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Oil and Gas Energy News Update

Thursday, March 31, 2011

BP Spill Study Says BOP Needs Further Work

BP Spill Study Says BOP Needs Further Work

Thursday, March 31, 2011
Parks Paton Hoepfl & Brown
by  G. Allen Brooks

Last week, the results were released from the forensic study of the blowout preventer (BOP) used on BP Ltd.’s (BP-NYSE) Macondo well in the Gulf of Mexico that blew out last year causing an explosion, fire and eventual sinking of the Deepwater Horizon semi-submersible drilling rig and this nation’s greatest offshore environmental accident.

Den Norske Veritas (DNV), the Norwegian engineering and risk-management firm hired by the U.S. Department of the Interior to assess the BOP and determine its role in last year’s Deepwater Horizon disaster, after examining and testing the unit recovered from the ocean floor, prepared a 200-page report with a 351-page appendix.

The inspectors’ conclusion was that the shear ram valves in the BOP were unable to fully sever the drillpipe as the unit is designed to do because the pipe inside buckled from the well’s initial blow-out and was out of alignment that prevented complete closure.

DNV found that the shear rams had closed to within 1.4 inches.  This gap, albeit small, provided sufficient room for an estimated 4.9 million barrels of oil to escape.

While the report details the failure, the conclusions confirm the early belief of many drilling engineers consulted about the disaster.

The inability of the shear rams to cut the pipe because of it being off center highlight potential problems for companies drilling over-pressured wells.

The buckling of the pipe was due to the high pressure fluids roaring up the drilling pipe and annulus lifting the pipe until it hit an obstacle.  At that point, the momentum of the pipe and pressures and heat of the flows resulted in its bending.

Exhibit 10.  Why BP’s Macondo Well Spilled Oil
Why BP’s Macondo Well Spilled Oil
Source:  The Wall Street Journal

The report quickly generated further criticism of the offshore oil and gas industry and its safety procedures in drilling deepwater wells that tend to exhibit high formation pressures.

All facets of the oil and oilfield service industry involved in drilling these wells is working on ways to improve the performance of the drilling and safety equipment, especially the BOP.

There still remain unanswered questions about what actually caused the well to blow out and there will be more information and hypotheses presented down the road, but the DNV report was the last major report on the equipment involved in the accident.

The belief of most observers is that the Deepwater Horizon disaster was the result of a confluence of questionable decisions and actions by all parties involved that resulted in the creation of an unbalanced pressure differential between the downhole formation and the equipment designed to hold back that pressure.

Criticism of the DNV report came immediately from political opponents of offshore drilling including Rep. Edward Markey (D., Mass.) who said, “This report calls into question whether oil-industry claims about the effectiveness of blowout preventers are just a bunch of hot air.”  The man responsible for overseeing U.S. offshore drilling rules until he retired in 2009, Elmer Danenberger III, was quoted by The Wall Street Journal as saying, “They have to rethink the whole design,” meaning the BOP.

The DNV report concluded that the BOP failure was due to a design flaw and not the operation, abuse or maintenance of the BOP by the companies involved in drilling the Macondo well.

The BOP in question was manufactured by Cameron International (CAM-NYSE), the leading provider to the drilling industry of such units for over 90 years.  The BOP has been the industry’s last and best defense against well pressures, which often came as a result of encountering pockets of higher-pressured natural gas at shallower depths while drilling a well.  In fact, the BOP that became the signature product for Cameron was developed in response to several high-pressure well workover accidents in 1922.

The co-founder and majority owner of then Cameron Iron Works, James Abercrombie, was also a successful contract driller with a history of putting out well fires and blow-outs, long before Red Adair made the occupation of fire-fighting glamorous.

In late 1921, Mr. Abercrombie secured a contract to work over a troublesome well in the Hull field in Liberty County, northeast of Houston.  This was a field with many small pockets of high pressured gas.  In the course of working over wells in this field, Mr. Abercrombie’s company had lost its newest and best rig and had encountered three blowouts.

While each of the blowouts resulted in lost equipment, fortunately no one was hurt.

The episode, however, focused Mr. Abercrombie on ways to design equipment that could be used to prevent wells from blowing out.

Originally, he had used an elementary blowout preventer called a “boll weevil.”  It was essentially a piece of heavy-gauge pipe surrounded by a thick lead casing.  There was stopcock on top of the arrangement.  If it was suspected that a well might blowout, the unit was slipped over the well’s casing and the stopcock closed.  The unit proved impractical as a well containment device but mainly it was used to try to give the drilling workers time to get away from the rig before the well blew.

There was another preventer on the market designed to improve on the “boll weevil” and Mr. Abercrombie purchased one of them to use on his next well workover in the Hull field.  Unfortunately it, too, failed to prevent another blowout.  Mr. Abercrombie came up with the idea of a ram-type preventer with the faces of the rams closing in on the drillpipe in order to close off the pressure in the well.  With a sketch of the concept, Mr. Abercrombie went to his co-founder and partner, Henry Cameron, the next morning and sketched out his concept in the sawdust and dirt of the machine shop’s floor.  With a casting produced by Howard Hughes’ nearby shop, Mr. Cameron machined the design.

A patent application was filed on April 14, 1922, but patent number 1,569,247 was not issued until January 12, 1926.

As the unit was tested it was discovered that it leaked when pressure increased.  Mr. Cameron designed a fix whereby the increasing pressure would force open a notch in the corner of the ram face and force it to close tighter.  Patent number 1,498,610 was issued as a modification to the original BOP design but before the original patent was even granted.

By adding steel and cast iron parts to the BOP and being able to guarantee the unit would work to shut off 2,000 pounds of flowing pressure, the orders started coming in, not only from domestic companies in Texas, Louisiana and California, but also for use in foreign locations such as Mexico and Venezuela.  The Cameron Iron Works company was on its way to a glorious history that continues today.  [Much of this history about Cameron comes from the book, Mr. Jim, by Patrick J. Nicholson.]

We have high confidence that the engineers in the drilling business will figure out how to improve the performance and safety of the drilling process, just as they have for the past 150+ years.  Well control episodes have occurred throughout the history of the petroleum industry.  The Deepwater Horizon was the latest and most devastating, both due to the loss of 11 lives and the environmental damage to the Gulf of Mexico from the oil spill.

The evidence from the investigations of the disaster continues to show the Macondo well blowout was an accident.  All aspects of our daily lives, including the energy, involve risks.  We need to better understand the risks and their potential ramifications.  Importantly, we need to keep a perspective on risk and our risk tolerance.  We don’t stop driving after a car accident.  We don’t stop flying after a plane accident.  We shouldn’t stop drilling after a drilling accident.

Buccaneer to Meet AIDEA for Rig Usage Offshore Alaska

Buccaneer to Meet AIDEA for Rig Usage Offshore Alaska

Thursday, March 31, 2011
Buccaneer Energy Ltd.
Buccaneer advised that the board of the Alaskan Industrial Development and Export Authority (AIDEA) is due to meet on April 1, 2011 to consider and vote on the investment by AIDEA of up to US $30.0 million to acquire a jackup rig for use in the Cook Inlet and other Alaskan waters.

AIDEA's involvement will be as a joint owner in the jackup rig to be acquired. Therefore the proposed investment by AIDEA does not involve the issuance of any securities by the Company.

Extensive due diligence has been undertaken by AIDEA management and a Joint Ownership Agreement (JOA) between the Company's subsidiary Kenai Offshore Ventures, LLC and AIDEA has been negotiated. The JOA contains Conditions Precedent that must be finalized before draw down of the AIDEA investment. The Company is confident that these Condition Precedents can be met in a timely manner.

AIDEA's management have made a recommendation to the board of AIDEA that it views participation on the terms and conditions contained in the JOA is in the best interests of AIDEA and recommends approval of the resolution to proceed.

If the resolution to proceed is approved by the AIDEA board it is anticipated that the JOA will be executed in the week commencing April 4, 2011. Further details will be released at that time.

Lexaria: 4 Wells Producing at Belmont Lake Field

Lexaria: 4 Wells Producing at Belmont Lake Field

Thursday, March 31, 2011
Lexaria Corp.
Lexaria announced that for the first time, there are now up to four producing oil wells at the Belmont Lake oil field, and a salt-water disposal well that is connected and operational. The necessary work was completed despite challenging field conditions prior to the seasonal rise in Mississippi River water levels. Some residual infrastructure work will be completed during the next dry season.

The Belmont Lake oil field has now produced over 100,000 barrels of oil.

Lexaria has drilled both oil and gas wells in the region since 2005, concentrating on shallow geologic horizons that are less expensive to exploit than deeper targets. There are a number of geologic target zones from the shallowest all the way to the Tuscaloosa Marine Shale. A 1996 Louisiana State University study estimates that 7 Billion recoverable barrels of oil may exist in this oil shale that in some regions is 400-800 feet thick.

Lexaria holds an option to drill up to 38 exploration wells on roughly 130,000 acres of land in the region, in which it holds a 60% interest. Shallow fields are of primary interest to the Company, in part, because of the history of this region. Some of the shallow oil fields in the area produced by others include:
  • 593,000 barrels produced at Ashwood Field
  • 730,000 barrels produced at Stamps Field
  • 55,000,000 barrels produced at Little Creek Field
  • 1,412,000 barrels produced at Freedom field
Lexaria currently holds a 40% gross working interest in the PP-F12-4 and PP-F12-5 directional wells, and a 32% interest in the PP-F12 and PP-F12-3 wells. It holds a minimum 32% interest with the potential for higher interests, in any additional development wells to be drilled at Belmont Lake.

