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Oil and Gas Energy News Update

Wednesday, June 29, 2011

Oil & Gas Post - All News Report for Wednesday, June 29, 2011

Wednesday, June 29, 2011

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Commodity Corner: Oil Gains on Bullish Stocks Report

- Commodity Corner: Oil Gains on Bullish Stocks Report

Wednesday, June 29, 2011
Rigzone Staff
by Matthew V. Veazey

August crude oil on the NYMEX gained $1.88 Wednesday after investors were caught off-guard by a particularly bullish report on oil stocks.

Oil settled at $94.77 a barrel after the U.S. Energy Information Administration (EIA) announced that the country's commercial oil inventories fell by 1.2 million barrels last week to 359.5 million barrels. The 4.3 million-barrel decline from the previous week was much higher than what analysts had projected. A survey of Platts analysts, for instance, had anticipated more modest draw of 1.7 million barrels.

Also supporting oil was a stronger euro, bolstered by the Greek parliament's approval of an austerity package that will qualify the country for a bailout from the European Union and International Monetary Fund. The euro gained 0.4 percent against the dollar Wednesday. Oil, priced in dollars, becomes a better value for investors holding the euro and other currencies other than the greenback when the dollar weakens.

The August WTI contract price peaked at $95.84 and bottomed out at $92.66 during midweek trading. Brent futures gained 3.3 percent Wednesday to reach a price of $112.45.

Natural gas for August delivery lost 4.5 cents to settle at $4.315 per thousand cubic feet. It traded within a range from $4.28 to $4.38.

The July natural gas contract surged 12 cents to end the day at $3.01 a gallon—the intraday high. A sharp decline in gasoline production, as revealed by the EIA, contributed to the rally. The intraday low for gasoline was $2.88.

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Interior Dept Asks Congress to Raise Oil-Drilling Violation Fines

- Interior Dept Asks Congress to Raise Oil-Drilling Violation Fines

Wednesday, June 29, 2011
Dow Jones Newswires
by Tennille Tracy

The Interior Department is asking Congress to increase fines for oil and natural gas companies that break offshore drilling laws, with one Interior official saying current fines are more of a "trivial nuisance than an effective deterrent."

The department urged Congress to take this step while announcing a modest increase to existing fines to reflect inflation adjustments, as required by law. The department said it is restricted from raising penalty rates beyond inflation rate increases.

The maximum civil penalty rate for violations of the Outer Continental Shelf Lands Act will increase from $35,000 to $40,000 per day, while violations under the Oil Pollution Act go from $25,000 to $30,000 per day.

Michael Bromwich, director of Interior's Bureau of Ocean Energy Management, Regulation and Enforcement, said in a statement Wednesday that Congress should raise the rates "significantly."

"The inadequacy of our civil authority hampers our ability to effectively regulate offshore activities, and renders such fines a trivial nuisance rather than an effective deterrent" he said.

The bureau has undertaken several measures to tighten offshore drilling standards since the Deepwater Horizon oil spill.

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

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Drilling Completed at Tunis Creek Prospect

- Drilling Completed at Tunis Creek Prospect

Wednesday, June 29, 2011
Victory Energy Corp.

Victory Energy, through its partnership with Aurora Energy Partners, announced the successful completion of its Tunis Creek Oil and Gas Prospect in Pecos County, Texas. The University "6" #1 Tunis Creek well was spud on April 22, 2011 and was completed in the Ellenburger formation on Friday, June 24, 2011.

Very preliminary testing of the Ellenburger formation indicates that oil reserves could exceed earlier estimates. Pre-drilling internal total prospect reserve estimates exceeded 500,000 barrels. These preliminary flow tests on the University "6" #1 Tunis Creek well were performed using its natural bottom-hole pressure and was limited to the lower 20 percent of the Ellenburger formation in the wellbore. Sustained flow tests to evaluate bottom-hole pressure and to develop optimal flow rates for this well should occur over the next thirty days. Storage tanks are scheduled to be installed this week with oil sales to market occurring shortly thereafter. Associated natural gas testing has not yet occurred. A natural gas delivery pipeline is nearby.

Based on the positive results of this first well and the previously identified multiple oil and gas pay zones above this producing formation, the company will immediately begin evaluating locations for a second well on the acreage. Several additional development wells may be drilled if production warrants. Field rules established by the State of Texas will determine the exact number of wells.

Robert Miranda, Victory Energy's chairman and CEO, stated, "These preliminary completion results are outstanding and offer the first sizable validation of our ability to use our extensive network of oil and gas contacts to deliver immediate value to our shareholders. Wells of this quality and with reserves of this size are not typically available to micro-cap companies like Victory Energy. The additional development drilling opportunities available on the Tunis acreage could afford us at least two additional years of drilling at this location."

Victory Energy, through its partnership with Aurora Energy Partners, holds a 5 percent working interest and a 3.75 percent net revenue interest in this oil focused prospect.

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Maverick Boosts Reserves at Blue Ridge Dome

- Maverick Boosts Reserves at Blue Ridge Dome

Wednesday, June 29, 2011
Maverick Drilling & Exploration Ltd.

Maverick Drilling & Exploration announced a significant upgrade to Maverick's 2P reserves on its flagship asset, Blue Ridge Dome, by approximately 26.8 million net oil barrels for Maverick's share of its leases. The reserves reflect no barrels equivalent in natural gas and are all true liquid oil barrels.

The reserve upgrade is a result of a combination of new lease acquisitions on Blue Ridge Dome and further analysis of results of Maverick's ongoing drilling program. A comparison to previously disclosed reserves is set out below:

Net Maverick Reserves
Proved 1P (million bbls) Proved + Probable 2P (million bbls)
ISO prospectus 7.8 25.6
Today 12.4 52.4
9 month increase (%) 59% 104%

Approximately 7.6 million net 2P barrels of the increase are the result of the company's improvements on those Blue Ridge Dome leases held at the time of listing (in September 2010). The remaining 19.2 million 2P barrels relate to acquisitions and expansion of holdings in the field.

Commenting on the upgrade, Maverick's executive chairman, Mr. Don Henrich said, "This is a superb outcome in Maverick's first nine months as a listed company. The substantial upgrade highlights the vale of Blue Ridge Dome, and the inherent potential of Boiling Dome, a piercement type salt dome with similar characteristics. The reserve upgrade underpins our aggressive acquisitions and in-field drilling and completion program which is achieving record production month over month for the past several months."

As previously announced, the company holds considerably larger net acreage on Boiling Dome than on Blue Ridge Dome. The Directors expect to announce maiden reserves for Boiling Dome later this calendar year, after commencement of the pilot drilling program.

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Abraxas Ramps Production at Bakken/Three Forks Play

- Abraxas Ramps Production at Bakken/Three Forks Play

Wednesday, June 29, 2011
Abraxas Petroleum Corp.

Abraxas provided an operational update.

Rocky Mountain – North Dakota / Montana

In McKenzie County, North Dakota, Abraxas drilled the Stenehjem 27-34 1H to a total measured depth of 16,504 feet, including a 5,965 foot lateral in the middle Bakken formation, and completed the well with a 17-stage fracture stimulation. The well was recently placed on production, including gas (and natural gas liquids) directly into the sales line, and is currently in the early stages of cleaning up and producing at rates in excess of 800 barrels of oil equivalent per day, which is comprised of approximately 600 barrels of oil, 100 barrels of natural gas liquids and 700 Mcf of residue gas. We anticipate providing initial rates (after recovery of frac fluid) when 30-day rates are also available. Abraxas owns an approximate 79% working interest in this well.

