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Oil and Gas Energy News Update

Monday, August 29, 2011

Oil & Gas Post - All News Report for Monday, August 29, 2011

Monday, August 29, 2011

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GE Hitachi Nuclear Energy and Exelon Nuclear Sign Services Contract

- GE Hitachi Nuclear Energy and Exelon Nuclear Sign Services Contract

Aug 29, 2011

General Electric (NYSE:GE) Hitachi Nuclear Energy announced that it has been awarded a nearly $150 million integrated outage contract by Illinois-based Exelon Nuclear to help ensure the continued, safe performance of the utility's entire fleet of boiling water reactor nuclear power plants in Illinois, Pennsylvania and New Jersey.

The agreement is effective immediately and runs through completion of the spring outage season in 2015. Terms of the contract call for GEH to provide services for assisting with the refuel floor activities and performing the under-vessel and inspection services.

General Electric (NYSE:GE) has a potential upside of 41.8% based on a current price of $15.92 and an average consensus analyst price target of $22.58.

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IHS: Consolidation of Small E&P Cos Could Increase

- IHS: Consolidation of Small E&P Cos Could Increase

Monday, August 29, 2011

The uncertainty of future oil prices, combined with falling share prices on both London's Alternative Investment Market (AIM) Index and the Standard and Poor's (S&P) Index in the U.S., has made close to 100 small exploration and production (E&P) companies in the U.K. and two dozen large U.S. producers, prime targets for consolidation in order to achieve future funding, reports IHS in its IHS Herold Oil and Gas Perspectives Report.

"There are nearly 100 E&P companies listed on London's AIM, and while a number of these are small companies, numerous others have participated in apparently significant discoveries around the world that may turn into important oil and gas fields," said Robert Gillon, director of energy company research at IHS, and author of the weekly IHS Herold Oil and Gas Perspectives. "However, almost none of these AIM-listed E&Ps have reached the production stage, which means they are not yet generating revenue. Without revenue, they are dependent on future funding to continue operations. That funding can be accomplished either through additional share sales or a farm-out of an interest in their exploration licenses."

In addition to the AIM-listed companies, Gillon said there are about two dozen large (market cap $0.5 billion to $3.0 billion) U.S. oil and gas producers that could be ripe for consolidation as well. "Some of these U.S. companies are also reliant on external financing to fund their capital budgets, but all of them have developed reserves that could be sold in the very liquid transaction market."

Gillon said it is probably "not a coincidence" that the AIM-listed stocks peaked at about the same time as the Greek financial crisis, while the U.S. companies started to slide after oil prices topped out in April. On August 4, both indices took a serious hit, with the London group down 9.6 percent, while the S&P index shed 7.8 percent, and both have suffered further losses since then.

The AIM index is now down by 40 percent from its recent peak, which means the average company would need to sell almost 70 percent more new shares to raise the same amount of money as it did a few months ago. Meanwhile, optimism about future oil prices is more subdued, and the potential farm-in partners recognize that. As a result, they will demand more favorable terms on the deal. But commitments to the host government must be honored to hold the license.

"We believe there could be a wave of consolidation in the exploration sector," said Gillon. "Selling out will become the most attractive alternative."

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PetroQuest Cheers LA Gas Find

- PetroQuest Cheers LA Gas Find

Monday, August 29, 2011
JGC Corp.

JGC announced that a large gas column has been discovered in the first exploratory well in Louisiana, USA, in which JGC holds an interest through its wholly-owned American subsidiary JGC Energy Development (USA) Inc. (JEDI). JGC joined in the exploration of the assets in November of 2010.

The well is located in a marsh area to the south of Vermilion Parish , Louisiana. The well was drilled to a total depth of 19,079 ft., with the gas column extending for 248 ft. in total.

Through JEDI, JGC hold an 9.5% share in the assets. The operator of the assets is PetroQuest Energy, Inc. (USA).

The well is scheduled to start gas production in early 2012. During the first quarter of 2012, a delineation well will be drilled to further investigate the extent of the gas reservoir.

This discovery of gas follows JGC's acquisition of an interest in the Eagle Ford shale oil assets in Texas and can be seen as a major step in the advancement of JGC's E&P business, which the company plans to further expand by increasing oil and gas assets in the future.

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AWE Reports Net Loss

- AWE Reports Net Loss

Monday, August 29, 2011
AWE Ltd.

AWE Limited has announced a statutory net loss of $117.6 million for the 12 months to June 2011. After adjustment for significant one-off, the underlying loss was $16.1 million.

The Company's production assets performed strongly with production of 6.1 million BOE. This delivered a 61% increase in after tax net cash flow from operating activities of $140 million, which included exploration expense of $21 million.

Investment in growth activities continued during the year, with $32 million invested in the completion of the Adelphi takeover, $69 million in exploration activities and a further $80 million in project developments (primarily BassGas MLE and Sugarloaf drilling).

