Oil and Gas News: 06/09/11

Thursday, June 9, 2011

Oil & Gas Post - All News Report for Thursday, June 09, 2011

Thursday, June 09, 2011

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Commodity Corner: Oil Soars Past $101 a Barrel

- Commodity Corner: Oil Soars Past $101 a Barrel

Thursday, June 09, 2011
Rigzone Staff
by Saaniya Bangee

Oil prices rose 1.2 percent Thursday as investors continued to speculate after OPEC's Wednesday meeting.

For the first time in almost 20 years, the Organization of Petroleum Exporting Countries (OPEC) was unable to reach a consensus on output quotas. The decision-divide, on whether to increase production or not, pushed prices past the $100-mark. Oil futures for July delivery gained $1.19 a barrel to settle at $101.93 Thursday.

The International Energy Agency, which advises some of the wealthiest nations on energy policies, said it was "disappointed" with OPEC's decision and was "ready to work with its member governments and others to help ensure that markets are well supplied."

Meanwhile, the U.S. Energy Department reported that 4.8 million barrels fell last week, the biggest decline of the year. Additionally, the Labor Department reported 427,000 jobless claims for this week, a thousand more than the previous week.

The intraday range for oil was $100.74 to $102.44 a barrel.

Futures for front-month natural gas plunged Thursday, settling at $4.674 per thousand cubic feet. The 3.6 percent-drop came on reports of above-average inventories. According to the Energy Information Administration (EIA), last week's supplies were at 2.187 trillion cubic feet, up 80 billion cubic feet. Prices for natural gas traded between $4.51 and $4.98 Thursday.

Gasoline increased by 6.11 cents settling at $3.04 a gallon. Gasoline futures fluctuated between $2.97 and $3.05.

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Subsea Wells Produce Most -NPD

- Subsea Wells Produce Most -NPD

Thursday, June 09, 2011
Norwegian Petroleum Directorate

Far more oil and gas is now being produced from subsea wells on the Norwegian continental shelf than from platform wells.

The Norwegian Petroleum Directorate has collated production from the fields in 2010 and found that subsea wells dominate the picture.

Last year, almost 131.3 million standard cubic meters (Sm3 o.e.) oil equivalents were produced from subsea wells and about 125.4 million Sm3 o.e. from platform wells.

Increased production of gas has caused the production from subsea wells to exceed production from the fixed platforms. Large gas producers, such as the Troll field in the North Sea and Ormen Lange and Åsgard in the Norwegian Sea, contribute extensively with their many subsea facilities.

In the past ten years, the trend of more subsea wells has been rising. Increasingly improved technological solutions have made it possible to develop many small reservoirs using subsea facilities in instances where a solution with a fixed platform has not been commercially viable.

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Stark County Commission Denies Tax Exemption to Oil Company

- Stark County Commission Denies Tax Exemption to Oil Company

Thursday, June 09, 2011
Knight Ridder/Tribune Business News
by Sean M. Soehren, The Dickinson Press, N.D.

Stark County Commission members denied the first-ever oil-related company request for a property tax exemption during a meeting at the Stark County Courthouse Tuesday.

Stark County Tax Director Diane Brines said after the meeting that the exemption would have allowed for more than $250,000 each year for the next five years.

Commissioners said they did not want to set a standard of giving exemptions to oil companies.

"We have not issued exemptions in the oilfield at this point, but I guess no one has come forward to us before either," Brines said during the meeting.

The request from EDOG Logistics, LLC, of Wichita, Kansas, was for a 100 percent five-year property tax exemption eligible under the new construction and expansion clause of the North Dakota Century Code.

"This is a difficult one for us to allow for exemption when the industry is doing so well," Commissioner Jay Elkin said during the meeting, adding that oil production has been very profitable and that other companies have not asked for exemptions.

EDOG plans on adding to the facilities where oil is transferred from storage tanks to transport railcars located northwest of Dickinson, representative John C. Wadsworth said. The plant plans to construct three oil storage tanks, truck unloading bays, pipeline receiving connections and railway loading for 12 railcars. Wadsworth said the estimated value of the improvements would create a $20 million asset.

"The plant will be a benefit to Stark County and the city of Dickinson," Wadsworth said, adding that it will create about 75 contractor jobs during construction and 15 full-time positions during operation, with growth estimated up to 35 direct positions in the next two years.

Commission Chairman Ken Zander said the county wants to be a "good neighbor" and support development, but he didn't want to set a precedent and the exemption would mean lost funding for other entities.

"We don't want to start allowing or giving a company or private developer an exemption that affects other taxing entities, such as the school district or city of Dickinson, without input from them and how they would be affected," Zander said.

Commissioner Pete Kuntz agrees.

"If we give it to one company, we will be expected to give it to others," he said during the meeting.

Stark County recently granted exemptions to an ethanol plant near Richardton, Baker Boy and Steffes, but they have not been total exemptions. The companies work with a graduated program where the amount exempt decreases over the years, Zander said.

Stark County States Attorney Tom Henning said EDOG could resubmit the request under different conditions, such as a smaller exemption percentage or a graduated program. Also, he said commissioners could design an exemption program that would feasibly fit the budget.

After the meeting, Wadsworth said EDOG was still excited to bring a profitable asset to the area.

Copyright (c) 2011, The Dickinson Press, N.D.

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Bucks County Republican Looks for Sponsor on Shale Fee

- Bucks County Republican Looks for Sponsor on Shale Fee

Thursday, June 09, 2011
Knight Ridder/Tribune Business News
by Brad Bumsted, The Pittsburgh Tribune-Review

A Bucks County Republican is asking legislators to co-sponsor her shale impact fee which she says is designed to try to win GOP Gov. Tom Corbett's approval.

Corbett has said any measure must be a fee and not a tax and the main purpose must be to help compensate municipalities for damages gas drilling causes. He has said revenue from a fee should not go into the state's General Fund.

