API: Policy Shift Could Create 1.4 Million New Jobs

- API: Policy Shift Could Create 1.4 Million New Jobs

Wednesday, September 07, 2011
American Petroleum Institute

U.S. oil and natural gas policy changes could generate more than 1.4 million new jobs, $800 billion in additional government revenue, and 10 million barrels worth of added daily oil and natural gas production by 2030, according to a study by Wood Mackenzie released Wednesday by API. New jobs could be added in every state.

"Our industry has kept more than 9 million Americans employed through some of the toughest economic times in America's history, and we created thousands of jobs just last month," said API President and CEO Jack Gerard. "The study shows we could provide another 1.4 million jobs, with as many as one million created in just the next 7 years, and thousands of shovel-ready jobs available next year. It's time our national energy policy let America take advantage of this opportunity."

"The creation of these jobs is within the president's control," Gerard added. "The policy changes involve actions he can take unilaterally. They do not require a super committee of Congress, and they do not require new legislation."

The policy changes include opening non-park federal onshore and offshore areas to development where now prohibited, returning permitting in the Gulf of Mexico to historical levels, approving the Keystone XL and other pipelines, and establishing a regulatory environment that permits full development of the nation's oil and gas resources, including those locked in shale formations.

U.S. oil and natural gas consumption would not necessarily increase as a result, according to API. The changes would allow America to produce at home a much larger percentage of the oil and natural gas it consumes, reducing imports. "If the full potential of domestic oil and gas production could be achieved while also increasing imports of Canadian oil, all of America's liquid fuels could come from secure North American sources within 15 years," Gerard said.

Wood Mackenzie is a Scotland-headquartered consulting firm with extensive experience analyzing oil and natural gas industry issues. API sponsored the study.

API represents more than 480 oil and natural gas companies, leaders of a technology-driven industry that supplies most of America's energy, supports 9.2 million U.S. jobs and 7.7 percent of the U.S. economy, delivers more than $86 million a day in revenue to our government, and, since 2000, has invested more than $2 trillion in U.S. capital projects to advance all forms of energy, including alternatives.

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IHS: Consolidation of Small E&P Cos Could Increase

- IHS: Consolidation of Small E&P Cos Could Increase

Monday, August 29, 2011
IHS CERA

The uncertainty of future oil prices, combined with falling share prices on both London's Alternative Investment Market (AIM) Index and the Standard and Poor's (S&P) Index in the U.S., has made close to 100 small exploration and production (E&P) companies in the U.K. and two dozen large U.S. producers, prime targets for consolidation in order to achieve future funding, reports IHS in its IHS Herold Oil and Gas Perspectives Report.

"There are nearly 100 E&P companies listed on London's AIM, and while a number of these are small companies, numerous others have participated in apparently significant discoveries around the world that may turn into important oil and gas fields," said Robert Gillon, director of energy company research at IHS, and author of the weekly IHS Herold Oil and Gas Perspectives. "However, almost none of these AIM-listed E&Ps have reached the production stage, which means they are not yet generating revenue. Without revenue, they are dependent on future funding to continue operations. That funding can be accomplished either through additional share sales or a farm-out of an interest in their exploration licenses."

In addition to the AIM-listed companies, Gillon said there are about two dozen large (market cap $0.5 billion to $3.0 billion) U.S. oil and gas producers that could be ripe for consolidation as well. "Some of these U.S. companies are also reliant on external financing to fund their capital budgets, but all of them have developed reserves that could be sold in the very liquid transaction market."

Gillon said it is probably "not a coincidence" that the AIM-listed stocks peaked at about the same time as the Greek financial crisis, while the U.S. companies started to slide after oil prices topped out in April. On August 4, both indices took a serious hit, with the London group down 9.6 percent, while the S&P index shed 7.8 percent, and both have suffered further losses since then.

The AIM index is now down by 40 percent from its recent peak, which means the average company would need to sell almost 70 percent more new shares to raise the same amount of money as it did a few months ago. Meanwhile, optimism about future oil prices is more subdued, and the potential farm-in partners recognize that. As a result, they will demand more favorable terms on the deal. But commitments to the host government must be honored to hold the license.

"We believe there could be a wave of consolidation in the exploration sector," said Gillon. "Selling out will become the most attractive alternative."

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State: Additional Cook Inlet Investments Could Find New Gas

- State: Additional Cook Inlet Investments Could Find New Gas

Monday, August 15, 2011
Alaska Journal of Commerce
by Tim Bradner

An investment of $1 billion to $2 billion by natural gas producers in additional drilling in gas fields in Southcentral Alaska could meet projected gas supply shortages in the region until 2018 or 2020, possibly eliminating the need for local utilities to import liquefied natural gas.

A recent study by the state Division of Oil and Gas shows that if producers drill eight new production wells per year in the four largest gas fields in Cook Inlet Basin, the fields will produce sufficient new gas to meet the current 90 million cubic feet per day demand in the region at a cost of $10 million to $20 million per well with an additional $100 million investment in compression.

"This study considers what we think it will take, in terms of revenue, to get producers to produce additional gas we believe is in these fields, although we can't say the price that the field operators will feel is acceptable to make the investment," said Joe Balash, deputy commissioner in the state Department of Natural Resources, in the briefing.

