Crude Oil Price by

Oil and Gas Energy News Update

Thursday, August 11, 2011

Oil & Gas Post - All News Report for Thursday, August 11, 2011

Thursday, August 11, 2011

Oil & Gas Post

Promote Your Page Too

Commodity Corner: Oil Rallies on Market Rebound

- Commodity Corner: Oil Rallies on Market Rebound

Thursday, August 11, 2011
Rigzone Staff
by Saaniya Bangee

Soaring to its highest all week, NYMEX crude rallied Thursday as U.S. equities opened higher and the Labor Department reported positive job data.

Front-month crude oil futures gained 3.4 percent, or $2.83, to settle at $85.72 a barrel. Likewise, Brent crude also advanced, settling up $1.34 at $108.02 a barrel.

Following the worst plunge in almost a year, U.S. stocks opened higher Thursday. The S&P 500 advanced 4.6 percent, while the Dow Jones Industrial Average increased by 3.9 percent in New York.

According to the U.S. Labor Department, the number of initial unemployment claims fell by 7,000 to a seasonally adjusted 395,000, marking a four-month low.

The intraday range for WTI was $81.03 to $85.97 and $104.51 to $108.19 for its European counterpart.

Natural gas for September delivery traded up 10 cents to $4.11 per thousand cubic feet. The September contract price for natural gas fluctuated between $3.94 and $4.14 Thursday.

The Energy Information Administration said stockpiles grew by 25 billion cubic feet in the week ended Aug. 5.

Two of three low-pressure systems in the Atlantic have a 40 percent chance of forming into a tropical cyclone, reported the U.S. National Hurricane Center.

Reformulated gasoline blendstock held on to yesterday's gains settling up 4.48 cents at $2.83 a gallon. Prices peaked at $2.839 and bottomed out at $2.745 Thursday.

Oil & Gas Post

Promote Your Page Too

First Subsea Scores Chevron Contract for Jack/St. Malo Facility

- First Subsea Scores Chevron Contract for Jack/St. Malo Facility

Thursday, August 11, 2011
First Subsea Ltd.

First Subsea has been awarded a contract by Chevron U.S.A. Inc. to supply the mooring connectors for the Jack/St. Malo semisubmersible hub production facility in the Jack/St. Malo fields located approximately 280 miles south of New Orleans, Louisiana, in water depths of 2,133 m (7,042 feet) in the Gulf of Mexico.

The semisubmersible, floating production unit (FPU) will be moored by 16 Ballgrab, ball and taper, mooring connectors attached to polyester mooring lines in a 4x4 arrangement. The Ballgrab Series III male connectors will be the largest produced so far with an un-corroded 2,599mT (25,491kN) MBL, and the first to comply with the new ABS Mooring Guide 2009.

The Ballgrab connector comprises a male connector and female receptacle. The female receptacle will be installed subsea with the mooring system's suction piles, mounted on docking porches. When the FPU is in position, the male connector, attached to the mooring line, is lowered from the surface into the female receptacle to complete the mooring installation. The process is then repeated until all 16 mooring lines are connected.

"We are delighted to have been awarded the Jack & St Malo FPU mooring connector contract," said Brian Green, general manager, First Subsea Ltd. "The Ballgrab mooring connector provides an efficient method of deploying deepwater mooring lines. For the Jack & St Malo connectors, we will be drawing on our world leading research into large scale forgings to optimize mooring performance."

Oil & Gas Post

Promote Your Page Too

Baker Hughes Prices Senior Notes

- Baker Hughes Prices Senior Notes

Thursday, August 11, 2011
Baker Hughes Inc.

Baker Hughes announced the pricing of $750 million aggregate principal amount of its 3.20% senior notes due August 15, 2021. Interest is payable on February 15 and August 15 of each year. The first interest payment will be made on February 15, 2012, and will consist of interest from closing to that date. The offering is expected to close on August 17, 2011, subject to customary closing conditions.

The company intends to use the net proceeds of the offering to redeem all of its outstanding 6.50% senior notes due 2013, of which an aggregate principal amount of $500 million is currently outstanding. The company will use any remaining net proceeds for general corporate purposes, which could include funding ongoing operations, business acquisitions and repurchases of the company's common stock. The net proceeds of the offering may be invested temporarily in short-term marketable securities pending such usages.

The notes to be offered have not been registered under the Securities Act of 1933, as amended (the "Securities Act"), or any state securities laws, and unless so registered, may not be offered or sold in the United States except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. The notes will be offered and issued only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the United States pursuant to Regulation S.

Oil & Gas Post

Promote Your Page Too

Entek Preps Battle Mountain Well for Testing in Niobrara Play

- Entek Preps Battle Mountain Well for Testing in Niobrara Play

Thursday, August 11, 2011
Entek Energy Ltd.

Entek provided an update on the Niobrara Shale Oil Project Appraisal Program in the Green River Basin.

Battle Mountain 14-10L – The well is currently being prepared for testing in the Frontier Sandstone secondary objective. The completion procedure, which includes testing and fracture stimulation for the potential Niobrara pay zones is currently being refined by Halliburton.
Completion operations for the Niobrara are expected to start in September 2011.

Slater Dome (SD) Federal 24-9DL – The well has been spudded and is currently drilling the surface hole section at 400 ft. Casing is planned to be set at 2,500 ft before drilling the remainder of the well. The planned total depth of the well is 8,627 ft.

Entek holds a 55% interest in the Green River Basin Joint Venture (GRBJV) with Emerald Oil & Gas holding 45%. Entek is the Operator. The GRBJV now controls close to 80,000 gross acres, approximately 60,000 net acres, covering the Niobrara Shale Oil Play.

Oil & Gas Post

Promote Your Page Too

Astec to Acquire GEFCO

- Astec to Acquire GEFCO

Thursday, August 11, 2011
Astec Industries Inc.

Astec has entered into a definitive agreement to acquire substantially all of the assets and certain liabilities of the GEFCO and STECO divisions of Blue Tee Corp.

Astec Industries has formed a new subsidiary, GEFCO, Inc., to operate the acquired businesses and will continue to manufacture the George E. Failing, SpeedStar, King Oil Tools and STECO equipment from the current Enid, Oklahoma headquarters. The transaction is expected to close during the fourth calendar quarter.

The total purchase price for the acquisition is approximately $26 million but is subject to certain closing adjustments.

Dr. J. Don Brock, Chairman and Chief Executive Officer, said, "We are delighted to welcome GEFCO and STECO to the Astec Industries family of companies. This acquisition adds a new range of products manufactured by Astec Industries, Inc. The gas and oil drilling equipment manufactured by GEFCO has numerous innovations that will enhance the American Augers line of gas and oil drilling equipment and directional drills. We believe that we can enhance the current operations by improving purchasing practices, reducing outsourced assembly items and by using our best practices. Additionally, under the leadership of Aaron Harmon, President, we look forward to growing the business, expanding the position in the energy market and providing innovative portable drilling equipment."

Aaron Harmon added, "I am excited about this move. This is a great opportunity, not only for GEFCO and STECO and our employees, but for our customers as well."