In various counties in North Dakota and Montana, fourteen non-operated horizontal wells, targeting the Bakken or Three Forks formation, in which Abraxas owns a working interest are currently in progress or recently placed on-line. Four gross (0.15 net) wells went on production in mid-June, three gross (0.15 net) wells have been fracture stimulated and are currently cleaning up, three gross (0.50 net) wells are waiting on completion and four gross (0.07 net) wells are waiting on a drilling rig. Since January 2010, Abraxas has elected to participate in 19 gross (1.02 net) non-operated wells in the Bakken / Three Forks play.

In McKenzie County, North Dakota, two gross (0.11 net) non-operated horizontal wells targeting the Mission Canyon have been drilled and completed and are currently waiting on production facilities.

Abraxas anticipates being in a position in the near future to discuss long-term service availability to allow a multi-year continuous development plan on its Bakken / Three Forks acreage.

Rocky Mountain - Wyoming

In Campbell and Niobrara Counties, Wyoming, a two well oil development program is scheduled to begin this fall. One of these horizontal wells will target the Niobrara formation and one will target the Turner formation. Abraxas owns a 100% working interest in each of these wells.

Rocky Mountain – Alberta Basin Bakken

Abraxas has been approached by a number of companies in the industry with respect to a joint venture or similar arrangement; however, Abraxas has elected to wait for more definitive results from wells drilled to-date in the play before planning a course of action. Abraxas' leases have a primary term of 5-10 years providing plenty of time to evaluate the results of other operators in the play.

South Texas – Eagle Ford

Abraxas currently owns a 50% equity interest in Blue Eagle, which is a joint venture between Abraxas and Rock Oil Company, LLC.
In DeWitt County, Texas, Blue Eagle's first well, the T-Bird 1H, continues to outperform expectations and is currently producing approximately 1,100 barrels of oil equivalent per day, which is comprised of approximately 200 barrels of condensate, 340 barrels of natural gas liquids and 3.2 MMcf of residue gas. The well has produced approximately 200,000 barrels of oil equivalent during its first 150 days on production. Blue Eagle owns a 100% working interest in this well.

In DeWitt County, Texas, Blue Eagle participated in a non-operated horizontal well with its 43.9% working interest. The well, the Matejek Gas Unit 1, was drilled to a total measured depth of approximately 17,865 feet, including a 3,600 foot lateral, and recently completed with a 14-stage fracture stimulation. The well flow tested at restricted rates in excess of 780 barrels of oil equivalent per day through a choke while recovering frac fluid. The well is currently shut-in waiting on pipeline hookup.

In Atascosa County, Texas, the Grass Farms 1H should spud this week as the rig is currently rigging up. This well is located in the oil window of the play and will be drilled to a total measured depth of approximately 12,500 feet, including a 5,000 foot lateral. A fracture stimulation date has been secured for this well in August. Blue Eagle owns a 100% working interest in this well.

South Texas – Portilla

In San Patricio County, Texas, seven wells have been drilled and completed to-date in the multi-well in-fill drilling program and one additional well was recently recompleted. Three of the new wells targeted the dual objectives of the 7,400 and 8,100 foot Frio sands and four targeted the 7,400 foot Frio sand. These wells have increased production in the field by 100% and have added approximately 300 barrels of oil equivalent per day, 82% of which is oil. This drilling program has met the Company's economic expectations and six additional locations remain to be drilled, all of which are scheduled for later this year. Abraxas owns a 100% working interest in each of these wells.

West Texas

In Nolan County, Texas, the Spires 126 2H recently reached a total measured depth of approximately 9,000 feet, including a 2,000 foot lateral. Completion operations will commence on this well in the near future. Abraxas owns a 100% working interest in this well.
In Coke County, Texas, in the NE Millican Reef field, Abraxas anticipates drilling two vertical delineation wells targeting the Canyon Sand play which is located approximately 30 miles to the southwest of Spires Ranch in the near future. The rig that drilled the Spires Ranch well will move to drill one of these two wells, after which, the rig will return to Spires Ranch for a continual horizontal development program, and assuming favorable results on the first well, the rig will return to NE Millican when convenient to drill the second well. Abraxas owns a 100% working interest in these wells.

In Reeves County, Texas, Abraxas recently acquired 640 net acres, for a total of approximately 3,000 net acres, in the emerging Wolfbone play. Two wells directly adjacent to our acreage are being currently drilled by the industry.

Canada - Pekisko

In Alberta, Canada, production from the Twining 9-11 remains relatively stable at approximately 100 barrels of oil equivalent per day. Two wells offsetting the successful Twining well will be drilled back-to-back, the first of which spudded this week. The two wells will be drilled horizontally and will target the Pekisko formation. Canadian Abraxas owns a 100% working interest in each of these wells.


"With the expected performance of the Portilla and Twining wells and the recent new production in the Bakken / Three Forks play, we have more than offset production disruptions from wells shut-in in the Williston Basin due to unprecedented high water and flooding. With all of our drilling activity, we should be in a position to continue sequential quarterly production growth for the foreseeable future," commented Bob Watson, Abraxas' President and CEO.

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Parex Finalizes Llanos Basin Acquisition

- Parex Finalizes Llanos Basin Acquisition

Wednesday, June 29, 2011
Parex Resources Inc.

Parex Resources has successfully closed the previously announced acquisition of a company which holds the 50% interest Parex does not already own in four Llanos Basin blocks in Colombia, including the Kona discovery on Block LLA-16, for approximately US $255 million in cash, net of closing adjustments.

The acquired assets are currently producing approximately 3,100 barrels of light oil per day ("bopd"). With the close of the Acquisition Parex is currently producing approximately 6,200 bopd. Further, post acquisition Parex anticipates that forecast capital expenditures, excluding the costs of the acquisition, to range between US $125 million and US $140 million, and year-end exit rate production to be in excess of 14,000 bopd.

The Acquisition was funded through a bought deal financing (the "Offering"), pursuant to which the Company issued 31.05 million subscription receipts of Parex (the "Subscription Receipts") at CDN $7.00 per Subscription Receipt for gross proceeds of CDN $217.35 million and CDN $85.0 million aggregate principal amount of 5.25% extendible convertible unsecured subordinated debentures of Parex (the "Debentures"), for total combined gross proceeds of CDN $302.35 million. The Offering was co-led by FirstEnergy Capital Corp. and Scotia Capital Inc., and included Haywood Securities Inc., CIBC World Markets Inc., Peters & Co. Limited, Raymond James Ltd., RBC Capital Markets and TD Securities Inc.

In conjunction with the closing of the Acquisition each Subscription Receipt has been automatically converted into one common share of Parex ("Common Shares") without any further action on the part of the holder and without payment of additional consideration. The maturity date of the Debentures has been automatically extended from the initial maturity date of July 15, 2011 to June 30, 2016.

Also in connection with the closing of the Acquisition, the Company has made application to the TSX Venture Exchange ("TSXV") to de-list the Subscription Receipts from trading on the TSXV, effective immediately and the Subscription Receipts have been halted from trading. The Common Shares into which the Subscription Receipts have been converted will be listed and posted for trading on the TSXV on the opening of the market on Monday, July 4, 2011. With the conversion of the Subscription Receipts there are approximately 108.2 million Common Shares outstanding.

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Transocean Board Member Resigns

- Transocean Board Member Resigns

Wednesday, June 29, 2011
Transocean Ltd.

