing to tap so-called unconventional projects. Horizontal wells help producers reach more of a resource than a traditional vertical well.

Oil production in the Eagle Ford during the first eight months of this year has more than doubled to 8 million barrels of oil from 3.76 million barrels produced in all of 2010, according to the Railroad Commission of Texas. The Eagle Ford shale is about 50 miles (80 kilometers) wide and 400 miles long in south Texas, the commission said.

EOG, an early participant in the Eagle Ford, said it has potential reserves of 900 million barrels of oil equivalent from the project, with hopes of increasing that.

Chesapeake’s Focus

The Utica formation in Ohio is similar to the Eagle Ford and likely has superior economics, Chesapeake said in a November investor slide presentation. The company estimated it has 1.36 million net acres in the Utica.

The days of discovering million-acre plays are drawing to a close, McClendon said. That leaves Chesapeake to develop what it has and to seek the best returns for shareholders, he said.

“I just think the industry has already evaluated all the sedimentary basins in the U.S. and have pretty much been able to eliminate any possibility that another Utica is lurking out there,” McClendon said.

David Ginther, a senior vice president at Overland Park, Kansas-based asset manager Waddell & Reed Financial Inc., said there are many oil discoveries to uncover in the U.S.

“I don’t know if plenty is the right word,” Ginther said in an interview at the Jefferies conference yesterday. “There’s a lot of good opportunities out there. I don’t think the window’s closing.”

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by Pierre Bertrand

Stymied by a six-month drilling moratorium, the climb to recovery appears slow for the oil and natural gas industries in the Gulf of Mexico since the Macondo spill of 2010.

In reality, it’s a little more ambiguous than public perception or data numbers suggest.

Of the 56 drilling rigs in operation in deep water regions of the Gulf before BP Plc’s spill, 36 are back online as of Nov. 18 and are actively drilling new wells for hydrocarbons, according to analysts with Baker Hughes. Twenty rigs have decided to leave the region altogether.

The U.S. Energy Information Administration, whose latest available data dates back to Feb. 3, shows offshore rig counts have progressively dropped throughout the country since 1981. That December, there were 283 offshore oil and natural gas rigs in operation. That number plummeted to 15 operating rigs in July of last year. As of September, there were 32 operating rigs.

Since then, rig numbers have appeared to stay flat. When the Gulf Coast moratorium was lifted last year on Oct. 12, the Bureau of Safety and Environmental Enforcement’s website, which updates the number of approved drilling permits in the Gulf on a daily basis, shows the number of approved unique deepwater wells totaled 56 as of Nov. 29.

The drop in rig counts since the 1980s, especially in the Gulf region, said Jonathan Cogan, a spokesman for the Energy Information Administration, is partly due to the drop in oil prices experienced at that time, and an increasingly pronounced interest in ultra deep-water prospecting. As technology improved to do so, the size of the rigs increased and so did their reach. Added reach meant rigs could dig deeper in the ground and harvest oil from a larger area – thus rig counts started dropping off.

But this is where it gets complicated.

David Smith, a spokesman with the Bureau of Safety and Environmental Enforcement, said comparing the difference between permit and rig numbers pre spill to those post spill will not be an accurate indication of the industry’s revival or decline in the Gulf region.

As part of the new permitting regulations put in place after the Macondo spill, rigs get counted and labeled differently. Where a rig drilling at 1,000 feet was considered a deep-water well before, now its considered at 500 feet. Distinctions are also made for wells that require blowout protectors and those that don’t.

Smith said the environmental enforcement bureau is actively working to devise a system of comparison, which should come out in the next few days.

It’s comparing oranges to apples, and Andy Radford, senior policy advisor for offshore with the American Petroleum Institute, said to get a real sense of the industry’s health, one needs to take a closer look.

“I guess you have to look behind the curtain and look at what they are doing,” Radford said, who added just because a permit allows for drilling, doesn’t mean they are specifically drilling for oil or natural gas.

But the reason why rig counts aren’t climbing back up post moratorium, reported the Financial Times on Nov. 13, is in part due to the drilling permitting process, which has became more stringent.

The Times reported that the 3,654 pages of paperwork and a wait of more than 100 days before a drilling permit is issued have contributed to more than 1 million barrel of oil equivalents lost this year compared to last.

The increased permitting demands have dampened people’s confidence in the region’s industry, according to Andy Radford, senior policy adviser for offshore with the American Petroleum Institute.

Though the permitting process is slowly getting better and faster, companies are almost having to do a cost benefit analysis when seeking drilling permits, segregating the wells for which they are certain to get approval while leaving others untapped, said Radford.

It is common for a company to have to wait 200 days between filing a plan for a well and the time the permit is finally approved, and the current permitting process is causing some companies to lose confidence in the industry, added Radford. Some want the permitting process to go faster to help promote growth, he said.

That could be costly come Dec. 14, when the Department of the Interior opens up more than 21 million acres of Gulf offshore oil leases.

At the heart of the issue is whether the Bureau of Safety and Environmental Enforcement can keep up with incoming permits, and after the moratorium, this sale is likely to be a platform for the industry to expel some of its pent up demand, Radford said.

“That increases uncertainty,” he said. “To make investment decisions, [companies] like certainty and predictability.”

John Filostrat, public affairs officer for BOEM’s Gulf of Mexico Region, said the regions up for sale contain anywhere between 222 to 423 million barrels of oil that can generate an estimated revenue of $5.7 to $9.6 billion.

For BOEM, this sale, though the first since the Macondo spill, is routine and “just getting back to normal business,” Filostat said.

The views and opinions expressed herein are the views and opinions of the author and do not necessarily reflect those of The NASDAQ OMX Group, Inc.

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Posted on November 30, 2011 at 6:36 am by Simone Sebastian

Domestic demand for chemicals used in hydraulic fracturing of oil and gas wells will continue to surge through at least 2015, according to a report released Tuesday by industry research firm Freedonia Group.

U.S. demand for oilfield chemicals will swell more than 8 percent each year, the firm forecasts, reaching $13.6 billion in 2015.  Of the major uses for chemicals in oil and gas production, well stimulation will see greatest demand growth, expanding by nearly 10 percent each year through 2015, according to the report.

Hydraulic fracturing is a form of well stimulation that uses chemicals, sand and massive amounts of water to open up rock deep underground and release the fossil fuels inside.

Rising oil prices and the shale rush boosted use of oilfield chemicals in recent years, the Freedonia report authors noted. Hydraulic fracturing is used in shale regions to force oil and natural gas from the dense rock, but has attracted the wrath of environmentalists who say it can contaminate drinking water.

Stimulation chemicals will make up nearly half of the oilfield chemical demand in 2015. In 2005, they were less than 40 percent of total oilfield chemical demand, according to the report.

The use of chemicals in U.S. oilfields has grown faster than Freedonia researchers predicted in the past. In a 2009 report, researchers forecast demand would grow 4.4 percent annually.  In fact, demand has grown by about 7.8 percent, the group found.

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