Oil & Gas Post

Promote Your Page Too

SBM Offshore Clinches LOI for FPSO Lease Offshore Brazil

- SBM Offshore Clinches LOI for FPSO Lease Offshore Brazil

Thursday, August 11, 2011
SBM Offshore

SBM Offshore announced that one of its Affiliates and Queiroz Galvao Oleo e Gas S.A. (QGOG), have received two Letters Of Intent (LOI), one from GUARA BV and one from BM-S-9 Consortium, established by the companies Petrobras (Operator, 45%), BG E&P Brasil (30%), and Repsol Sinopec Brasil S.A. (25%) for a twenty year charter and operation of an FPSO for the Guará Norte development in the pre-salt area, offshore Brazil.

The Guará Norte field is located in block BM-S-9 in the Santos basin at approximately 300 kilometers offshore and 2,300 meters water depth. The FPSO will include topside facilities to process 150,000 bpd of production fluids, associated gas treatment for 6,000,000 Sm3/d with compression and carbon dioxide removal, hydrogen sulphide removal, and a water injection facility for 180,000 bpd.

It is the intention that the unit will be owned and operated by a consortium in which SBM Offshore's shareholding will not be less than 49.5% and not exceed 62.25%.

The project schedule foresees delivery of the FPSO in 35 months from LOI.

The non-discounted total of the revenues payable under this contract to the consortium, excluding escalation and bonus, amounts to approximately US $4.5 billion.

Oil & Gas Post

Promote Your Page Too

Salamander Appoints New CFO

- Salamander Appoints New CFO

Thursday, August 11, 2011
Salamander Energy plc

Salamander announced the appointment of Dr. Jonathan Copus as Chief Financial Officer, and a Board director, of the Company. He is expected to take up his position in the fourth quarter of 2011.

Jonathan, 39, has worked as an oil and gas equity research analyst for over 10 years, most recently as a Director of Deutsche Bank's Oil and Gas Equity Research team. Prior to becoming an analyst, he worked for Shell International as a geologist in its Deepwater E&P team based in Holland and Houston.

Jonathan has a PhD from the University of Cambridge and a First Class BSc in Geology from the University of Durham.

James Menzies, Chief Executive of Salamander Energy, said, "Jonathan is an individual of caliber and drive; an excellent hire for Salamander. He brings an outstanding grasp of our sector and the essential combination of geological and financial skills for a growing, technically-led E&P company. I and my fellow directors look forward to working with him and we believe that Jonathan will make a strong contribution to the future of Salamander."

Jonathan Copus, commented on his appointment, "I am excited to be opening a new chapter in my career. Salamander is a balanced business in which I believe great upside to exist. I look forward to working with James and the team to realize this potential."

Oil & Gas Post

Promote Your Page Too

Europa O&G Welcomes New CEO

- Europa O&G Welcomes New CEO

Thursday, August 11, 2011
Europa O&G Holdings plc

Europa O&G announced the appointment of Hugh Mackay as a director and Chief Executive Officer with effect from October 10, 2011.

Mr. Mackay was more recently founding Chairman of Avannaa Resources, a mineral exploration company focused on grass roots exploration in Greenland. Mr. Mackay has a wealth of experience in the oil and gas sector, including eight years at BP in a variety of roles in the UK, the Oman and Egypt, ten at Enterprise Oil in leadership roles, culminating as head of the SE Asia division. He played a pivotal role in the development of the Peak Group and its eventual sale to AGR Petroleum Services where he was Group Business Development Manager. Mr. Mackay has a BSc in Geology from the University of Edinburgh and a Sloan MSc in Management from the London Business School.

On appointment, Mr. Mackay will be granted options, expiring after ten years from the date of grant, over 5,000,000 ordinary shares with an exercise price of 13p. The share options will vest in five equal tranches when the share price of the Company has been at or above 25 pence, 35 pence, 45 pence, 50 pence and 60 pence respectively for a period of 30 consecutive trading days. Prior to appointment, Mr. Mackay has also purchased 455,615 ordinary shares of the Company, representing 0.35% of the Company's issued share capital.

Disclosures required pursuant to Schedule 2(g) of the AIM Rules for Companies in respect of Hugh Mackay are set out below.

Bill Adamson, Chairman of the Company commented, "We are delighted that Hugh has accepted our offer to join us. His track record shows that he has the right skills and experience in senior management positions, oil and gas project development, and entrepreneurial flair that Europa needs as it enters an exciting period in its development."

As previously notified on April 26, 2011, Paul Barrett will be standing down as Managing Director to pursue other interests.

Oil & Gas Post

Promote Your Page Too

GM Confirms A123 Systems Awarded Contract For Future Batteries

- GM Confirms A123 Systems Awarded Contract For Future Batteries

Aug 11, 2011

GM (NYSE:GM) announced today that the company has awarded a production contract to A123 Systems (NASDAQ:AONE) for batteries to be used in future GM electric vehicles to be sold in global markets.

Micky Bly, an executive director at GM said, "GM is committed to offering a full line of electrified vehicles - each of which calls for different battery specifications. We work with a variety of battery developers and A123's advanced Nanophosphate lithium ion technology offers ideal performance capabilities for a future electrified vehicle application."

The specific vehicles and brands will be announced at a later date.

This contract win is being attributed as a driver of A123's stock move, with shares up about 42% so far today.

Oil & Gas Post

Promote Your Page Too

W&T Offshore Seals Stake in Shell's Fairway Field, Yellowhammer Facility

- W&T Offshore Seals Stake in Shell's Fairway Field, Yellowhammer Facility

Thursday, August 11, 2011
W&T Offshore Inc.

W&T Offshore has closed its acquisition of Shell Offshore's 64.3% interest in the Fairway Field along with a 64.3% interest in the associated Yellowhammer gas processing plant, with an effective date of September 1, 2010. This acquisition was part of a larger transaction between Shell and W&T for three Gulf of Mexico deepwater producing fields known as Tahoe, SE Tahoe, and Droshky. As of the close date, the adjusted purchase price paid for the Fairway Field and Yellowhammer gas plant, as adjusted on the preliminary closing statement, was approximately $36.7 million, subject to further post-effective date adjustments and assumption of asset retirement obligations associated with these properties.

The Fairway Field is located in the shallow state waters south of Mobile Bay, Alabama and the Yellowhammer plant is located onshore in Alabama about 17 miles northwest of the Fairway Field. Current production, net to our interest in the Fairway Field, is approximately 19.5 MMcf of natural gas per day and 1,200 barrels of natural gas liquids per day or approximately 26.9 MMcfe per day, which was not included in previously provided production guidance. W&T's internal estimates of proved reserves associated with the acquired property as of June 30, 2011 are 39.4 billion cubic feet of natural gas and 2.5 million barrels of natural gas liquids, or 54.5 Bcfe. These reserves were based on SEC reserves definitions and pricing as of June 30, 2011.

Tracy W. Krohn, Chairman and Chief Executive Officer, commented, "This completes our acquisition from Shell and it serves to increase the borrowing base of our revolving bank credit facility by $50 million."

Oil & Gas Post

Promote Your Page Too

Mancos Oil Drilling Possible in 2012

- Mancos Oil Drilling Possible in 2012

Thursday, August 11, 2011
Knight Ridder/Tribune Business News
by Chuck Slothower, The Daily Times, Farmington, N.M.