Honda Motor, Mazda Will Resume Limited Production At Japanese Factories In April

Honda Motor, Mazda Will Resume Limited Production At Japanese Factories In April

Honda (NYSE:HMC) and Mazda said they will resume limited production at several Japanese factories in April, but full production will depend on the availability of parts, which is another sign that the Japanese auto industry is starting to come back from the March 11 earthquake and tsunami.

Industry analysts say it could take until summer before factories are back at full output.

Japan is the second-largest supplier of cars in the world, and is also a major parts producer. The impact of the earthquake is already causing production cuts in other countries, including the U.S. Few plants were seriously damaged in Japan but water and electricity supplies have been hampered.

Commodities Report: Gold Hits Record High; Crude Tops $106 a Barrel

Commodities Report: Gold Hits Record High; Crude Tops $106 a Barrel

Commodities rallied to finish higher Thursday as both crude oil and gold futures surged as the first quarter came to a close.

Light, sweet crude oil for April delivery finished up 2.4% to $106.72 a barrel. In other energy futures, heating oil was up 1.7% to $3.09 a gallon while natural gas was up 0.99% to $4.39 per million British thermal units.

Meanwhile, gold futures ended at a record high helped in part by a weaker dollar.

Gold for June delivery finished up $15 to $1,439.90 an ounce. In other metal futures, silver was up 0.78% to $37.80 a troy ounce while copper traded up 0.82% to $4.30.

The U.S. dollar index (DXY) is down 0.36% to $75.84.

Robbins & Myers Reports Q3 Results

Robbins & Myers Reports Q3 Results

Robbins & Myers Inc (NYSE:RBN) reported Q2 EPS today of $0.62 excluding one time charges related to its acquisition of T-3 Energy Services, beating the consensus estimate for $0.48 per share. Consolidated revenue was up 65% year-over-year to $215 million, beating the consensus estimate for $199 million. Excluding revenue from T-3 Energy, sales were up 38% from the year ago period.

"We are rapidly integrating T-3 into our Fluid Management Group and have secured most of the expected $9 million of annualized synergies," said Peter C. Wallace, President and CEO. "Other potential benefits from the acquisition have surfaced, such as new sales opportunities with key account relationships, opportunities to leverage regional strengths and capabilities, and savings through low-cost sourcing. All of this is occurring against a backdrop of strong order levels at T-3, which continues to benefit from increased North American oil & gas maintenance and repair activity as well as higher spending related to shale projects. Our legacy energy business is also benefitting from high levels of customer demand, tempered somewhat by capacity constraints for one product line, for which we expect additional capacity to begin coming on line at the end of the third quarter."

Gas Driller Citations to Be Reviewed

Gas Driller Citations to Be Reviewed

Thursday, March 31, 2011
Knight Ridder/Tribune Business News
by  Timothy Puko, The Pittsburgh Tribune-Review

Every Marcellus shale drilling citation will need a review from the new Department of Environmental Protection chief before final approval, said an agency spokeswoman.

All violation notices for gas drillers and the enforcement actions the agency plans must be e-mailed to Acting Secretary Michael Krancer, spokeswoman Katherine Gresh said. The department's six regions each enforce rules differently, and Krancer is trying to improve consistency across the state, she said, noting the policy may be temporary.

But putting a political appointee in a position to micromanage regulatory enforcement could lead to unfair interference on behalf of campaign donors, said Myron Arnowitt, state director for Gov. Tom Corbett received $835,000 in campaign contributions from gas companies, according to, a website run by Common Cause Pennsylvania and Conservation Voters of Pennsylvania.

"Krancer has talked a lot about being scientifically-based, factually-based and implementing the law," Arnowitt said. "It's not clear how what he's doing does any of that."

Corbett has promised he will give no special consideration to the industry because of the donations he has received.

The DEP has spent much of the past three years playing catch-up with the gas drilling industry, going on a hiring spree to ensure it had enough employees to match the plethoraof permit requests statewide. There were 1,200 violations last year, and adding another layer of bureaucracy to enforcement raises more questions about how quickly the agency can stop lawbreakers, Arnowitt said.

Gresh said the effort won't be time consuming, but she didn't know how much time it might add to Krancer's day or how many more documents he might need to review. Ultimately, it will make the agency more efficient by ensuring new staffers received proper training and are enforcing regulations consistently, she said.

"We have communications like that around the department all the time. This is one aimed at achieving a goal that is very important to Secretary Krancer," Gresh said. "We'll take whatever time is necessary to ensure the consistency to improve efficiency, protect the environment, and, you know, which will benefit all Pennsylvania."

Samson O&G Closes Asset Sale, Sets Frac Date for Earl Well

Samson O&G Closes Asset Sale, Sets Frac Date for Earl Well

Thursday, March 31, 2011
Samson O&G Ltd.

Samson O&G has closed its previously announced sale of gas assets in the Jonah and Lookout Wash Fields in Green River Basin, Wyoming for $6.3 million to a group of private buyers, with an effective date of January 1, 2011. Samson's cash balance following this transaction stands at US $73.3 million.

Samson has also been advised that a frac date has been set for the Earl #1-13H well and it is expected that frac operations will commence Monday April 4th. Earl #1-13H was previously drilled to a measured total depth of 17,342 feet, and a 5,700 foot liner set in the horizontal section. This horizontal section will be fracced with 20 stages and the treatment is expected to place 2.3 million pounds of proppant. This operation will take approximately five days.

Devon Chairman Sees Plenty of Barnett Drilling

Devon Chairman Sees Plenty of Barnett Drilling

Thursday, March 31, 2011
Fort Worth Star-Telegram, Texas
Devon Energy, the largest producer in North Texas' Barnett Shale, has lots of drilling ahead of it in the big natural gas play, Executive Chairman Larry Nichols told the Star-Telegram in a telephone interview.

"We have at least 7,500 undrilled locations," said Nichols, who last year gave up his CEO title after 30 years in the job. Devon plans to keep about a dozen drilling rigs busy in the Barnett this year and will drill perhaps 325 wells, he said.

The Oklahoma City-based company has an office in downtown Fort Worth and 550 employees involved in Barnett Shale operations.

Devon's net Barnett production peaked at the equivalent of 1.2 billion cubic feet of natural gas per day in the fourth quarter last year. As a result of weak gas prices and limited demand, the company will probably maintain production at about that level this year, but it has the capability to increase output to at least 1.5 billion cubic feet Nichols said.

While current natural gas prices of slightly more than $4 per million British thermal units are not sufficiently high for sustaining production levels for "dry gas," it can be sufficient for "wet gas" production, which includes natural gas liquids that generate additional revenue, Nichols said. Devon's Barnett production is a mix of dry and wet gas, he said.

A geologist and lawyer by training, Nichols said he expects continued technological advances in drilling and completion of wells that will result in greater recovery of oil and natural gas.

As an example, he cited major technological advances in horizontal drilling and hydraulic fracturing that -- along with higher oil prices -- have revived activity in West Texas' heavily drilled Permian Basin.

Devon currently has 17 drilling rigs running in the Permian, where the company has about one million acres under lease, Nichols said.

He said he's "very excited" about the company's new 50-story corporate headquarters under construction in Oklahoma City. It will allow the company to consolidate its approximately 1,700 workers in Oklahoma City into a single building. They presently are scattered among five buildings, he said.

All the Devon employees are expected to be in the new building by the end of 2012. 

Exxonmobil to Start Exploration Offshore Vietnam Next Month

Exxonmobil to Start Exploration Offshore Vietnam Next Month

Thursday, March 31, 2011
Asia Pulse Pte. Ltd.

ExxoMobil will start its first exploratory drilling off the central coast of Vietnam late next month.

The decision was agreed upon at a city on March 29 between leaders of the People's Committee of Da Nang City and representatives from ExxonMobil Exploration and Production Vietnam Ltd.

The drilling will be conducted at block 119 on the continental shell offshore Quang Ngai Province and Da Nang City. Phung Tan Viet, Vice chairman of the Da Nang People's Committee, asked the company to strictly guarantee technical requirements to avoid environmental pollution. The two sides also discussed plans to ensure safety during oil-rigs construction.

Viet also ordered the city's Department of Agriculture and Rural Development to inform fishermen not to use the exploration area during the 40 days of drilling.

According to reports from state-owned Vietnam Oil and Gas Group PetroVietnam, Vietnam's crude oil reserve in 2010 was estimated at 4.4 billion barrels. The crude oil and gas exploration output in 2010 reached 15.1 million metric tonnes and 9.4 billion metric tonnes, respectively.

UK Oil Producers to Lobby Osborne Over North Sea Tax Hike

UK Oil Producers to Lobby Osborne Over North Sea Tax Hike

Thursday, March 31, 2011
Dow Jones Newswires

PetroChina Drills China's 1st HZ Shale Gas Well

PetroChina Drills China's 1st HZ Shale Gas Well

Thursday, March 31, 2011
Dow Jones Newswires

Reef Reaches TD at Ausable Well

Reef Reaches TD at Ausable Well

Thursday, March 31, 2011
Reef Resources Ltd.