Transocean announced that W. Richard Anderson has resigned from its Board of Directors, effective immediately, due to the demands of his duties as Chief Financial Officer of Eurasia Drilling Company Limited.

Transocean Ltd. President and Chief Executive Officer Steven L. Newman said, "We greatly appreciate the many contributions that Rich Anderson has made to our Board of Directors and our company, in particular his financial insights. We will miss Rich and wish him all the best."

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Fugro-Jason Acquires 5 Licenses to TerraSpark's Insight Earth Platform

- Fugro-Jason Acquires 5 Licenses to TerraSpark's Insight Earth Platform

Wednesday, June 29, 2011
TerraSpark Geosciences LLC

TerraSpark Geosciences announced that Fugro-Jason, a member of the Fugro companies and recognized global leader in seismic inversion and reservoir characterization software and services, has acquired five licenses to TerraSpark's Insight Earth® 3D seismic interpretation platform. The licenses include complete access to Insight Earth Base™ and Insight Earth Structure™ application tools.

According to Fugro-Jason's geoscience consulting teams, they will use Insight Earth to support exploration and production projects worldwide. The teams will leverage Insight Earth to improve structural interpretation speed and accuracy, while accelerating reservoir characterization projects.

Fugro-Jason found that its inversion results, when combined with Insight Earth interpretation tools, provide an optimally productive environment for rapidly defining faulting and structure. After Fugro-Jason inversion improves interpretation accuracy by transforming the interpretation environment from reflectors to impedances and lithologies, applying Insight Earth tools allows quicker, easier, more robust interpretation decisions and workflows.

"We are fully confident that Insight Earth will deliver multiple efficiency and performance upgrades to enhance various workflow functions within Fugro-Jason's consulting base," said Geoffrey Dorn, PhD, CEO and president of TerraSpark. "Geoscientific consulting is a time-sensitive discipline, and requires best-in-class tools and technologies that support continual optimization and efficiency improvements."

Insight Earth Base provides data management, including data input/output, data transfer, workflow definition, workflow and process control, and interactions modes. This enables geoscientists to condition seismic data for subsequent processing, and to optimize volumes for interpretation. Insight Earth Structure allows users to more rapidly and accurately interpret 3D surfaces including faults, horizons, canyons and salt bodies in seismic volumes for prospect definition and reservoir delineation.

Insight Earth is widely recognized throughout the energy exploration and production market for its workflow-accelerated True Volume seismic interpretation process, wherein each step in the interpretation process informs and improves the next step.

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HWCG Makes Headway in Expanding Deepwater Capabilities

- HWCG Makes Headway in Expanding Deepwater Capabilities

Wednesday, June 29, 2011
Helix Well Containment Group

The Helix Well Containment Group (HWCG) announced that it is now capable to respond to a subsea well containment incident in water depths of up to 10,000 feet.

The consortium previously announced its intention to achieve this milestone by mid-summer, and has achieved this ahead of schedule. Previously, it had capabilities to operate in water depths of up to 8,000 feet.

HWCG is a consortium of 24 deepwater operators in the Gulf of Mexico that have come together with the common goal of expanding capabilities to quickly and comprehensively respond to subsea well incidents to protect employees, communities and the environment.

"Combining ultra-deep water depth capability with a 15,000 pounds per square inch-gauge (psig) intervention capping stack, the HWCG consortium has the technology, expertise and resources of a diverse group of companies to respond immediately in the unlikely event that a deepwater well's blowout preventer fails to operate as designed," said David Coatney, HWCG's Managing Director.

Coatney was recently named HWCG Managing Director in May. He has more than 35 years of experience in the oil and gas industry, both in the United States and overseas. In previous roles, Coatney has served as an international upstream oil and gas asset consultant, Vice President of Production for Swift Energy and in various management and engineering capacities for Marathon Oil Company, where he worked for 29 years.

Coatney has been integrally involved in emergency preparedness and response for more than 20 years. He has acted as an Incident Commander—both domestically and abroad—and has led many successful responses in operational, natural disaster, well control and civil unrest incidents.

"Dave's combined expertise in drilling, production, offshore operations and incident response will be a strong asset to HWCG," said John Weust, HWCG's Steering Committee Chair. "I am confident he will play a significant and positive role in the ongoing operations of HWCG, in addition to enhancing the group's position in responding to the future needs of the industry."

Coatney holds a Bachelor of Science degree in Petroleum Engineering from Louisiana State University. He is a member of the Society of Petroleum Engineers, the American Petroleum Institute and the Association of International Petroleum Negotiators.

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Fracking Foes Resort to Rest Area Prank Signs

- Fracking Foes Resort to Rest Area Prank Signs

Wednesday, June 29, 2011
Pittsburgh Post-Gazette
by Don Hopey

The professionally printed sign bearing the banner message "SAFE TO DRINK" and affixed to a drinking fountain in the Pennsylvania Turnpike's Midway Service Plaza looked official at first glance, even if it seemed to state the obvious.

But something didn't look quite right to Tonya Markiewicz, who stopped in for a drink June 8 while on a trip to Philadelphia and New York City, and it had nothing to do with the stream of cold water arching from the fountain.

The message of the sign, which bore what purported to be a Pennsylvania Department of Environmental Protection logo in the upper left hand corner and has since been discovered in several other turnpike service plazas, was coyly equivocal. It read: "This water is most likely safe. If you have any concerns about contamination due to hydraulic fracturing, expose water to flame."

That procedure -- unsafe at best and potentially fatal at worst if the water contained ignitable concentrations of methane -- was depicted in a graphic that shows a hand holding a lit match under a water faucet.

That raised a big red flag for Ms. Markiewicz.

"I didn't want to try to drink the water after seeing that sign," said Ms. Markiewicz, a Braddock resident, who took a photograph of it. "After reading closely it occurred to me it was posted as part of an activist project, but it was so well done. It gets right at you when you're about to consume the water."

At the bottom of the sign, posted by an as yet unknown activist prankster, was a list of symptoms from drinking contaminated water, including "headaches, nausea, vomiting, dizziness, hair loss, itchy skin and kidney failure," and a DEP phone number to call for more information.

Kevin Sunday, a DEP spokesman, confirmed that the not-so-subtly subversive sign was not posted by the department. He noted that its appearance at the Midway Service Plaza near Harrisburg roughly coincided with the June 7 rally in Harrisburg by hundreds of people protesting Marcellus Shale gas well drilling and development.

"That's not from DEP," Mr. Sunday said last week, noting that the "E" in the DEP logo on the sign was different from the DEP's real logo.

Bill Capone, a Pennsylvania Turnpike Commission spokesman, said last week that after inquiries by the Pittsburgh Post-Gazette, the bogus DEP signs were found on water fountains in "most of the service plazas west of Harrisburg." He said they were probably up on the drinking fountains for almost two weeks and viewed by hundreds of turnpike travelers and service plaza attendants who didn't raise questions about its message, which he termed, "odd, curious and somewhat alarming."

"We found them in Somerset and New Stanton and others, and we are having them removed," he said.

He said not only do the signs appear official but the contact number for more information is a working DEP phone line that belonged to Katy Gresh, the department's spokeswoman in its Southwest District office in Pittsburgh before her promotion to head the DEP's Harrisburg media office in March.

The signs' water contamination test, using a lighted flame, is a reference to problems caused by faulty well casing and drilling operations at Marcellus Shale gas wells in Dimock, Susquehanna County, that allowed high concentrations of methane gas from shallower formations to contaminate well water at several homes.

