Penn State Study Finds Smaller Marcellus Jobs Impact; 'Still Big Numbers'

- Penn State Study Finds Smaller Marcellus Jobs Impact; 'Still Big Numbers'

Tuesday, August 30, 2011
Pittsburgh Post-Gazette
by Bill Toland

Jobs related to natural gas drilling in Pennsylvania's Marcellus Shale field were about half what previous studies had estimated for 2009, but the industry still supported about 23,500 jobs that year, according to a new study issued by Penn State researchers.

"It's still big numbers," said Timothy W. Kelsey, professor of agricultural economics with Penn State's College of Agricultural Sciences, and one of the study's authors.

"It's just not as big as what the industry is talking about."

The study, issued Monday by the Marcellus Shale Education & Training Center, a partnership of the Pennsylvania College of Technology and the Penn State Extension, also said that about half of the land being leased by drillers was owned by people living in those counties in 2009 -- the rest was owned by people or firms based out of state or elsewhere in Pennsylvania, or owned by the state itself.

That means much of the leasing and royalty money derived from drilling goes out of the county in which the drilling takes place, according to the study.

It's an economics phenomenon known as "leakage" -- money that looks as if it is benefitting a particular area is actually going elsewhere. And it's not an economic phenomenon native to gas drilling: Coal interests, limestone and gravel deposits and other mineral-related economic activity is subject to the same kind of leakage.

The study, "Economic Impacts of Marcellus Shale in Pennsylvania: Employment and Income in 2009," bills itself as the first paper to look at not just the number of jobs and amount of revenue generated by drilling but also where that money is going and how quickly it's being spent.

The jobs figure, as with previous studies, accounts for actual jobs created -- front office jobs, drilling jobs, engineering jobs -- as well as "induced" and "indirect" jobs, which are those not created by the industry itself but by the money the industry spreads around to local suppliers, hotels and restaurants, for example.

The study suggested that the industry generated around $3.1 billion in economic activity -- $1.2 billion in income and $1.9 billion in "added value."

Also of note was that locals who benefit from the gas play do not spend their lease and royalty checks immediately, meaning the money is not a direct, immediate benefit to the local economy. By surveying landowners in Bradford and Tioga counties, the study's authors estimate that leaseholders save or invest about 55 percent of leasing proceeds and about 66 percent of royalty payments in the year they are received, instead of spending the money.

The study's attempt to get a more accurate read on who -- and which areas -- benefit from drilling activity was hampered, Mr. Kelsey said, by the absence of any state or county database for who owns mineral rights (and thus owns the royalty rights to gas and shale deposits).

While it was relatively easier to find out who owns the land being leased -- about 51 percent of drilling plots are owned by people in that county -- it's far less clear who owns the rights to the gas below the surface and where those people live. The researchers, in calculating the economic benefits of the shale play, assumed an identical local ownership share (51 percent) for the mineral rights as well as the surface rights.

"We know that's not accurate," Mr. Kelsey said. "But there isn't anybody who has that data."

In many cases, mineral rights were separated from surface rights decades ago. It's more likely, he said, that the mineral rights owner lives out of state than the actual landowners, which means that it's also more likely gas royalty payments are going out of state.

But suspecting that and finding data to prove it are two different things, he said.

The state and county assessment offices need to do a better job of tracking that information if they want to have a more accurate picture of where mineral rights royalties are going, he said.

The study also surveyed 2,000 randomly selected businesses in Bradford and Washington counties to "identify the impacts they are experiencing from Marcellus Shale development." The responses "indicated positive economic impacts are occurring broadly across the economy in the communities where drilling is very actively occurring."

About 23 percent of Washington County business respondents said that natural gas drilling had helped to improve sales, while only 2 percent of respondents said that the drilling had hurt sales.

The full paper is available at http://extension.psu.edu/naturalgas/publications.

The study was paid for by funding from state Department of Community and Economic Development and money from Penn State and the Pennsylvania College of Technology.

(c)2011 the Pittsburgh Post-Gazette. Distributed by MCT Information Services.