The Adelphi Energy takeover, completed during the year, provides AWE with access to an exciting gas and liquids development project in the US, which is delivering strong initial production performance. Reserve reporting to date at Sugarloaf has highlighted the growth potential of the asset, with 2P reserves increasing to 8.5 million BOE at June, 2011.

The Company reported a cash position of $117 million, at June 30, 2011 with an undrawn $150 million loan facility.

Commenting on the result, AWE's Managing Director Bruce Clement said, "The Company's core business continues to perform well as evidenced by the increased operating cashflow of $140 million for the year, reflecting the strength and diversity of AWE's portfolio of production assets.

"The statutory loss of $118 million was impacted by a number of significant one-off factors, primarily asset impairments and the derecognition of previously booked tax losses.

"The second half of 2010/11 has been a period of consolidation for AWE following an extended period of major exploration activity.

"The Company's focus has been on delivering its core production operations, exploiting its existing asset base and establishing its tight gas and shale gas business through the Sugarloaf acquisition and the Perth Basin exploration initiatives. The Company has also completed a comprehensive review of its core assets.

"Looking forward, AWE has a strong balance sheet, robust future cash flow from its 66 million BOE 2P reserve base and significant potential in its Perth Basin gas exploration assets with access to premium domestic markets.

"The Company's near term plans will focus on continuing the strong performance of the base business, exploiting its tight gas and shale gas projects and pursuing selective growth opportunities.

"The Board and Management of AWE are confident about the Company's future. AWE is well positioned to build on its existing assets and to take advantage of opportunities in the current volatile business environment."


Operating cashflow was strong for the year, rising 61% to $140 million. The reported cashflow included exploration expense of $21 million and significant Tui and Cliff Head workover costs of $29 million.

The year-end financial position of the Company was strong, with cash of $117 million and no debt (and with a $150 million undrawn corporate debt facility available if required).

AWE's sales revenue fell 14% to $305 million for the year, with net field contributions also lower at $172 million. Total oil and gas sales volumes were in line with the prior year, although oil production was down by 36%, offset by increased gas and associated gas liquids sales over the period. Average received oil prices improved to approximately $91 per barrel, as a result in the stronger international prices partially offset by the stronger A$.

In accordance with AWE's successful efforts accounting policy, $63 million of exploration costs were expensed during the year. These costs were largely related to unsuccessful drilling activity in New Zealand, Yemen and Australia.

A net exploration impairment charge of $61 million (post tax) impacted the statutory results. This impairment included the write down of the Yemen and Bass Basin exploration assets acquired as part of the ARC Energy merger in 2008. In addition, a post-tax net oil and gas asset impairment of $15 million was also recorded (largely related to the Cliff Head project).

Subsequent to the end of the year, AWE sold its shareholding in Buru Energy Limited for a cash consideration of $17 million. These funds were received after year end and are not included in the reported results.


Exploration expenditure for the year was primarily incurred on the conventional oil and gas exploration opportunities in Australia, New Zealand and Yemen.

In the latter part of year, AWE accelerated activities in tight gas and shale gas exploration in the onshore Perth Basin, where drilling of the Arrowsmith-2 well has been completed and hydraulic stimulations are being planned. Timing of the hydraulic stimulation activity is subject to the receipt of all regulatory approvals.

AWE continues to pursue further conventional and unconventional exploration opportunities, applying an added degree of financial and technical discipline.


The Adelphi takeover was completed during the year, and development drilling activity in its USA operations has accelerated since the acquisition was finalised. An independent reserve statement was released in March 2011, which reported a 37% improvement (to 8.6 million BOE net to AWE) in existing 2P reserves in the Sugarloaf AMI. Further drilling activity is expected to see added conversion of possible reserves into the 2P reserves category during 2011/12.

The $346 million gross budget for first phase of the Yolla MLE project was approved during the year and significant progress has been made with the onshore fabrication of gas compression and accommodation modules and preparations for offshore installation at the end of 2011. An extended production shutdown is planned during the offshore installation activities (December to April).

The second phase of the development will incorporate the drilling of at least two additional development wells on the Yolla field and remains on schedule for late 2012/early 2013. Engineering planning, including the evaluation of additional upside potential in the field, is continuing with budget commitment expected by end 2011. Total expenditure to June 30, 2011 on the MLE project was $107 million.

Production well workovers were successfully completed on the Pateke and Cliff Head projects, with the Cliff Head-12 well workover increasing production from the Cliff Head field by over 1,500 bopd after coming on stream in August 2011.

2011-2012 guidance

Production guidance for the current financial year has been set at 5.0 to 5.5 million BOE, substantially impacted by the planned extended shutdown of the Yolla field for the offshore installation activities associated with the MLE project. Based on a A$100 per
barrel Brent oil price for the year, AWE expects oil and gas sales revenue to reach a range of $270 to $300 million. Planned exploration expenditure for the year is estimated at $50 million, with development expenditure planned to reach $150 million, the majority of which will be incurred on the BassGas MLE project.