ConocoPhillips, Marathon Oil Co. and Chevron Corp. are operators at the four fields included in the study.

The region's utilities, however, are skeptical that investments by producers will actually be made, and are proceeding with plans to have imported LNG available in Cook Inlet within three years.

"We can't take a chance. Our estimates show a supply gas in the region as early as 2014," said Jim Posey, general manager of Anchorage's city-owned Municipal Power & Light, one of several utilities in negotiations with potential LNG suppliers.

Despite what the state study said, Cook Inlet producers are actually drilling about half the new wells needed to sustain current production levels, Posey said. Four new development wells are planned for 2011.

The study by the Division of Oil and Gas examines gas reserves the state believes remain in the four largest gas fields, which include the Beluga, Ninilchik, North Cook Inlet and the McArthur River Grayling gas sands based on data that is public and some that is confidential, and relies on known costs for drilling and compression.

Balash said the state study included only the large producing fields and did not include new gas found though exploration, such as a recent 10 billion-cubic-foot gas discovery made by Buccaneer Energy LLC, an independent, on the Kenai Peninsula.

The study indicates that producers could earn a 20 percent internal rate of return in 2018 at a gas price below $6 per thousand cubic feet (mcf), a price that is about what producers are selling most gas produced in Cook Inlet, and a 15 percent rate of return on a gas price below $5 per mcf.

However, another assessment made in the study is that the net present value of many of the investments in wells will be modest, which could discourage some companies, particularly larger companies, from exploring, Balash said.

"It's quite possible that smaller projects could have quite good rates of return and yet have small net present values. This kind of investment might be very attractive for a small independent and less attractive for a larger company," said Jeff Dykstra, a commercial analyst in the state oil and gas division and one of the authors of the gas study.

Independent companies are in fact showing much more interest in Cook Inlet than are large companies such as the current producers.

"Most companies use several financial indicators in assessing possible investments including rate or return and net present value as well as their cash-flow needs," Bill Barron, director of the state oil and gas division, said in the briefing. Whether an investment will be made depends on a company's internal investment threshold, Barron said.

Information in the study will be used by state legislators next year as they consider additional funds needed for planning a possible $7.9 billion, 24-inch gas pipeline that could be built by the state from the North Slope. The 24-inch pipeline, which could bring gas from the slope to southern Alaska by 2019, is being considered as an alternative if a large 48-inch Alaska gas pipeline is seriously delayed.

Balash said the division will do a second increment to its Cook Inlet gas study taking into consideration a new estimate of technically-recoverable gas resources released by the U.S. Geological Survey. The USGS estimated that Cook Inlet could hold as much as 19 trillion cubic feet of conventional and unconventional gas resources, more than twice the amount of conventional gas discovered so far.

"We will try to determine a minimum economic field size that would allow some of these new resources to be developed," Balash said.

Copyright (c) 2011, Alaska Journal of Commerce, Anchorage

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IEA: Recession Could Put Oil Market Back Into Surplus

- IEA: Recession Could Put Oil Market Back Into Surplus

Wednesday, August 10, 2011
Dow Jones Newswires
LONDON
by James Herron

The International Energy Agency said Wednesday that a double-dip recession could reduce energy demand enough to push global oil markets into surplus next year, although it made only small adjustments to its current forecasts despite the deepening economic gloom.

This assessment indicates that the recent plunge in international oil prices, down more than 12% at Tuesday's close compared with the start of August, could have some way further to fall if developed economies do slip back into recession.

However, given the tremendous economic uncertainty and the current finely balanced state of the oil market, the IEA warned against pre-emptive action from oil producers to defend high prices. "There is no justification at the present time for OPEC to think of substantially adjusting production downwards," said David Fyfe, head of the Oil Industry and Markets Division at the IEA.

OPEC members have so far made a "concerted effort" to keep the market well supplied, the IEA said in its monthly oil market report. Its most important member, Saudi Arabia, raised production in July to its highest level in 30 years, as it filled the gap left by lost Libyan exports, it said.

If global growth this year and next falls below 3%--a level previously said by the International Monetary Fund to be indicative of recession--oil demand could be significantly lower than current forecasts, the IEA said. Such an outcome could push the world's need for crude from the Organization of Petroleum Exporting Countries below the group's current production, it said, implying a market in surplus.

The IEA made clear this was only one possible scenario and has only slightly trimmed its current 2011 demand growth estimates despite growing signs of trouble in major consuming countries the U.S. and China. However, it also warned that these forecasts were based on the most recent IMF global growth estimates of over 4% for this year and next, which, "may ultimately prove too optimistic," in the current economic climate.

The IEA noted "serious concerns" about the U.S. outlook given weak second quarter GDP and high fuel prices. In recent days, the IEA, the U.S. Energy Information Administration and OPEC have all slashed their demand forecasts for the U.S. The IEA now expects U.S. oil demand to fall by 200,000 barrels a day, or 1%, this year.