For starters, Rep. Marguerite Quinn says her proposal is a fee. It is not based on gas well production nor is it tied to the price of natural gas like a half-dozen or so tax proposals pending in the House and Senate, she said. It's a flat rate on a declining scale, starting at $50,000 per well.

While the state Department of Revenue would collect the fee, the revenue would not go into the General Fund, Quinn told colleagues in a memo seeking co-sponsorship.

"I've been working on it -- something that does meet the governor's criteria," Quinn said today. "I tried to respect the governor's call for no tax. I made it a simple impact fee."

Asked about Quinn's proposal, Kevin Harley, Corbett's spokesman was non-committal. "Gov. Corbett has said he is open to an impact fee. But he wants to wait until his Marcellus Shale Advisory Commission issues a report."

The commission, headed by Lt. Gov. Jim Cawley, is attempting to quantify local drilling costs. The report will be issued July 22 while lawmakers are likely on summer recess after adopting a state budget by June 30.

Quinn said she plans to meet with Cawley to outline her proposal.

Under Quinn's proposal, half of the revenue would be deposited into an "impact mitigation fund" for use by counties and municipalities hosting drilling. That would cover fire, police and emergency service costs, as well local water issues, and repairing roads and bridges.

Twenty-five percent of money would go for statewide environmental projects and hazardous waste cleanup. The money would go to a state fund for environmental use called Growing Greener. It would be used for projects such as watershed protection, acid mine drainage abatement and cleanup and plugging of wells.

And 20 percent of the revenue would go to the state Motor License fund for road and bridge repairs. Five percent would go to local conservation districts.

Quinn says she is calling her plan a fee on shale, not Marcellus shale. The point is to cover drilling in deeper layers beneath the Marcellus shale formation such as the Utica formation.

"We don't want to be shortsighted in structuring this and have to re-invent the wheel later," she said.

Copyright (c) 2011, The Pittsburgh Tribune-Review

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Exxon Mobil Gains 0.9%; Refiner Inks Pact to Buy Natural Gas Producers

- Exxon Mobil Gains 0.9%; Refiner Inks Pact to Buy Natural Gas Producers

Jun 9, 2011

Shares of Exxon Mobil (XOM) are higher on a Bloomberg report the oil major spent $1.69 billion for two privately held energy explorers to gain shale-gas reserves in Pennsylvania and adjacent states.

Exxon bought XTO Energy last year, making it the largest gas producer in the US, he report said.

Exxon shares are up 0.92%, or $0.74, to $81.50.

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Commission Leases Land to Oil Company

- Commission Leases Land to Oil Company

Thursday, June 09, 2011
Knight Ridder/Tribune Business News
by Josh Mitchell, Wyoming Tribune-Eagle, Cheyenne

The Laramie County Commission on Tuesday leased county-owned mineral rights for oil development.

Pacer Energy Acquisitions of Gillette is leasing the 9.7 acres on Chalk Bluff Road, south of Cheyenne, from the county for $500 an acre for five years.

The county also may lease more than 800 acres of mineral rights at the Archer Complex east of Cheyenne to the same company.

Pacer Energy is a third-party land broker acting on behalf of Texas-based Anadarko Petroleum.

For the Chalk Bluff Road lease, the county will get 18.75 percent of the royalties from any minerals extracted.

"The parcel is located near an area where we currently have ongoing operations," Anadarko spokesman Brian Cain said. "Land acquisition is a normal part of early-stage oil and natural-gas exploration."

The county owns 50 percent of the mineral rights under the property, county attorney Mark Voss said.

That means the county will get 18.75 of the royalties on 50 percent of the minerals extracted.

Voss and County Commission Chairwoman Diane Humphrey both said they do not know who owns the other half of the mineral rights.

Pacer has offered the same lease rate and royalty percentage for the Archer land as well, Humphrey said.

The county owns 100 percent of the mineral rights the Archer property, which totals 875 acres.

Humphrey said she is pleased with the amount of money the county is getting for the Chalk Bluff Road lease. She said a royalty of 18.75 percent is "almost unheard of."

It could take two to three years to see revenue from royalties, Commissioner Gay Woodhouse said.

The Chalk Bluff Road land is unlikely to generate hundreds of thousands of dollars in royalties because it is a small parcel, Humphrey said.

But the county could make significant money if it leases the Archer property and it pays off.

At $500 an acre, the lease itself at Archer would generate over $400,000. In addition, the county would make money from the mineral royalties.

The commission will advertise the property to other oil production companies as well to get the best deal, Humphrey said.

Since it is taxpayer-owned land, the county has an obligation to get the most money it can from the property, Humphrey said.

Voss said the county will solicit offers for the Archer mineral lease until June 17.

Money made off the oil leases could help build a new fairgrounds at the Archer Complex, Humphrey said. Also, it could go toward county employees and road construction.

Voss said it is unusual for the county to own mineral rights as it usually only has surface interests.

In Wyoming, there can be two owners to a piece of property -- the surface owner and the mineral owner. For the most part, the county only owns the surface rights to property.

It is unclear how many acres of mineral rights the county owns.

Woodhouse supports the leasing.

"I am in favor of getting the money we can for the leases," she said. "It's a good source of revenue."

Some of the revenue could help complete the indoor shooting range at the Archer Complex, Woodhouse said. She added that there remains about $700,000 worth of work to finish the project.

Copyright (c) 2011, Wyoming Tribune-Eagle, Cheyenne

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Beach to Begin Flow Stimulation at Holdfast Shale Well

- Beach to Begin Flow Stimulation at Holdfast Shale Wel

Thursday, June 09, 2011
Beach Energy Ltd.

Beach has rigged up on site, conducted mechanical checks and is ready to commence stimulation of the target zone in its PEL 218 Holdfast-1 shale gas well.

The flow stimulation of Holdfast-1 will be undertaken in eight stages and is expected to be completed within two weeks, with the first flow results expected in early July.

Both the Holdfast-1 and Encounter-1 wells were specifically designed as data gathering wells and not production wells. This will likely result in lower flow rates than would otherwise be achieved from horizontal wells typically used in plays in the USA and likely to be used in Beach's future production and development activity.