With a net cash position of $117 million AWE is well positioned to further exploit those assets within the Company's existing portfolio and take advantage of opportunities to add to its asset base.

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Contango Spotlights Year-End Results

- Contango Spotlights Year-End Results

Monday, August 29, 2011
Contango O&G Corp.

Contango reported natural gas and oil sales from continuing operations for the fiscal year ended June 30, 2011 of approximately $203.8 million, compared to $159.0 million for the same period last year. The Company reported net income attributable to common stock for the year ended June 30, 2011 of approximately $65.0 million, or $4.15 per basic share and $4.14 per diluted share, which included approximately $1.6 million of income from discontinued operations, or $0.10 per basic and diluted share, related to the sale of our Conterra Company assets and the distribution of Contango ORE, Inc. This compares to net income attributable to common stock for the year ended June 30, 2010 of approximately $49.7 million, or $3.14 per basic and $3.08 per diluted share, which included a loss from discontinued operations of approximately $0.5 million, or $(0.03) per basic and diluted share.

For the three months ended June 30, 2011, natural gas and oil sales from continuing operations were approximately $48.9 million, up from $40.1 million for the three months ended June 30, 2010. Contango had net income attributable to common stock of approximately $17.5 million, or $1.12 per basic and diluted share, compared to net income attributable to common stock for the three months ended June 30, 2010 of approximately $15.4 million, or $0.97 per basic and $0.95 per diluted share.

For the remainder of fiscal year 2012, our capital expenditure budget calls for us to invest approximately $81.4 million. Of this, we expect to invest approximately $50 million to drill two wildcat exploration wells in the Gulf of Mexico, at an estimated dry hole cost of approximately $25 million each, net to Contango, subject to permitting approval by the Bureau of Ocean Energy Management, Regulation and Enforcement. We also plan to invest approximately $19.6 million in Alta Energy Partners, LLC, and $11.8 million to complete payment on several capital projects.

Our production is currently 78.1 million cubic feet equivalent per day, net to Contango. As of August 29, 2011, we had no debt and approximately $120 million in net available cash.

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Odfjell Inks Management Deal for Semisub

- Odfjell Inks Management Deal for Semisub

Monday, August 29, 2011
Odfjell Drilling AS

Odfjell Drilling has signed a management agreement for the semisubmersible drilling rig Island Innovator owned by Marine Accurate Well ASA – Maracc (OTC MARA). The rig will be ready for operations in Norway 4Q 2012.

Odfjell Drilling CEO Simen Lieungh stated, "We are very pleased to announce this management agreement with Marine Accurate Well
ASA for the Island Innovator. The expansion of the Odfjell Drilling management portfolio is a part of the company growth strategy, and we will actively tender the rig both in Norway and Internationally. The Island Innovator is a drilling and intervention rig perfect for
operations at the NCS among others. We are looking forward to a prosperous and successful collaboration with Marine Accurate Well ASA."

Odfjell Drilling will be responsible for management including crew, quality systems and technical operation. The co-operation will start immediately and Odfjell Drilling will commence mobilization of personnel and crew into the project and the operation.

The rig is currently under completion at Cosco in China. The rig will be ready for operations in Norway 4Q 2012.

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Expro to Provide Integrity System to Tullow Globally

- Expro to Provide Integrity System to Tullow Globally

Monday, August 29, 2011
Expro International Group

Expro is undertaking a contract to provide its SafeWells integrity management software system globally to Tullow Oil Plc.

Expro Well Services has been awarded a contract to provide SafeWells to Tullow in support of centralising Tullow's management of well integrity.

Tullow is a major independent oil company with operations in Africa, Europe, South Asia and South America.

SafeWells has been specifically developed to deliver an effective well integrity management solution. The bespoke software system monitors and reports well integrity performance in real time, highlighting problems and prompting remedial actions as issues arise. It has been deployed successfully by major operators globally.

Like many major oil companies, Tullow's operating environments are diverse and the range of well types equally broad. Over the coming years, the wellstock will include onshore, platform and subsea wells, both oil and gas, with a wide range of flow rates.

A plan was implemented in Tullow's wells engineering department to review the corporate approach to well integrity and put in place a centrally managed well integrity system.

This process would provide management with a retrospective position for the integrity of all wells and effectively 'raise the bar' on the operating standards of all assets. SafeWells is critical to this plan.

The SafeWells implementation process was launched on the Bangora Gas Field in Bangladesh and was followed with UK and Ghana operations.

Simon Copping, Expro client account manager, said, "It is great to see the hard work of the team starting to pay off. We have a fantastic software system in SafeWells that really complements Tullow's well integrity strategy. I'm excited about the future and building on the foundations of the Bangladesh success as we continue to roll the software out to the rest of the business."