Also, a homeowner in Colorado was able to ignite his tap water, a dramatically explosive scene shown in the 2010 Oscar-nominated documentary film "Gasland" by Josh Fox, who, coincidentally, spoke at the anti-drilling rally.

Myron Arnowitt, state director for Clean Water Action, one of the environmental organizations that helped organize the rally, said last week that he hadn't seen the prank signs and doesn't endorse them, but thought them "an amusing way to raise some public awareness."

"Of course it's not a good idea to give the public misleading information on water quality and we would want any signs to be clearly factual," he said. "And as far as I know, any of the activists I've been in touch with, no one is taking credit for it."

Copyright (c) 2011, Pittsburgh Post-Gazette

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Aker Buys Majority Stake in Norwegian Subsea Duo

- Aker Buys Majority Stake in Norwegian Subsea Duo

Wednesday, June 29, 2011
Aker Solutions

Aker Solutions has acquired 70 percent of the Norwegian companies Ing. Harald Benestad AS (Benestad) and Phaze Technologies AS.

Benestad and Phaze Technologies, founded and owned by Harald, Pål and Randi Benestad, are well established globally in the subsea industry and have been among the key suppliers to Aker Solutions as well as other major subsea companies for a number of years. Both companies are located in close proximity to Aker Solutions' subsea technology and manufacturing centre in Lier, Norway, and employ 33 people and with a 2010 operating revenue of NOK 49 million (USD 9 million).

Benestad, a highly specialized materials science company, delivers high technology products for hostile, extreme pressure and high temperature subsea environments. All subsea instruments and power consumers require leak free connections through pressure housings and Benestad's power and signal penetrators are viewed by Aker Solutions as the best quality with the highest functionality in the industry.

Phaze Technologies provides advanced and reliable instruments for hydrocarbon leak detection, water leak detection, pressure and temperature measurements and water cut metering. The market for such products is growing as a consequence of more stringent environmental regulations and optimization of production from subsea fields.

"Benestad and Phaze Technologies have unique competence and experience within their fields and a strong commitment to developing leading edge and extremely reliable products. They have very strong technological expertise which will significantly broaden and deepen Aker Solutions' competence base," said Mads Andersen, executive vice president of Aker Solutions' subsea business area.

Pål Benestad, chairman of Benestad and Phaze, said, "Aker Solutions share our vision to be the preferred partner to our existing and new customers. Innovative solutions based on strong technological know-how will remain our focus area going forward and access to Aker Solutions' customers and regional network will enable further growth for both Benestad and Phaze."

Both companies will continue to operate as independent companies with existing management and brands servicing a broad range of long standing clients.

Completion of the agreement is subject to clearance by Norwegian competition authorities. The transaction value is undisclosed.

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Debate on Gas Drillers' Impact Fee Put Off

- Debate on Gas Drillers' Impact Fee Put Off

Wednesday, June 29, 2011
The Morning Call, Allentown, Pennsylvania
by John L. Micek, The Morning Call, Allentown, Pa.

Hours after a threatened veto, Republicans who control the state House pulled the plug Tuesday on a planned debate over a local impact fee for natural gas drillers, saying they'll take up the issue this fall.

The 180-degree turn came as lawmakers worked to put the final pieces of a $27.15 billion budget into place so they could send it to Gov. Tom Corbett before the new fiscal year starts on Friday.

At a news conference, the GOP governor said he wants lawmakers to wait to debate any impact fee bill until after a Marcellus Shale commission submits its report next month on the effects of drilling.

"I have sent this message back: If something gets to my desk, it will be vetoed," Corbett said.

The budget cleared a major hurdle as the Senate voted 30-20 along straight party lines to approve it, positioning it for a vote by the House as soon as Wednesday.

Also on Tuesday, House and Senate Democrats withdrew their opposition to funding bills for Penn State, Temple and Lincoln universities and the University of Pittsburgh, and the veterinary school at the University of Pennsylvania, mustering the two-thirds majority needed for approval.

Democrats in the two chambers withheld their votes for the schools Monday, complaining they hadn't had time to review the details of the sprawling main budget bill. Once that happened overnight and into Tuesday, the Democrats said they were prepared to withdraw their opposition. In short order, the House and Senate separately voted to approve the appropriations.

A key budget bill governing how the state regulates public education and a bill known as the fiscal code, which implements the spending in the main budget, were also moved into place. The House advanced the fiscal code bill, positioning it for a vote Wednesday. The school code bill cleared the Senate on a 33-17 vote and went to the House for approval.

During lengthy debate in the Senate, Democrats repeated arguments that the budget, which trims overall state spending by about 3 percent largely through more than $1.1 billion in cuts to public schools and 18 universities, would result in reduced services for the needy and the aged, tuition hikes for college students and local property tax increases for homeowners.

They also reiterated longstanding complaints that Republicans and the administration had refused to tap a year-end stimulus of as much as $700 million to restore some of the deepest cuts. The spending plan includes more than $100 million in surplus funds.

"This budget recognizes that there are tough, tough choices, I understand that," said Sen. Lisa Boscola, D-Northampton. "But it also includes some bad choices on how to reinvest $27.15 billion for as many Pennsylvania families as we can."

Republicans have said they're not comfortable with all the reductions in the spending plan. But they stressed that the plan "reflects the circumstances of the times," while ducking any major tax increases.

"The document reflects the need for the commonwealth to be fiscally responsible at a time of difficult financial challenges," said Majority Whip Pat Browne, R-Lehigh.

Negotiations continued on two of Corbett's key legislative priorities: authorization of public school vouchers and legislation closing most of the loopholes in a law requiring voter referendums for any school tax hike that outpaces inflation. The governor wants both measures passed before lawmakers start their summer break.

"The House and the Senate have worked with us to reach a final budget," Corbett said. "Because we planned carefully, estimated conservatively, we have a framework to put our budget together."

Corbett has pressed hard to close the loopholes in the "back-end referendum" law, raising the issue in nearly every negotiating session with legislative leaders. Implementing language sponsored by Rep. Seth Grove, R-York, has been attached to a Senate bill currently scheduled for a House vote Wednesday. The governor appeared ready to play hardball with lawmakers, saying "until there is a budget, until I sign one, there is no budget."

Talks on the school-choice bill are continuing, with House leaders saying it's up to the Senate to make the first move. "The Senate has always been in the lead," said House Majority Leader Mike Turzai, R-Allegheny.

Senate President Joe Scarnati, R-Jefferson, said the chamber is "continuing to work with the House to see if there's support" for a school-choice bill and to "see what we can get done before we leave."

House Republicans denied that Corbett's veto threat had anything to do with their decision to put off a vote on an impact fee until the fall. They were complying with his long-stated position that lawmakers delay voting until the Marcellus Shale commission presents its report.

"We'll try to design a legislative package that addresses the full impact of drilling," House GOP spokesman Steve Miskin said.

Scarnati, who spearheaded the push for a drilling fee, said Corbett's veto threat had "changed the dynamic. ... Obviously, it's not going to get done by June 30 if the governor has put his marker down," he said.

Copyright (c) 2011, The Morning Call, Allentown, Pa.

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SM Energy Selling 12.5% Interest in Eagle Ford Shale Position to Mitsui & Co for $680 Million

- SM Energy Selling 12.5% Interest in Eagle Ford Shale Position to Mitsui & Co for $680 Million

Jun 29, 2011

SM Energy Company (NYSE:SM) announced today the sale of a 12.5% interest in its non-operated Eagle Ford shale position to a subsidiary of Mitsui & Co for $680 million.