The San Juan Basin could see an uptick in Mancos Shale drilling as soon as 2012, an oil and gas industry official said Wednesday.

"We think we'll see a critical mass by next year," said Steve Dunn, drilling and production manager at Merrion Oil and Gas. "We'll see some drilling."

Dunn was touting the potential for an oil boom in the Mancos Shale, a geologic layer deposited about 100 million years ago in the San Juan Basin. His remarks came at Wednesday's San Juan Economic Development Service meeting.

Horizontal drilling and hydraulic fracturing have made it possible for drillers to reach previously unavailable oil and gas deposits deep within shale rock. Plays, as the booms are called, have overtaken the Bakken Shale in North Dakota, the Barnett Shale in Texas and elsewhere.

"We believe the Mancos is going to be the next big play," he said.

Drilling in the Mancos Shale would require 10 to 20 stages of fracturing per well, Dunn said. Once drillers gain experience, the wells could be completed for about $5 million each.

"It takes a lot of money to do it, but there's the potential to make a lot of money if you're successful," Dunn said.

The oil-rich area of the Mancos Shale is mostly south of Farmington, spanning 3,400 square miles in San Juan, Rio Arriba and Sandoval counties, he said.

Drillers increasingly are focusing on drilling for oil as natural gas prices stagnate. Oil, however, hasn't been immune from economic worries. Investors

have driven down the price of oil this week, to $81 on the New York Mercantile Exchange on Wednesday. Natural gas traded for $4.07 per MMBtu on the Henry Hub.

A few wells already have been drilled in the Mancos Shale. EnerVest saw disappointing results for two wells drilled near Lindrith, Dunn said. However, Williams Exploration and Production got promising results from wells drilled near Navajo Lake.

Williams has applied to build eight well pads on Middle Mesa that could host as many as 13 well bores per pad. The project calls for a purpose-built drilling rig that would operate year-round, a major investment for the company.

The Middle Mesa project is slated to begin in fall 2012, pending an environmental impact statement and approval by the U.S. Bureau of Land Management.

Merrion Oil and Gas has been in discussions with several large producers interested in exploring the Mancos Shale.

"I really think Merrion Oil and Gas and our partners will lead the way in this Mancos Shale play," said T. Greg Merrion, the company's president.

Dunn said the Mancos Shale could support 13,000 additional wells.

"Keep in mind, I'm talking about potential here," he said.

Mayor Tommy Roberts said tax incentives play a big role in encouraging oil an gas production. A federal tax credit for coal-bed methane production helped spur the drilling boom during the 1990s.

New tax incentives are a tough sell in an uncertain economy, he said.

"Our state legislators seem to be reluctant to pursue it in an environment where the governor is trying to eliminate tax incentives," he said.

Copyright (c) 2011, The Daily Times, Farmington, N.M.

Oil & Gas Post

Promote Your Page Too

Crown Point Flows Oil at Argentina Well

- Crown Point Flows Oil at Argentina Well

Thursday, August 11, 2011
Crown Point Ventures Ltd.

Crown Point has successfully completed EV 31 which is the fourth well of the 2011 drilling as a successful flowing oil well. To date this year, the Company has drilled, cased and completed four wells as successful oil wells at the El Valle field in the San Jorge Basin in Southern Argentina. Since commencing drilling operations at El Valle, the Company has drilled and completed ten wells with a 100% drilling and completion success rate.

The completion rig will be moving later this week to commence a work over operation on an EV 19 which was one of the first wells drilled by Crown Point at El Valle. Once that work over has been completed we expect to start completion operations on EV 27 which is currently drilling and is the fifth well of the current drilling program.

Completion Update: EV 31

Crown Point successfully completed a 4.0 meter thick section of the Canadon Seco formation in the EV 31 wellbore. This zone was perforated and fracture stimulated. The well during its evaluation period flowed oil through a 20 mm choke at a 24 hour extrapolated rate of 370 barrels per day of 100% oil.

Due to the excellent production test results obtained from the currently completed 4.0 meter Canadon Seco zone in EV 31, the Company has indefinitely deferred the completion of two additional highly prospective zones in the Canadon Seco.

Drilling Plans 2011-2012

This drilling program is part of a larger 20-25 well program to be conducted at El Valle over the next 24 months. Crown Point is planning to drill two to four more wells at El Valle prior to year end. At Canadon Ramirez the Company plans to drill 2-5 wells on its 100% interest exploitation concession over the next 12 months and one 50% interest well at Laguna de Piedra in the first or second quarter of 2012. At Cerro Los Leones Crown Point anticipates receiving the required environmental permits in the near term and plans to commence the shooting of the 3-D and 2-D programs shortly after receiving these permits. The completion and interpretation of the seismic program is expected to be followed by a 2-5 well 50% interest program in 2012.

Oil & Gas Post

Promote Your Page Too

Chesapeake to Start Deducting Some Costs from Royalty Checks

- Chesapeake to Start Deducting Some Costs from Royalty Checks

Thursday, August 11, 2011
Fort Worth Star-Telegram, Texas
by Jack Z. Smith

About 20,000 royalty owners who have Barnett Shale natural gas leases with Chesapeake Energy will likely see their royalty checks slashed by roughly 25 percent after the company deducts expenses associated with post-production, such as gas gathering, compression and transportation.

The actual percentage and dollar amount decreases in royalty checks will vary monthly based on natural gas prices, post-production costs and output from wells.

Affected royalty owners were notified of the new company policy in recent letters. The changes took effect with July royalty checks that were based on May production, according to Julie Wilson, Chesapeake vice president for urban development and the top executive in its Fort Worth regional office.

Chesapeake is the No. 2 producer in the natural gas-rich Barnett Shale, which underlies more than 20 North Texas counties.

Henry Hood, senior vice president and general counsel for Oklahoma City-based Chesapeake, said post-production costs run from 70 cents to $1 per 1,000 cubic feet of gas produced. Natural gas prices have recently been around $4 per 1,000 cubic feet.

At that price, royalty checks will be "about 25 percent lower," Hood said.

Wilson said about 75 percent of Barnett Shale royalty owners with Chesapeake leases received letters advising them of the change.

The royalty owners whose monthly checks won't be affected are those who have lease provisions precluding assessments for post-production costs, Hood said.

As a general rule, large property owners who hired attorneys to help them negotiate leases and residents who are members of neighborhood associations that negotiated carefully crafted leases appear much more likely to have provisions precluding those charges.

Roger Venables, assistant director of community development and planning for the city of Arlington, said it has lease provisions barring Chesapeake from assessing post-production costs.

Representatives for the city of Fort Worth, Tarrant County and Dallas/Fort Worth Airport were not immediately able to confirm late Wednesday whether they have such provisions.

Hood said Chesapeake did an exhaustive internal audit of all its Barnett Shale leases to determine which could be assessed the post-production costs.

The audit took about six months, he said.

The post-production costs are routinely assessed against royalty owners in Texas unless lease provisions prohibit it, he said.

Chesapeake said in its letter to royalty owners that they will not be retroactively assessed any charges for post-production costs that the company incurred before its policy change.