Simon Sparke, well integrity focal point of Tullow Oil said, "SafeWells is to be used throughout Tullow and is being rolled out company-wide. With 10 different wells types in challenging engineering and cultural environments, having a software package that was user friendly, flexible and working seamlessly in the background was crucial. So far this product and the team supporting it have fulfilled all my expectations."

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Aker Solutions Names New Head of Geo Business

- Aker Solutions Names New Head of Geo Business

Monday, August 29, 2011
Aker Solutions

Aker Solutions has appointed Bengt Larssen as head of its geo business.

Mr. Larssen has since February 2010 been with Aker Solutions' geo business as vice president exploration. Prior to Aker Solutions he has spent 16 years in various management positions at Schlumberger/Western Geco, operating as geophysicist on both the exploration and production side of the business. He has also spent two years at Tromsø-based oil company Front Exploration AS.

Mr. Larssen, who will be based in Stavanger, Norway, holds a masters degree in geology from the University of Oslo. He starts in his new role on September 1, 2011.

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Bill Barrett Board Member Resigns

- Bill Barrett Board Member Resigns

Monday, August 29, 2011
Bill Barrett Corp.

Bill Barrett announced that Randy A. Foutch resigned from the Company's Board of Directors in order to focus his time on his duties as Chief Executive Officer and a director of Laredo Petroleum, Inc., an exploration and production company founded by Mr. Foutch in 2006.

Chairman, CEO and President Fred Barrett commented, "Randy has a long and successful history in the oil and natural gas industry and has provided our Company with valuable leadership and insight through his position on our Board of Directors. We are grateful for his contributions to our success over the years and wish him continued success at Laredo Petroleum."

Mr. Foutch joined the Bill Barrett Corporation Board of Directors in July 2006. His resignation from the Company was effective August 25, 2011.

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Excelerate Awarded Brazilian FRSU Contract

- Excelerate Awarded Brazilian FRSU Contract

Monday, August 29, 2011
Excelerate Energy L.P.

Excelerate Energy has executed with Petrobras a 15-year time charter party to provide an advanced floating storage and regasification unit (FSRU). This vessel, designated by Petrobras as VT3, will deliver 20 million cubic meters per day of natural gas to the Southeast Region of Brazil.

In addition, from July 2013 until the arrival of the VT3 newbuilding, the Guanabara Bay Terminal will make use of the Exquisite, one of Excelerate Energy's existing FSRUs with an increased regasification plant, expanding the terminal's delivery capacity from 14 to 20 million cubic meters per day.

The VT3 newbuilding design is based on Excelerate Energy's existing fleet and Petrobras requirements, and will have a storage capacity of 173,400 m(3) making it the largest FSRU in the industry. Capable of operation as both an FSRU and a fully tradable LNG carrier, this vessel is expected to enter into service in May of 2014.

Excelerate Energy has selected DSME for the construction of the new vessel, the same shipyard that built its previous eight FSRUs. Working with DSME, Excelerate is continuing the evolution of a highly reliable and proven design, while at the same time, expanding its fleet of compatible vessels.

"We are extremely pleased with the selection of Excelerate Energy to provide this industry-leading vessel, and we are confident that with our experience and expertise in floating regasification that we will provide a high standard of service to justify the confidence that Petrobras has placed in us," said Rob Bryngelson, President and CEO of Excelerate Energy.

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Drilling Ops Commenced at Polish Kutno Well

- Drilling Ops Commenced at Polish Kutno Well

Monday, August 29, 2011
FX Energy Inc.

FX Energy announced the start of drilling on the Kutno-2 well in the Company's 700,000 acre Kutno concession. The Kutno-2 well is planned to test a large (approximately 35,000 acres or 140 square kilometers) 2-D defined Rotliegend structure at a depth of approximately 6,500 meters (21,000 feet).

"FX Energy is pleased to be joined in this project by PGNiG, the most experienced explorer in Poland," said David Pierce, the Company's CEO. "Given that Poland currently imports approximately one-third of a Tcf of gas annually, and the Kutno prospect could have an EUR of up to 9.5 Tcf, both companies recognize that this project has the potential to change the energy balance in the entire region."

The current rig will be used to drill the first sections of the well prior to moving Nafta Pila's larger IDM 2000 rig with 500 ton load capacity onto location for the bottom sections of the well. Drilling is expected to take approximately eight to nine months. FX Energy is the operator and will be 50% owner of the Kutno concession; PGNiG will earn 50%.


The Plawce-2 tight gas well reached total depth of 4,200 meters. Gas shows were encountered as expected throughout the Rotliegend sandstone reservoir. Cores and logs are currently being analyzed. Based upon the results of this analysis, the well is expected to be perforated at the deepest part of the well to determine whether the entire Rotliegend reservoir is water-free. Thereafter, current plans call for perforating and fracking approximately 50 meters of Rotliegend in the upper portion of the well where porosity is approximately 9-10%. After testing, the well is expected to be completed as a vertical producer.