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IEA 'Still Assessing' Oil Market after OPEC Stalemate

- IEA 'Still Assessing' Oil Market after OPEC Stalemate

Tuesday, June 14, 2011
Dow Jones Newswires
PARIS
by Geraldine Amiel

The International Energy Agency is in talks with member countries following last week's OPEC meeting and is "still assessing" the oil market situation before considering any potential response, Executive Director Nobuo Tanaka said Tuesday.

Tanaka reiterated that the IEA "stands ready to act" if the market requires additional oil. At the same time, Tanaka, whose organization represents consuming countries, expressed confidence that Saudi Arabia could pump additional oil to meet supplies, he said in an exclusive interview with Dow Jones Newswires. The IEA has authority to coordinate an emergency response of oil from its member governments.

Tanaka's remarks came less than a week after a Vienna meeting of the Organization of Oil Exporting Countries concluded in acrimony after members failed to agree to boost output to meet anticipated demand growth. The surprising outcome continued to reverberate Tuesday, as OPEC's Secretary General expressed concerns that oil prices could rise later this year.

OPEC split last week on whether to boost output by some 1.5 million barrels a day, a plan favored by Saudi Arabia and some other Gulf producers. Some OPEC members, including Iran, were skeptical additional supplies were needed. The members that fought the increase have also tended to favor somewhat higher oil prices.

OPEC Secretary General Abdalla Salem Al-Badri, the official spokesman for the organization, said Tuesday that oil prices "will go up for sure" if the would rise later this year if the supply gap in many official forecasts comes to fruition, Reuters reported. The OPEC official was also quoted as saying high prices will hurt economic growth, Reuters said.

Also Tuesday, EU Energy Commissioner Gunther Oettinger told Dow Jones Newswires in Stockholm that the European Union plans to discuss oil market issues at a meeting with OPEC in Vienna later this month.

"We want to speak (with OPEC) about security of supply for 2011 and 2012 and to speak about what is a feasible price," Oettinger said in an exclusive interview.

Asked whether he was worried about a high oil price, Oettinger said: "No, I'm not worried".

Meanwhile, Tanaka said he was confident Saudi Arabia could use its spare production capacity to put additional oil on the market following the OPEC meeting. Saudi Arabia plans to immediately boost output to as much as 10 million barrels a day, Gulf sources have said.

The issue will be "how fast" the Saudis can put additional oil on the markets, Tanaka added, noting that Saudi domestic oil consumption is expected to increase during the summer.

Tanaka later told the audience that the at the IEA, "we stand ready to take all our options." But Tanaka said the IEA would tap emergency supplies only after a "disruption" such as if Saudi Arabia and other OPEC members were unable to pump more oil. He said some of the current anxieties were reminiscent of the oil market in 2008.

The IEA warned on May 19 that it was prepared to "consider using all tools" if OPEC failed to boost output, a statement that was seen by producers as a veiled threat that the IEA would tap strategic supplies if OPEC didn't pump more oil.

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

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Banda Results Poor But Still Encouraging

- Banda Results Poor But Still Encouraging

Monday, June 06, 2011
Kosmos Energy Ltd.
by SubseaIQ

Kosmos announced that the company's Banda-1 exploration well has discovered oil offshore the Republic of Ghana on the West Cape Three Points Block. The results of drilling, wireline logs and reservoir fluid samples show the Banda-1 well penetrated net oil-bearing pay of 3 meters (10 feet). Oil samples recovered from the Cenomanian-age reservoir indicate oil of approximately 40 degrees API gravity.

The Banda-1 discovery opens a new play fairway not previously encountered on the West Cape Three Points Block or adjacent Deepwater Tano Block. The Paradise-1 exploration well, recently drilled by Hess, successfully penetrated a hydrocarbon-bearing, equivalent-age reservoir. The Paradise-1 well is located 32 kilometers (km) (20 miles) southwest of the Banda-1 well location. The Banda-1 well also was designed to test the Upper Campanian interval, which was water bearing. Additional technical evaluation will be required to analyze the impact and extent of this new play discovery, which is deeper than existing Campanian and Turonian discoveries on Kosmos' Ghana blocks.