"Please be assured that we do not intend to recoup these charges on past production," the letter said. "However, effective with the July 2011 check, your payments will reflect those charges going forward."

Both in its letters to royalty owners and in an explanation of the new policy on its website, Chesapeake did not provide specific information about how much royalty owners' checks might be reduced as a result of the new policy.

Hood said the company's decision to begin assessing royalty owners for post-production costs was triggered by its agreement with Total, the French oil giant, which paid $2.25 billion for a 25 percent interest in Chesapeake's Barnett Shale operations.

Total was about to begin deducting post-production costs from royalty owners' checks based on its share of the Chesapeake wells' production, so Chesapeake also decided to begin assessing for the costs, Hood said.

Otherwise, payment to royalty owners would have required two separate checks, and "it didn't make any sense to have two different checks from two different companies," Hood said.

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

Oil & Gas Post

Promote Your Page Too

El Paso Names E&P Spinoff

- El Paso Names E&P Spinoff

Thursday, August 11, 2011
El Paso Corp.

El Paso Corporation announced that it has taken important steps related to the planned spinoff of its E&P business before year-end 2011. On Thursday, El Paso filed its initial Form 10 with the U.S. Securities and Exchange Commission. This filing provides information about the spinoff and provides a detailed look at all aspects of the E&P business.

El Paso also announced that the new company will be named EP Energy Corporation, and it will be listed on the NASDAQ stock exchange under the ticker symbol EPE.

"We're excited about the creation of two outstanding publicly traded companies through the spinoff of our E&P business," said Doug Foshee, chairman, president, and chief executive officer of El Paso Corporation. "We are also excited about the new name for our E&P company -- EP Energy. The new name leverages the equity we have built in the El Paso brand, and it speaks directly to what our E&P business does so well: finding and producing oil and natural gas."

Brent Smolik, who will become president and chief executive officer of EP Energy, said, "While our name will change, many things will not, including the fundamental pillars of our E&P strategy. We have more than 10 years of drilling inventory that we expect will deliver significant growth in oil and condensate revenues. We will continue to focus on maintaining a significant drilling inventory of repeatable programs, being a leader in safe and responsible energy development, and driving high-end performance across our operations."

Leadership and Governance "El Paso Corporation and EP Energy will move forward with two outstanding boards," added Foshee. "By populating each board from the existing El Paso board, we take advantage of a history of good governance; we ensure each board has seasoned, knowledgeable members, and we maintain continuity for our shareholders."

The boards of directors expected to be in place for El Paso Corporation and EP Energy upon completion of the planned spinoff are shown below.

El Paso Corporation Douglas L. Foshee - Chairman J. Michael Talbert - Lead Director Juan Carlos Braniff Anthony W. Hall, Jr. Thomas R. Hix Ferrell P. McClean Timothy J. Probert Robert F. Vagt John L. Whitmire

EP Energy Corporation Douglas L. Foshee - Non-executive Chairman

David W. Crane Robert W. Goldman Ferrell P. McClean Steven J. Shapiro Brent J. Smolik Robert F. Vagt

Oil & Gas Post

Promote Your Page Too

Shale Plays, Foreign Investments Drive U.S. Oil & Gas M&A Value

- Shale Plays, Foreign Investments Drive U.S. Oil & Gas M&A Value

Thursday, August 11, 2011

Ongoing interest in shale acreage, deals for midstream assets and increased investments from foreign buyers in the U.S. oil and gas industry helped drive U.S. oil and gas mergers and acquisitions (M&A) value to $39 billion in the second quarter of 2011, according to PwC US.

In the second quarter of 2011, there were 51 deals with values greater than $50 million, compared to 61 announced deals totaling $41 billion in the same period last year. While the volume and value of transactions dipped slightly in the second quarter of 2011 when compared to the same period last year, average deal value for deals over $50 million jumped to $765 million in the second quarter 2011, a 14 percent increase over the same period last year when average deal value was $672 million.

"There continues to be steady M&A activity in the oil and gas sector with strong competition for prized assets, which has maintained the deal momentum throughout the first half of the year. The second half of the year has already kicked off with one mega deal announced, and we expect that deal momentum to continue," said Rick Roberge, principal in PwC's energy M&A practice. "Foreign and private equity interest in North American oil and gas assets remains very high and will likely be a driver of ongoing activity."

Foreign buyers announced 18 deals valued at over $50 million or more in the second quarter of 2011, which contributed $36.2 billion or 72 percent of total deal value, versus 27 deals valued at $24.2 billion in the same period last year.

For deals valued at over $50 million, there were 11 midstream deals that accounted for $19.9 billion, or 51 percent of total deal value, compared to six deals worth $3.4 billion in the same period last year. Transactions in the upstream space led all oil and gas subsectors with 26 deals, or 51 percent of volume in the second quarter.

According to PwC, seven of the top 10 deals by value in the second quarter of 2011 were related to shale plays, including four upstream deals and three transactions in the midstream and oil field services space. For all deals greater than $50 million, there were 10 shale-related transactions totaling $7.5 billion, or 19 percent of total deal value, including two deals involving the Marcellus Shale totaling $2.3 billion.

"Shale-gas assets continue to be very attractive acquisition targets as multinationals look to gain technical know-how and exploit the long-term value and opportunities from rising energy needs," said Steve Haffner, a Pittsburgh-based partner with PwC's energy practice. "At the same time, there is tremendous activity developing around natural gas infrastructure, which is necessary to move the extracted gas to market. The U.S. 'shale gale' continues to attract the attention of global companies."

There were five financial sponsor-backed transactions over $50 million, representing $6.1 billion, or 16 percent of total deal value, compared to 10 financial sponsor deals contributing $6.2 billion during the same period last year. During the first six months of 2011, there were 16 financial sponsor deals contributing $20.6 billion, a whopping 129 percent increase in deal value, compared to the first half of 2010 when there were 15 financial sponsor-backed deals, valued at $9.0 billion.

"With oil prices hovering at $100, private equity funds continue to make a very strong push in the oil and gas sector," added Roberge. "The private equity deal makers, who used to largely play in the midstream space, are now heavily involved in exploration and production (E&P), shale plays, and oil field services and equipment sector. However, along with the great opportunities and rewards of investing in oil and gas, there is still risk in this space – and new entrants need to understand the pitfalls before trying to exploit these possible opportunities."

For deals with values greater than $50 million, there were 18 corporate transactions totaling $26.8 billion or 69 percent of total second quarter deal value, compared to 22 deals that accounted for $25.9 billion in deal value in the same period last year. Thirty-three asset deals for a combined total of $12.2 billion were announced in the second quarter of 2011, versus 39 deals totaling $15.1 billion in the same period last year. However, when comparing the first six months of 2011 to the first half of 2010, the number of corporate transactions increased by three deals to 35 transactions, while total corporate deal value jumped 26 percent to $59.7 billion in 2011 from $47.6 billion in 2010.

Another potential driver for M&A activity is the desire from some oil companies to sell assets and break apart key lines of business, according to PwC.