The Plawce-2 well is located on an uplifted tight Rotliegend block that could contain as much as 500 Bcf of gas in place within the Fences concession. The Company holds a non-operating 49% interest in the Fences concession and the Plawce-2 well; PGNiG operates and holds 51% interest.

U.S. Alberta Bakken

In Montana, FX Energy is in the early stages of appraising the Alberta Bakken oil potential in approximately 75,000 net acres. The Company has drilled and fracced a vertical well in its Cutbank acreage and is currently monitoring the flow back. The Company has drilled a second vertical well in another of its acreage blocks and plans to frac the vertical section. In three to four weeks the Company plans to drill a lateral section of approximately 4,000 feet at this location. Two further wells are planned in the fourth quarter, one vertical and one with a lateral section, assuming results of the Company's first two wells meet technical expectations. FX Energy is operator and holds a one-third working interest in approximately 75,000 net acres; American Eagle Energy, Inc., and Big Sky Operating, LLC, each own a one-third working interest.

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Sinopec to Strengthen Investments in Upstream Assets

- Sinopec to Strengthen Investments in Upstream Assets

Monday, August 29, 2011
Dow Jones Newswires
by Yvonne Lee

China Petroleum & Chemical Corp., or Sinopec, said Monday that it plans to strengthen investments in upstream oil and gas assets and unconventional resources over the next 5-10 years to further diversify its operations.

Chairman Fu Chengyu also said the company will accelerate the development of unconventional gas production, including shale gas and tight gas, in China and will disclose details of the development plan next year.

"We have 20 unconventional gas wells in China at the experimental stage. The output results are encouraging and better than expected," Fu said.

Shares of Sinopec ended up 6.7% at HK$7.49 Monday after Asia's largest refiner by capacity Sunday reported a better-than-expected 12% increase in first-half net profit to CNY41.17 billion from CNY36.80 billion a year earlier due to a stronger contribution from its oil production business, although its refining business recorded an operating loss due to rising fuel costs.

Fu said he is optimistic on the company's refining business prospects in the second half as crude prices will stay in a US $90-US $110 range.

However, he expects the global economy will be gloomy in the next 3-5 years if the U.S government launches a full-fledged third bond-buying program, commonly known as quantitative easing, or QE3.

"We hope to increase our cash level through the issuance of bonds to prepare any arising challenging," he said.

Sinopec said Sunday that it plans to raise up to CNY50 billion through the sale of domestic corporate bonds and the issuance of the convertible bonds in China.

Analysts expect Sinopec's refining margins to improve in the July-December period as crude prices eased recently, although the government price controls will still weigh.

"While the refining division is likely to continue to post a significant loss in the third quarter, we believe the second quarter was likely the peak for refining losses and the division could be close to break even in the fourth if Brent is around $107 or lower," Citigroup analyst Graham Cunningham said.

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

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Analysis: What's Happening in the Oil Market, Anyway?

- Analysis: What's Happening in the Oil Market, Anyway?

Monday, August 29, 2011
Rigzone Staff
by Barbara Saunders

The summer of 2011 could not have a much more dramatic close as a major hurricane hurled up toward the U.S. East Coast on the heels of a rare earthquake, the U.S. summer driving season closes with the Labor Day holiday, and Libyan rebels appear to be taking over Tripoli.

How will major refineries and pipelines along the East Coast be affected by the hurricane? How will holiday driving plans proceed, amid what OPEC is terming the gathering "dark clouds of recession?" How long will take to see the effects of the Libyan situation play out on the oil market? And when it does, will the roughly 1.2 million barrels per day (mbpd) of oil that Gaddafi's Libya typically produced be welcomed back, by rebounding economies thirsty anew for more? Or, will it be almost like a "white elephant," in American vernacular, that is, almost excess in a recessionary market?

The answers: Nobody really knows, of course.

But what is evident, looking back over the summer, is that nobody who usually "calls" the market has done so with much confidence for months. On a day-to-day basis, prices have recently just eased up or down, depending upon the news of that day. While that in itself isn't unusual, the activity of late has been relatively static, with price moves fluctuating within a few dollars per day, and sometimes dancing around a dime or so of the previous day's price.

The U.S. Energy Information Administration (EIA), for instance, noted that West Texas Intermediate (WTI) had risen only by $2.92 per barrel from a week earlier on Friday Aug. 26 – with a major hurricane approaching – and was up $12.78 from a year earlier. This increase over last year came despite large drops during the summer driving season, which mostly came in small day-to-day increments. WTI crude oil spot prices fell from an average of $110 per barrel in April to $97 per barrel in July, EIA noted. During the first week of August, world crude oil prices fell by about $10 per barrel, reflecting market concerns about world economic and oil demand growth, the agency said.