Reef Resources reported that drilling of its Ausable # 5 well reached total depth of 615 meters on March 29. A total of 4 cores were taken over a depth of 32 meters with overall good recoveries. Oil staining was observed on the core sample which is currently being analyzed with results to be released in the near future. Data from the core samples will provide information on cap rock integrity and will be utilized, in addition to existing 3D seismic data, to pinpoint further drilling targets for future horizontal wells in the Ausable pinnacle reef.

The Ausable # 5 wellbore is being logged to identify the intersected hydrocarbon zones in the Ausable reef at this location. Results will be analyzed and released as soon as it is available.

The Ausable reef is currently on production and is generating revenue from the initial Enhanced Oil Recovery Natural Gas Recycling program which commenced in 4th quarter 2010.

Executive Director of Solo, Neil Ritson commented, "The presence of oil on the cores is considerable encouragement that we will be able to commercially produce this well while we awaiting the further planned development of the EOR scheme by Reef later this year."

BP Extends Aker's Maintenance, Modification Contract

BP Extends Aker's Maintenance, Modification Contract

Thursday, March 31, 2011
Aker Solutions
BP has decided to extend the maintenance and modification contract with Aker Solutions, exercising a one year option in the existing
agreement for the Ula, Valhall, Hod and Tambar fields. Work under the new option will last until April 2012. The contract value is estimated to be NOK 2-300 MNOK.

The original maintenance and modification contract was signed in 2005.

"We are very pleased that BP again demonstrates their trust in Aker Solutions. We look forward to continue our long term cooperation with BP," said executive vice president for Maintenance, Modifications and Operations in Aker Solutions, Tore Sjursen.

Scope of work under the contract includes engineering, procurement, fabrication, installation and maintenance support services and currently employs approximately 280 people in Stavanger, 50 in Egersund and 1000 in offshore rotation. The contract also includes hook-up and completion of the new PH platform at Valhall and tie-in of Oselvar to the Ula field.

Contract parties are Aker Solutions subsidiary Aker Offshore Partner AS and BP Norway AS.

Shell to Start Drilling at Iraq Majnoon Oil Field in July

Shell to Start Drilling at Iraq Majnoon Oil Field in July

Thursday, March 31, 2011
by  Hassan Hafidh

Shell along with its partners, Malaysia's Petronas and the Iraqi state Missan Oil Co., will start drilling the first new well in the super-giant Majnoon oil field in July, a company executive said Thursday.

"Shell is targeting July 2011 to spud the first well," Ole Myklestad, managing director of Shell in Iraq told reporters in Basra.

Between 15 and 20 wells will be drilled in Majnoon oil field in southern Iraq and some 27 others will be refurbished to bring output to 175,000 barrels a day by the end of next year from the current 60,000 barrels a day, Myklestad said. The new wells and the refurbish work is part of an early production plan.

The well drilling is part of a contract Shell and its partners signed with U.S. service giant Halliburton and the state-run Iraqi Drilling Co. last year.

The executive also said that Shell has opened a new office in Basra to manage its projects in Iraq. The office is to make sure that "we have the human resources and all the supports required by an international company in Basra."

Myklestad said that there are some 300 Iraqis working on the Majnoon project and they are from the state-run South Oil Co. Some 50 Shell expatriate personnel are also working on the project, he said.

Shell and Petronas won the right to develop Majnoon oil field, located in Basra governorate in southern Iraq, at an auction held in Baghdad December 2009. Shells owns 45% of the venture and Petronas 30%, with Iraq's Missan Oil Co. the remaining 25%.

Shell also will start constructing a 75 kilometer pipeline to connect Majnoon with the crude oil depots in Faw, as a stop before shipping the crude into vessels in the Gulf. Myklestad said that Shell and its partner would provide the finance for building the pipeline.

The Anglo-Dutch giant is also planning to commence a seismic survey but after clearing mines left from the 1980-88 Iraq-Iran war.

"We want to get results of a seismic survey in the next two years," he said.

Pacific Rubiales Acquires Maurel & Prom Stake in Colombia

Pacific Rubiales Acquires Maurel & Prom Stake in Colombia

Thursday, March 31, 2011
Pacific Rubiales Energy Corp.

Pacific Rubiales announced the acquisition of 50% of the interests held by Maurel et Prom in the Sabanero, Muisca, SSJN-9, CPO-17 and COR- 15 blocks, which are all located on-shore in Colombia.

Mr. Ronald Pantin, Chief Executive Officer of the Company, commented, "We are very pleased to join forces with Maurel et Prom. This acquisition adds significant resources and exploratory potential to our already robust resource base. Moreover, this acquisition fits synergistically with our other assets located in the same basins, paving the way to significant efficiencies in production and transport. With this acquisition we continue raising the bar as the premier explorer and operator in Colombia."
Upon completion of the transaction, Pacific Rubiales will partner with Maurel et Prom in respect of the following interests:
  • 100% participation in the Sabanero Block ("E&P Contract No. 17 of 2007 Sabanero") located in the central region of Colombia in the Department of Meta.
  • 100% participation in the Muisca Block ("E&P Contract No. 20 of 2008 Muisca") located in the central region of Colombia in the Departments of Boyacá and Cundinamarca.
  • 50% participation in the SSJN-9 Block ("E&P Contract No. 47 of 2008 SSJN- 9") located in the northern region of Colombia in the Departments of Bolivar, Cesar and Magdalena. The remaining 50% interest is currently held by HOCOL.
  • 50% participation in CPO-17 Block ("E&P Contract No. 40 of 2008 Llanos Orientales - Area Occidental CPO-17") located in the central region of Colombia in the Department of Meta. The remaining 50% interest is currently held by HOCOL.
  • 100% participation in the COR-15 Block ("Special Technical Evaluation Agreement Type 3 Contract") located in the central region of Colombia in the Department of Boyacá.
This agreement is subject to legal and regulatory approvals of the ANH and certain contractual approvals with the partners in Colombia.
The general terms of the agreement with Maurel et Prom are as follows:
  • Pacific Rubiales will pay to Maurel et Prom cash consideration to a maximum of US $66 million as a reimbursement for past exploration costs in the blocks, as at March 31, 2011.
  • Pacific Rubiales will assume a full carried obligation on the exploration and delineation activities in the Sabanero Block with a reimbursement out of the free cash flow. The Company will also secure the financing required by Maurel et Prom to execute its portion of the development activities in such block.
  • Reimbursement will also be made by means of free cash flow derived from future hydrocarbon production. Pacific Rubiales offers to assume a full carried obligation of up to US $120 million in three years for exploration activities in the SSJN-9, CPO-17 and Muisca Blocks. This obligation will be subject to revisions pending the activity results and negotiations with the other applicable partners.
  • Pacific Rubiales will assume a full carry obligation on exploration activities for Block COR-15, with reimbursement by means of free cash flow derived from future hydrocarbon production. The Company will also secure the financing required by Maurel et Prom to execute its portion of the development activities in such block. Reimbursement will also be made by means of free cash flow derived from future hydrocarbon production.

BHP Billiton Hands Reins to FOGL Offshore Falklands

BHP Billiton Hands Reins to FOGL Offshore Falklands

Thursday, March 31, 2011
Falkland O&G Ltd.
by  SubseaIQ

FOG announced further progress on its rig contract negotiations and certain changes to its license arrangements.

Changes to license arrangements

On March 30, 2011 FOGL signed a binding Heads of Agreement with its joint venture partner, BHP Billiton, that provides for the exit of BHP Billiton from the Northern license area once certain conditions have been satisfied, including approval of the Falkland Islands Government to both the assignment of BHP Billiton's 51% interest and transfer of operatorship to FOGL.

In relation to this withdrawal BHP Billiton will contribute towards the costs of drilling the Loligo well, by placing funds in an escrow account. The funds are to be drawn by FOGL against the costs of drilling the Loligo well. In the event that the Loligo well encounters hydrocarbons, BHP Billiton will have the option to back in to the Loligo development area only, for a maximum 40% non-operating interest in the discovery, in return for making a cash contribution to FOGL's future exploration and appraisal costs. Such a reassignment of interests will also be subject to approval by the Falkland Islands Government.

The settlement with BHP Billiton will, together with other funds available to FOGL, provide FOGL with total cash resources of US $110 million. These cash resources will be sufficient to fund the Loligo well, other exploration expenditures and allow the Company to fulfill the Phase 1 work commitment of the Northern license area.


Further to its announcement on March 15, the company is close to finalizing a rig contract for its deep water exploration program.

FOGL is also considering additional drilling options. The site survey program is progressing well, with surveys already completed on three locations. FOGL is considering the most appropriate means of financing and advancing these options and is in discussion with several parties that are interested in farming in to its licenses.

Tim Bushell, Chief Executive of FOGL, said, "We are pleased to have made good progress in our rig contract negotiations and to have reached an amicable agreement with our joint venture partner that gives FOGL control over its deepwater exploration program, commencing with the drilling of the Loligo prospect."