China, the world's second major engine of oil demand, is also looking weaker. "For the first time since March 2009, China's monthly apparent demand contracted on an annual basis, falling by 1.5% in June," the IEA said. "The decline coincided with evidence that China's economy is also slowing down and that higher end-user prices are weighing upon demand."

Copyright (c) 2011 Dow Jones & Company, Inc.

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Oil Cos Could Adopt BP's New Safety Standards - US Official

- Oil Cos Could Adopt BP's New Safety Standards - US Official

Friday, July 15, 2011
Dow Jones Newswires
WASHINGTON
by Tennille Tracy

The nation's top offshore drilling regulator welcomed a plan by BP Friday to voluntarily beef up safety standards and said ExxonMobil, Shell and other major oil companies are equipped to follow suit.

Speaking at a congressional hearing, the director of the Bureau of Ocean Energy Management, Regulation and Enforcement said BP knows it has to prove it can operate safely following last year's Deepwater Horizon oil spill in the Gulf of Mexico.

"BP has clearly been through a lot," said bureau Director Michael Bromwich. The company is going to have to "win back not only regulators' confidence, but the public's confidence as well."

BP disclosed Friday it was adopting drilling standards that go beyond existing federal requirements. Specifically, BP said it will require drillers to use more robust equipment, mandating subsea blowout preventers to be equipped with at least two blind shear rams.

BP also said it will use third parties to verify maintenance procedures and oversee testing, and enhance certain measures for responding to an oil spill.

Bromwich said he suspected that Exxon Mobil, Shell and other major oil operators could adopt similar measures, adding that the standards were technologically and economically viable for large companies.

Bromwich also said the measures that BP was undertaking could be folded into a set of new drilling regulations on which his agency is working. He said those new rules would be "broad" and "far-reaching," but he acknowledged the oil and natural-gas industry is wary of the agency adopting new requirements too often and too quickly.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Eliminating Tax Deductions on U.S. Energy Cos Could Increase Debt -Study

- Eliminating Tax Deductions on U.S. Energy Cos Could Increase Debt -Study

Wednesday, July 13, 2011
American Energy Alliance

Louisiana State University Endowed Chair of Banking and nationally-renowned economist Dr. Joseph R. Mason released a just-completed study that finds the Administration's proposal to carve out U.S. energy firms from receiving certain tax deductions would have a net negative impact on federal revenues. In his study, "Budget Impasse Hinges on Confusion among Deficit Reduction, Tax Increase and Tax Reform: An Economic Analysis of Dual Capacity and Section 199 Proposals for the U.S. Oil and Gas Industry," Dr. Mason finds repealing tax deductions for American energy manufacturers would result in:

• $30 billion in Federal tax revenue at the expense of some $341 billion in economic output;
• Over 155,000 lost jobs, $68 billion in lost wages, and $83.5 billion in reduced tax revenues; and,
• A net fiscal loss of $53.5 billion in tax revenues.

"The administration's proposal to eliminate tax deductions on U.S. oil and gas companies is grossly counterproductive toward the goal of increasing federal revenues," Dr. Mason said. "Such a move would have a net negative impact on revenue, thereby increasing federal deficits.

"If the goal is deficit reduction, a far more meaningful approach would be reforming federal tax and business policies that encourage economic growth. Expansion of oil and gas exploration and production on the Outer Continental Shelf, for example, would generate an estimated $11 billion annually in Federal tax revenue in the short run, and $55 billion annually in Federal tax revenue in the long run.

"Reform supports business development in both developing and developed countries, alike. The best reformers have several things in common. First, their reforms are part of a broad agenda of boosting global competitiveness and, second, they never stop. Even developing countries previously stung by fiscal imbalances and committed to business reform rarely retreat to increased taxes as a way to raise revenues. The U.S. should also step up to the challenge of reform."

Dr. Mason's conservative economic analysis employs the same government modeling – the U.S. Commerce Department's RIMS II system.

Dr. Mason's report was sponsored by the American Energy Alliance ("AEA"). To learn more and get exclusive information on upcoming projects, sign up for AEA's In The Pipeline.

Thomas Pyle, president of the American Energy Alliance, issued the following statement in response to the study's findings:

"This study confirms that President Obama's insistence on imposing discriminatory tax changes on American oil and gas companies has nothing to do with deficit reduction – it has everything to do with satisfying his anti-energy agenda. The president's insistence on these senseless tax hikes is further proof of his outright hostility to the oil and gas industry - an industry that provides over 9 million jobs and billions in revenue to the federal government."

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Could Energy Resources Cause Russia to Spark a Naval War in the Caspian?

- Could Energy Resources Cause Russia to Spark a Naval War in the Caspian?

Monday, July 11, 201
OilPrice.com
by John Daly

In the past three decades the Islamic Republic of Iran has developed a well-earned sense of paranoia. First, in September 1980 Saddam Hussein invaded Iran in what he thought would be a quick military victory, but which quickly turned into an eight-year bloody slugfest, leaving an estimated 500,000-1,000,000 dead before the guns fell silent.

More recently Iran has been subjected to increasingly militant rhetoric from both Tel Aviv and Washington over its civilian nuclear energy program, with thinly veiled threats of possible military action if Tehran does not abandon its efforts, even though they are completely complaint under the terms of the Nuclear Non-Proliferation Treaty (NPT), which Iran has signed.