Market Remains Tight

Despite the woebegone worries about the world slipping into recession again, with corresponding demand cutbacks, the thing to bear in mind is that demand is still growing. It's just that OPEC, the International Energy Agency (IEA), EIA and other leading analysts are cutting back the pace of demand growth to reflect lagging economic performance, along with debt woes in both Europe and the U.S.

"We are still expected to remain near record levels of demand," said John Feldman, chief economist of the American Petroleum Institute, in an interview with Rigzone. "It's still a limited supply market. Libya resuming production should be helpful." He observed that Libya's internal strife took a "relatively small proportion" (about 1.2 mbpd) off the market, but had "disproportionate" effects. This was one reason why the IEA eventually called for member nations, including the U.S., to contribute to the market from emergency stockpiles.

For once, OPEC could not just turn up the oil taps after the organization had a rift in June. Specifically, Saudi Arabia, Kuwait and the United Arab Emirates voted to increase output as early summer demand kept roaring – and Libya's contribution, disproportionately felt, perhaps – stayed off the market. The other OPEC members, meanwhile, voted against hiking production. Because even the Middle East couldn't bring on sought-after light oil production right away, IEA member nations contributed some 60 million barrels to the supply equation.

"It made sense," Feldman continued, "That [Middle East and other] producers would have sold their light, sweet crude varieties first."

Looking ahead, EIA said that it "still expects oil markets to tighten as growing liquid fuels demand in emerging economies continues to outpace supply growth with continuing upward pressure on oil prices." EIA forecasts that WTI spot prices, which averaged $79 per barrel in 2010, will average $96 per barrel in 2011 and $101 per barrel in 2012.

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Eni Signs Libya Agreement, Paving Way to Restart Of Operations

- Eni Signs Libya Agreement, Paving Way to Restart Of Operations

Monday, August 29, 2011
Dow Jones Newswires
by Giada Zampano

Italy's energy giant Eni said Monday it signed a memorandum with the Libyan National Transitional Council, or NTC, that strengthens co-operation in the country and paves the way to the restart of Eni's oil and gas operations there.

Under the terms of the agreement Eni and NTC committed "to creating the conditions for a rapid and complete recovery of Eni's activities in Libya and to doing all that is necessary to restart operations on the Greenstream pipeline" that brings gas from Libya to Italy.

Following previous pledges by the Italian government, Eni will provide a first supply of refined petroleum products to the transitional government, to contribute to the basic and most urgent needs of the Libyan population.

Eni will also provide technical assistance to assess the state of facilities and energy infrastructure in Libya and to define the type and extent of operations required to safely restart the activities.

Eni, which is the largest foreign player in Libya, has been active in the country since 1959.

Monday, the Italian company said it is evaluating with NTC "various possible forms of co-operation in order to ensure the timely resumption of operations in the oil and gas sector and to enhance the country's natural resources to benefit the Libyan people and in respect of the existing contract."

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

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Statoil Makes Gas Find in North Sea

- Statoil Makes Gas Find in North Sea

Monday, August 29, 2011
Norwegian Petroleum Directorate
by SubseaIQ

Statoil Petroleum AS, operator of production license 569, is in the process of completing the drilling of wildcat well 16/7-10. The well proved gas/condensate.

The well was drilled 16 kilometers northeast of the Sleipner Øst field in the North Sea.

The purpose of the well was to prove petroleum in Paleocene reservoir rocks (the Ty formation). Only a thin gas/condensate column was encountered in a 115-meter thick reservoir with the expected reservoir quality. The licensees will evaluate the discovery together with other nearby discoveries.

The well was not formation tested, but data acquisition and sampling have been carried out.

The well was drilled to a vertical depth of 2487 meters below the sea surface and was terminated in the Shetland group in the Upper Cretaceous. The well will now be permanently plugged and abandoned.

The well is the first exploration well in production license 569, which was awarded in APA 2010.

Well 16/-10 was drilled by the Ocean Vanguard drilling facility, which will now proceed to production license 120 in the northern part of the North Sea to drill production wells at the Visund Sør field, where Statoil Petroleum AS is the operator.

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Cobalt Kicks Off Drilling Ops Offshore Angola

- Cobalt Kicks Off Drilling Ops Offshore Angola

Monday, August 29, 2011
Cobalt International Energy Inc.
by SubseaIQ

Cobalt provided the following update on its West Africa drilling program.

Cobalt has initiated drilling operations on its Cameia No. 1 well in Block 21, Offshore Angola. Well operations are being conducted with the Diamond Ocean Confidence drilling rig. After drilling and evaluating the Cameia-1 prospect, Cobalt will drill the Bicuar-1A well to test the Bicuar prospect, also in Block 21. Both wells are targeting pre-salt objectives.

As previously announced, Cobalt expects each well to take 80 to 100 days to drill and an additional 10 to 20 days to evaluate, if successful. Cobalt is the operator of Cameia and Bicuar and has a 40% working interest in each prospect.