Flow stimulation of conventional gas wells has been an ongoing part of gas production in the Cooper Basin over the past 40 years, however, this will be the first time flow stimulation has specifically targeted shale target zones at depth.

The Encounter-1 shale well has experienced completion delays as a result of a well bore mechanical issue. During final checks of the recently installed stimulation work string, some adjustments were found to be necessary. While attempting to recover the work string from the wellbore, difficulties were experienced in removing it from the downhole latch assembly and it appears additional equipment will now be required to resolve the issue. This will likely result in a delay in the stimulation activities of Encounter-1.

There will be no impact on the shale gas pilot production program, set down for early 2012, as a result of the likely delay in the Encounter-1 flow stimulation. Indeed, this now provides Beach with more time to assess the results from Holdfast-1, from which it will be able to optimize the flow stimulation of the Encounter-1 well should it be required.

It is expected that a shale gas resource addition will be made in July/August 2011.

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Rodinia Spuds Well in South Australia

- Rodinia Spuds Well in South Australia

Thursday, June 09, 2011
Rodinia Oil Corp.

Rodinia has spudded its first well, Mulyawara 1, in the Officer Basin of South Australia.

Rodinia began drilling Mulyawara 1 on the morning of Thursday June 9, 2011, Australian Central Standard Time. Rodinia has an 80% working interest in this well and prospect, and is the operator. Drilling of Mulyawara 1 is expected to take approximately six to eight weeks to reach total depth after which prospective hydrocarbon shows will be tested.

Mulyawara 1 is located in the northwest corner of PEL 253 in the Officer Basin on a structure of approximately 36.3 square kilometers (per horizon) in size as identified on seven separate 2-D seismic lines. It will be drilled vertically to an estimated total drilling depth of 2,700 metres to test five prospective reservoir horizons: Murnaroo, Talina, Mundallio, Emeroo and Pindyin, the deepest of which is the aeolian Pindyin sandstone (also called the sub-salt unit).

Rodinia's drilling contract with Ensign International Energy Services includes four firm wells with the option for up to four additional wells in the Officer Basin. Rodinia's second drilling location, Kutjara 1, has recently been hi-graded and re-confirmed by additional 2-D seismic lines. Kutjara 1 is located in the west-central portion of PEL 253 approximately 35 kilometers southeast of Mulyawara 1.

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Tethys Updates Operations at Tajik Well

- Tethys Updates Operations at Tajik Well

Thursday, June 09, 2011
Tethys Petroleum Ltd.

Tethys announced a further update on the East Olimtoi EOL09 exploration well in south-western Tajikistan.

Electric logs have now been run in the well over the Alai interval (a secondary target) which, as previously announced produced live oil and gas to surface while drilling and showing high formation pressures. The electric logs have confirmed the probable presence of moveable hydrocarbons in the interval from 3,341 to 3,500 meters. Independent petrophysical interpretation indicates up to 32 meters of net hydrocarbon bearing pay in the section with porosities of up to 17%. No oil-water contact is interpreted in this section of the well. The potential closure covers an area of over 10 km2 in the East Olimtoi prospect alone.

The well is currently drilling ahead at a depth of 3,544 meters in the Suzak shale which separates the Alai from the Bukhara limestone. Depending on formation pressures it is planned to set 7 inch casing at the base of the Suzak Shale prior to drilling through the Bukhara. It is planned to conduct production testing on all zones of interest after the drilling has been completed in approximately 3-4 weeks.

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Eagle Oil Holding, Questus Enter Farmout Agreement

- Eagle Oil Holding, Questus Enter Farmout Agreement

Thursday, June 09, 2011
Eagle Oil Holding Co., Inc.

Eagle Oil Holding announced the execution of a Farmout Agreement with Questus.

Pursuant to the Agreement, Questus will provide the funding and other resources necessary to recondition and restart up to 173 wells at the Company's East Texas field, including the previously announced farmout agreements that totaled up to 20 wells, the Questus Agreement represents the completion of the Company's strategy to outsource the reconditioning of its oil resources. The Agreement is subject to an initial payment being made by Questus by June 22, 2011. The parties expect work on the wells to commence shortly thereafter. Questus will also complete the compliance requirements of the Texas Rail Road Commission.

Questus will provide the necessary capital and resources to restore the pumping operations with no additional capital investment by the Company in exchange for a share oil the revenue generated by the wells.

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Tag Concludes Initial Flow Testing at Sidewinder-4 Well

- Tag Concludes Initial Flow Testing at Sidewinder-4 Well

Thursday, June 09, 2011
TAG Oil Ltd.

TAG Oil reported the initial flow testing of the Sidewinder-4 discovery well, the third of four Sidewinder wells to be tested, is now complete. The Sidewinder oil and gas discovery is located in TAG Oil's Petroleum Exploration Permit 38748 in the Taranaki Basin, New Zealand.

The Sidewinder-4 exploration well was drilled to a depth of 1,410 meters (4,626 feet), targeting a fault bounded 3-D anomaly identified in the Mt. Messenger Formation. The well was drilled down-dip of Sidewinder-3 and encountered 19 meters of net oil-and-gas-charged sandstones, with no water column evident. A 4-Point Isochronal test achieved stabilized flow rates of 6.98 million cubic feet per day (~1163 BOE per day) with a 25% drawdown. These results are consistent with the other Sidewinder oil and gas discovery wells tested to date, as summarized below:

Sidewinder Discovery Flow Test Results

Sidewinder Well	Gas Flow Rate (MMcfpd)	BOE Flow Rate (boepd)	Final Drawdown Rate	Net O&G Encountered
Sidewinder-1	7.40	1,233	28%	14 meters
Sidewinder-2	Testing Underway	Testing Underway	Testing Underway	47 meters
Sidewinder-3	7.21	1,202	40%	15.4 meters
Sidewinder-4	6.98	1,163	25%	19 meters
Totals	21.59 MMcfpd	3,598 Boepd

Flow testing of the Sidewinder-2 discovery is currently underway. This well encountered the largest net pay of all Sidewinder wells to date, with 47 meters of oil-and-gas bearing sandstones. Five separate zones will be tested, including new zones both above and below the primary Sidewinder discovery zone.