After the close of this sale, as well as the previously announced divestiture of assets in LaSalle and Dimmit Counties, SM Energy will have roughly 196,000 net acres in the Eagle Ford shale, of which about 75% will be operated by the company.

Because the transactions are expected to close later in the year than originally anticipated and SM Energy is retaining a larger position in Eagle Ford than was originally assumed, reported production and capital expenditures for the year will exceed the company's previously announced guidance.

A full update to capital, production, and cost guidance for the remainder of 2011, as well as preliminary capital and production guidance for FY 2012, will be included in the company's second quarter earnings release.

Tony Best, President and CEO, remarked, "I am pleased to announce the final phase of our planned Eagle Ford sell down effort. Combined with our previously announced LaSalle and Dimmit Counties Eagle Ford divestiture, we are generating nearly $1 billion in funds that will allow us to further develop our Eagle Ford assets while locking in some solid returns and maintaining a strong balance sheet. This specific transaction allows us to continue participating in the development of high value Eagle Ford assets, while providing us more control over our capital investment decisions."

Shares of SM Energy are trading up 7.81% at $71.9.

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Cobalt to Spud GOM Well in 3Q

- Cobalt to Spud GOM Well in 3Q

Wednesday, June 29, 2011
Cobalt International Energy Inc.

Cobalt provided the following update on its U.S. Gulf of Mexico drilling program.

U.S. Gulf of Mexico Drilling Program

On June 8, 2011, Ensco Offshore Company entered into a settlement agreement with the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) among other federal defendants. As part of the settlement agreement, the BOEMRE agreed to "take action" with respect to a number of drilling permits, including Cobalt’s Application for Permit to Drill (APD) for its North Platte #1 exploratory well and its APD for its Ligurian #2 exploratory well, which means that the BOEMRE must initially either approve the APDs, deny the APDs or return the APDs to Cobalt with a statement specifically identifying all then-existing deficiencies within 30 days of the settlement agreement. If an APD is returned with deficiencies and is thereafter resubmitted by Cobalt, the BOEMRE must again take action within 30 days. As part of the agreement, the BOEMRE is not permitted to identify additional deficiencies during its review of the resubmission that existed during, but had not been identified in, the initial review.

North Platte #1. Cobalt formally submitted the North Platte #1 APD on June 3, 2011. Subsequent to the execution of the settlement agreement, Cobalt has been advised by the BOEMRE that Cobalt’s APD for its North Platte #1 exploratory well, Garden Banks 959 #1, is complete. The BOEMRE has identified two remaining deficiencies or further requirements that must be satisfied prior to it approving the APD. The first requirement is that the Ensco 8503 drilling rig obtain an American Bureau of Shipping (ABS) certification. This certification has been obtained. The second requirement is that Cobalt obtain a Coast Guard Certificate of Compliance for the Ensco 8503 drilling rig. The inspection required to obtain this certificate will take place upon the Ensco 8503’s return to the U.S. Gulf of
Mexico. Cobalt does not anticipate any issues related to obtaining this routine Coast Guard certification.

As previously announced, the Ensco 8503 drilling rig is currently drilling a well in French Guiana pursuant to a sublet agreement between an affiliate of Ensco Offshore Company and a subsidiary of Tullow Oil plc. Cobalt expects that the Ensco 8503 drilling rig will be released and returned to the U.S. Gulf of Mexico late in the third quarter of 2011. As noted previously, Cobalt believes that it will have satisfied all requirements stipulated by the BOEMRE for issuance of the APD. Based on information available today, Cobalt believes that it should be able to spud its North Platte well by the end of the third quarter depending on when the Ensco 8503 returns to the U.S. Gulf of Mexico.

Cobalt expects the North Platte #1 exploratory well to take approximately six months to drill. Cobalt is the operator of North Platte and has a 60% working interest in the prospect. TOTAL E&P USA, INC. owns the remaining 40% working interest.

Ligurian #2. Cobalt formally resubmitted the Ligurian #2 APD on June 9, 2011. Under the terms of the above-mentioned settlement agreement, Cobalt expects the BOEMRE to provide Cobalt with any remaining requirements with respect to the APD for its Ligurian #2 exploratory well, Green Canyon 814, on or before July 10, 2011. Cobalt expects that any such remaining requirements will be promptly addressed and resubmitted to the BOEMRE for it to take action on the Ligurian #2 APD within 30 days thereafter. If the BOEMRE approves the Ligurian #2 APD prior to the return of the Ensco 8503 drilling rig and spud of the North Platte #1 exploratory well, then Cobalt plans to drill the Ligurian #2 exploratory well prior to drilling the North Platte #1 exploratory well.

Cobalt expects the Ligurian #2 exploratory well to take approximately six months to drill. Cobalt is the operator of Ligurian and has a 45% working interest in this prospect. TOTAL E&P USA, INC. owns a 30% working interest and Sonangol Exploration and Production International, LTD. owns the remaining 25% working interest.

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Shell Shares Safe Shale Principles

- Shell Shares Safe Shale Principles

Wednesday, June 29, 2011
Royal Dutch Shell plc

Today, from the 2011 Aspen Ideas Festival, Shell makes its Global Onshore Tight/Shale Oil and Gas Operating Principles available to the public with examples of how the company delivers them. Shell has a rigorous set of five global operating principles that provide a tested framework for protecting water, air, biodiversity, and the communities in which Shell operates.

Shell is openly sharing these operating principles to address public concern about tight/shale oil and gas development - especially regarding hydraulic fracturing – encourage feedback and challenge from our stakeholders, and drive continuous improvement. Shell also supports regulation and enforcement that reinforces responsible operating practices and continues to improve the industry's overall performance.

"We understand there is concern around the development of shale gas, and we must give the public more knowledge of how we operate," said Marvin Odum, President, Shell Oil Company. "People have asked the industry for transparency; we have listened and are responding."

Specific on water, hydraulic fracturing has attracted a great deal of attention in recent months. As an example of how we deliver these principles, which are now described online, Shell mandates a stringent well construction standard that focuses on the use of safe drilling and completion processes, including reducing the risk of water contamination.

Further, Shell supports the disclosure of chemicals used in hydraulic fracturing fluids, monitoring of groundwater, and a reduction in the amount of water used in the drilling process. Shell does not fracture wells unless it has pressure tested the wellbore for integrity. And, the company recycles as much water at each project as reasonably practicable. For example, in the Marcellus Shale, Shell recycles almost 100% of produced fluids, substantially reducing our fluid waste and reducing the amount of water volumes needed for hydraulic fracturing.

In the last decade, the industry has discovered an abundance of natural gas. Of the world's 250-year supply of gas estimated by the International Energy Agency (IEA), almost half is contained in shales, tight sandstones, and coal beds. More than one-third of the global gas-production increase, forecasted by the IEA over the next 25 years, could come from these sources.

"If the innumerable benefits of natural gas are to be realized, we must address the concerns of citizens and share the principles that we hold ourselves to at Shell," said Odum. "These principles manage the risk we know exists when producing energy, but just as importantly, they demonstrate our operational integrity and focus on collaboration, underpinning our belief that natural gas can be produced safely and responsibly."