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Beach Secures Rigs for Shale Gas Plays in Cooper Basin

- Beach Secures Rigs for Shale Gas Plays in Cooper Basin

Monday, August 29, 2011
Beach Energy Ltd.

Beach has secured two Ensign rigs, Ensign#65 and Ensign#16, to drill both horizontal and vertical wells targeting its unconventional gas play in the Nappamerri Trough of the Cooper Basin. From recent drilling results, it is clear that the target zone in PEL 218 (Beach 90%) goes beyond shale and incorporates other lithologies that are also gas saturated. Beach believes, that in addition to the substantial shale gas potential, it is now dealing with an unconventional basin centered gas play.

The 2012 program for these rigs will focus on pilot horizontal production wells in both ATP 855P (Beach 40%) and PEL 218, as well as a series of vertical delineation wells in PEL 218. The program is designed to test the significant potential of the basin centered play in what is now considered a thick, continuous, multi lithology gas accumulation across the PEL 218 permit and potentially ATP 855P.
Details of the rigs and the two separate programs are as follows:

Ensign#65 (ADR1500):
  • New build 1,500 horsepower rig out of Canada and the US which is expected to arrive around April 2012;
  • Encompasses the latest proven technology being used for drilling horizontal wells in the Haynesville shale province in the US;
  • Will be built to meet Australian standards and conditions and has the capability to drill 1,500 meter laterals from a depth of 4,000 meters; and
  • Will drill the first horizontal well in ATP 855P to target shale and other lithology target zones. Upon completion of this well, the rig will commence the horizontal pilot well program in PEL218, with two pilot horizontal wells planned adjacent to Holdfast-1 and Encounter-1.

  • 1,200 horsepower rig used to drill Holdfast-1 and Encounter-1, which is currently in the Officer Basin and expected to be available around January 2012;
  • Will drill a series of vertical wells in PEL 218 to continue the evaluation of the continuous basin centred gas play in the permit; and
  • Has the capability of drilling to 4,270 meters, with the vertical program set to increase the size of the resource in PEL 218 beyond the initial booking of 2 trillion cubic feet. This booking relates to a restricted area of 100km2 around each of Holdfast-1 and Encounter-1.

Beach Managing Director Reg Nelson said, “Beach has started to unlock a significant basin centred unconventional gas play in the Cooper Basin. These two rigs will take us a step closer to understanding the extent of the gas resource that resides within our permits. The horizontal pilot wells to be drilled by Ensign#65 will be production style wells designed to flow gas at commercial rates. Should these wells be successful we will seek to commence a pilot development program as soon as possible.”
  • PEL 218 (Permian JV): Beach (90% and Operator), Adelaide Energy Ltd (10%)
  • ATP 855P: Beach (40% and Operator), Icon Energy Ltd (40%) and Adelaide Energy Ltd (20%)

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ADX Spuds Sidi Dhaher Well in Tunisia

- ADX Spuds Sidi Dhaher Well in Tunisia

Monday, August 29, 2011
ADX Energy Ltd.

ADX announced that the Sidi Dhaher-1 well in the Chorbane license, onshore Tunisia, spudded at 07:00 am GMT, Saturday August 27, 2011.

The current operation is drilling the 16" hole. Sidi Dhaher-1 has a planned total depth of 2,168 meters and is expected to take about 33 days to drill. Additional time will be required in the event of formation testing.

The Sidi Dhaher prospect is located in the 2,428km2 large Chorbane Exploration Permit onshore central Tunisia near the port city of Sfax. It is surrounded by several producing oil fields and extensive oil and gas infrastructure. The Sidi Dhaher well is targeting an Eocene reservoir with estimated prospective resources of 175 billion cubic feet (5 billion m³) of recoverable gas and a Cretaceous reservoir with estimated prospective resources of 44 million barrels (5.9 million tons) of oil. Additional targets exist in the deeper Douleb and Bireno reservoirs that produce oil and gas in the Guebiba-El Hajeb field immediately east of the Chorbane permit

Participant interests in the Sidi Dhaher -1 well will be as follows:
  • ADX Energy Ltd 40% (Operator)
  • Gulfsands Petroleum Plc 40%
  • XState Resources Ltd 10%
  • Verus Investments Limited 10%

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Cougar O&G Bags Additional Leases in Alberta Land Sale

- Cougar O&G Bags Additional Leases in Alberta Land Sale

Monday, August 29, 2011
Cougar O&G Canada Inc.

Cougar O&G has acquired an additional 3 sections of land (1920 acres) at an Alberta Provincial Government land sale on Wednesday August 25, 2011.

These lands are on the southern boundary of lands we acquired in July of 2010 and the 3D seismic program conducted in early 2011. We believe there are extensions of reserves identified in the seismic and the Reserves Assessment and Evaluation of the new or previously unevaluated Trout Core oil properties of Cougar, released on July 14, 2011.