Chariot O&G In Talks to Farm-Out Blocks Offshore Namibia

Chariot O&G In Talks to Farm-Out Blocks Offshore Namibia

Thursday, March 31, 2011
Chariot O&G Ltd.

Chariot O&G provided an update on the farm-out process and progress with regard to drilling plans and further exploration work achieved across its license acreage offshore Namibia.

Chariot has been very encouraged with the offers that have been received to date and reported that it is at the advanced negotiation stage on several blocks in the farm-out process. Discussions continue and the Company looks forward to updating the market with further information shortly.

Chariot remains committed to drilling its first well in 4Q 2011 and is pleased to report that a contract has been signed with Senergy (GB) Ltd to provide drilling and support services for its planned wells on the Tapir North (Northern License) and Nimrod (Southern License) prospects. Chariot management and a team from Senergy recently visited Namibia as part of this process, meeting with government officials and local contractors. As previously stated, Chariot is planning to drill one well in 4Q 2011 with a second in 1Q 2012.

Chariot also reports that additional attribute analysis and mapping work has continued on the 3D seismic acquired in the Southern blocks. As a result it expects to release a further resource update following the completion of this work in the early part of the second quarter.

Paul Welch, CEO of Chariot commented, "Our farm-out efforts continue to be our main focus of activity and these discussions are progressing very well. Concurrent to these negotiations, we are very pleased with our developments in regard to moving our drilling efforts forward. This year is going to be one of significant progress for the Company and I look forward to providing updates in due course."

TGS Commences Reprocessing Program Offshore Indonesia

TGS Commences Reprocessing Program Offshore Indonesia

Thursday, March 31, 2011
TGS-NOPEC Geophysical Co. ASA
TGS has commenced an extensive multi-phase reprocessing program of 2D seismic data located in the Makassar Strait, Indonesia. The first phase consists of 2,700 km of seismic data in the Northern Mahakam Delta.

The original and reprocessed data support the exploration potential of the deepwater area of the Mahakam Delta. Interpretation of the seismic data since 2001 has demonstrated potential hydrocarbon prospectivity in the basin, resulting in the award of exploration acreage and the drilling of several exploration wells. Partial relinquishment of the exploration blocks have also recently created opportunities for new exploration in the area.

The data will be reprocessed with customized techniques to enhance imaging of the main structures and reservoir targets in the basin. The reprocessed data is intended to enhance definition of Direct Hydrocarbon Indicators (DHIs) and Amplitude Versus Offset (AVO) anomalies associated with turbidite reservoirs seen on the original 2D seismic data.

Data from this initial phase of reprocessing will be available for clients in 3Q 2011. This project is supported by industry funding.

Aztec Encounters Formations at Tx. Well

Aztec Encounters Formations at Tx. Well

Thursday, March 31, 2011
Aztec O&G Inc.
Aztec announced the Welder A-37 was drilled to a total depth of 6,208 feet and encountered multiple formations.

"Utilizing sidewall cores to further evaluate the well's electric log, there appear to be four to five zones of commercial interest in the probable to possible categories," stated Waylan Johnson, President of Aztec Oil & Gas, Inc. Furthermore, he stated, "The A-37 is our second successful well in the area, and we are working on several more ideas in San Patricio County. This county is typical of the type of area in Texas where we are afforded the opportunity to find sizeable reserves shallower than 6,500 feet."

Several Texas Independent Producers have joined Aztec as Partners in the San Patricio County area drilling as Aztec continues its dedication to drilling low-risk, shallow oil wells in Texas.

KCA Deutag Finishes Refinancing Process

KCA Deutag Finishes Refinancing Process

Thursday, March 31, 2011

KCA Deutag announced the completion of a refinancing process. The successful conclusion of this process has resulted in a transaction that strengthens the capital structure of the Company and ensures the long term financial stability of the business.

KCA Deutag will benefit from a strong institutional shareholder base led by existing shareholder Pamplona Capital Management together with funds and accounts managed by GoldenTree Asset Management, EIG Global Energy Partners, and BlackRock Financial Management. Pamplona is the largest shareholder and will have a majority on the new board. The shareholders have equitized mezzanine debt and injected $550 million of new equity into KCA Deutag's holding company Turbo Alpha, of which $300 million will be used to pay down senior debt and $250 million to further develop the business.

Simultaneously, KCA Deutag also confirms that non-executive chairman, Tim Summers, has stepped down following successful conclusion of the restructuring and has been replaced by Alex Knaster from Pamplona Capital. Non-executive directors Chris Hughes and Bob Ellis, appointed at the commencement of the refinancing also step down.

John Halsted of Pamplona commented, "We would like to thank Tim Summers, Chris Hughes and Bob Ellis for their leadership and guidance in steering the Company through a prolonged and intensive refinancing period. The Company has emerged with a significantly strengthened balance sheet, growth capital in the business and an experienced and knowledgeable shareholder base, committed to assisting the Company grow and capitalise on the many opportunities in its core international markets. As shareholders we are very excited about the prospects of the Company in a strongly improving market sector."

Despite the tough economic and trading condition, 2010 was a year in which KCA Deutag delivered robust financial, operational and HSE performance. Compared to our international and US peer group, KCA Deutag mitigated the effects of economic and industry factors better than most, emerging from 2010 with:
  • An improved contract backlog. In our platform drilling division almost every contract was extended by negotiation or competitive tender, securing a revenue backlog of more than $1.5 billion, with the major highlight being the award by AIOC in Azerbaijan of a six-rig, five-year plus options contract.
  • Continued high utilization in our international land fleet with strategic awards in both northern and southern Iraq and increased activity in Algeria and Nigeria.
  • Maintained and extended contracts for all three owned jack-ups.
  • Major contract extensions and awards in our engineering division RDS, relating to the UK, Azerbaijan, Newfoundland, Australia and Brazil.
  • Significant success in KCA Deutag sister Company Bentec, the specialist rig and drilling equipment manufacturer, with the successful introduction of it's top drive and six rigs currently under construction.
  • Best ever company-wide HSE performance.
  • Continuous improvement in our operating efficiency and equipment uptime.
Holger Temmen, CEO of KCA Deutag, commented, "We are pleased to have completed the refinancing of the Company and to have emerged with a strengthened balance sheet and debt position. Throughout this period, KCA Deutag's operational and financial performance remained very robust. This performance has been recognized in the many contract extensions and awards given by our clients and our shareholders and lenders also demonstrated their faith in our business plan by approving the build of five new land rigs during 2010 for key growth markets in Europe, Russia and MENA.

"KCA Deutag's strategic presence in the major international markets has allowed us to outperform the majority of our drilling peer group, especially those exposed to the US domestic market. The opportunities developing in markets such as Russia, Iraq, Algeria and the emerging unconventional oil and gas plays in Europe leave me very optimistic about our medium term growth prospects.

"I would like to thank all staff in KCA Deutag, our clients and suppliers for their patience and understanding as we have progressed through the refinancing process. I am delighted that we can now completely focus on delivering the business plan and continuing to meet and exceed our clients' expectations for safe, effective and trouble- free operations."

Petrofac Lands Contract for Shell's Majnoon Field

Petrofac Lands Contract for Shell's Majnoon Field

Thursday, March 31, 2011
Petrofac Ltd.
Petrofac has been awarded a contract, in excess of US $240 million by Shell Iraq Petroleum Development B.V. for developments in the Majnoon Field, Southern Iraq.

Under the competitively tendered contract, Petrofac is providing engineering, procurement, fabrication and construction management services for the development of a new early production system comprising two trains each with capacity for 50,000 barrels of oil per day, along with upgrading of existing brownfield facilities. Work on the project began in mid-2010 and is expected to complete during the fourth quarter of 2012.

Ayman Asfari, Petrofac group chief executive, said, "Majnoon is one of Iraq's largest developments and we are delighted to be working with Shell to assist them with unlocking the field's potential. Iraq's geographic location, adjacent to many of our existing areas of operation, made it a natural market for the group as we continue to broaden our geographic footprint."

Subramanian Sarma, managing director, Petrofac Engineering & Construction added, "Prior to beginning work with Shell in Iraq last year, we had spent many months preparing in order to achieve a sufficient level of readiness across several aspects of our business operations. All of our activities are underpinned by our strong commitment to safety, quality and integrity and alongside Shell and the local community, we are working to deliver this project to the standards our customers and stakeholders expect from us."

Subsea 7 Secures E.ON Contract for Huntington Development

Subsea 7 Secures E.ON Contract for Huntington Development

Thursday, March 31, 2011
Subsea 7 Inc.
Subsea 7 announced the award of an engineering and installation contract by E.ON Ruhrgas UK E&P for the Huntington Development in the North Sea.

The Subsea 7 workscope comprises the installation of 12km of the 8-inch Gas Export pipeline, installation of infield flexible flowlines, main static umbilical and associated risers as well as installation of subsea structures followed by tie-ins, pre-commissioning and system testing. Engineering work has commenced in the Aberdeen office with installation using several of Subsea 7's fleet occurring through to 2012.