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EGPI Firecreek's Tx. Well Online

- EGPI Firecreek's Tx. Well Online

Thursday, June 09, 2011
EGPI Firecreek Inc.

EGPI Firecreek announced additional progress for its two well workover programs in its recently acquired oil and gas interests in the Tubb Leasehold Estate located in the AMOCO/CRAWAR Field in Ward County, TX.

The Company previously reported completing its workover program on the Crawar (Highland) #1, successfully perforating 200 feet in the Glorietta zone at approximately 3,700 to 3,900 ft. The well has now entered production of oil & gas and is now online. Additionally, the Company has completed its work program for the second well of the work program, the Tubb 18-1 well located on the North 40 acres.

As previously reported, work has been performed in the 18-1 perforated select segments of both the Upper Clearfork zone at approximately 4,100 to 4,200 ft. and the Tubb zone at 4,517 to 4,600 ft. As of today, the 18-1 well cleanup has been completed and Success Oil Co., Inc., the Company' operator, has confirmed the well is ready to go online for production shortly after pump jack balancing.

The Company further announced that they have entered into discussions and have initiated project evaluations, for the proposed development of the Jackson X-1 Project with Firecreek Global, Inc.

EGPI is looking to participate in a 50% net revenue interest in the program. The proposed project is a combination of the development of existing proven formations and a possible deep wildcat into the Cambrian formation at 8,500 feet. Firecreek's GeoScience Team has noted encouraging indications of a deep structure in the Cambrian formations. This will be confirmed and defined by a seismic program focusing on the deeper formation of the 1,060 acre plus block. Global has already started a rehabilitation program on the multi-zone shallower formations which have been productive. This is a part of the old Magnolia Red Horse Field, located in Northern Callahan County, Texas, 5 mi North of Baird, TX and 25 mi NE of Abilene, TX.

Dennis Alexander, CEO and Chairman, stated, "We are very pleased with our recent progress in the Tubb Field and are excited to be seeing an increase in that fields performance. We look forward to the pursuit of other Tubb field related developments." He further stated, "The recent climate is looking extremely promising and very encouraging for us to begin increasing our growth pattern for oil and gas over the next several months."

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Cooper Briefs on Worrior Divestment

- Cooper Briefs on Worrior Divestment

Thursday, June 09, 2011
Cooper Energy Ltd.

Cooper Energy has been advised that GBX has not raised the capital necessary to conclude the purchase.

In light of the above, Cooper Energy has issued a notice of termination in relation to the Share Sale Agreement under which GBX was to purchase all of the shares in Worrior (PPL 207) Pty Ltd. Cooper Energy will therefore retain full beneficial ownership of the following assets:

30% of the Worrior Oil Field
25% of PEL90
30% of PEL93

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Bridge Completes NCS Farm-Down

- Bridge Completes NCS Farm-Down

Thursday, June 09, 2011
Bridge Energy Norge AS

Bridge has completed the agreement with Total E&P Norge AS for the farm-down of 40% working interest in production licenses PL554 and PL554B on the Norwegian Continental Shelf. The agreement also includes transfer of operatorship from Bridge Energy to Total. After the transaction Bridge Energy hold 20% working interest in the two licenses. The main prospect in the licenses, Garantiana, is scheduled for drilling 1Q 2012 with the semisub Borgland Dolphin.

Einar Bandlien, Bridge Energy CEO, commented, "We are delighted that Total EP Norge has joined us in the PL554 license which demonstrates robust support for the technical potential of the acreage. In addition, we welcome the wealth of capability Total brings to the partnership in its role as Operator."

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Trinidad Drilling Sells Service Rigs

- Trinidad Drilling Sells Service Rigs

Thursday, June 09, 201
Trinidad Drilling Ltd.

Trinidad Drilling has entered into an agreement to sell its well servicing rigs and related equipment (TWS) to Central Alberta Well Services Corp. (CWC) for $38 million in cash, excluding positive working capital.

Well servicing has been an important part of Trinidad's operations for more than ten years and has provided a level of diversification as the Company has grown its contract drilling business. Trinidad now operates more than 120 drilling rigs across North America, providing broad geographic diversification and reducing the need for the diversification added by the well servicing division.

"As well servicing has become a less significant part of our overall business, we needed to invest capital to grow this division or to narrow our focus more tightly towards contract drilling," said Lyle Whitmarsh, Trinidad's President and Chief Executive Officer. "Our growth over past few years has largely been through adding deep, technically advanced drilling rigs and we have developed a reputation as an industry leader in this area. Our decision to sell our well servicing assets reflects our strategy to focus on the deep, modern contract drilling market where returns are generally stronger and where we see opportunities for future growth."

Trinidad's well servicing division has 22 well servicing rigs operating from three centers in Alberta. The well service fleet is made up of:

Two skid doubles
Six mobile free standing class III singles
Five mobile class III doubles
Two mobile class III free standing doubles
Seven mobile free standing class II singles

CWC has agreed to purchase all 22 of TWS's service rigs and anticipates that they will retain the vast majority of employees currently working for TWS. The sale is expected to close on June 15, 2011. Trinidad expects to use the proceeds from the sale to fund the growth of its deep, technically advanced drilling fleet or to reduce overall corporate indebtedness.

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Total: Ekofisk South, Eldfisk II Get Govt Nod for Development

- Total: Ekofisk South, Eldfisk II Get Govt Nod for Development

Thursday, June 09, 2011
Total

Total announced the launch of the Ekofisk South and Eldfisk II projects offshore in the southern Norwegian North Sea on Production Licence (PL) 018. Total holds a 39.90% interest in the license.

The plan for development and operation for each project has been approved by the Norwegian authorities.