The Atwood Hunter semi-submersible rig drilled the Banda-1 well in a water depth of 921 meters (3,021 feet) to a total depth of 4,580 meters (15,022 feet) in the eastern portion of the West Cape Three Points Block. The well is located 28 km (17 miles) east of Kosmos' Mahogany-1 exploration well that discovered the Jubilee oil field in 2007.

Tullow's Exploration Director Angus McCoss commented, "The Jobi-East-1 and Mpyo-3 well results mark an excellent start to this next phase of our exploration and appraisal campaign in the Lake Albert Rift Basin. We look forward to many more exciting wells as we endeavor to determine the total oil resource base which will underpin the basin-wide development preparations currently in progress."
West Cape Three Points Block Ownership Interest

Kosmos Energy is the operator of the West Cape Three Points Block in which the company holds a 30.875% interest. An affiliate of Anadarko Petroleum Corporation has a 30.875% interest; an affiliate of Tullow Oil plc has a 22.896% interest; E.O. Group Limited has a 3.5% interest; Sabre Oil & Gas Holdings Limited has a 1.854% interest; and Ghana National Petroleum Corporation has a 10% carried interest.

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European Shale Gas Is Still Hot Air

- European Shale Gas Is Still Hot Air

Tuesday, May 31, 2011
Dow Jones Newswires
by Andrew Peaple

Shale gas has been a game-changer for U.S. energy markets. Following an estimated $250 billion of investment, 23% of US gas production now comes from rocks several thousand meters underground, up from 1% 10 years ago. Could Europe see a similar shale gas revolution?

That seems unlikely for the moment. True, Europe could have 639 trillion cubic feet of shale gas, only 25% less than the U.S., according to the U.S. Energy Information Administration. That could reduce its reliance on gas imports and more polluting alternative fuels. Around 50 companies are exploring for gas now, from majors like ExxonMobil to small independents.

But European shale gas is likely to be much more costly to develop. European shale depths are on average 1.5 times lower than in the U.S., according to the Oxford Institute for Energy Studies. Europe's dense population doesn't help, as the number of wells needed for commercial shale gas production requires lots of space. Drilling costs are also likely to be higher in Europe, given the lack of a high-tech services sector to support the industry.

Meanwhile shale gas faces opposition from environmentalists who fear the extraction process could damage water supply. France is close to banning activity, despite having substantial potential reserves. Production costs could be as high as $16.2 per thousand cubic feet (mcf), according to OIES. That compares with the $8.7 per mcf Gazprom, Europe's main gas supplier, charged for contracted gas in 2010. Existing gas imports from Russia and Africa cost between $3 and $6 per mcf, while US shale gas production costs are around $3 per mcf.

Clearly, the outlook for shale gas would improve if gas prices rise. But few expect them to rise high enough to make European shale gas profitable; Bernstein Research expects prices to reach $13.8 mcf by 2015 while Wood Mackenzie expects oil-linked gas prices to rise to only around $11 per mcf by 2025. And in the U.S., the shale gas supply shock has seen prices fall rapidly, meaning producers' returns on investment are in single-digits now, according to TPH.

Europe's shale gas revolution may be a long time coming.

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

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Cook Inlet Drilling Still Lags Pace Needed to Sustain Gas Supply

Cook Inlet Drilling Still Lags Pace Needed to Sustain Gas Supply

Monday, May 09, 2011
Alaska Journal of Commerce
by Tim Bradner

More drilling is under way in Cook Inlet natural gas fields, but the pace is still short of the number estimated to needed to forestall shortages of gas in the region.

Still, there are glimmers of hope. Although the quantities are still small, new gas is coming into Enstar Natural Gas Co.'s pipeline system from a new producer, Armstrong Oil and Gas.

Also, explorers drilling for gas in Southcentral appear to be finding some, although it is too early to know whether the wells can be commercially produced.

The overall pace still falls short of what is needed.