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Norwegian MPE Gives Statoil's Hyme Green Light

- Norwegian MPE Gives Statoil's Hyme Green Light

Wednesday, June 29, 2011

Just six weeks after the plan for development and operation (PDO) for Hyme (ex-Gygrid) was submitted on May 12, the Norwegian Ministry of Petroleum and Energy (MPE) has given the green light. First oil is scheduled for the first quarter of 2013.

The approval was given the same day as Norwegian petroleum and energy minister Ola Borten Moe presented the main elements of the Norwegian government’s petroleum report. One of the areas mentioned in the report was the aim for quicker PDO decision-making processes.

The Hyme PDO is the fourth fast-track development submitted to the MPE this year, following Visund South, Vigdis Northeast and Katla.

"The approval of Hyme in record time shows that fast-track developments now are accepted as an important approach to infrastructure-led discoveries on the Norwegian continental shelf (NCS). By reducing the time from discovery to first oil by means of standardized solutions, we make small-size discoveries profitable," said Ivar Aasheim, Statoil’s senior vice president for NCS field development.

Discovered in June 2009, the Hyme field is located 19 kilometers north-east of the Njord field on the Halten Terrace.

The development calls for a production well and a water injection well through a subsea template with four well slots. The field will be tied in to existing infrastructure on the Njord A platform, which has idle processing capacity.

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Niko Updates Financial, Operational Results for Year-End

- Niko Updates Financial, Operational Results for Year-End

Wednesday, June 29, 2011
Niko Resources Ltd.

Niko reported its financial and operating results, including consolidated financial statements and notes thereto, as well as its managements' discussion and analysis, for the year ended March 31, 2011. The operating results are effective June 28, 2011. All amounts are in U.S. dollars unless otherwise indicated.

  • There was a year-over-year increase of 32 percent in funds from operations.
  • In October 2010, Niko repaid all of its outstanding long-term debt.
  • At March 31, 2011, the Company's unrestricted cash totaled $108 million.
  • In January 2009, the Company announced that the Canadian authorities were engaged in a formal investigation into allegations of improper payments in Bangladesh. The Company cooperated in the investigation, which was concluded on June 24, 2011. The Company pleaded guilty to one count of bribery under the Corruption of Foreign Public Officials Act, was fined Cdn$9.5 million and is subject to a 3-year Probation Order. In early 2009, the Company adopted a full anti-corruption compliance program.

  • Indonesia: Four new offshore exploration blocks were added and the Company farmed out 45 percent of its working interest in the Seram and East Bula blocks and 40 percent of its working interest in the North Makassar Strait, West Papua IV and Halmahera-Kofiau blocks. Seismic acquisition activity continued during the year and the planning of drilling has commenced.
  • Trinidad: The Company increased its exploration acreage in Trinidad with three new offshore blocks, all of which are in proximity to producing gas fields, and entered into an agreement, which closed subsequent to year-end, to acquire a 25 percent working interest in Block 5(c), located 94 kilometres off the east coast of Trinidad.
  • Madagascar: Seismic acquisition has been completed and processing is underway.
  • Kurdistan: Drilling was completed to a depth of 3,908 meters in May and testing is underway and expected to continue into July 2011.


The Company's strategy of accumulating a highly prospective exploration portfolio continued.

In Indonesia, four new blocks were added and farm-outs occurred in five blocks. Farm-outs are a part of the Company's exploration strategy. Partners in Indonesia now include Exxon/Mobil, Marathon, Repsol and Statoil.

In Trinidad & Tobago, four new blocks were added. Partners in this country include Centrica and RWE.

From a drilling perspective, in Trinidad and Tobago, the Company has contracted an offshore rig that is expected to spud the Company's first offshore well in the country in October. In Indonesia, Niko has established an extremely strong drilling organization staffed with seasoned professionals that bring extensive deep-water drilling experience.

During the past year, uncertainty regarding D6 production, reserves and gas price has been a concern. This uncertainty has been largely removed by an independent reserve report that shows that the revision to the Company's worldwide net proved plus probable reserves was approximately 6.8 percent. Operationally, the D6 field's gross gas production averaged approximately 2 billion cubic feet per day over the year with no downtime.

Due to a pre-emptive right, Niko expects to have the opportunity to increase its net interest by 30 percent in each or all of the D6, NEC-25 and D4 blocks in India. Niko expects this opportunity would be financed with debt.

Niko has a strong production base and an extensive portfolio of exploration prospects. Two thousand and twelve could prove to be Niko's most exciting year ever.

Production from the D6 Block has increased year-over-year and is the primary reason for total production increases of 25 percent compared to production in the prior year. The D6 Block is also the primary reason for improved operating netbacks as the D6 Block has higher realized prices and lower profit petroleum than the average of the Company's other properties.

Gas sales volumes from the D6 Block for the year averaged approximately 198 MMcf/d versus a budget of 210 MMcf/d due to well performance. Current gas sales volumes from the block are approximately 167 MMcf/d. Production from the D6 Block is expected to decline until additional wells are drilled and tied-in.

The Company is forecasting total production of 236 MMcfe/d for Fiscal 2012, which assumes that no additional wells will be tied in at D6 during the year and is consistent with the estimated production from total proved reserves in the Company's reserve report.

Operating cashflow increased in Fiscal 2011 primarily as a result of increased oil and gas sales from the D6 Block. Forecast operating cashflow for the coming year is expected to decrease with the decrease in production described above. In addition, maintenance of the onshore terminal and subsea systems for the D6 Block are expected to result in a decreased operating netback.

Exploration expenditures for Fiscal 2011 were for drilling activities on three exploration wells in the D6 Block, seismic acquisition in Indonesia and Madagascar, drilling of the first exploration well in Kurdistan and seismic on Block 2AB in Trinidad and carrying costs of the Trinidad blocks. Forecast expenditures for Fiscal 2012 include drilling on the D6 and D4 Blocks in India; seismic activity and preparation for drilling activities in Indonesia; completion of drilling the well in Kurdistan, and seismic activity in Trinidad on all blocks and commencement of drilling on Block 2AB.

Development expenditures forecast for Fiscal 2012 are primarily for workovers, drilling new wells and acquisition of compression equipment for the D6 block.

In addition to exploration and development expenditures, the Company's acquisition of Block 5(c), located 94 kilometres off the east coast of Trinidad closed in June 2011 for a purchase price of $78.1 million.

Funds from operations improvements resulted from improved volumes and operating netbacks partially offset by higher current income taxes, higher interest expense related to the Company's convertible debentures, a Cdn$9.5 million (US$9.7 million) fine described previously herein and lower other income as the prior year periods benefited from a favorable arbitration ruling related to a pipeline dispute.

Net income increased year-over-year as a result of the increase in funds from operations. The benefit from improved funds from operations was offset by higher non-cash charges related primarily to depletion and a loss on short-term investments.

Exploration Acreage

Niko has increased its exploration acreage with the addition of three blocks in Trinidad and four blocks in Indonesia. In addition, Niko farmed out 45 percent of its working interest in two blocks in Indonesia to Repsol and 40 percent of its working interest in three blocks in Indonesia to Statoil.

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Drilling Commenced at Aurelian's Krzesinki-1

- Drilling Commenced at Aurelian's Krzesinki-1

Wednesday, June 29, 2011
Aurelian O&G plc

Aurelian provided the following operational and corporate update.