Now however, potential is brewing for Iran from an unexpected direction - the north.

Russia is sharply increasing its military presence in the Caspian. Russian Federation Navy Commander in Chief Admiral Vladimir Vysotskii has stated that Russia's Caspian Sea Flotilla will receive up to 16 new ships over the next decade, while some aviation units will be transferred to the Navy from the Russian military's southern operational-strategic command. What has really got to have the mullahs in Tehran fingering their worry beads however is Vysotskii's promise to provide the Caspian Sea Flotilla with Bastion shore-based missile systems armed with Yakhont hypersonic missiles, which are designed to destroy surface targets at distances of up to 200 miles.

Russia's Caspian Sea Flotilla flagship, the Tatarstan frigate, is already the most powerful vessel on the Caspian, armed with Uran missiles with a range of 100 miles. Later this year the Tatarstan will be joined by a sister ship, the Dagestan.

The Caspian Sea Flotilla is also taking delivery of the first in a series of new Project 21631 Buyan-M-class rocket-artillery ships, along with three amphibious assault ships.

The Iranian Navy has a total of approximately one hundred, mostly small combat and supports ships on the Caspian. They include three Iranian-made midget submarines (of a North Korean type that can transport a group of combat divers and have a range of 1,200 miles), an outdated Salman-class minesweeper (American-made), and patrol cutters.

Russian analysts believe that Iran however has the ability to increase its Caspian naval forces by 50 percent in short order by relocating craft from the Persian Gulf.

As for the other Caspian littoral states - Azerbaijan, Turkmenistan and Kazakhstan, their naval forces are negligible, to be polite.

So, why is Russia beefing up its naval presence?

The most likely reason is the one that has bedeviled the region for the last two decades - a final treaty delineating the ownership of the Caspian's offshore waters and seabed has yet to be signed. While Moscow and Tehran might agree about keeping the U.S. locked out of exploiting the Caspian's energy resources, worth an eye-watering $3 trillion, they remain at loggerheads over the issue of dividing the Caspian, with Russia insisting that each nation receive offshore waters in proportion to its coastline, while Iran insists that all five nations receive an equitable twenty percent apiece. Under the Russian definition Iran's share would be 11-13 percent.

Complicating the issue is that international law has yet to definitively designate whether the Caspian is an inland "sea" or a lake, an adjudication which has enormous implications for both the applicability of the 1982 U.N. Convention on the Law of the Sea and negotiation of the boundary demarcation regime affecting the littoral states' rights to significant undersea oil deposits.

Ironically, Iran has itself played the "gunboat diplomacy" card in the past. On 23 July 2001, an Iranian warship and two jets forced two Azeri research vessels, the Geofyzik -3 and the Alif Hajiyev, operating in what Azerbaijan calls the Alov oilfield on behalf of BP-Amoco, to leave the field where they were conducting surveys, which lies 60 miles north of Iranian waters. BP-Amoco immediately announced it would cease exploration activities and withdrew the research vessels. Azerbaijan denounced the move as a violation of its sovereignty and on 31 July charged that an Iranian reconnaissance aircraft had violated Azeri airspace and come within 90 miles of Baku. Ramping up the pressure, Iranian former Pasdaran Commander Mohsen Reza'i pointedly reminded Azerbaijan that the whole country had once been Iranian territory and that Iran might decide to take it back, even as the Iranian press speculated that the whole thing was a provocation cooked up by Azerbaijan who was scheming to bring about American intervention in the Caspian.

In the unlikely event that hawks in Washington ever considered, then or now, to fly the Stars and Stripes on the Caspian while taking a few potshots at the evil Russkies or the even more perfidious Axis of Evil mullahs, then geography seems to have thrown a spanner in the works, as the Caspian's sole exit point, the Volga-Don canal, is controlled by... Moscow.

What seems to be happening is that Russia has decided that gunboat diplomacy has its uses, and an upping of its naval presence in the Caspian might finally persuade Iran's obstinate mullahcracy that it's time to divvy up the Caspian pie according to Moscow's formula.

And, after all, 11-13 percent of $3 trillion is no small chunk of change, even to an OPEC member.

(John Daly is an energy and geopolitical specialist with OilPrice.com. The full article is available here.)

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GOM Employment Could Increase if Admin. Allows -Study

- GOM Employment Could Increase if Admin. Allows -Study

Monday, July 11, 2011
American Petroleum Institute

Almost 190,000 new jobs could be created in 2013 if permitting in the Gulf of Mexico for offshore development returned to levels before the Obama administration's moratorium, a study by Quest Offshore Resources, Inc., says. The study, "United States Gulf of Mexico Oil and Natural Gas Industry Economic Impact Analysis," also projects a 71 percent increase in Gulf development spending to $41.4 billion and a 70 percent increase in economic activity related to Gulf development to $44.5 billion.