Steph McNeill, Subsea 7's Vice President – UK stated, "I'm delighted that E.ON Ruhrgas UK E&P has chosen Subsea 7 to work on its prestigious Huntington development. We have safely and successfully delivered numerous North Sea projects whilst maximizing efficiencies through security of supply and early engagement in the planning and design process. We look forward to similar success with the Huntington Development over the coming year."
The Huntington Development is located 140 nautical miles North East of Aberdeen in Block 22/14 in the Central North Sea with water depths of 90m. E.ON Ruhrgas UK E&P is the operator and has a 25 % interest.

Statoil Allows Extra Time for Tenderers to Mature

Statoil Allows Extra Time for Tenderers to Mature

Thursday, March 31, 2011
Statoil has decided to allow more time for the tenderers to mature their respective category B rig concepts, which includes an extended front end engineering and design (FEED) phase. The planned award date is set for the fourth quarter of 2011.

Statoil has had an ongoing tender process for the new category B rig type – a semi-submersible designed and equipped for subsea well intervention. The rig will be a highly anticipated contribution to the rig fleet on the Norwegian continental shelf (NCS).
"The decision to allow more time to mature category B is motivated by input from the bidders. We see that an integration of additional services, combined with more time for an in-depth FEED phase, can improve the robustness of the concept," said Statoil's chief procurement officer, Jon Arnt Jacobsen.

"In reality, this is to be regarded as an extension of the bidding process where we according to plan will be able to award the final contract within 2011. Expected delivery from the yard should take place in 2014," Jacobsen added.

The design of the category B service unit is based on the bidders own FEEDs. The rig is designed for year-round well intervention operations for Statoil, providing a full range of heavy well intervention and light drilling techniques – including through-tubing rotary drilling (TTRD), wireline, coil tubing, high pressure pumping and cementing. Statoil is asking for a minimum of one rig of this type for work on the NCS.

"Traditional drilling rigs are not efficient enough for well intervention purposes, so Statoil has developed a new rig type for well intervention in collaboration with industry partners. This rig type will close the gap between light intervention vessels and conventional drilling units. The category B rig with its integrated service lines is expected to reduce well intervention operations costs by up to 40%," Jacobsen said.

The key to maintaining the current production level on the NCS through 2020 is increased recovery from existing fields and fast and effective development of new fields. It is becoming more important to increase drilling activity in mature fields to attain the full potential of the NCS.

"Improved subsea well intervention methods are making vital contributions to increased recovery. Increased recovery is one of the most important contributions to keep up current production level at the Norwegian continental shelf," says Knut Gjertsen, responsible for Operations North field development.

Strike Preps for Testing at Sadie Well

Strike Preps for Testing at Sadie Well

Thursday, March 31, 2011
Strike Energy Ltd.

Strike advised that production casing has been set in preparation for testing at the Sadie-1 well at the onshore Homeplace prospect in the Gulf Coast, Texas, USA.

Gas shows encountered while drilling and subsequent wireline logging indicate potential gas pay intervals in the main Wilcox Formation objective.

The current plan is to test the well direct to sales. Options to tie into nearby pipelines are currently being investigated. It is anticipated that pipeline installation and scheduling of fraccing equipment will enable testing to commence in two to three months.

The Homeplace prospect in the Wilcox Formation, in which Strike holds a 40% working interest, has a prospective gas resource of 15-20 billion cubic feet (Bcf). The prospect has the potential to more than double the Company’s growing gas and condensate reserves.

Wednesday, March 30, 2011

Shell Gets Go-Ahead to Drill in Deepwater GOM

Shell Gets Go-Ahead to Drill in Deepwater GOM

Wednesday, March 30, 2011

The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) approved a deepwater drilling permit for a new well that was described in Shell's recently approved Exploration Plan. The proposed well was also considered in the Site-Specific Environmental Assessment (SEA) completed as part of the plan review. In order to receive the permit approval, Shell complied with rigorous new safety standards implemented in the wake of the Deepwater Horizon explosion and resulting oil spill. This includes satisfying the requirement to demonstrate the capacity to contain a subsea blowout. The approved permit is a permit to drill a new well for Shell's Well #DC001 in Garden Banks Block 427 in 2,721 ft. water depth, approximately 137 miles off the Louisiana coastline, south of Lafayette.

"Today's permit approval represents a culmination of a broad and comprehensive review process involving an exploration plan, a site-specific environmental assessment, and the application for the drilling permit - all of which complied with our rigorous safety and environmental standards," said BOEMRE Director Michael R. Bromwich. "The completion of this process further demonstrates that we are proceeding as quickly as our resources allow to properly regulate offshore oil and gas operations in the most safe and environmentally-responsible manner."

All offshore wells are identified either an exploration or development plan, which require approval prior to drilling permits being issued. Shell's supplemental Exploration Plan which includes Well #DC001 was approved March 21, 2011 as the first new deepwater exploration plan approved since the Deepwater Horizon explosion and resulting oil spill. As part of the plan's review process, BOEMRE prepared a SEA to examine Shell's proposed exploration activities in accordance with the National Environmental Policy Act and the implementation of departmental and bureau regulations.

As part of the permit approval process, the bureau reviewed Shell's containment capability available for the specific well proposed in the permit application. Shell has contracted with the Marine Well Containment Company to use its capping stack to stop the flow of oil should a well control event occur. The capabilities of the capping stack meet the requirements that are specific to the characteristics of the proposed well.

BOEMRE has worked diligently to help industry adapt to and comply with new, rigorous safety practices. These standards ensure that oil and gas development continues, while also incorporating key lessons learned from the Deepwater Horizon oil spill. This new permit meets the new safety regulations and information requirements in Notices to Lessees N06 and N10, and the Interim Final Safety Rule.

HWCG Expands Deepwater Capabilities

HWCG Expands Deepwater Capabilities

Wednesday, March 30, 2011
The Helix Well Containment Group

The Helix Well Containment Group (HWCG) announced it will substantially increase its subsea well containment capabilities this year by expanding its ability to control and contain a release in water depths up to 10,000 feet.

HWCG is a consortium of 22 deepwater operators in the Gulf of Mexico that has come together with the common goal of expanding capabilities to quickly and comprehensively respond to such an incident to protect employees, communities and the environment. HWCG's current system is capable of facilitating control and containment of spills in water depths up to 5,600 feet and will utilize Helix Energy Solutions Group's Q4000, the intervention vessel effectively used during the Deepwater Horizon response.

The system features a 10,000 psig capping stack.

By April 8, 2011, the system is expected to have increased containment capacity and capabilities for water depths up to 8,000 feet, as well as capture and processing capabilities of 55,000 barrels of oil per day and 95 million cubic feet of natural gas per day. In the coming weeks, HWCG will also add a 15,000 psig capping stack.

Full operational capability for water depths of up to 10,000 feet is anticipated mid-summer 2011.

"Our enhanced response and containment capabilities would exceed the depth of any well currently drilled or planned by the consortium's 22 members and would allow operators to control capping and containment stacks at the greater depths," said Roger Scheuermann, commercial director for HWCG.

Building upon equipment effectively used in the Deepwater Horizon response, HWCG has signed an agreement with Helix Energy Solutions Group to provide the primary components of the response. Additionally, HWCG has agreements in place with more than 30 service providers who will provide additional services, products and personnel, if needed.

LG International to Take Stake in Geopark Assets

LG International to Take Stake in Geopark Assets

Wednesday, March 30, 2011
Geopark Holdings Ltd.

LG International and GeoPark announced the acceleration of their strategic partnership by the acquisition of and investment in certain upstream oil and gas interests of each company.
In 2010, GeoPark and LGI entered into a strategic partnership to acquire a portfolio of oil and gas upstream assets in Latin America. As an initial step to cement this relationship, GeoPark has reached an in-principle agreement to sell to LGI a 10% interest in GeoPark Chile Limited, a company registered in Bermuda, for US $70 million. The transaction is expected to close in 2Q 2011.

In addition, in a separate transaction, and subject to obtaining regulatory approvals, GeoPark has reached an in-principle agreement to invest up to US $10 million in the drilling of an exploration well on the Sholkara prospect in the LGI-operated Block 8 in Kazakhstan, which would give GeoPark effectively a 25% participating interest in Block 8. The Sholkara prospect has an unrisked mean oil resource estimate of 100-400 million barrels and represents an exciting opportunity for GeoPark outside its historical and principal area of focus.

LGI is the energy, natural resource and trading affiliate of LG Corporation, the large international Korean company with 147 subsidiaries operating in over 50 countries and with annual sales exceeding US $100 billion. LGI has successfully invested and operated in the oil and gas exploration and production business for over twenty years including current upstream oil and gas projects in Oman, Vietnam and Kazakhstan. LGI has adopted a long term strategy of investing in oil and gas upstream investments in emerging resource-rich countries and has targeted Latin America as a new growth region.

Both transactions are subject to the signing of definitive legal agreements and final approval of the GeoPark and LGI Boards of Directors.

Commenting on today's announcement, James F. Park, Chief Executive Officer of GeoPark, said, "GeoPark views its strategic partnership with LGI as a key element of its future growth and expansion in Latin America. The opportunity to cement this relationship by an initial sharing of projects builds a solid base for a promising long term and committed acquisition partnership. It also clearly demonstrates the value of the business that GeoPark has developed since 2006. GeoPark's primary operational focus will continue to be on developing an exploration and production business in Latin America and we look forward with genuine excitement to the prospect of growing our business across Latin America in partnership with LGI."