  • First Siekierki South-West well, Krzesinki-1, spudded on 24th June 2011
    • Target depth of 4,150 meters expected to be reached in early 4Q 2011
    • Targeting mid case of 44bcf net to Aurelian
    • Well on trend with conventional producing fields and at present horizontal drilling and fraccing are not planned
  • Completion of disposal of Romanian non-core interests generates initial payment of €6.85 million plus future upside potential
    • Consideration made up of €6.85 million initial proceeds, plus future potential payments depending on ongoing exploration success of Aurelian Oil & Gas Romania SRL
    • Deal structure also adjusts up and down depending on future gas prices and final production achieved from the Bilca and Climauti Gas Project Areas
    • Disposal allows Aurelian's resources to be redirected towards Romanian Carpathian Thrust Fold Belt Core Area

First Siekierki South-West well

Krzesinki-1, the fourth well to be drilled in the Greater Siekierki appraisal program, spudded on June 24, 2011. It will test a structural high 6 kilometers south west of the core area where Trzek-1, 2 and 3 have been drilled. The structure lies on trend and to the north of a number of conventional Rotliegendes fields developed by PGNiG and FX Energy in the license to the south. It is therefore possible that a discovery could be developed without any requirement for the fraccing technology which was utilized in the core area. The well is expected to take three months to reach target depth of 4,150 meters and is targeting mid case net resources to Aurelian of 44bcf with an upside case of 465bcf.

The Siekierki project is located on the Poznan licenses which are 100% held by Energia Zach?d Sp. z.o.o., a company owned 90% by Aurelian and 10% by Avobone N.V.

Completion of the disposal of Romanian non-core interests

Following the Company's announcement of February 4, 2011 advising of the strategic review of its Romanian business and the reorganization and refocusing of its Romania operations on its Carpathian Fold Belt Core Area, the Company is pleased to announce that all regulatory and third party approvals have now been received allowing the completion of the disposal of Aurelian Oil and Gas Romania SRL ("AOGR"). AOGR holds Aurelian's non-core Romanian interests in the Bilca Gas Project Area of the Brodina Concession, the Suceava Concession, and the Bacau North Areas (A and B) of the Bacau Concession.

The purchaser of AOGR is Raffles Energy Netherlands B.V., a subsidiary of the Raffles Energy Group, a private equity investor that has a significant focus in natural resources, energy projects and commodities trading.

As well as enabling Aurelian to redirect resources to focus on its Romanian Carpathian Thrust Fold Belt Core Area, the Company will receive an initial payment of €6.85 million made up of a 'base' cash consideration of €5.3 million plus a further cash consideration of €1.55 million relating to final working capital and other completion adjustments. The consideration mechanism also provides Aurelian with exposure to future exploration success in AOGR by way of a deferred cash consideration structure whereby payments will be made, starting on first production, for each discovery equating to €50,000 for each Bcf of gas discovered (AOGR's share) and €300,000 for each million barrels of oil discovered (AOGR's share) based on the volumes of proved and probable reserves approved in the relevant Field Development Plans. The deal structure also provides for further adjustments (up and down) to the 'base' consideration depending on future gas prices and final production achieved from the Bilca and Climauti Gas Project Areas.

In the year ended 31 December 2010, AOGR achieved net turnover of approximately RON 10.80m (€2.56m) and a loss before tax of approximately RON 10.97m (€2.61m) under Romanian GAAP.

Interests in the Bilca Gas Project Area are Aurelian Oil & Gas (Romania) SRL 62.5% and S.N.G.N. Romgaz S.A. 37.5%.

Interests in the Suceava Concession are Aurelian Oil & Gas (Romania) SRL 50%, Regal Petroleum PLC 50%.

Interests in the Bacau North Area (A) are Aurelian Oil & Gas (Romania) SRL 41.0%, S.N.G.N. Romgaz S.A. 40.0% and Europa Oil & Gas SRL 19.0%.

Interests in the Bacau North Area (B) are Aurelian Oil & Gas (Romania) SRL 60.0%, S.N.G.N. Romgaz S.A. 40.0%.

Interests in the Brodina Exploration Area are Aurelian Petroleum SRL 33.75%, S.N.G.N. Romgaz S.A. 37.50% and Europa Oil & Gas SRL 28.75%.

Interests in the Cuejdiu Concession Area are Aurelian Petroleum SRL 45.0%, S.N.G.N. Romgaz S.A. 37.50% and Europa Oil & Gas SRL 17.5%.

Rowen Bainbridge, Chief Executive commented, "We are pleased to have spudded the Krzesinki-1 well on time and look forward to reaching target depth early in 4Q 2011. Krzesinki-1 is an exciting prospect which, if successful, could add significant conventional gas to the existing 346 bcf (net to Aurelian) in the Siekierki Tight Gas Project.

"We have now completed the refocusing of our business in Romania and look forward to moving ahead with the appraisal of Voitinel and our oil exploration activities in the Romanian Carpathians. The exit of our Romanian non-core interests has been achieved at a value that we are pleased with whilst also providing us with further upside based upon the future exploration success of AOGR."

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Chevron Exec: East Europe Shale Development Slower Than In US

- Chevron Exec: East Europe Shale Development Slower Than In US

Wednesday, June 29, 2011
Dow Jones Newswires
by Jacob Gronholt-Pedersen

U.S. oil major Chevron is optimistic about the geological potential at recently acquired shale acreage in Eastern Europe, but says lack of infrastructure and a poor regulatory environment will slow down the development.

Unconventional gas sources such as shale gas, which has shaken up the U.S. gas market in the past two years, have also caught the interest of major players in Eastern Europe.

"It's not easy to replicate the shale gas developments we saw in the U.S.," Jay Pryor, Chevron Vice President in charge of global business development, told Dow Jones Newswires in an interview.

The U.S. oil major has acquired shale gas acreage in Poland, Bulgaria and Romania.

"We certainly think the reservoir potential is there, but it will take a little longer to develop," Pryor said.

"The regulatory environment as well as the infrastructure, including pipelines and service work necessary to drill the wells, just isn't as developed (as in the U.S.)," he added.

Shale gas and oil are being produced using relatively new technologies such as hydraulic fracturing, which involves injecting a mixture of water, sand and chemicals underground at high pressures to release oil from hydrocarbon deposits.

In recent years, these technologies have unlocked shale oil and gas that weren't previously accessible, leading to a boom in new wells across the U.S. and flooding the market with natural gas. In 2009, the U.S. surpassed Russia as the world's biggest gas producer in 2009.

Most of the attention is in the U.S. around accomplished shale basins in North Dakota and Texas. Following a $3.2 billion acquisition of gas producer Atlas Energy in the beginning of the year, Chevron last month acquired the rights to 228,000 acres in the Marcellus Shale.

"We expect others are to be found around the world, and we are certainly looking for them," said Pryor.

However, there are significant hurdles to further development of shale deposits both in the U.S. and globally. After years of rapid growth, shale gas producers have begun to bump into cost constraints and particularly environmental concerns about water contamination during the drilling process.

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

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Schlumberger Takes Remaining Shares of Frank Engineering

- Schlumberger Takes Remaining Shares of Frank Engineering

Wednesday, June 29, 2011
Schlumberger Ltd.

Schlumberger announced the acquisition of the remaining equity shares from Frank Mohn AS in Framo Engineering AS—a privately owned Norwegian company specialized in the business of developing, manufacturing and selling products and services relating to multiphase pumps and subsea pump-systems, multiphase metering systems, and swivels and marine systems to the oil and gas industry. The closing of the transaction is subject to regulatory approval.