"The slow pace of Gulf development since the accident has cost jobs, revenue and energy production," said API President and CEO Jack Gerard. "The study shows what could be accomplished on jobs if project approvals and permits could get back to a normal pace. We've done the necessary work raising the bar on safety. We cannot continue to delay developing energy and hiring people in the Gulf. The disappointing unemployment numbers from the government last week make this more important than ever," Gerard added.

Quest Offshore conducted the study for API and the National Ocean Industries Association. Quest based its forecasts on actual project development data and historical benchmarks of spending for specific equipment and services.

"Total employment related to offshore Gulf of Mexico oil and natural gas industry operations could reach 430,000 jobs in 2013 if the permitting slowdown is reversed," Gerard said. "As large as the jobs numbers are, however, they are just a fraction of all the jobs our industry could create with more forward-looking development policies in all federal onshore and offshore areas. And along with the increased jobs and energy production could come hundreds of billions of dollars of desperately needed additional revenue to the government. Policymakers now debating tax increases on the industry should understand that producing at home more of the oil and natural gas our nation will need is a far better way to help fix our economy and pay down our debt," Gerard said.

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U.S. Gas Exports to Mexico Could Grow in 2012

- U.S. Gas Exports to Mexico Could Grow in 2012

Monday, June 27, 2011
Rigzone Staff
by Karen Boman

Exports of U.S. natural gas into Mexico are expected to average 1.3 Bcf/d, a 450 MMcf/d increase from 2010, and the tightening of Mexican supply/demand balances should lead to further U.S. export growth in 2012, Barclays Capital reported last week.

Exports to Mexico grew sharply in the beginning of the past decade before stabilizing in the 850 MMcf/d range from 5001-2010; however, first quarter 2011 exports averaged the highest in the past 10 years.

U.S. gas exports to Mexico represent a relatively small part of U.S. gas balance, or one percent in 2010, and have not attracted much attention, but the exported BTUs are starting to add up, and more important, several factors suggest this trend could continue in the next few years. Barclays expects U.S. flows to Mexico to increase by another 200 MMcf/d in 2012, to an average of 1.5 Bcf/d.

While gas is primarily used for refining and petrochemicals production and reinjection for oil production, power generation has been driving gas demand growth, and plans for generation capacity additions suggest that Mexico's gas consumption should grow rapidly in the next few years.

Domestic production also is in decline, showing a growing need for imports. more than 60 percent of Mexico's gas output comes in association with oil production. While associated gas is growing slightly, non-associated production is steeply declining, with PEMEX reporting a decline of non-associated gas output of 13 percent year/year for the first four months of 2011. "While LNG imports could meet some of the incremental demand, they are disadvantaged in favor of cheaper U.S.- sourced gas," Barclays said in a June 21 report.

Shale gas development in Mexico is one bright spot for Mexican non-associated gas output. Earlier this year, PEMEX reported production of its first shale gas at an exploratory well in the Eagle Ford shale formation in the northeastern state of Coahuila. PEMEX plans to drill 10 additional wells, including in the La Pena and Glenrose formations, targeting gas and condensates.

"While the potential for Mexico shale gas production could be significant, its development is at an early stage, and there is considerable uncertainty about the scale and time-frame for shale production growth," Barclays said.

Mexico has technically recoverable shale gas resources of 681 Tcf, according to the U.S. Energy Information Administration's April report, World Shale Gas Resources: An Initial Assessment of 14 Regions Outside the United States. Mexico has five basins, including the Burgos, Sabinas, Tampico, Tuxpan and Veracruz, and eight gas shale formations.

Thick, organic-rich and thermally mature source rock shales of Jurassic and Cretaceous-age occur in northeast and east-central Mexico, along the country's onshore portion of the Gulf of Mexico Basin. These shales are time-correlative with gas productive shales in the U.S., including the Eagle Ford, Haynesville, Bossier and Pearsall shales.

However, compared with the shale belts of Texas and Louisiana, Mexico's coastal shale zone is narrower, less continuous and structurally much more complex.

Advanced Resources International estimates that the five Mexico onshore basins assessed in the EIA study contain approximately 2,366 Tcf of geologically risked shale gas-in-place. Structural complexity (faulting and folding), excessive depth of over 5,000 meters, and locally thin or absent shale on paleo highs constrain the resource assessment.

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Rosneft Sell-off Could Be Brought Forward to 2012 - Report

- Rosneft Sell-off Could Be Brought Forward to 2012 - Report

Monday, June 20, 2011
Dow Jones Newswires
LONDON
by London Bureau

Russia wants to hasten its planned privatization of state-owned oil giant Rosneft in the wake of the collapsed share swap deal with U.K. supermajor BP, the Guardian reports Monday, citing an interview with one of President Dmitry Medvedev's key economic advisers.

"We want Rosneft to be a normal commercial company," said Arkady Dvorkovich, according to the paper. "The original government proposals were to start [the share sale] in 2013 but maybe now will be brought forward to 2012," Dvorkovich said.

The Russian government was planning to sell more than 85% of its stake in the company in 2013 if BP had gone ahead as planned. Now ministers are looking at bringing this process forward a year, the newspaper reports, adding that state control in the firm could fall below 50%.

The government would be happy if BP bought shares in Rosneft, according to the Guardian.