"We believe that another factor to keep a close eye on throughout the year, which may add to the already robust M&A activity we're seeing, is the trend of integrated oil companies looking at the various options to unlock shareholder value through separating their E&P businesses," said Roberge. "While this trend could be a very positive driver of M&A activity, these are highly complex transactions with potential consequences around tax considerations, valuations and financial reporting. Companies should consider the risk with these types of transactions as every potential scenario needs to be thoroughly and diligently evaluated to succeed."

PwC's Oil & Gas M&A analysis is a quarterly report of announced U.S. transactions with value greater than $50 million analyzed by PwC using transaction data from John S. Herold, Inc.

Oil & Gas Post

Promote Your Page Too

Gas Damage Recovery Fund Proposal Premature, Official Says

- Gas Damage Recovery Fund Proposal Premature, Official Says

Thursday, August 11, 2011
Rigzone Staff
by Karen Boman

A bill proposed by New York Comptroller Thomas P. DiNapoli to establish an energy industry-supported fund to cover damages caused by natural gas production seems premature since the Department of Environmental Conservation (DEC) has not completed work on the state's new permit requirements, said Brad Gill, executive director of the Independent Oil & Gas Association of New York.

"The proposal does not take into account existing permit requirements, which address bonding for site reclamation, and it does not acknowledge existing environmental, criminal and civil law, which holds businesses accountable on many levels," Gill said, noting that the state's new permit requirements would likely be the strictest in the nation.

"The industry's outstanding record of environmental protection in New York should give the public the assurance that we operate with the best interests of the environment in mind," said Gill. "There is simply no basis for such a fund at this time."

DiNapoli on Aug. 9 proposed Comptroller's Program Bill #20 to remediate contamination related to gas production; the proposed legislation would apply to current drilling operations as well as to proposed high-volume hydraulic fracturing.

"Preventing accidents and contamination should always be our first priority," said DiNapoli. "If an accident does occur, the State needs to be ready with a rapid response and a reliable mechanism to hold polluters responsible. New Yorkers should not have to bear the burden from contaminations that damage their air, water and property. Whatever final decisions are made regarding high-volume hydraulic fracturing, this program and new fund will provide the necessary resources to respond to any accidents."

DiNapoli's program is modeled after the New York State Environmental Protection and Spill Compensation Fund (Oil Spill Fund), which draws on the expertise and collaborative efforts of the DEC, the Office of the Attorney General and the Office of the State Comptroller.

Under the program, strict liability would be imposed on owners or operators of drilling sites that cause contamination. The DEC would be empowered to order immediate clean-up by owner or operator or take over sites for immediate clean-up, or would impose a surcharge on drilling permits to create the Natural Gas Damage Recovery Fund similar to structure to the existing Oil Spill Fund.

Oil and gas companies also would be required to post surety bonds to cover any shortfall between fund resources and remediation costs. Additionally, the program would create for the first time an online registry of all gas drilling related incidents in New York State.

The Natural Gas Damage Recovery Fund would pay for any remediation of contamination undertaken by DEC where a responsible party could not be identified, responsible parties refused or responsible parties were unable to pay for needed remediation, according to a statement from the comptroller's office.

The Office of the Attorney General would determine who is legally responsible for the contamination and, if necessary, commence civil damage-recovery litigation against responsible parties. Any recovered funds would be returned to the Natural Gas Damage Recovery Fund to cover cleanup of future contaminations.

DEC on July 1 released its revised recommendations on high-volume hydraulic fracturing, including the prohibition of high-volume fracturing in New York City and the Syracuse watersheds, including a buffer zone. DEC also is recommending the prohibition of drilling within primary aquifers and within 500 feet of their boundaries. Additionally, surface drilling also would be prohibited on state-owned land including parks, forest areas and wildlife management areas.

Previous recommendations had permitted drilling in the New York and Syracuse watersheds, as well as in primary aquifers and forest areas. DEC said the new recommendations would protect the state's environmentally sensitive areas while realizing the economic development and energy benefits of the state's gas resources, and that approximately 85 percent of the state's Marcellus shale resources would be accessible to gas extraction under these recommendations.

DEC plans to hold a 60-day public comment period on the recommendations beginning this month.

Oil & Gas Post

Promote Your Page Too

UK O&G Industry Successfully Tests Emergency Spill Response Equipment

- UK O&G Industry Successfully Tests Emergency Spill Response Equipment

Thursday, August 11, 2011

The UK oil and gas industry has successfully tested its ability to deploy a well capping device in the waters west of Shetland. As part of the industry's commitment to further strengthen the UK's emergency response capabilities, the Oil Spill Prevention and Response Advisory Group (OSPRAG) has undertaken a number of initiatives to improve well engineering and oil spill response capability, including the development of a well capping device for use in UK waters to seal-off an uncontrolled subsea oil well in the unlikely event of a major well control incident.

The purpose of the recent Emergency Equipment Response Deployment (EERD) exercise was to simulate the logistical process of transporting a well capping device, loading it on to a vessel and lowering it over the side before fixing it to a specially-built simulated well on the sea floor.

The exercise was project-managed and executed by Total E&P UK on behalf of Oil & Gas UK and ran from July 16-26, 2011 at a site in block 206/4, around 75km north west of Shetland.

The various stages of the exercise included:
  • Exercise site prepared by deploying a specially-built landing base to the seafloor at a depth of 300 meters to accurately simulate a subsea well.
  • Remotely operated vehicles (ROVs) used to deploy subsea oil dispersant (in this instance, a non-toxic fluorescent dye).
  • Heavy-duty cutting shears deployed to sever a subsea marine riser pipe. This would be done in a real-life scenario in order to clear the riser out of the way to make room for the cap to be landed.
  • Capping device deployed over the side of a multi-service vessel using a crane.
  • Device landed on to the well, locked on to the base and activated using ROVs.
  • All equipment, including the landing base, recovered.

Oil & Gas UK's chief executive, Malcolm Webb, said, "The UK oil and gas industry has a very high level of confidence in its ability to prevent blowouts. We haven't experienced one here in over 20 years – in which time over 7,000 wells have been drilled.

"No matter how unlikely a blowout is, we recognize the importance of being prepared for low-probability, worst-case scenarios. This is why we regularly test our emergency response capabilities and why we wanted this particular exercise to be as realistic as possible.

"Its success proves we can not only quickly mobilize and deploy the capping device, but also incorporate the use of a wide variety of other related equipment, such as subsea dispersant and cutting shears, which in a real-life situation would be used as part of the same operation.

"The next stage will involve a full debrief involving all participants to identify any learning opportunities and Oil & Gas UK will share these findings throughout the industry."

Oil & Gas Post

Promote Your Page Too

BP Readies for Major North Sea Projects

- BP Readies for Major North Sea Projects

Thursday, August 11, 2011
The Herald
by Mark Williamson

The head of BP's North Sea business said the oil and gas giant expects to approve three more huge projects off Scotland this year despite the Budget's tax hike.

Trevor Garlick said BP expects to proceed with projects involving an outlay of billions of dollars within months, subject to winning Government approval.

The plans represent a huge vote of confidence in the mature province by BP, which expects to recruit hundreds of skilled staff to keep pace with increased activity in the North Sea.

Last month the firm confirmed it would proceed with the pound(s) 3 billion redevelopment of the giant Schiehallion field west of Shetland with partners. The field contains much more oil than originally expected.