"This transaction is an important step in the development of subsea technologies and solutions to improve hydrocarbon recovery and lower costs in the subsea environment," commented Paal Kibsgaard, Chief Operating Officer, Schlumberger Limited. "The combination of Schlumberger subsea flow assurance and surveillance capabilities with Framo Engineering's extensive subsea multiphase boosting and metering capabilities will help our customers better design their subsea infrastructure, optimize production and increase recovery over the life of the field."

"I believe this to be a great opportunity for Framo Engineering and for all of its employees," commented Ole Steine, Managing Director of Framo Engineering. "We are very pleased to be a Schlumberger company and see a fantastic future together by combining our skills. Our successful 14-year collaboration with Schlumberger for the development of the multiphase metering activity proved a good cultural fit between us that we believe will foster increasing innovation and create further opportunities."

Frederik Mohn, Managing Director of Frank Mohn, minority owner, concluded, "We are proud to have been at the inception of Framo Engineering. The company has gone through an exciting transformation, considerably strengthening its strategic positioning and the depth of its management team. The sale to Schlumberger is an outstanding recognition of the value that has been created over many years. We are confident that being part of Schlumberger will enable Framo Engineering to take on the upcoming large integrated subsea projects worldwide, while clearly recognizing Norwegian skills."

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Cobalt Anticipates Rig Arrival Offshore Angola

- Cobalt Anticipates Rig Arrival Offshore Angola

Wednesday, June 29, 2011
Cobalt International Energy Inc.

Cobalt has received notification that the Ocean Confidence drilling rig, which is currently under assignment to an Angolan affiliate of Total S.A., will be returned to Cobalt on Block 21 on or about July 12. Upon its return, Cobalt will immediately commence its initial two well pre-salt deepwater exploration drilling program on Block 21 offshore Angola. Given the proximity of the two exploratory well locations, Cobalt plans to drill the surface hole of the Bicuar #1 exploratory well, move the drilling rig to the Cameia #1 exploratory well to drill and evaluate that prospect, then return to the Bicuar #1 exploratory well to drill and evaluate it. Cobalt expects each well to take 80 to 100 days to drill and an additional 10 to 20 days to evaluate if successful. Cobalt is the operator of Cameia and Bicuar and
has a 40% working interest in each prospect.

In addition, Cobalt anticipates the execution of the production sharing agreement for its 40% working interest and operatorship of Block 20 offshore Angola will occur early in the third quarter of 2011.

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Keppel Secures Shipbuilding Contracts from Brazilian Operators

- Keppel Secures Shipbuilding Contracts from Brazilian Operators

Wednesday, June 29, 2011
Keppel Corp. Ltd.

Keppel Singmarine Brasil (KSM Brasil), Keppel Offshore & Marine Ltd (Keppel O&M)'s new 7.6-ha shipbuilding facility in the state of Santa Catarina, has secured two newbuild contracts worth about S$140 million from fleet operators in Brazil.

The first contract entails building a series of six 45-tonne bollard pull twin-screw Azimuth Stern Drive (ASD) harbour tugboats, for REBRAS - Rebocadores do Brasil S.A. (SMIT Rebras).

In the second contract, the yard will construct a large-sized 4500dwt Platform Supply Vessel (PSV) based on its proprietary MTD 9045P-DE design for Keppel O&M's Brazilian ship-owning arm, Guanabara Navegacao.This is the first vessel constructed under the business model to build Offshore Support Vessels in anticipation of demand in Brazil, and such vessels will be offered for bare-boat charter or sale upon completion.

KSM Brasil specialises in constructing Offshore Support Vessels such as Anchor Handling Tug Supply (AHTS) vessels, PSVs, Oil Recovery Support Vessels and harbour/terminal tugboats.

The new facility in Brazil is also able to fabricate offshore steel structures and support major projects undertaken by Keppel's BrasFELS yard in Angra dos Reis.

Mr. Hoe Eng Hock, Executive Director of KSM Brasil shared, "Petrobras will need over 100 Brazilian-built offshore support vessels by 2020, to facilitate the exploration and development of the Santos Basin's deep water pre-salt fields. We see a growing market for purpose-built support vessels that can operate safely and efficiently offshore Brazil.

"Keppel Singmarine has been building harbour tugs for the global fleet of Smit in Singapore and China Nantong for the past 20 years. With the award of six harbour tugs contract, the relationship and partnership between Smit and Keppel has deepened and expanded to the new frontier in Brazil."

KSM Brasil's scope for the six tugboats includes detailed design and engineering work and the purchase of all equipment. The first tugboat will be delivered in 4Q2012, followed by the remaining five at three-month intervals. These Robert Allan-designed tugboats will be deployed by SMIT Rebras to work at key ports across Brazil.

Meanwhile, GNL's 4500 dwt PSV is slated for completion in 2013. The PSV is custom-designed by Keppel's Marine Technology Development unit to meet the stringent requirements of Petrobras. The unique arrangement of the PSV's internal tanks and systems enable it to transport a wide combination of oil-based and water-based bulk cargoes for offshore exploration and production.

This ABS Classed PSV spans 94.2m long and 19.8m wide. It features a large deadweight capacity in excess of 4,500 tonne and a deck space of 1000sqm which can accommodate 26 crew members. Equipped with a diesel-electric propulsion system and dynamic positioning (DP) 2 capability, this PSV is well suited to operate in different offshore conditions.

The above contracts are not expected to have any material impact on the net tangible assets and earnings per share of Keppel Corporation Limited for the current financial year.

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Clean Diesel Technologies Announced Pricing Of Underwritten Public Offering Of Shares

- Clean Diesel Technologies Announced Pricing Of Underwritten Public Offering Of Shares

Jun 29, 2011

Clean Diesel Technologies (NASDAQ:CDTI) announced the pricing of an underwritten public offering of 2,725,000 shares of its common stock at a price to the public of $3.75 per share. Clean Diesel is offering 2,645,000 of these shares and 80,000 of these shares are being offered by selling stockholders.

The company has granted a 30-day option to the underwriters to purchase up to an additional 408,750 shares of common stock to cover over-allotments.

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McMoran Unveils Davy Jones Find; Affirms Shallow-Water Projects' Safety

- McMoran Unveils Davy Jones Find; Affirms Shallow-Water Projects' Safety

Wednesday, June 29, 2011
Dow Jones Newswires
by Tess Stynes

McMoRan confirmed that its ultra-deep drilling programs in shallow waters of the Gulf of Mexico can be pursued safely, and unveiled more finds in its Davy Jones prospect.

The company said its exploration activities have indicated the potential for large accumulations of hydrocarbons at the deeper depths.

Its shares were up 8.6% at $18 in recent premarket trading. The stock through Tuesday's close has risen 50%.

McMoran, which focuses on such "deep gas plays" has been pinning its hopes on the Davy Jones project, which the company has said has the potential to be one of the largest on the Gulf's shelf in decades.

This month, one of its wells in the Davy Jones prospect encountered 192 net feet of potential hydrocarbons. McMoRan is evaluating development options and expects to complete the well in the second quarter of next year.

The company late this year also plans to complete and flow test another well, which it previously reported logged 200 net feet of hydrocarbon pay. McMoRan holds a 60.4% working interest and a 47.9% net revenue interest in Davy Jones.

Other working interest owners include Energy XXI (Bermuda) with a 15.8% interest, Nippon Oil Exploration USA Limited at 12%, W.A. "Tex" Moncrief, Jr. at 8.8% and a private investor with 3%.

McMoRan late last year acquired Plains Exploration & Production Co.'s shallow-water operations in the Gulf plus other assets in a deal initially valued at $818.1 million.

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

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