Copyright (c) 2011 Dow Jones & Company, Inc.

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Little Lizard Could Cause Big Disruptions for Texas Drillers

- Little Lizard Could Cause Big Disruptions for Texas Drillers

Monday, June 20, 2011
Fort Worth Star-Telegram, Texas
by Anna M. Tinsley

Deep in the West Texas sand dunes is something that some say could threaten the state's oil and gas production: A tiny lizard.

But it's not just any lizard: It's a dunes sagebrush lizard, also known as the sand dune lizard.

This little brown reptile is a concern for state officials, who hope that federal officials don't designate it an endangered species. That, they say, could disrupt oil and gas exploration in the heart of Texas' oil country, leading to higher gas prices and shrinking dollars for schools.

"It's reptile dysfunction," said Texas Land Commissioner Jerry Patterson, who oversees the permanent school and university funds, which get money from royalties and leases on some of the potentially affected land. "It has the potential to bring oil exploration and production to a halt."

The U.S. Fish and Wildlife Service, which has had the issue before it for about a decade, is considering protections because oil and gas exploration and ranching are shrinking the lizard's habitat. A decision could come by year's end.

The lizard

The blunt-nosed lizard at the heart of the issue has bright yellow eyes but is barely as long as a person's hand. The lizard is important prey for a number of other species, including some birds and mammals.

It can be found in the West Texas counties of Andrews, Crane, Gaines, Ward and Winkler -- part of the Permian Basin, known to petroleum officials as the most "prolific oil-producing region in onshore America" -- as well as in southeast New Mexico.

There it lives, in the shade of shinnery oak trees, which look like bushes and are found mainly in the sand dunes. The lizard lives only in dunes that have medium-size sand grains.

Environmentalists say the spiny lizard is in danger of extinction because its habitat has been disturbed or removed by oil and gas development. Shinnery oaks, for instance, have been destroyed by drillers, who clear space and move equipment. They have also been killed by ranchers, who say the plant can be poisonous to cattle.

The lizard has been a candidate for endangered status since 2001, when the Center for Biological Diversity asked the federal government to list it. But this proposal was moved forward at least in part because of a federal lawsuit by the environmental advocacy group WildEarth Guardians.

"I think the current federal proposal is based on a number of years of examining the status of the lizard," said Ken Kramer, director of the Lone Star Chapter of the Sierra Club. "It's not a last-minute sort of proposal."

State opposition

Patterson, who has compared the sand dune lizard to Godzilla for its ability to potentially freeze gas and oil work, said this fight is about more than just a reptile.

It's about what he said is a new strategy to gain endangered status for many animals and essentially block industries from doing their work.

"You overwhelm Fish and Wildlife with requests ... and rather than do science on several hundred species, they just settle the lawsuit," he said.Patterson, who has held a sand dune lizard and said it actually is "a cute little bugger," is calling on federal officials to reject the proposed designation.

"The science is not complete, it's out of date, and there's no decent information that has been sufficient to warrant the designation," he said. "If the designation comes, and it isn't based on sound science, we will file a lawsuit."

Texas Agriculture Commissioner Todd Staples, University of Texas System officials and Texas Association of Business President Bill Hammond also oppose the designation.

UT System officials manage more than 2.1 million acres for the benefit of the system, including acreage that could be a habitat for the lizard. They sent a letter to federal officials saying that listing the lizard as endangered is "at best premature" because that decision would be based on "faulty science, inadequate data and seriously erroneous assumptions."

Patterson said that a herpetologist from Texas A&M University has been hired and that studies of the lizard have been commissioned.

The Texas Endangered Species Task Force, primarily made up of property and business owners who could be affected, is developing conservation plans, said R.J. DeSilva, a spokesman for the Texas comptroller's office.

"The goal is to have a plan by November," he said. "There's a need to balance the development of the industry, and economic development in the industry, and take actions to mitigate and preserve the habitat."

Political move?

This year, the Obama administration said a decade's worth of petitions to add wildlife to the endangered species act would be addressed over the next six years.

About 1,400 plant and animal species are designated endangered. Officials work to protect their habitats and review what can be done. Several Texas Republicans in Congress, including Reps. Michael Conaway of Midland, Randy Neugebauer of Lubbock and Francisco Canseco of San Antonio, have asked colleagues to keep the lizard from being designated as endangered. Sen. John Cornyn filed an amendment to prevent federal officials from offering protections to the lizard.

"If the Obama administration has its way, this scaly political pawn will land on the Endangered Species List, without sufficient supporting research to back up the move, and effectively bring new and existing oil and gas production in parts of Texas and New Mexico to a screeching halt," he said in a statement.

Federal officials say they used the best science available and are working with companies to minimize problems or interruptions. Some petroleum companies have signed on to voluntary conservation agreements, agreeing to pay for habitat restoration and use techniques to lessen the impact on the lizards.

Kramer, of the Sierra Club, said he believes that state and industry officials are exaggerating the crisis.

"Practically every time there is a proposal, we get these people saying ... 'The sky is falling. This is going to be the end of civilization as we know it,'" Kramer said. "There is almost always an overreaction based upon their lack of understanding in which the species can be protected."