The projects that Mr. Garlick expects to confirm include a plan to develop a new area of the huge Clair field west of Shetland. This could be on the same scale as the Schiehallion project.

BP expects to invest around $1B (pound(s) 610MM) each in developments on the Kinnoull oil field and the Devenick gas field, in the Central and Northern North Sea respectively.

Mr. Garlick said the oil and gas firms partnering BP on each of the schemes have given their approval, although final agreements have not been written. He believes there could be plenty of money to be made in the North Sea for years.

"People are ill-informed when they talk about this area being over," said Mr. Garlick, noting that there could be billions of barrels oil equivalent still to be recovered.

Mr. Garlick said BP could make big returns by boosting recovery rates on its extensive acreage and making the most of the huge network of production facilities it has in the North Sea. His responsibilities include the Norwegian North Sea.

Advances in technology, combined with the increase in oil prices in the last two years, have transformed the economics of some fields.

Mr. Garlick discounted the effect of the recent fall in crude prices, saying BP made decisions based on long-term expectations.

"Most predict supply and demand will keep the price reasonably high," he said.

Noting that the tax regime can have a big influence on investment decisions, Mr. Garlick said the changes in North Sea taxes in the Budget were unhelpful.

The 12 percentage point increase in tax rates will reduce returns from all projects. "Some of the fields that we are looking at will be even more marginal, a couple look more difficult," he said. But BP has not scrapped any projects as a result of the tax increase.

Mr. Garlick said BP is investing at record rates in the North Sea. The company is recruiting to help it grow. It plans to hire around 300 skilled workers this year for the North Sea business and the same again in 2012.

Some 3500 BP and agency staff work on its North Sea operations currently. BP's proposals will boost the Government's claims that the tax increase is likely to have only a marginal impact on investment in the province.

The industry body Oil & Gas UK has warned that the hike could threaten billions of pounds of investment in the North Sea.

It said concessions granted by the Government last month, intended to encourage investment, did not go far enough.

However, Mr. Garlick, a board member of Oil and Gas UK, said the industry wants limited changes. He said Oil and Gas UK is lobbying for stability in the fiscal regime. It wants further allowances for difficult fields and predictability about costs of decommissioning assets.

Copyright (c) 2011 The Herald. via ProQuest Information and Learning Company; All Rights Reserved

Oil & Gas Post

Promote Your Page Too

Completion Operations Underway at Breitling-Turner Well

- Completion Operations Underway at Breitling-Turner Well

Thursday, August 11, 2011
Breitling O&G Corp.

Breitling announced that the Breitling-Turner #2 in Hardeman County, Texas is being completed as a possible oil and gas producer after reaching a total vertical depth of 7,900 feet.

The well was subsequently logged by Halliburton and based on analysis by Breitling's engineers and geologists as well as Halliburton's analysis of the Turner #2 logs. Chris Faulkner, CEO of Breitling Oil and Gas, said, "As expected, this well has some great-looking zones that are similar to what we saw in the Breitling-Turner #1 producing well that we drilled 90 days back."

Oil & Gas Post

Promote Your Page Too

Chevron Subsidiary Spuds Well in Agbami Field

- Chevron Subsidiary Spuds Well in Agbami Field

Thursday, August 11, 2011
Pacific Drilling S.A.

Pacific Drilling announced that its ultra-deepwater drillship the Pacific Bora commenced operations at the Agbami Field in Nigeria on August 10, 2011. The rig is contracted for three years to a wholly owned Chevron subsidiary.

The Pacific Bora is capable of operating in water depths of up to 10,000 feet and drilling wells 37,500 feet deep.

Oil & Gas Post

Promote Your Page Too

Imperial Commences Drilling Ops at Green Tide SWDF

- Imperial Commences Drilling Ops at Green Tide SWDF

Thursday, August 11, 2011
Imperial Resources Inc.

Imperial announced that, further to its announcement of rig arrival on August 9, 2011, the drilling rig to deepen the disposal well at the Company's Green Tide Salt Water Disposal Facility ("SWDF") is expected to commence drilling operations, slightly earlier than expected, Thursday, August 11, 2011.

The rig is expected to set a whipstock and sidetrack the well to TD over the next 10 days. The aim is to deepen the Green Tide SWDF well from 3,100 to 8,500 feet to establish the well around 500 feet to 600 feet into the Ellenburger formation. Casing will then be cemented from 500 feet into the Ellenberger to approximately 1,000 feet back up the hole and the well then drilled ahead to ideally create about 2,000 feet of open hole exposure in the Ellenburger so as to maximize disposal capacity.

Subject to success, commercial disposal operations are expected to commence immediately targeting full disposal capacity of 15,000 barrels per day as quickly as possible. At full capacity, the Company believes the Green Tide SWDF has the potential to generate significant cash flow at relatively low operating costs.

The Green Tide SWDF

The Green Tide SWDF is conveniently located for the disposal of large volumes of salt water generated from essential fracture stimulation operations on Barnett Shale gas wells. There are approximately 6,000 such Barnett wells within 20 miles of the SWDF.

Imperial plans to reopen Green Tide to dispose of up to 15,000 barrels of salt water a day. The Company's acquisition and development of the low run-time Green Tide assets and disposal permit is expected to save in excess of $5,000,000, compared to a new build cost.

Green Tide is one of two key projects identified as transformational for Imperial (the other being the Company's Oklahoma project).

Oil & Gas Post

Promote Your Page Too

Aurora Drills Ahead at Tx. Alwan West Prospect

- Aurora Drills Ahead at Tx. Alwan West Prospect

Thursday, August 11, 2011
Victory Energy Corp.

Victory, through its partnership with Aurora Energy Partners, announced that its Alwan West (#1 Goff Mineral Trust) prospect well was spud on August 2, 2011 and is currently drilling ahead at 5,097 feet.

Prior to reaching the proposed target depth of 7,100 feet, all three target sands (first Yegua, Frio and second Yegua) will be tested. All three sands are anticipated to be reached and tested in the coming days. These sands do not require a fracking procedure to be productive. Anticipated completion after a successful testing generally occurs in less than two weeks.

The lease area is surrounded on all sides by gas condensate production and a delivery pipeline is within 1,000 feet of the well.

Alwan West lies on strike between two Yegua fields, Lost Fork (one mile west) and AVO Grande (3,000 feet east). Lost Fork has produced over 42 BCF, while AVO Grande has produced 7 BCF of natural gas. Both of these fields are stratigraphic traps, as is the Alwan West prospect. This area produces from the Frio and Yegua (Oligocene) formations.

This prospect's potential reservoir covers an area of 175 acres and has a reserve potential of 8.5 billion cubic feet (BCF) of natural gas and 43.75 thousand barrels of gas condensate.

The reserve potential is based on 50 feet of reservoir sand, one million cubic feet per acre-foot of natural gas and five barrels per million cubic feet of gas condensate. These reserve estimates are for the first Yegua sand only, which is the primary objective, and do not include potential in the secondary objectives.