Firms operating producing fields in Southcentral Alaska this year plan four new production wells. Independent companies also have drilled three exploration wells this winter. The last one, being drilled near the city if Kenai, is now being completed.

However, seven new gas wells in total drilled this year are less than half the 18 new wells estimated to be needed each year if the region's gas reserves are to be sustained.

The estimate was done for the regional utilities in 2010 by Petrotechnical Resource Alaska, an Alaska-based petroleum-consulting firm.

Meanwhile, Southcentral electric utilities have kicked off construction of a number of new gas-fueled power generation facilities, but there are questions about where the gas for these new plants will come from.

Chugach Electric Association and Municipal Light and Power have the new $369 million Southcentral Power Project plan underway in south Anchorage.

Matanuska Electric Association's new $250 million gas-fired generation plant in Eklutna is in the early stages of permitting.

Homer Electric Association also has two new, smaller power generation projects, one that has started construction.

The Regulatory Commission of Alaska has approved Chugach's request to pass its share of the Southcentral power plant costs, about $200 million, on to its customers. A similar request is anticipated from ML&P for its one-third share, RCA chairman Bob Pickett said.

Although the turbines in the new facilities will be more efficient, typically using a third less gas to generate power than older equipment now used, the net result may still be an increase in total gas use.

It isn't clear where the gas will come from. A gas pipeline from the North Slope is years away, if it can even be built. Several utilities, including the regional gas utility, Enstar Natural Gas Co., are working on possible imports of liquefied natural gas.

"There's not much we can say about it right now," Enstar spokesman John Sims said.

Jim Posey, ML&P's general manager, said about the same.

"I'm much more encouraged about this than I was three months or six months ago," Posey said. He said he hopes to be able to talk in more detail sometime in the summer.

Pickett, at the RCA, said the regulatory commission wants to know about this, however.

The commission will ask the utilities to tell it where things stand on possible LNG imports in a meeting in late May or early June, Pickett said.

Although the pace of drilling isn't enough, there are some positive developments for the regional gas supply pictures.

Enstar is now taking delivery of gas from the small North Fork gas field on the Kenai Peninsula near Homer, Enstar said.

Armstrong Oil and Gas, a Denver-based independent company that owns the North Fork field, began deliveries in early April, Enstar spokesman Sims said.

The utility is taking about 15 million to 25 million cubic feet of gas daily, although this is expected to increase. Enstar's contract with Armstrong calls for the company to deliver 1 billion cubic feet of gas per year.

Enstar built a $21 million, 21-mile, eight-inch pipeline from an existing pipeline from Ninilchik to Anchor Point, where it has linked with two four-inch pipelines built by Armstrong from the North Fork field.

Armstrong is now producing from two wells at North Fork and has drilled two more wells, Sims said.

Companies operating producing fields in the region have four new production wells planned. Marathon Oil Co. plans one well in the Ninilchik gas field on the Kenai Peninsula. Marathon also plans two new production wells on the Steelhead platform in Cook Inlet. Marathon owns the platform, which produces gas, although Chevron Corp. manages production operations.

One new production well is planned for the Beluga gas field, according to Municipal Light & Power, which owns a third of the field.

Exploration wells drilled this winter meanwhile have found some gas, although it is too early to know if they can be produced.

Linc Energy, an Australian independent, reported finding gas at its test well drilled in the Matanuska Susitna Borough late last fall, although testing is now under way on possible production.

Nordaq Energy completed an exploration well on the Kenai Peninsula in April, and although results weren't announced the company said it is working on permits for surface facilities, a good sign.

Buccaneer Energy Ltd. is now completing its exploration well, also on the Kenai Peninsula. The well has encountered gas shows but whether these can be produced remains to be seen.

There are also plans for two jack-up rigs to be operating in deeper waters of Cook Inlet this summer. One rig is now being transported to the Inlet by Escopeta Oil and Gas, another independent.

Buccaneer Energy plans to bring a second, larger jack-up rig to the Inlet this summer.

Both companies own leases with prospects that will be tested by the two jack-up rigs.