Antrim Reports Year-End 2010 Financial, Operating Results

Antrim Reports Year-End 2010 Financial, Operating Results

Wednesday, March 30, 2011
Antrim Energy Inc.
Antrim released its 2010 year-end financial and operating results. The results include a summary and evaluation of reserves that have been independently assessed by McDaniel & Associates Consultants Ltd. in accordance with the standards specified by National Instrument 51-101.

All financial figures are audited and in US dollars except for quarterly figures which are unaudited.

2010 Highlights:
  • Conditional sale and farm-out terms agreed for the UK North Sea Causeway and Fyne Development properties
  • Multiple exploration targets identified on Antrim's UK North Sea 25th Round licenses
  • Two new UK North Sea licenses awarded in the 26th Seaward Licensing Round
  • Terms agreed for Antrim's carried interest through the seismic phase on the Pemba-Zanzibar License in Tanzania
  • Argentina 2010 drilling program completed - eight wells cased for production
  • Average gas price in Argentina increased 20% to $1.84 per mcf over 2009
2011 Highlights:
  • Antrim raised $48.5 million in net proceeds from equity financing to drill exploration targets on the UK North Sea 25th Round licenses
  • Current cash position of $75 million and no bank debt
Antrim completed 2010 with a healthy cash position of $25.7 million, no bank debt and proved plus probable reserves of 34.9 million barrels of oil equivalent ("boe"), approximately 6.2% lower than in 2009. Production in Argentina decreased slightly to 1,783 barrels of oil equivalent per day ("boepd") from 1,840 boepd in 2009. Production decreased due to the sale of the Puesto Guardian property in February 2010, partially offset by production from new wells drilled in Tierra del Fuego.

In the United Kingdom, total proved plus probable reserves were 27.7 million boe (net to Antrim) as at December 31, 2010, the same as in 2009. Fyne and Dandy total proved plus probable reserves at December 31, 2010 remained at 17.5 million boe, unchanged from 2009. Two exploration wells are planned for the latter part of 2011 in licences adjacent to Fyne (the "Greater Fyne Area"). The Fyne and Dandy fields represent 50.2% of the Company's total proved plus probable reserves as at December 31, 2010. Causeway total proved plus probable reserves remained at 10.2 million boe (net to Antrim).

In October 2010, Antrim signed an Earn In Agreement ("EIA") with Premier Oil UK Limited ("Premier") to jointly explore development options for Fyne and the Greater Fyne Area located in the UK Central North Sea. Under the terms of the EIA, Premier paid initial consideration of $2 million to Antrim for an option to acquire a 39.9% interest in the UK Continental Shelf ("UKCS") License P077 Block 21/28a (the "Fyne License).

In return, Antrim will receive up to $50 million, less the initial consideration, towards its remaining working interest share of development costs of the Fyne Field. The option to farm-in has not yet been exercised. The UK reserves previously described do not reflect the impact of this transaction as it has not yet closed.

In March 2010, Antrim signed a Conditional Letter Agreement ("CLA") with Valiant Petroleum plc ("Valiant") to sell a 30% interest in UKCS Licenses P201 Block 211/22a South East Area and P1383 Block 211/23d (the "Causeway Licenses"). In return, Antrim will receive up to $21.75 million towards their remaining working interest share of development costs of the Causeway Field. The UK reserves previously described do not reflect the impact of this sale as the transaction has not yet closed.

In Argentina, total proved plus probable reserves in Tierra del Fuego decreased by 22.6% to 7.1 million boe as at December 31, 2010 compared to 9.24 million boe in 2009 (net to Antrim). This reduction was due to 2010 production and the impact of remapping of undeveloped drilling locations in the Los Flamencos gas field following the 2010 drilling campaign.

In Tierra del Fuego, a ten well (net 2.5) development drilling program designed to increase gas and NGL production from the Los Flamencos gas field, commenced in late February 2010 and was completed in December 2010. Eight of the ten wells have been cased as producers and three have been tied in as of December 31, 2010. The remaining five cased wells are expected to be completed and placed on production by the end of the second quarter of 2011.

In December 2010, Antrim signed an agreement with Ras Al Khaimah Gas Tanzania Limited ("RAK Gas") and NOR Energy AS whereby Antrim replaced its previous right to be carried for 30% through the pre-drilling exploration phase of the Pemba-Zanzibar Production Sharing agreement ("P-Z PSA") with a 20% carried interest through the pre-drilling phase and an additional 10% right to participate in the P-Z PSA to be exercised up to 180 days following receipt of the initial drilling results. The carried interests (up to 30%) are to be repaid from future production.

On March 17, 2011, Antrim issued 48,191,700 common shares at a price of Cdn $1.07 per common share for gross proceeds of Cdn $51.6 million (net proceeds Cdn $48.5 million) which included 6,191,700 common shares issued to the underwriters pursuant to the 98.3% exercise of the over-allotment option.

Net proceeds from the equity financing will be used for exploration of the Greater Fyne Area including the "West Teal" Fulmar Prospect at 11,500 feet drilling depth, which contains a discovery well drilled by a previous operator in 1991 that was subsequently abandoned after encountering mechanical problems, and the "Carra" Tay Prospect at 5,000 feet drilling depth.
On March 28, 2011, Antrim announced that it had signed a Letter of Award ("LOA") with AGR Peak Management Limited to drill two wells (the West Teal and Carra Prospects) commencing in the third quarter of 2011. The LOA is for a minimum duration of 50 days.

Reserves Summary

Oil and gas revenue of $12.5 million for the year ended December 31, 2010 decreased from $13.0 million in 2009. Revenue decreased as a result of lower oil production partially offset by higher gas production and by higher oil and gas prices received. Antrim generated cash flow from operations of $1.5 million in 2010 compared to a cash flow from operations deficiency of $1.1 million in 2009. Cash flow increased due to lower operating and general and administrative costs and higher interest and other income offset by lower revenue.

Net production to Antrim in 2010 was 1,783 boepd compared to 1,840 boepd for 2009. For the three month periods ended December 31, 2010 and 2009, net production was 1,757 and 1,990 boepd respectively. Production decreased due to the sale of the Puesto Guardian property in February 2010 partially offset by production from new wells drilled in Tierra del Fuego. All of Antrim's production is based in Argentina.

Expenditures on petroleum and natural gas properties in 2010 were $6.7 million compared to $4.8 million in 2009. The 2010 capital expenditures are net of $2 million received from Premier for the Fyne option. Capital expenditures in 2010 related to the drilling program in Argentina and ongoing development costs on the UK properties.

2011 Outlook

Antrim expects to have a Field Development Plan for Causeway submitted and approved in 2011 for an anticipated production startup in the middle of 2012. Production startup from the Fyne Field is anticipated in the middle of 2013.

In 2011, Antrim will use its strong financial position to take a leading role in the exploration of the Greater Fyne Area. The drilling program is scheduled to begin in the third quarter with a well drilled and tested on the West Teal Prospect (Antrim 100%). The well is expected to take 55 days to drill and test and cost approximately $30 million.

An additional exploration well in the Greater Fyne Area is expected to be drilled on the Carra Prospect. The well is expected to take 19 days to drill, at an estimated cost of $12 million.
An East Fyne appraisal well is scheduled to be drilled on the Fyne Field. This well is intended to de-risk the eastern extent of the Fyne Field and extend the submission deadline of the FDP for Fyne to June 25, 2012.

In Argentina, Antrim's focus will be on the recently acquired Cerro de Los Leones License (Antrim 50.1% and operator) in the Neuquen Basin. A 3-D seismic program is planned to be shot to support the drilling of at least one exploration well on the license in 2011. Cash flow from Antrim's expected 1,800 boepd from Tierra del Fuego will be used to support this exploration program and any new in-country opportunities.

In East Africa, Antrim holds an option to participate up to 30% working interest in an exploration program on the Tanzanian Pemba-Zanzibar License. This region has recently experienced a significant increase in exploration activity, with several major discoveries announced by consortiums led by Anadarko and British Gas. The Pemba-Zanzibar License has been in an effective force majeure for several years. Antrim expects this impasse could be resolved with the recently announced agreement signed with RAK Gas LLC, a UAE-based exploration and production company with interests elsewhere in Tanzania.

Antrim also considers other global exploration opportunities and views its bilateral strategy of balancing longer term and capital-intensive investments in the UK North Sea with shorter investment cycle on-shore exploration and production opportunities as central to its corporate development.

Royal Dutch Shell issued deepwater drilling permit by BOEMRE

Royal Dutch Shell issued deepwater drilling permit by BOEMRE

The Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, approved a deepwater drilling permit for a new well that was described in Shell Offshore’s recently approved Exploration Plan. In order to receive the permit approval, Shell complied with new safety standards implemented in the wake of the Deepwater Horizon explosion and resulting oil spill, BOEMRE said. The approved permit is a permit to drill a new well for Shell’s Well #DC001 in Garden Banks Block 427 in 2,721 ft. water depth, approximately 137 miles off the Louisiana coastline, south of Lafayette.

FirstService launches FS Energy to improve energy efficiency

FirstService launches FS Energy to improve energy efficiency

FirstService announced the official launch of FS Energy, an energy management company that is leading environmental change by improving energy efficiency and lowering operating costs across FirstService's extensive property management portfolio. FS Energy is initially concentrating on the 450 high rise buildings the company manages in New York City.