Copyright (c) 2011, Fort Worth Star-Telegram, Texas

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Oil-Extraction Method Could Reduce Greenhouse Gas

- Oil-Extraction Method Could Reduce Greenhouse Gas

Monday, June 13, 2011
The Columbus Dispatch, Ohio
by Spencer Hunt

A gas tied to climate change could someday bring new life to old Ohio oil fields.

State officials are investigating whether carbon dioxide could be used to draw millions of barrels of crude oil from fields that were all but played out.

Energy companies have injected carbon dioxide into old oil fields in Texas and California for decades. The gas increases the pressure underground and mixes with the oil, freeing it from nooks and crannies.

"It lightens the oil. It fluffs it up," said Larry Wickstrom, chief of the Ohio Geological Survey. "It actually makes it so you can push (the oil) through."

Wickstrom oversaw Ohio's first test, during which 81 tons of carbon dioxide were pumped into a low-yield well about 10 miles southeast of Canton in Stark County.

After the injection in 2008, the well produced 58 percent more oil. The results were so promising that they inspired a state proposal for more-extensive testing by Columbus-based research giant Battelle and $11 million in federal funding.

Officials say the project could help reduce climate change and increase U.S. oil production.

"There is a substantial opportunity here," said Neeraj Gupta, Battelle's senior research leader for geological carbon storage.

The idea isn't embraced by all. Environmental advocates say that a substantial amount of carbon dioxide returns to the surface with the oil.

"I don't doubt the workability of enhanced oil recovery," said Nachy Kanfer, the Midwest coordinator of the Sierra Club's coal-to-clean-energy campaign. "I doubt carbon dioxide's ability to remain underground."

Carbon dioxide was first used in the oil fields of western Texas in 1972. Wickstrom said it hasn't been used in Ohio's oil fields because there is no readily available supply.

That might seem a little strange, considering the millions of tons of carbon dioxide that coal-fired power plants in Ohio emit each year. But capturing and transporting the gas is not cheap.

FirstEnergy's Sammis plant and American Electric Power's Cardinal plant, which are along the Ohio River, emitted a combined 23.1 million tons of carbon dioxide in 2010. They are within about 40 miles of the test site.

The process to draw a pure stream of carbon dioxide can consume one-third of a power plant's electricity. Power companies still are testing equipment that could do that.

Gary Spitznogle, AEP's director of new-technology development, said power plants probably would charge $80 to $100 per ton to cover their costs. He estimated that commercial carbon dioxide sells for $20 to $40 a ton.

Wickstrom and Gupta said the money made by wringing more oil out of the ground could help offset those costs.

The test site was at the 175,000-acre East Canton oil field in Carroll, Harrison, Stark and Tuscarawas counties. Officials say that more than 1 billion barrels might remain there. Pumping carbon dioxide into the wells could draw as much as 279 million barrels from the field.

A more-extensive test at the site, involving as much as 20,000 tons of carbon dioxide injected over months, would help to confirm those early estimates, officials say.

Wickstrom said the state and Battelle have applied for an $11 million U.S. Department of Energy grant to help conduct that test. They won't know until September whether they'll get the money.

In the meantime, Battelle is involved in several federally funded projects to see whether carbon dioxide can be safely injected and stored underground. It's also helping AEP test a system that captures and injects 1.5 percent of the carbon dioxide produced by its Mountaineer power plant in West Virginia.

As far as using carbon dioxide to free oil, a larger test also would show how much of the gas resurfaces with the oil.

Wickstrom said that, on average, 20 to 30 percent of the carbon dioxide that's injected comes back up.

Gupta said wells in Texas and California include equipment to capture the carbon dioxide that comes off the oil so that it can be recycled and reinjected.

"There is a huge economic potential for more oil supply and storage of CO2 if we can make this work," Gupta said.

Copyright (c) 2011, The Columbus Dispatch, Ohio

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Eagle Ford Production Could Overtake Barnett, Haynesville

- Eagle Ford Production Could Overtake Barnett, Haynesville

Thursday, May 19, 2011
Rigzone Staff
by Karen Boman

The liquids rich Eagle Ford shale play in southwest Texas may overtake the Barnett and Haynesville shale gas plays in Texas and Louisiana in terms of production, potentially becoming the largest producing shale play in Texas and the entire U.S., according to a recent report by London-based Evaluate Energy.

The Eagle Ford is currently dwarfed by its neighbors in terms of production, with the Barnett producing 877,000 BOE/d, the Haynesville producing 708,000 BOE/d and Eagle Ford producing 66,000 BOE/d in the fourth quarter of 2010. However, a recent surge in new wells suggests this all about the change, with horizontal drilling for both oil and gas in the Eagle Ford growing rapidly.

Source : Evaluate Energy

Drilling activity in the 22 Texas counties that Eagle Ford formation encompasses has been growing dramatically for the past year, and at the end of first quarter 2011, the area had the most new wells being drilled in Texas. In comparison, the number of new horizontal wells in Barnett Shale counties has fallen to a much lower level than its mid-2008 peak. The number of new wells in Haynesville counties in Texas and Louisiana also has slipped into a slight decline following a two-year increase up to the second quarter of 2010.