The Ekofisk South project will include a new platform (Ekofisk 2/4Z) and a new subsea facility (Ekofisk 2/4VB) at the Ekofisk complex. The platform will have a 40 years design life and a capacity of 70,000 barrels of oil equivalent (boe) per day. The new facilities will enable the drilling of 35 production and 8 water injection wells to further develop the Ekofisk field and increase oil recovery. Production start-up is expected early 2014.

The Eldfisk II project will include a new platform (Eldfisk 2/7S) at the Eldfisk complex and substantially upgrade the existing facilities on the Eldfisk field. The new platform will have 40 years design life and a capacity of 70,000 boe per day. It will provide accommodation, new process facilities, and will enable the drilling of 30 production and 9 water injection wells to further develop the Eldfisk field and increase oil recovery. Production start-up is expected in 2015.

These two projects will enable the development of around 450 million barrels of oil equivalent of reserves.

"These two projects represent major investments for Total and clearly demonstrate our long-term commitment to continued value creation in Norway," said Patrice de Viviès, Senior Vice President Exploration & Production Northern Europe, Total.

The Ekofisk and Eldfisk fields were discovered in 1969 and 1970. First production was achieved from the Ekofisk field in 1971 and Eldfisk came on stream in 1979. The two fields produced around 260,000 boe per day on average in 2010.

PL 018 partners are Total (39.90%), ConocoPhillips (35.11% and Operator), ENI (12.39%), Statoil (7.60%) and Petoro (5.00%).

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Trinidad Drilling Expands Rig Fleet

- Trinidad Drilling Expands Rig Fleet

Thursday, June 09, 2011
Trinidad Drilling Ltd.

Trinidad Drilling announced the acquisition of four drilling rigs that, following enhancements, will be added to its US drilling operations.

"We were able to purchase these rigs at a very attractive price and following their upgrades, they will be a good fit with our fleet of deep, technically advanced equipment," said Lyle Whitmarsh, Trinidad's

President and Chief Executive Officer. "The design and style of these rigs will work well in today's drilling environment, and by applying our drilling automation and electrical expertise to the rigs, we will be able to add efficient, high performing equipment to our fleet at a relatively inexpensive cost."

The total cost of the rigs is expected to be US $44 million, including the initial purchase price and subsequent upgrades. Following their enhancement, the rigs will be highly automated, 1,500 horsepower, AC triple rigs with a depth capacity of 20,000 feet (6,096 meters). The first rig is expected to be operational by the end of the third quarter of 2011 and the remainder will be ready by the end of the year.

The forecast annual EBITDA for these four rigs is expected to more than offset any EBITDA associated with the service rigs recently sold. In addition, the land rigs generate a stronger return on capital and align with the Company's strategy to narrow its focus towards contract drilling.

Following the completion of the 2011 and 2012 rig build program, Trinidad will have a total of 129 drilling rigs with 56 rigs in Canada, 70 rigs in the US and 3 rigs in Mexico.

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Norwest Drills Ahead at Arrowsmith Well

- Norwest Drills Ahead at Arrowsmith Well

Thursday, June 09, 2011
AWE Ltd.

AWE reported that at 0600 hours today (WST) the Arrowsmith-2 exploration well was drilling ahead at a measured depth of 2,291 meters after running and cementing 9-5/8" casing at a measured depth of 2,284 meters, as planned. Progress for the week was 1,691 meters.

The Arrowsmith-2 well is designed to test the unconventional gas potential of the Carynginia Formation, Irwin River Coal Measures and Kockatea Shale and will be drilled to a proposed total depth of approximately 3,420 meters.

The well is located approximately 25 kilometers from the Woodada Deep-1 well (deepened by AWE in April 2010 to acquire cores over the Carynginia Shale interval), and approximately 500 meters south east of the Arrowsmith-1 well, which tested gas from the Carynginia Formation.

During drilling, the joint venture is planning to cut conventional cores from the middle Carynginia Shale and Irwin River Coal Measures. On completion of drilling, the well will be suspended for future fracture stimulation and testing which is planned for later in the year.

The participants in EP 413 are:

AWE Limited (via subsidiaries) 44.252%
Norwest Energy NL (Operator) 27.945%
Bharat PetroResources Ltd 27.803%

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Nido Updates Gindara Ops

- Nido Updates Gindara Ops

Thursday, June 09, 2011
Nido Petroleum Ltd.

Nido, on behalf of the SC 54B Joint Venture, provided the following update on the Gindara-1 well.

The 9 5/8" casing has been successfully run to the casing setting depth of 3,337.6 meters MD (3,315.6 meters TVDss). The 9 5/8" casing is currently being cemented in-place. Following completion of casing operations, the 8 ½" hole section will be drilled through the remaining Lower Pagasa shales and into the Nido Limestone Formation, the primary reservoir objective in the Gindara-1 well.

Jon Pattillo, Nido's Head of Exploration commented, "We are looking forward to drilling ahead at Gindara-1 following completion of the 9 5/8” casing activities. Drilling operations at Gindara-1 have gone very well and we have now reached the most exciting stage as we approach the primary reservoir objective – the Nido Limestone.

The results from the Coron Clastics secondary reservoir objective do not impact the hydrocarbon potential of the deeper Nido Limestone, which we look forward to drilling with keen anticipation over the coming week."

Subject to any operational delays, Nido anticipates that it will be drilling ahead over the weekend and will provide a further update to the market when the results from the Nido Limestone are known.

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Calvalley to Boost Production in Yemen

- Calvalley to Boost Production in Yemen

Thursday, June 09, 2011
Calvalley Petroleum Inc.

Calvalley provided an operational update regarding current production development activities on the Company's Malik Block 9 which is approximately 350 kilometers east of Sana'a, the Capital of the Republic of Yemen.

During the current political unrest in Yemen, Calvalley has continued operations at all key production locations, including the Company's Central Production Facility ("CPF") at the Hiswah Field. The Company also continues to deliver blended crude oil from the Hiswah and Ras Nowmah Fields into the Masila Export Pipeline System ("MEPS") through its newly operational Truck Offloading Facility ("TOF").