The Alwan West prospect is located in far western Wharton County, Texas, near the Jackson County line. Victory Energy acquired the prospect, which includes a 5 percent working interest (WI) and a 3.8 percent net revenue interest (NRI), from Miramar Petroleum, Inc. of Corpus Christi, Texas, who will be the operator and who also owns a significant working interest in the well.

Oil & Gas Post

Promote Your Page Too

OGX Intensifies Appraisal Campaign; Posts 2Q Loss

- OGX Intensifies Appraisal Campaign; Posts 2Q Loss

Thursday, August 11, 2011

OGX announced its results for the second quarter of 2011. The financial and operating data is presented on a consolidated basis in accordance with the international financial reporting standards (IFRS) issued by the International Accounting Standards Board (IASB), and in Reais, except where otherwise indicated.

"We remain focused on executing our business plan, which has advanced significantly as we have intensified our appraisal campaign and performed additional drill-stem tests, all of which are essential in converting our resources into reserves. With the recent bond issuance as well as the significant progress made in the past three months, we are not only technically but financially prepared to proceed towards production," commented Mr. Paulo Mendonça, General Executive Officer and Exploration Officer for OGX.

From the perspective of our drilling campaign, highlights of the second quarter include the drilling of 11 appraisal wells in the Campos Basin and 2 in the Parnaíba Basin, two successful drill-stem tests performed in horizontal wells in the Campos Basin and the declaration of commerciality for two fields in the Parnaíba basin, confirming our projections and attesting to the excellent execution of our business plan. In addition, we drilled wildcat wells that continue to demonstrate the great potential of our portfolio.

With respect to the commencement of production, important steps have been achieved in the past three months including the arrival of the newly built vessel Aker Wayfarer which will be used throughout the system installation, as well as the final stage of commissioning for the FPSO OSX -1. In addition, the construction of the turret, a disconnectable buoy which is part of the OSX-1 mooring system, has been completed and is already in the mobilization process to Brazil.

Second Quarter Highlights and Subsequent Events:
  • Intensification of the appraisal campaign in Waimea (OGX-50D, OGX-53D and OGX-55HP), Waikiki (OGX-41D, OGX-44HP and OGX-45D), Pipeline (OGX-39HP, OGX-40D, OGX-42D and OGX-48D), Illimani (OGX-43D) and Fuji (OGX-54D and OGX-56D) accumulations located in the Campos Basin;
  • Declaration of commerciality for the California and Fazenda São José accumulations in the Parnaíba Basin, for which the newly designations are Gavião Azul and Gavião Real Fields;
  • Performance of drill-stem test for the first horizontal well (OGX-44HP) in the Waikiki accumulation, with excellent results;
  • Important discoveries in the Parnaíba basin through the drilling of wells OGX-38 and OGX-46D;
  • Significant discoveries in the Santos basin through the drilling of wells OGX-30 and OGX-47;
  • Performance of a drill-stem test for the first horizontal well (OGX-39HP) in the Pipeline accumulation with very good results;
  • Initiated drilling of well OGX-55HP, the second horizontal well in the Waimea accumulation;
  • Raised US $2.563 billion through a bond issuance; and
  • Announcement of the Company's business plan for discoveries in the Campos and Parnaíba Basins.

Campos Basin

Among the activities performed in the second quarter of 2011 in Campos Basin we can highlight the intensification of the successful appraisal campaign, the results of drill-stem tests in Waikiki and Pipeline accumulations, the drilling of wildcat wells, and the arrival and preparation of equipment for the start-up of production. On June 6, we formally announced our business plan relating to discoveries made in the basin.

During the quarter we intensified our appraisal campaign in the Waimea, Waikiki, Pipeline, Illimani and Fuji accumulations. In Waimea, we concluded the drilling of well OGX-50D encountering a hydrocarbon zone with 52 meters of net pay in the Albian section. In addition, we initiated the drilling of wells OGX-53D and OGX-55HP, which are still ongoing. In the Waikiki accumulation, we have concluded the OGX-41D, OGX-44HP and OGX-45D wells. The directional well OGX-41D found a net pay of 92 meters in the Albian section and was the pilot well for OGX-44HP, which was horizontally drilled for more than 1,000 meters in Albian-Cenomanian reservoirs. The well OGX-45D, which was intended to test the limits of the Waikiki accumulation, discovered hydrocarbons only in the Maastrichtian section, indicating an additional potential in sandstone reservoirs which extend towards the Ingá-Peró Complex. In the Pipeline accumulation, wells OGX-39HP, OGX-40D, OGX-42D and OGX-48 were drilled, identifying the presence of hydrocarbons in the Albian section with net pays of more than 1,000 (horizontal column), 107, 82 and 12 meters, respectively. In the Illimani accumulation, we have concluded well OGX-43D which confirmed the extent of the reservoirs in the Albian section and identified a net pay of 50 meters. Finally, we began the drilling of wells OGX-54D and OGX-56D in the Fuji accumulation, both of which are still in progress.

Additionally, we obtained the results of the drill-stem tests in horizontal wells OGX-39HP and OGX-44HP in the Pipeline and Waikiki accumulations, respectively. The test in well OGX-39HP, which is the first horizontal well in the Pipeline accumulation, indicated good reservoir conditions, implying a production capacity of around 10,000 barrels per day and oil of approximately 19° API. The test in well OGX-44HP identified oil of approximately 23° API and a production potential of 40,000 barrels per day, which will be limited to a flow rate of 15,000 to 20,000 barrels per day per well to optimize oil recovery from the reservoir.

Continuing with our wildcat drilling campaign, well OGX-33 was drilled in the Chimborazo accumulation and identified a net pay of 42 meters in the Albian section. We have also drilled well OGX-52 in the Tambora accumulation, which has identified a net pay of 96 meters in the Albian section and we have initiated OGX-58DP well also in this accumulation that is still ongoing.

The commencement of OGX's production is scheduled for October/November this year in the Campos Basin. The first project in the Waimea Complex will take place through an Extended Well Test (EWT) and will have an anticipated production of up to 20,000 barrels per day from well OGX-26HP.

All of the critical equipment for the start-up of production has been secured. The wet christmas tree and the electric submersible pumping system are already installed and other equipment such as flexible lines, moorings and piles (which are part of the FPSO mooring system) and the installation vessel have already been delivered. The FPSO OSX-1 is ready in the shipyard in Singapore and the turret (a buoy, part of the mooring system) is in the mobilization process to Brazil.

Parnaíba Basin

During this quarter, we made important discoveries in this basin and presented to the ANP declarations of commerciality for the Gavião Azul and Gavião Real fields. The development plans for these fields have already been submitted by OGX, who are still in the process of analyzing them.

We concluded the drilling of four wells, including two wildcat wells, OGX-34 and OGX-46D, and two appraisal wells, OGX-38 and OGX-51DP, which identified net pays of 23, 15, 43 and 8 meters, respectively, in the Devonian section. We also started the drilling of wildcat well, OGX-49, and appraisal well, OGX-57, which are still in progress.

Following the seismic campaign in this basin, we engaged a second seismic team during the quarter to focus on the southern blocks, while the first team remains focused on seismic in the northern blocks.