That review completed based on existing information in the public domain coupled with the extensive Cougar 3D seismic program placed a $77.4 million Cdn Net Present Value (NPV) discounted 10% for Proven (P1) plus Probable (P2) plus Possible (P3) and an estimated 2.7 million barrels recoverable P1+P2+P3 from the project. The report is based on a previously announced logical development plan with a 2-4 well drill program to be followed up with a 4-6 well program. Those programs are dependent upon financing.

William Tighe, CEO of Cougar provided, "We are pleased with the extension of the lands acquired based on the geological analysis with extensions of structures identified in the 3D seismic. Despite challenges from the horizontal well inconclusive results due to insufficient pumping capability with the equipment currently available to properly test that well, the continued Rainbow Pipeline shut in since late April and the resulting need to truck our oil to markets in a 12hr round trip per load often in inclement weather and at discounts to contract prices, the Slave Lake area wild fires in early May, during which the focus was to keep all the wells producing, - we in addition have kept the projects moving forward wherever possible.

The drilling program, as a drill ready program which is subject to financing, is ready to move forward as soon as financing is sourced. The engineering report identifies this project has the potential to add revenue, estimated cash flow with pay outs on the capital program in the 130 day range, and add substantial proven reserves once the wells have been producing for 6 months, while continuing our goal of attaining 2000 bbl/d production from operations."

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Samson O&G Increases Acreage in Hawk Springs Area

- Samson O&G Increases Acreage in Hawk Springs Area

Monday, August 29, 2011
Samson O&G Ltd.

Samson O&G has been awarded, on a conditional basis, approximately 956 net acres of leasehold offered by competitive tender from the University of Wyoming. This land is part of the University's agricultural research facility. Because the acreage is within Samson's propriety 3-D seismic coverage, Samson had a significant advantage by being knowledgeable about the rock qualities in the area. Samson has also been successful in acquiring additional acreage in the State of Wyoming's lease sales as well as leasing acreage from fee owners. Accordingly, Samson has now increased its holding to 17,489 net acres in the Hawk Springs area. This holding assumes that Samson's farminee exercises its full right to earn a 25% interest within the farmin area.

Defender US33 #2-29H, Goshen County, Wyoming, Samson 37.5% working interest (carried)

Samson further advises that the Defender US33 #2-29H well has reached the Niobrara core point at a depth of 6,937 feet and is currently cutting 120 feet of core from the Niobrara 'A' and 'B' intervals.

This vertical pilot hole will then be drilled to an approximate total depth of 7,450 feet, at which point the hole will be logged, with both the core data and the log data used to determine the final horizontal azimuth. The vertical pilot hole will be plugged back to a kick-off point above the Niobrara. From the kick-off point, the borehole angle will be built until it is horizontal and the bit is positioned within the Niobrara "B". Then 7-inch intermediate casing will be set through the curve and the lateral will thereafter be drilled for a distance of approximately 4,300 feet within the Niobrara "B". The well will be completed using a plug and perforation process in 15-stages that is expected to involve the placement of approximately 3,000,000 pounds of proppant into the Niobrara Formation. The Defender US33 #2-29H is the first Niobrara appraisal well in Samson's Hawk Springs project.

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OGX Concludes Drill-Stem Test in Santos Basin

- OGX Concludes Drill-Stem Test in Santos Basin

Monday, August 29, 2011

OGX has concluded the drill-stem test performed in the Santonian section of well 1-OGX-47-RJS, in the BM-S-59 block, in the shallow waters of the Santos Basin. OGX has a 100% interest in this block.

"With a successful exploration campaign underway in the Santos Basin, we initiated the drill-stem test phase. This is the first of a series of tests which has obtained significant productivity data from our sandstone reservoirs and represents an important step in broadening our understanding of this basin and in beginning the development of this area," commented Paulo Mendonça, OGX's General Executive Officer and Exploration Officer.

Following the discovery announced on July 1, 2011, a drill-stem test was performed in a vertical well in the Maceió accumulation. Besides the presence of gas, the test confirmed the existence of condensate of about 50° API that should account for around 20% of the hydrocarbon volume of this structure. The results of this test, with three production intervals, indicate a production potential of 1 million cubic meters per day in a vertical well, which could reach 2.5 million cubic meters per day in a horizontal well, both at Absolute Open Flow.

The test information is extremely important to the Company, because when combined with the accumulations of Natal (OGX-11), which will be the next well to be tested, and Aracaju (OGX-19), which will be tested in a Discovery Appraisal Plan, indicate the existence of one more important gas and condensate region in Brazil.

The well OGX-47, named 'Maceió', is located in the BM-S-59 block and is situated approximately 110 kilometers off the coast of the state of Rio de Janeiro at a water depth of approximately 185 meters. The Ocean Quest rig initiated drilling activities on May 24, 2011.

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