As well, Calvalley is proceeding with facilities upgrades at the CPF to improve water handling capacity and to increase overall production through-put. This work priority is on schedule and is in anticipation of both increased production from the Hiswah field and increased blending of crude oil from the Ras Nowmah and Al-Roidhat Fields.

Calvalley is an international oil and gas company, with offices in Calgary, Alberta, Canada, that operates its 50% working interest in Block 9 of the Masila Basin, in The Republic of Yemen. Calvalley also operates its 100% working interest in the Gimbi and Metema Blocks of the Blue Nile Basin, in The Republic of Ethiopia.

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Entek Discovers Additional Oil Pay in GOM

- Entek Discovers Additional Oil Pay in GOM

Thursday, June 09, 2011
Entek Energy Ltd.

Entek provided an update on the VR 342 well in the Gulf of Mexico where the Company has a 50% working interest. The well is at 8,480 ft. Measured Depth (7,635 ft. True Vertical Depth) which will be the Total Depth of the well. The well has been deepened after wire-line logging of the primary L1 Sand target where greater than 40 ft. of oil pay has been interpreted.

The Company reported that the L2 Sand has successfully been penetrated by the well with preliminary results suggesting the potential for an additional 10 ft. of oil pay. Oil pay in the L2 sand in the fault block being tested by this well was not previously factored into the reserves calculation for the field. The joint venture will incorporate the results of wire-line logging and sidewall core analysis into mapping of the L2 Sand interval to determine its reserves potential. The L2 Sand will be considered as a completion interval in this well after depletion of the L1 Sand that will be developed first.

Previous gross 3P Reserves potential, established by previous drilling on the block, have been independently evaluated at circa 7.5 MMBO (1P 2.5 MMBO; 2P 4.8 MMBO; 3P 7.5 MMBO) and 9.5 BCFG (1P 3.8 BCFG; 2P 6.3 BCFG; 3P 9.5 BCFG), which did not include any reserves attributed to the L2 Sand in this fault block.

The 7 inch production liner has been run over both the L1 and L2 pay zones, the well has been suspended as a future producer and the rig has left location.

CEO and Managing Director Trent Spry commented, "Our intention was always to drill the current well deep enough to test the L2 sand section in this fault block. The L2 and L3 Sands are the target zones for two new wells (planned for 2012) in the fault blocks to the south of the one we have tested with this first well. In these fault blocks to the south both the L2 and L3 sands have been shown to contain hydrocarbons by previous drilling, as shown on the map above. It is a great result to have potential reserves in the L2 sand in the northern fault block as well. Development planning is now underway."

Entek provided an update on the VR 342 well in the Gulf of Mexico where the Company has a 50% working interest. The well is at 8,480 ft. Measured Depth (7,635 ft. True Vertical Depth) which will be the Total Depth of the well. The well has been deepened after wire-line logging of the primary L1 Sand target where greater than 40 ft. of oil pay has been interpreted.

The Company reported that the L2 Sand has successfully been penetrated by the well with preliminary results suggesting the potential for an additional 10 ft. of oil pay. Oil pay in the L2 sand in the fault block being tested by this well was not previously factored into the reserves calculation for the field. The joint venture will incorporate the results of wire-line logging and sidewall core analysis into mapping of the L2 Sand interval to determine its reserves potential. The L2 Sand will be considered as a completion interval in this well after depletion of the L1 Sand that will be developed first.

Previous gross 3P Reserves potential, established by previous drilling on the block, have been independently evaluated at circa 7.5 MMBO (1P 2.5 MMBO; 2P 4.8 MMBO; 3P 7.5 MMBO) and 9.5 BCFG (1P 3.8 BCFG; 2P 6.3 BCFG; 3P 9.5 BCFG), which did not include any reserves attributed to the L2 Sand in this fault block.

The 7 inch production liner has been run over both the L1 and L2 pay zones, the well has been suspended as a future producer and the rig has left location.

CEO and Managing Director Trent Spry commented, "Our intention was always to drill the current well deep enough to test the L2 sand section in this fault block. The L2 and L3 Sands are the target zones for two new wells (planned for 2012) in the fault blocks to the south of the one we have tested with this first well. In these fault blocks to the south both the L2 and L3 sands have been shown to contain hydrocarbons by previous drilling, as shown on the map above. It is a great result to have potential reserves in the L2 sand in the northern fault block as well. Development planning is now underway."

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Ex-BP CEO's Energy Investment Vehicle Aims for $1.6B IPO

- Ex-BP CEO's Energy Investment Vehicle Aims for $1.6B IPO

Thursday, June 09, 2011
Dow Jones Newswires
LONDON (Dow Jones Newswires)
by Alexis Flynn

The new investment vehicle headed by financier Nathaniel Rothschild and former BP Chief Executive Tony Hayward Thursday announced plans for a London listing later this month, that could see the venture raise as much as GBP1 billion to invest in emerging market oil and gas assets.

The special purpose acquisition company, called Vallares in a nod to Rothschild's earlier commodities venture Vallar, marks Hayward's return to the spotlight less than a year after he left BP in the wake of the Deepwater Horizon disaster and Gulf of Mexico oil spill.

The June initial public offering will aim to sate investor hunger for resource stocks following the listing of giant commodities trader Glencore International last month.

Vallares, which has attracted the backing of a number of U.S. and U.K. long-only and hedge funds as well as sovereign wealth funds, will look to invest primarily in upstream oil and gas exploration and production, said Hayward.

"What we're looking to fund is an emerging market player with good resources and good assets but that has neither the capital nor capability to fully develop them, and to merge with them," said Hayward, who explained that Vallares wouldn't use the capital raised to buy assets, but would instead look to use its equity to enact mergers with emerging market firms, who would then benefit from London's access to capital and Vallares' management experience.

Hayward said Vallares was looking at a range of investment targets.