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BP Profit, Output Still Weighted Down by GOM Effects

BP Profit, Output Still Weighted Down by GOM Effects

Wednesday, April 27, 2011

Dow Jones Newswires

by Alexis Flynn

BP Wednesday posted a 5% fall in adjusted profit for the first quarter, as the damage wrought by the Deepwater Horizon disaster last year continued to weigh down its earnings and petroleum production outlook despite high oil prices.

The oil giant's results narrowly missed expectations for "clean replacement cost of supplies," which strips out gains or losses from inventories and other non-operating items. Profits under this keenly-watched benchmark totaled $5.37 billion for the quarter, compared with $5.65 billion for the first quarter of 2010. Analysts had expected $5.71 billion.

On the positive side, BP's latest charge of $400 million in Gulf of Mexico cleanup costs was more modest than some analysts feared. But BP said year-on-year oil and gas output dropped 11% in the first quarter, and signaled continued weakness in the second quarter, partly the result of increased maintenance procedures instituted after the 2010 U.S. drilling disaster.

While BP shares "look attractive," the "risk remains high for now" due to the uncertain status of BP's efforts in Russia, said Evolution Securities analyst Richard Griffith.

Analysts and investors will be looking for guidance on the company's ongoing Russian travails when Chief Financial Officer Byron Grote discusses the first-quarter results this afternoon at 1300 GMT.

BP's $16 billion share-swap and exploration deal with Russian state-owned giant Rosneft was blocked by an arbitration court last month following objections from BP's partners in its TNK-BP joint venture, and the U.K. firm could be forced to pay substantial compensation for it to go ahead. TNK-BP is also scheduled to report earnings Wednesday.

BP said it booked an additional $400 million charge related to the Gulf of Mexico spill, citing higher cleanup costs. But analyst Jason Kenney of ING said investors were relieved the latest charge was not higher.

Total oil and gas production was 3.58 million barrels a day, a decline of 11% on the year. This drop was partly the result of asset sales to pay for the Gulf of Mexico cleanup and production effects from due to the ongoing drilling shutdown in the U.S. Gulf. But BP said its output was also weighed down by higher maintenance in the North Sea and Angola, and by an interruption in the Trans-Alaska oil pipeline.BP said its second-quarter oil and gas output would also reflect these impacts.

"The main impact by far on production is the Gulf Of Mexico moratorium," a BP spokesman said. "There's also higher turnaround activity that we've been doing as we go through the increased spending on safety, particularly in the North Sea."

In the year since the disaster, BP has re-emerged as a fundamentally different company: it is smaller than before, having already shorn some $22 billion of assets; and with a different strategic focus, looking to fresh opportunities abroad to underpin its future growth.

However, a key part of this new strategy already appears to be floundering, with the challenge to the Russian deal.

BP didn't receive a dividend from TNK-BP for the period, the first time it hasn't received a payout from its Russian joint venture since the first quarter of 2009.

A BP spokesman said the decision to withhold the dividend was made by TNK-BP's board. However its partners in the joint venture, the Alpha-Access Renova group, in April threatened to withhold dividend payments for the year. BP is currently engaged in a dispute with AAR over its proposed alliance with Rosneft.

Net profit for the quarter was up 17% at $7.12 billion, compared with $6.08 billion a year ago.

Adjusted profit from BP's downstream business improved substantially year on year, nearly trebling to $2.07 billion, although the company cautioned that this was due to a favorable refining environment and a good performance by its trading division, and was unlikely to be repeated in the second quarter.

Musings: Updated 2011 Hurricane Forecast Still Calls for Active Year

Musings: Updated 2011 Hurricane Forecast Still Calls for Active Year

Tuesday, April 12, 2011
Parks Paton Hoepfl & Brown
by G. Allen Brooks


The latest forecast update from Professors Philip Klotzbach and William Gray of the Department of Atmospheric Science at the Colorado State University (CSU) says the upcoming hurricane season is expected to see above-average activity. The April 6th forecast is slightly lower than their December 2010 forecast largely due to uncertainty about the sea surface temperatures in both the South Pacific and South Atlantic oceans that can assist or retard the development and strengthening of tropical storms.