The Gavião Azul and Gavião Real fields will be the first natural gas fields developed by OGX. We expect that gas production in this basin will start in the second half of 2012, as announced in our business plan for the discoveries made in this basin. We estimate that these fields will reach a production level of 5.7 million m3/day in 2013, which corresponds to total production of 1.1 Tcf of gas. Natural gas produced in the region is expected to be the supply source for thermoelectric power plants to be built by MPX Energia SA, an EBX Group company, in association with Petra Energia SA, both of which are partners with OGX in this basin.

MPX has entered into a term sheet with Bertin Energia e Participações to acquire two projects, which are still awaiting ANEEL's approval, that have the authorization for the construction of thermoelectric power plants with a total capacity of 660 MW. MPX intends to transfer these licenses acquired in the A-5 auction in 2008 to the Parnaíba Thermoelectric Complex, where it already has a prior installation license to implement 3,722 MW. This acquisition represents an important step in the integration of natural gas production provided by OGX Maranhão, to power generation in the Parnaíba Basin.

We have recently approved the leasing agreement of two additional onshore drilling rigs for the production development plan in Parnaíba Basin.

Santos Basin

In the second quarter of 2011, we continued our exploratory campaign and achieved important results testing classic targets and new geological models. We have concluded the drilling of well OGX-30, which confirmed a new play in fractured carbonates in the Albian age, showing a significant gas column and a large structured area. This discovery enabled us to confirm this new geological model for the region so that we can begin the appraisal campaign.

The recent discovery in sandstones in the Santonian age in well OGX-47, in the Maceió accumulation, contributed significantly to the development of our assets in this region and, when combined with the discoveries already made in the basin, will generate greater economies of scale and cost-effectiveness. We intend to focus on the appraisal campaign and proceed with the development of the production model for the region.

OGX currently has nine rigs at its disposal, including six semi-submersible rigs, two onshore rigs and one jack-up for drilling in the Campos, Santos, Parnaíba and Pará-Maranhão basins. Eight rigs are in operation and one is currently being mobilized.

Oil & Gas Post

Promote Your Page Too

Kosmos to Boost Jubilee Production, Exploration Targets

- Kosmos to Boost Jubilee Production, Exploration Targets

Thursday, August 11, 2011
Kosmos Energy Ltd.

Kosmos announced financial and operating results for the second quarter ended June 30, 2011. The Company generated a net loss of $9.1 million in the second quarter of 2011, or $0.03 pro forma basic and diluted net loss per share attributable to common shareholders. This compares with a net loss of $32.5 million for the same period in 2010.

Second-quarter 2011 oil revenues were $124.1 million on sales of 996 thousand barrels of oil, or $124.62 per barrel. Jubilee Field average production for the quarter was approximately 66 thousand barrels of oil per day (bopd) gross. EBITDAX was $102.5 million for the second quarter of 2011, compared with $9.7 million for the second quarter of 2010.

The Company's cash on hand at the end of the second quarter grew to $818 million. Total liquidity, including cash and available borrowing under the existing debt facility was nearly $1 billion.

"Kosmos' recent initial public offering enhanced our strong financial foundation and provided additional capacity to continue accelerating the development and exploration of our assets. The commissioning of the Jubilee Field Phase 1 development is ongoing, with water and gas injection facilities now progressing well. We are seeing continued improvement in operating uptime, and field production is anticipated to further ramp up during the remainder of 2011. The Company's near-term outlook includes growing Jubilee production and a number of exploration and appraisal drilling targets. In addition, we are progressing our inventory of discoveries in Ghana, and our exploration team continues to enhance our overall portfolio with significant new areas," said Brian F. Maxted, President and Chief Executive Officer.

Operational Update


Current gross production at the Jubilee Field is approximately 80 thousand bopd. With final commissioning of process and injection facilities, completion of the remaining wells and the sidetrack of an existing well, the Company is targeting production reaching the FPSO capacity around year-end 2011. Planning for the next phase of Jubilee Field development is underway, and Kosmos expects implementation to commence during 2012.

The Atwood Hunter semi-submersible rig is currently drilling the Akasa-1 exploration well on the Kosmos-operated West Cape Three Points Block. The Akasa-1 well is expected to reach final target by the end of August 2011. In addition, the Company plans to further appraise the Teak discovery with an initial two-well program, commencing as early as late 2011.

Appraisal activity to support development planning continues on the adjacent Deepwater Tano Block. Drillstem tests were recently performed on the Tweneboa-2 and Tweneboa-4 wells as part of an integrated reservoir evaluation program. Kosmos also anticipates drilling two additional appraisal wells in the Enyenra Field later this year.


Kosmos continues to perform an extensive technical evaluation of the Kombe N'sepe Block following initial drilling results. The Kombe N'sepe Block operator recently has exercised a contractual right for a six-month extension to the current exploration phase. The Company anticipates drilling the Liwenyi prospect on the Kosmos-operated N'dian River Block in 2012.


The Company recently entered into two new petroleum agreements covering the Foum Assaka and Cap Boujdour areas offshore the Kingdom of Morocco. The Foum Assaka license covers approximately 1.6 million acres, and Kosmos will be the operator with a 37.5 percent working interest. The Cap Boujdour license agreement covers 7.3 million acres. Kosmos also will be the operator of the Cap Boujdour license with a 75 percent working interest.

Oil & Gas Post

Promote Your Page Too

Nautical Captures Kraken

- Nautical Captures Kraken

Thursday, August 11, 2011
Nautical Petroleum plc

Nautical announced that the Kraken 9/02b-5 pilot well, located in UKCS North Sea Block 9/2b, has successfully encountered oil in the Heimdal III sandstone interval.

The pilot well was drilled to a total depth of 4,785 feet Measured Depth (MD). The top of the target Heimdal III reservoir was encountered at 4,168 feet MD and the overall sand interval has a gross thickness of 145 feet. The well has exceeded predrill expectations, with a thicker net oil pay than expected. Preliminary log evaluation indicates a calculated net oil pay of 94 feet True Vertical Thickness (TVT), with average porosity of 38% and average oil saturation of 78%. As anticipated, an Oil Water Contact (OWC) was not encountered at this location.

The well was designed to target an area of strong amplitude anomalies interpreted on Coloured Inversion seismic data. The net oil pay encountered correlates with the seismic, providing increased confidence for using these seismic techniques for the selection of locations of development wells.

Following the successful completion of the pilot well, the co-venturers will now commence the drilling of a horizontal sidetrack of up to 600m, which will be completed with a gravel pack and tested using an Electric Submersible Pump (ESP). This activity is expected to take approximately 40 days in total, subject to weather and any operational downtime.

Nautical has a 50% interest in Block 9/2b and is the operator. The other participants are Celtic Oil Limited, a fully owned subsidiary of First Oil Expro Limited (30%) and Canamens Energy North Sea Limited (20%).

Steve Jenkins, Nautical's Chief Executive Officer, commented, "This is an excellent start to the appraisal activity. The well has encountered the thickest net pay in the field to date and has exceeded our pre-drill expectations. We now have five successful penetrations of the main reservoir in the core area of the field. We look forward to commencing the 9/02b-5Z sidetrack, which aims to prove a commercial flow rate on contingent resources of 83 MMbo, net to Nautical."

Oil & Gas Post

Promote Your Page Too