General Motors to develop Buick plug-in hybrid

General Motors to develop Buick plug-in hybrid

General Motors (GM) is developing a Buick using the Chevrolet Volt's plug-in hybrid technology, reports Bloomberg. According to two people familiar with the project, designers are working on a version of the hybrid Opel Ampera scheduled for sale in Europe this year. The Buick version would go on sale in 2013 if it receives final approval.

Credit Suisse Lowers U.S. GDP Forecasts for First Half 2011

Credit Suisse Lowers U.S. GDP Forecasts for First Half 2011

Credit Suisse has revised down its U.S. GDP forecasts for the first half of 2011. The firm now expects 2.5% real GDP growth in Q1, down from its previous forecast of 3.5%. Its Q2 forecast was also revised down to 3.3% from 3.7%. However, the firm's 2011 second half forecasts remain unaltered at 3.8% and 4.0% for Q3 and Q4, respectively. Credit Suisse expects full year 2011 growth of 3.4% on a year-over-year basis and 3% on an annual average basis. This is down from its previous estimate of 3.8% and 3.3%, respectively. The firm sees 4.0% real GDP growth in 2012.

Credit Suisse issued a statement saying: The first quarter's forecast revision is mostly due to current quarter accounting. The monthly building blocks that add up to GDP have consistently printed below expectations this quarter, defying the much rosier readings from other parallel evidence on the economy (such as the ISM surveys). The list of GDP "source data" disappointments includes home sales, housing starts, capital goods shipments, non-residential construction, federal spending, and a sharp increase in the trade deficit. Most importantly, the GDP's largest building block - consumer spending - is slowing sharply on a sequential basis, on track for less than 2% growth in Q1, compared to 4% growth in Q4. Our revision to second quarter growth is partly a consequence of higher oil prices and the negative effect on real income growth. Consumer confidence gauges also fell sharply in March, presumably due to higher gasoline prices. Another reason for our Q2 downgrade is housing, particularly the 22% plunge in February housing starts. Falling starts will impact future readings on construction outlays and the associated GDP component - residential investment.

ConocoPhillips up 2% on Plans to Explore Angola, Poland for Oil, Gas

ConocoPhillips up 2% on Plans to Explore Angola, Poland for Oil, Gas

ConocoPhillips is up 1.56% to $80.04, helped by the general bullish sentiment on energy shares Wednesday, as well plans to expand its operations in Angola, the Gulf of Mexico and Poland.

The company is negotiating leases on two deepwater blocks in Angola, exploring for oil and gas in the deepwater area of the Gulf of Mexico, and is active in exploring for resources in Poland. It has rights to one million acres in several different parts of the country, according to Investopedia.

Edge Boosts Production, Drills 3 Wells

Edge Boosts Production, Drills 3 Wells

Wednesday, March 30, 2011
Edge Resources Inc.
Edge has completed the first three wells of a multi-well drilling program. Additionally, the Company has increased production by fracturing and tying two wells into its 100% owned and operated, dedicated shallow-gas infrastructure.

The drilling rig, on contract from Ensign Energy Services, moved to the Company's location directly from northern Alberta on March 14, 2011. The rig drilled the first of at least eight licensed locations, with several others soon to be licensed and drilled. The rig was released because of "spring breakup", a period during which the winter frost comes out of the ground and the various counties restrict the movement of large equipment over the roads.

Brad Nichol, President and CEO of Edge commented, "I'm pleased with the operational team's ability to have squeezed this rig into our drilling plan prior to break-up versus waiting until break-up is over and competing with many other companies for the rigs. I am equally impressed with how quickly my team reacted to the availability of fracturing equipment.

On notice that the equipment was coming available, we immediately moved to put that equipment to work on our wells, and already have two of those wells producing into our own pipeline."

The Company commenced fracturing operations on several wells, after waiting since December 2010 for equipment to come available. The Company has successfully fractured two wells, both of which were immediately tied-into 100% owned and operated, existing shallow-gas infrastructure. Other wells will be fractured as part of this program but will not be tied-into pipeline until after spring breakup.

These two wells are flowing over 1,000 mcf/day (167 boe/day) on initial production, which adds significantly to the Company's total production mix. The Company is now generating significant revenue and positive cash flow on a monthly basis.

The Company has very low operating and F&D costs, and expects to be profitable at a natural gas price of less than $2.00/mcf.

Edge has now earned or acquired a total of 23 sections of Edmonton Sands natural gas property, each containing one drilled Edmonton Sands well. The Company has executed agreements that allow for up to another 27 sections of prospective Edmonton Sands land to be earned by drilling 1 well on each respective section.

Europa O&G Updates Ops

Europa O&G Updates Ops

Wednesday, March 30, 2011
Europa O&G plc

Europa O&G provided an update on several active projects.


  • UK Production tested oil from two zones in the new onshore West Firsby well
  • WF-9
  • Installation of jet pump is key to maximizing rates
  • Well stimulation work being planned for Crosby Warren
  • Romania Barchiz-1 sidetrack to deepen the well to the primary target
  • France 3D reprocessing complete at Berenx, new 3D and engineering work planned

West Firsby

Two zonal pumping tests have been conducted on the new WF-9 well. As previously reported, the well encountered oil in two reservoir zones.

The lower of these, Zone 2, produced oil at rates of around 80bopd with strong associated gas but very little water. Heavy wax build-up in the well and the high gas rates are thought to have impaired flow through the beam pump.

Zone 1 produces much higher volumes of fluid, but with a high water cut. Net oil production from this zone under a beam pump regime is 40bopd. The beam pump, however, is only able to drawdown the well some 300psi, indicating that there is significant production upside with a properly configured pump. It should be possible with a jet pump to produce drawdown in the region of 1,500psi or more and the main constraint will be fluid handling capacity. The recent successful re-completion of WF-3 as a water disposal well is key tool in managing this issue long term.

A jet pump system has been sourced and will be commissioned to undertake further tests on both zones. Following the results of these new tests, a longer term zonal production strategy will be decided.

The workover of WF-7, which required a new bottom hole assembly, is due to commence this week and it is hoped the well will be back onstream within the next 2 weeks. Once WF-7 is back onstream, it is expected that Group production should be approximately 300bopd with further upside expected following installation of the jet pump on WF-9 and well stimulation work at Crosby Warren.

Crosby Warren

Engineering studies are complete on the question of undertaking a new hydraulic frac stimulation of the CW-1 reservoir. The study has shown that the historical frac has become ineffective over time. Consequently, a repeat frac stimulation presents an opportunity to significantly increase field production. The original frac was highly successful and led to a 15 fold increase in production rate. It is hoped that this work can be carried out in the next 2-4 months.

Discussions are ongoing with regard to the acquisition of a new 3D seismic survey jointly with neighboring license holders later this year which would lead to a much more robust subsurface model for both the Crosby Warren field and the Company's nearby Wressle exploration prospect.


Barchiz-1, drilled late last year, recovered oil on DST from a shallow sandstone reservoir with approximately 35 feet of net pay. The main exploration target of the well was not reached due to technical constraints. Following partner meetings last week, Europa has declared an intention to deepen the Barchiz-1 well to the primary objective as a sole-risk operation, subject to financing. The Operator proposed acquiring further seismic data along trend from Barchiz to identify a new exploration well location in the play. However, the Directors' view is that this an opportunity to test whether the Oligocene reservoir is present beneath the current well TD, a concept supported by nearby well control.

The joint venture group has applied for a license extension in order to pursue the remaining undrilled prospectivity on the license and the associated work program is currently being agreed with the authorities. Barchiz-1 sidetrack is expected to be drilled in the second half of 2011.


Planning the appraisal of this potentially multi-TCF gas project has taken a step forward with the completion of 3D seismic reprocessing by CGG, which has greatly improved the seismic image. NRG, the Aberdeen-based well engineering company, have been retained to undertake detailed well engineering for the planned Berenx-3 appraisal well.

In the meantime and following the success of the CGG work, further 3D seismic data is planned for later this year. This survey, which could be acquired in Q4 2011, will quantify the western extent of the Berenx structure, which tested dry gas in the 1970's.

Acquiring this survey will fulfil the work commitment of the first phase of the permit and allow for automatic renewal in early 2012.


It should be noted that achieving optimum rates on the new West Firsby well will take some weeks and that, in conjunction with the earlier drilling delays this will generate full year (to July 31, 2011) projected revenue and profits below market expectations.

The Company is actively engaged in new venture activity, including current and near-term licensing rounds in its core area of NW and Continental Europe. The aim is to add significant high impact exploration acreage into the asset portfolio for drilling in 2012 onwards.

Paul Barrett, Managing Director, said, "There has been significant progress in a number of value-enhancing projects and we look forward to a sustained newsflow from seismic, drilling and new venture activity through the coming 12 months. Production growth over the coming months is expected to support this activity."

Lamprell Bags Weatherford Contract

Lamprell Bags Weatherford Contract

Wednesday, March 30, 2011
Lamprell has received a new contract award from Weatherford Drilling International for the engineering, construction and delivery of two 3000HP land drilling rigs, with a total contract value of $41 million.