The forecasting team has developed a new April methodology based on a data collected from 1982-2010. There are four predictors employed in the model with two of them based on sea surface temperatures in the Atlantic and Pacific oceans. The Pacific Ocean for most of the past year has been cooler than normal, which helped contribute to the Atlantic basin’s storm activity last year mostly turning north before reaching the U.S. In general, sea surface temperatures in the eastern and central tropical Pacific Ocean have been 0.50C-1.00C below average.

Exhibit 21.  Pacific Ocean Sea Surface Temperatures Low


Source:  Colorado State University

On the other side of the globe, Atlantic Ocean sea surface temperatures remain at or above average levels. They have cooled recently but most likely that has been caused by a shift from a negative phase for the North Atlantic Oscillation to a positive phase. Atmospheric conditions currently are conducive for an active hurricane season as wind shear, a force that can limit the development and strengthening of tropical storms, across the basin has been well below average over the past two months.

Exhibit 22.  Atlantic Ocean Temperatures Near Normal
   
Source:  Colorado State University

With these conditions, the CSU forecasting team began looking for analog years to help fine-tune their forecast. They were looking for years generally characterized by weak to moderate La Niña conditions and above-average tropical Atlantic and far North Atlantic sea surface temperatures during February and March. They found five seasons that met these conditions. Four of them had either neutral or La Niña conditions during the hurricane season and all four of them were very active years. Those four years were 1955, 1996, 1999 and 2008.

Exhibit 23.  Analog Years For Hurricane Forecast
   
Source:  Colorado State University, PPHB

The forecasters also found 2006, which had the same February-March conditions. That year, however, experienced an unexpected El Niño, which greatly reduced hurricane activity.

The CSU team anticipates 2011 to be slightly more active than what was experienced in the average of these five analog years due to the very active season predicted by their new statistical model. It is interesting that there were only two analog years that fit the parameters for both the December 2010 and April 2011 forecasts, and those years were 1999 and 2008.

Exhibit 24.  Latest Hurricane Forecast Down Slightly

Source:  Colorado State University, PPHB

The CSU forecast calls for a total of 16 named storms, down one from the December 2010 forecast total. It also expects there to be nine hurricanes and five major hurricanes. The total number of storm days will be down by five, from 85 to 80, with a similar reduction for each of the other storm categories.

In terms of landfall probabilities, the forecast calls for a 72% probability of a storm hitting the entire U.S. coastline compared to the 52% average for the past century. There is a 48% chance of a landing on the East Coast including the Florida peninsula compared to the historic 31% rate.  For the Gulf Coast from the Florida Panhandle to Brownsville, Texas, there is a 47% chance of a tropical storm landfall versus the historical average of 30%. Despite the higher probabilities, nature is such that it is impossible to forecast with any degree of accuracy until a storm is on its way whether it will reach land.  For the offshore energy industry, it will need to be on alert this hurricane season, although if the current pace of permitting continues, there won’t be too many offshore rigs to have to worry about this fall. Is that a backhanded positive?

Download the PDF Musings041211.pdf

Australia Players Still Pursuing Cooper Basin Shale Gas Potential

Australia Players Still Pursuing Cooper Basin Shale Gas Potential

Tuesday, March 29, 2011
Rigzone Staff
by  Karen Boman

Despite once-in-a-generation rainfall and flooding that disrupted exploration and production activity last year, Australia-based oil and gas producers are forging ahead this year with plans this year to drill for and develop the Cooper Basin's conventional and unconventional oil and gas resources.

Santos Ltd., noted that reports of the death of Australia's onshore Cooper Basin, which stretches across the northeast corner of South Australia into southwestern Queensland, are "greatly exaggerated" as the basin contains unconventional gas resource potential of more than 39,000 petajoules (PJ) and booked contingent resources of about 5,000 pj. Santos reports that undeveloped unconventional shale gas resources lay beneath the developed conventional resource Moomba basin, while tight gas and deep coal exist below shale gas. Gross gas thickness in the Cooper is approximately 1,600 feet.