"The truth is we have a very broad base pipeline of potential ideas. It does pretty well spread the world, from South America, West Africa, Russia, the Middle East, South East Asia," said Hayward.

In addition to Hayward and Rothschild, Vallares was founded by former head of Goldman Sachs' U.K. investment banking business, Julian Metherell and Tom Daniel, who helped establish Vallar with Rothschild.

The firm's senior management team, meanwhile, includes ex-BAE Systems Group Finance Director George Rose and former Enterprise Oil CEO Sir Graham Hearne.

Hayward said he would build an operating team around him with "the necessary skills and capabilities." However, he downplayed the prospects of approaching his ex-colleagues at BP. "Where they come from will depend a little bit on the day, but I'm certainly not going to go poaching from any of my previous employers, so you don't need to worry about that," he said.

Credit Suisse Group (CS) is acting as the IPO's global co-ordinator and joint bookrunner, while J.P. Morgan Cazenove is acting as joint bookrunner and Evolution Securities is acting as co-lead manager.

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

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Norway Sets Barents Sea Seismic Acquisition for July

- Norway Sets Barents Sea Seismic Acquisition for July

Thursday, June 09, 2011
Norwegian Petroleum Directorate

It has now been determined that there will be seismic acquisition in the eastern part of the Barents Sea from July 7. The necessary formalities surrounding the Treaty on Maritime Delimitation and Cooperation in the Barents Sea and the Arctic Ocean between Norway and Russia are now in place. The activity can start 30 days following this.

The Norwegian Petroleum Directorate will be responsible for the seismic acquisition on behalf of Norwegian authorities, and the PGS vessel Harrier Explorer will carry out the acquisition.

Harrier Explorer is now on its way to Jan Mayen to start seismic acquisition there. The vessel will acquire seismic in this area, starting June 10 and lasting three to four weeks, before setting course for the eastern part of the Barents Sea. The voyage from Jan Mayen to the eastern part of the Barents Sea will likely take four to five days.

An agreement has been entered into with PGS regarding hiring the vessel for three months with an option of an extension for approx. one month. This entails that the acquisition activity in the Barents Sea East will take place for two to three months.

The data acquisition will take place with the aid of PGS' Geostreamer technology. This is a new technology for 2D seismic acquisition, characterized in part by the fact that the streamer, which in this case is eight kilometers long, is towed somewhat deeper in the water than is the case in conventional seismic acquisition. This means that the streamer can withstand higher waves, thus making the acquisition activity less dependent on weather and consequently more efficient.

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Drilling Commences at Petro Matad's Mongolian Well

- Drilling Commences at Petro Matad's Mongolian Well

Thursday, June 09, 2011
Petro Matad Ltd.

Petro Matad announced that the Davsan Tolgoi-6 ("DT-6") exploration well was spudded at 14:30 Mongolian time (07:30 hrs BST) on June 9, 2011.

The DT-6 well is being drilled vertically to an estimated target depth of 2,100 meters. The well is being drilled by the Company's contractor, DQE International.

The DT-6 site is approximately 2.3km SSE of DT-1. DT-6 will test a very thick section of the Tsagaantsav formation, including 234m of the Uppermost Tsagaantsav (Uvgan Gol horizon) within a well-defined northeast-trending paleovalley, as well as 364m of the underlying Lower Tsagaantsav formation.

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Production Resumed at Leni's Eugene Platform

- Production Resumed at Leni's Eugene Platform

Thursday, June 09, 2011
Leni Gas & Oil plc

Leni Gas & Oil announced resumption of production from the Eugene Island-184 ("EI-184") platform in the Gulf of Mexico.

Production operations were resumed safely on June 3, 2011 at the EI-184 facilities following the transfer of operatorship to Marlin Energy LLP ("Marlin") as previously announced in late May. All previously active wells (A1, A3, A4, A5 and A8) were returned to production and operational reporting to the Joint Venture partners has now been resumed.

During the initial five day ramp up period; gross physical production has averaged 1,199 mcfpd and 402 bopd (609 boepd). Once downtime is accounted for, this equates to an average daily rate of approximately 922 boepd. LGO holds a 7.25% working interest in the EI-184 field.

Early indications are that production has been re-established at higher than pre-shut down levels, however, stabilized rates are not yet available and some flush production after a 60 day shut-in period would be expected.

Neil Ritson, LGO's Chief Executive, commented, "We are pleased that production and revenue has been restored so quickly and that all the wells have come back on-line after the shut-down. We now look forward to working with the new operator to plan for sidetracking and recompleting wells in the field to increase production."

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O&G Companies Fear Higher Royalty Payments under Obama Effort

- O&G Companies Fear Higher Royalty Payments under Obama Effort

Thursday, June 09, 2011
Dow Jones Newswires
WASHINGTON (Dow Jones Newswires)
by Tennille Tracy

Energy companies are concerned they could be forced to pay higher oil and gas royalties under a new Obama administration effort to revamp royalty calculations for energy extracted from federal lands and waters.

The Interior Department, which launched the effort last month, insists the proposed changes will simplify how oil and gas is valued and should not increase or decrease the royalty payments themselves.

Oil and gas companies are not so sure. They say changes could create an unfair calculation that leads to higher royalty payments, which would dampen the industry's profits and hurt smaller producers particularly hard.

"It makes us nervous when we hear of the government trying to simplify things," said Kathleen Sgamma, director of government affairs for the Western Energy Alliance, a group representing oil and gas producers in western U.S. states.

This debate comes as the energy industry has battled the Obama administration on other matters, such as a bid to eliminate billions of dollars of tax incentives for oil and gas companies.

The new royalty formula also comes as the Obama administration looks for ways to trim the widening deficit. Generating nearly $9 billion in reported revenue last year, oil and gas royalties represent one of the largest sources of non-tax revenue for the federal government.

The Interior Department is also considering, through a separate effort, an increase to onshore production royalty rates, now at 12.5%. The royalty rate for offshore production is 18.75%.