The rigs have a static hook load capacity of 1,500,000 lbs and 800,000 lbs set back capacity.

The mast will accommodate a 750T top drive supplied by three triplex mud pumps rated at 2200HP with a 7500psi high pressure mud system. The rig will be powered by five 3516B CAT engines. Lamprell will fabricate the rigs at its yard in Jebel Ali. The project is planned to be completed during the first quarter 2012.

Commenting on the contract award Nigel McCue, Chief Executive Officer, Lamprell said, "We are delighted to be announcing this significant new contract award from Weatherford.

We believe that this land rig award, the largest yet for our oilfield engineering business, demonstrates the exciting opportunity to develop Lamprell's offering in this developing regional market. We look forward to working with Weatherford on this important project."

Obama to call for more use of natural gas, biofuels

Obama to call for more use of natural gas, biofuels

President Obama will set a goal today of reducing the nation's oil imports by one-third by 2020, according to The Washington Post. The president will call on Congress and Americans to accomplish the goal by conserving energy, using more natural gas and biofuels, setting higher fuel standards for heavy trucks, and drilling for oil in more areas.

Solimar: Potential Oil Pay at San Joaquin Basin

Solimar: Potential Oil Pay at San Joaquin Basin

Wednesday, March 30, 2011
Solimar Energy
Zodiac Exploration of Canada has announced potential oil pay of up to 1,000 feet in sandstone and fractured oil shale reservoirs in its Zodiac 4-9 well in the NW San Joaquin Basin. Solimar Energy has a 1.13% carried interest in the well and in a very large, approximately 101,000 acre surrounding acreage position. Solimar also owns a small, 0.5% royalty over some 26,000 acres of this acreage position.

In addition to the minority position in the Zodiac acreage, Solimar has approximately 20,000 mostly operated acres with interests from 33.33% to 75% in other leases within and adjacent the NW San Joaquin Basin oil shale play trend. Oil shales of the Kreyenhagen and McLure (Monterey equivalent) Formations are proven producers in the area and the main targets.

The Company also has a back in right for a 10% interest in a further approximately 2,900 acres in the trend flanking the Kettleman Middle Dome which is also productive from the fractured oil shales and is the subject of a redevelopment program.

There is accelerating industry activity in California oil shales lead mainly by major oil companies that is revaluing Solimar Energy's San Joaquin Basin acreage.

Key offset industry activity includes:
  • The Zodiac 4-9 well which is being prepared for a flow testing program after encountering potentially 1,000 feet of pay in both sandstone and shale reservoirs
  • Occidental Petroleum have become the biggest acreage holder in the NW San Joaquin oil shale trend and are already producing 45,000 bopd from fractured oil shales in California
  • Chevron are redeveloping the giant Kettleman Dome field immediately adjacent Solimar's acreage focusing on production from the Kreyenhagen Shale
  • A multi party JV has been successfully redeveloping the Kettleman Middle Dome which is productive from sandstone reservoirs and both the Kreyenhagen and McLure Oil Shales. Additional appraisal drilling immediately adjacent Solimar's back in right acreage is planned within 12 months

Update Summary

The Board of Solimar provided this brief update note to inform shareholders that very positive commercial activity is occurring within and adjacent the Company's asset focus area the San Joaquin Basin, with particular emphasis on the development of fractured oil shales.

The Company has been aggressively building its acreage position and adding to its California (Ventura) based operating team over the past 15 months and is positioning to exploit both its conventional (sandstone which includes the recent Guijarral Hills discovery) and unconventional (oil shales) reservoir projects.

The timing of execution of the Company's strategy to accumulate oil prone acreage focussed in the San Joaquin Basin has been excellent:
  • Oil prices are now very high relative to the USA domestic gas price supporting robust project economics
  • Land prices for oil shale acreage are increasing in California. However Solimar believes large uplifts are still likely to bring California into line with other states of the USA where oil shale land prices can be up to 10 times higher than in California.
The Schematic Map attached to this release shows the position of Solimar's acreage within and adjacent the NW San Joaquin Basin oil shale play trend, highlighting the acreage position relative to the key industry players.

More detail will be provided in due course about each of the Company's projects that have potential for oil shale production as the individual work plans are crystallized. The following brief descriptions are examples however of two large projects the Company has that are expected to significantly impact the Company in 2011.

The Company's largest project is at Kreyenhagen with over 15,000 operated acres under lease and containing extensive occurrences of thick Kreyenhagen and McLure Formation oil shales within targetable depths. Both these formations are oil productive in the adjacent oil fields where these rocks are the subject of active field redevelopment programs.

The Company is in the early stages of evaluation of the Kreyenhagen Project which also contains a large, known shallow oil accumulation in a sandstone reservoir.

There may be up to 300 million barrels of oil in place within this reservoir in the project acreage.

The Kreyenhagen Project will be the subject of considerable field activity by Solimar commencing in 2011 including re entry and production testing of some suspended wells.

The Company is also watching closely the progress of the Zodiac 4-9 well which Canadian listed Zodiac Exploration recently drilled to almost 15.000 feet and announced on 21 March a potential oil pay of over 1,000 feet in the well. Solimar has a 1.13% interest free carried through the Zodiac 4-9 and a following well in a very large acreage position totaling some 101,000 acres. In addition the Company owns a small 0.5% royalty over approximately 26,000 acres within this overall acreage position but not at the well location.

The well is being prepared for production testing as part of a program to verify the commercial potential of the multiple potential pay zones encountered.

Commenting on the evolving potential of Solimar's San Joaquin Basin acreage, CEO John Begg said, "We spent much of last year securing an acreage position focused on the oil prolific San Joaquin Basin. This strategy has placed the Company in an exciting position literally and figuratively. In most cases our immediate neighbors are major oil companies that are accelerating their work programs in the San Joaquin Basin on play types represented in our acreage. So not only do we have active programs of our own that could deliver a substantial uplift in value but escalating industry activity in and adjacent our acreage that could also be transformational at no cost to the Company."

Tullow Sells Uganda Stake to Total, CNOOC for $2.9B

Tullow Sells Uganda Stake to Total, CNOOC for $2.9B

Wednesday, March 30, 2011
Tullow Oil plc

Tullow has signed Sale and Purchase Agreements (SPAs) with CNOOC and Total in respect of the sale of a one third interest to each party of the interests Tullow holds in Exploration Areas 1, 2 and 3A in Uganda. Tullow will retain a one third interest. The terms of the transactions include a total cash consideration payable to Tullow of US $2.9 billion.

With the signing of these SPAs, a key condition of the Memorandum of Understanding (MoU) agreed between Tullow, the Government of Uganda (GoU) and the Uganda Revenue Authority (URA) on March 15, 2011, has been satisfied. The next step is for Tullow to make certain tax related payments to the GoU, on receipt of which all relevant consents become final and the other provisions of the MoU become effective.

Under the MoU, Tullow and its new Partners, CNOOC and Total, have been granted new licenses over EA-1 and an onshore area of EA-3A and the partnership's rights to develop the Kingfisher discovery have been confirmed. A clear plan for the resolution of tax disputes on the various asset sales has been agreed by the GoU, the URA and Tullow.

Tullow and its Partners will now reactivate the significant program of exploration and appraisal drilling and progress their development plans for the basin which they will jointly present to the Government of Uganda for approval.

Commenting, Aidan Heavey, Chief Executive, said, "These agreements have secured the future of oil production in Uganda. Tullow, its partners and the Government of Uganda will now agree a development plan for the Lake Albert Rift Basin with a target of delivering production of at least 200,000 bopd and potentially much more as we continue to explore and appraise the basin. We are looking forward to working with CNOOC and Total, and continuing our strong relationship with the Government to bring the benefits of the oil to the people of Uganda."

Statoil, KazMunaiGas Team Up in Caspian Sea JV

Statoil, KazMunaiGas Team Up in Caspian Sea JV

Wednesday, March 30, 2011
Statoil and KazMunaiGas have signed the Heads of Agreement (HoA) on the Abay block in the Kazakhstani sector of the Caspian Sea.

Under the HoA, the parties plan to conduct evaluation of the hydrocarbon potential of the Abay block in the Northern Caspian Sea. Statoil and KazMunaiGas will jointly establish a company that will serve as operator of the project. The exploration work program will cover seismic surveys, data acquisition and the drilling of one exploration well.

"Joint cooperation in the Abay block is an important strategic step for Statoil as we continue our international growth. This agreement marks an important milestone in Statoil's re-entry into Kazakhstan and I am very pleased that we have strengthened our partnership with KazMunaiGas," said Tim Dodson, executive vice president for Exploration in Statoil.

In addition to the work program the joint operating company will participate in social investment projects including training of local personnel. Statoil will provide financial and technical assistance to KazMunaiGas' project to build, own and operate a jack-up drilling rig for the use in the Caspian Sea.

"We are interested in cooperation with Statoil in attracting and using their experience and technologies in operating international offshore oil and gas projects. The HoA signing confirms the intentions of the parties about the strategic partnership of our two companies on the joint activities in the Caspian Sea," said Kairgeldy Kabyldin, Chairman of the management board of JSC NC KazMunaiGas.

The Abay block is located 65 km from the shore, at a water depth of 8-10 meters.