Another Australia-based oil and gas company, Beach Energy, reports it has an aggressive exploration and development program planned for this year in its Cooper Basin holdings, and better land access for these activities following the Cooper Basin floods of last year, which washed out roads and prevented companies from accessing work sites.

The company currently operates 19 oil fields in the Cooper-Eromanga with five gas discoveries awaiting development and owns an approximate 21% interest in the Cooper Basin project operated by Santos. Since late 2006, Beach has participated in more than 100 oil wells operated by Santos, delivering net reserves of 4 million barrels. Beach Energy is in discussions with Santos, to supply its Gladstone liquefied natural gas (LNG) project.

Cooper Basin

 

Beach said its Cooper Basin position will allow it to tap the growing eastern Australian gas markets while also feeding the growing LNG demand in Asia. Beach noted that current Australian gas demand is approximately 700 pj per year, with around 100 pj to come from the Cooper Basin. Demand for more Cooper Basin gas is anticipated as domestic gas demand for use in power generation is expected to grow to around 1,100 pj by 2025.

The company estimates the Nappamerri Trough, which runs beneath its PEL 218 license, holds potential gas in place of more 200 Tcf, and holds properties similar to the best U.S. shale plays. Beach has drilled off-structure to determine the trough's deep basin gas potential, and found the target section thicker than anticipated at 1,289 feet and the target section gas saturated and over-pressured. Beach noted that no water bearing permeable sections were intersected in the target zone and immediately above and below target; the lack of water in these zones will assist in fracture stimulation.

The company has drilled two wells in PEL 218, which contains the Nappamerri Trough. The shale and sandstone target area for Beach's Encounter-1 well was 30 percent thicker than expected; Beach also spudded the Holdfast-1 well in January of this year.

Beach notes it has had encouraging results to date and expects material resource booking to take place this year. Results will assist in the design of future activities, including fracture stimulation in this year's second quarter and a pilot well program in the third or fourth quarter.

The company also sees near-term growth opportunities for oil in the Western Flank of the Cooper Basin. Beach began an operated 16-well development program here last month to accelerate production and will drill 12 exploration/appraisal wells with prospects ranging from .5 million barrels to 5.5 million barrel (gross).

The Cooper/Eromanga Basin

 

Drillsearch, which holds significant interests in the Cooper Basin, will began a five-well drilling program next month at its PEL91 license in Cooper's Basin's Western Flank. The five prospects, whose primary targets are the Namur and Birkhead channel, have estimated recoverable mean barrels of between 430,000 and 1.1 million. These prospects were defined using 3D seismic analysis; historically, Drillsearch has had 50 percent success rates using 3D seismic. Multiple commercial discoveries have been made on adjacent permits, and Drillsearch anticipates a short development cycle for the wells.

The company anticipates a formal award at mid-year for nine blocks in southwest Queensland, which will expand its Cooper Basin holdings. Drillsearch expects potential farm-outs of select areas starting in this year's second quarter.
Drillsearch is planning a significant drilling program for its estimated wet gas resources of 11.5 million BOE in the Cooper Basin. The company has made 10 gas/condensate discoveries in the area, including four declared commercial, and will pursue potential pilot development of the Middleton, Brownlow and Canunda discoveries. In the near term, the company plans a five well appraisal, development and near-field exploration program in PEL106B and PEL107.

Bengal Energy reports it has defined numerous leads and prospects on the Tookoonooka exploration permit ATP 732P, which the Queensland government announced a final grant of title to for Bengal effective April 1. Bengal will begin gather seismic data on the block and plans to drill between five and eight wells over the next 18 months. The company said the large block is offset by producing oil and gas fields, and features seven different play types, including four conventional light oil plays, two conventional gas and gas liquid plays, and one unconventional gas play.

The company also reports finding new potential fairway for oil-bearing Cretaceous Murta sandstones in its Cuisinier 1 discovery well, which began production in May 2010. Three wells are awaiting completion and testing either this month or in April, with the Cuisinier 3 cased as a potential oil well.