Government watchdogs have said the Interior Department's royalty program fails to collect the government's fair share of revenue from the industry. Earlier this year, the Government Accountability Office identified the program as being at a "high risk" of fraud, waste, abuse or mismanagement.

When calculating royalty rates, the Interior Department can often rely on the sale price between the buyer and seller to determine the value of the oil or gas. But in many cases--such as when affiliated companies sell to each another--the Interior Department questions whether this sale price reflects the true market value and conducts its own review. This creates a burden for government officials and leads to disputes with the industry.

Hoping to simplify the process, the Interior Department is considering a process where it relies on standardized prices to calculate royalty payments. These could be published prices from trade publications or prices at which the products are traded on exchanges.

But the industry is concerned standardized prices could lead the Interior Department to assign a higher value to oil and gas than what producers receive from a sale. And that would lead to bigger payments to the federal government.

Such a system could hurt smaller producers particularly hard because they often receive less money for their production than large multinational companies, said L. Poe Leggette, partner-in-charge at Fulbright & Jaworski's Denver office.

Interior Department spokesman Patrick Etchart said they welcome the industry's comments. Interior wants a system "that provides fair certainty to us that we get paid the proper amount," he said.

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

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Bowleven's Sapele Sidetrack Tests Positive Offshore Cameroon

- Bowleven's Sapele Sidetrack Tests Positive Offshore Cameroon

Thursday, June 09, 2011
BowLeven plc

Bowleven announced the results of testing activities at the Sapele-1ST appraisal well drilling in the Douala Basin, offshore Cameroon. Drill stem testing was performed within the Deep Omicron interval at Sapele-1ST and a light oil flowed on test.

Highlights

Stabilized flow rate of 3,101 boepd produced on test at Sapele-1ST
High quality light oil (39.2 degree API) produced on test; oil quality and gas-oil ratio comparable to that encountered at the original Sapele-1 well
Testing program underway at Sapele-2

Sapele-1ST update

The principal objective of Sapele-1ST was to appraise the Deep Omicron oil discovery encountered in the Sapele-1 exploration well.

As previously announced, the Sapele-1ST well encountered log evaluated net pay conservatively estimated to be approximately 10 meters within the Deep Omicron interval, based on conventional wireline logs. The well was drilled to a TVD of 3,634 meters (4,483 meters measured depth) in water depths of around 25 meters approximately 2 kilometers south east of the Deep Omicron oil discovery in the original Sapele-1 vertical well.

Drill stem testing at Sapele-1ST was conducted over a 71 meter perforated interval. The interval flowed at a stabilized rate of 2,023 bopd of 39.2 degree API oil and approximately 6.47 mmscfd of associated gas on a 56/64 inch choke.

The interval tested at Sapele-1ST correlates on seismic with the equivalent Deep Omicron interval drilled by the original Sapele-1 well, where better developed sands were encountered. The Sapele-1 well had a confirmed oil pressure gradient at Deep Omicron and oil samples were obtained during logging activities. The oil quality, gas-oil ratio and pressures measured on test at Sapele-1ST are comparable to the samples and pressures taken at Sapele-1.

Forward plan

Due to the stratigraphic nature of the Omicron discoveries further analysis and appraisal is required to delineate the fields and to assess the implications for resource estimates and potential development options for these discoveries. The productivity demonstrated by the Deep Omicron test at Sapele-1ST is a key step forward. In addition, a testing program is ongoing at Sapele-2, drilled to appraise both the Lower and Deep Omicron discoveries, and the results from this will be integral to this process.

As planned the Noble Tommy Craighead rig is being released after Sapele-1ST testing for a mandatory recertification process.

An update announcement and conference call are planned on completion of the full test program at Sapele-2, which is expected in around two to three weeks. Further announcements on drilling activities will be made as appropriate.

Kevin Hart, Chief Executive of Bowleven plc, commented, "Bowleven is delighted to announce its first oil flow test in the Douala Basin, offshore Cameroon, at Sapele-1ST. The flow rates produced at Sapele-1ST are believed to be commercial. These are highly encouraging, particularly so given that better sand development was encountered in the original Sapele-1 well at the equivalent level, with good indications of comparability between the two. While further appraisal is required to fully understand the resource potential, we are encouraged by the result and the likelihood of a commercial development at Sapele given the shallow water depths. Our acreage in Cameroon shows increasing potential as we focus on our dual strategy of targeting high impact exploration potential in the Douala Basin and converting resources to reserves."

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Seadrill Lines Up Semi-Tender for 2013 Delivery

- Seadrill Lines Up Semi-Tender for 2013 Delivery

Thursday, June 09, 2011
Seadrill Ltd.

Seadrill has entered into an agreement with Keppel FELS Limited in Singapore to build a new semi-submersible self-erecting tender rig (semi-tender). Total project price for the rig is estimated at below US $200 million (including the drilling equipment set, project management, spares, capitalized interest and operation preparation).

The new rig is scheduled for delivery in the second quarter 2013 and will be based on a similar design and specification as the semi-tender West Jaya, which was delivered from the Keppel FELS yard in March this year and is contracted for a minimum of two years. Similar to previous semi-tenders, the new unit is suited for harsher environment and deepwater drilling operations in combination with floating wellhead platforms such as Tension Leg Platforms and Spars.

The new unit is based on the KFELS SSDT 3600E design and adds to the seven semi-tenders that Keppel has earlier built for Seadrill since the launch of the design in 1994. The unit will feature a crane capacity of 250 tones, four mud pumps and accommodation for 160 people.

Alf C Thorkildsen, Chief Executive Officer of Seadrill Management AS said, "We are pleased to announce the addition of a new semi-tender to our existing fleet of 19 tender rigs. The tender rig business has delivered excellent operational results as well as outstanding economics over the last decade. Based on the continued strength of the offshore drilling market we continue to see strong growth and earnings potential for our business. The new semi-tender has a favorable construction price and an equipment specification list that will meet our customers' future needs. We have had very good experience with the Keppel FELS yard and this design and we are confident that the new unit will be delivered on time and within budget once again."

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