Like its Texas counterparts, Eagle Ford drilling activity is now mostly development drilling, which suggests that Eagle Ford production may overtake Barnett and Haynesville production sooner rather than later, Evaluate noted.

EIA Shale Gas Estimate Jumps 134 Percent

Oil and gas producers have increasingly switched their focus from drilling shale gas plays to oil shale plays after the U.S. shale gas drilling boom significantly increased U.S. gas supply and depressed U.S. gas prices.

The supply increase has prompted the U.S. Energy Information Administration (EIA) to raise its estimate of technically recoverable shale gas resources by 134 percent. In its Annual Energy Outlook 2010, technically recoverable shale gas resources were estimated at 368 Tcf. For its Annual Energy Outlook 2011, EIA's estimate rose to 862 Tcf, bringing total U.S. recoverable gas resources to 2,629 Tcf.

EIA attributed the increase in gas resources to technological advances in horizontal drilling and hydraulic fracturing. "This is a welcome change because as little as 10 years ago, analysts and politicians said that the United States could not drill its way out of a natural gas shortage," EIA said.

U.S. shale gas produced 2.3 Tcf of natural gas in 2008, or 11 percent of the U.S. gas market share, and is expected to produce 12.3 Tcf by 2035, a 47 percent share of the gas market. U.S. shale gas resources are the second largest in the world behind China, according to a study EIA commissioned with ARI International.

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Offshore Regulation Could Grow

Offshore Regulation Could Grow

Wednesday, April 13, 2011
Houston Chronicle
by Jennifer A. Dlouhy

The Obama administration is exploring whether to expand federal oversight of offshore drilling beyond oil and gas companies to rig suppliers, oil field services providers and other contractors now outside regulators' reach.

Michael Bromwich, the director of the Bureau of Ocean Energy Management, Regulation and Enforcement, told reporters Tuesday that the existing system imposes artificial limits on what his agency can do to make offshore drilling safer. Its enforcement power now ends with oil and gas companies that hold leases to drill in U.S. waters.

"That dramatically limits the scope of our oversight," he said. "It is very important for our regulatory oversight to extend as broadly as possible to all of the entities that are operating offshore and not for us to be artificially limited just to the individual operator that applies for permits and submits exploration plans."

Bromwich said that approach may have seemed adequate before the lethal blowout of BP's Macondo well nearly a year ago -- which killed 11 and started a multimillion-gallon oil spill -- but isn't compatible with the regulatory agenda that arose from the disaster.

"We are very interested in pushing that in an aggressive and in a responsible way," he said, "and if that requires us to extend our scope beyond the operator, that's something that needs to be seriously considered."

Last year's accident sharpened lawmakers' and regulators' focus on the broad spectrum of companies involved in offshore drilling.

According to the presidential commission that investigated the oil spill that began last April 20, the disaster was the result of a series of decisions made by BP and its contractors at the site, including Transocean, which owned the Deepwater Horizon drilling rig, and Halliburton, which did cement work.

 

Opposed by GOP?

Any move to expand the ocean energy bureau's regulatory powers would probably require congressional action, according to a preliminary review by Interior Department officials. And it seems unlikely that key lawmakers would be eager to bolster the bureau's rule-making authority, especially in the House, where Republicans are moving to limit the agency's discretion.

The bureau can impose requirements on equipment used and work done by contractors, but oil and gas companies operating offshore are ultimately responsible for whether those mandates are fulfilled.

 

No immediate position

"Even though a lot of this stuff is done by somebody else, the requirements still apply to the activity," said Erik Milito, upstream director for the American Petroleum Institute, which didn't take an immediate position on expanding the agency's authority. "As far as who is ultimately responsible for that, generally it is the operator."

Separately, the government is reviewing how to consider companies' safety records and other factors in weighing their proposed offshore drilling projects.

Bromwich said the ocean energy bureau is evaluating the evidence "that ought to factor in as to whether a company can continue to be a player" but said it could include disciplinary records, history of violations and past fines.

 

More funding

The government imposed a swath of new safety and environmental mandates after the Deepwater Horizon disaster, including a requirement that companies prove they have the equipment and know-how to harness crude from any future deep-water well blowout.

The ocean energy bureau can count on a big boost in funding -- at least for a few months -- under the budget deal congressional leaders and the White House reached last week.

The legislation to keep the government running through the end of fiscal year 2011 on Sept. 30 includes $47 million more for the bureau than it got in fiscal 2010.

That's about half as much as the administration wanted to add to the agency's fiscal 2011 funding, but the boost came amid cuts totaling $40 billion in many non-defense programs.

 

Hiring more inspectors

Even other units of the Interior Department didn't fare as well. For instance, funding for the Bureau of Land Management, which handles onshore oil and gas leases, would be trimmed $18 million from the fiscal 2010 level.

The administration has asked Congress for $358 million in fiscal 2012, which would allow the bureau to hire 116 new offshore inspectors, triple what it has now, and 41 new permitting personnel, nearly doubling the current 50-member team. Much of the administration's planned funding increase would come from proposed new fees on oil and natural gas producers.