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Oil and Gas Energy News Update

Friday, August 5, 2011

Oil & Gas Post - All News Report for Friday, August 05, 2011

Friday, August 05, 2011

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Commodity Corner: Oil Takes a Wild Ride

- Commodity Corner: Oil Takes a Wild Ride

Friday, August 05, 2011
Rigzone Staff
by Matthew V. Veazey

After settling at its lowest point in six months Thursday, light sweet crude oil for September delivery managed to eke out a small gain for the day.

The WTI settled at $86.88 a barrel, representing a 25-cent day-on-day increase, after a volatile trading session. The benchmark plunged to an intraday low of $82.87 on escalating debt crisis fears within the eurozone.

Italy is the latest EU country to risk defaulting on its massive public debt. Making debt service less manageable is Italy's stagnant economic growth rate. A possible Italian bailout, along with other debt restructuring initiatives elsewhere in the eurozone, has caused the region's currency to lose value; in this situation, dollar-denominated crude oil becomes a less attractive buy for investors holding the euro.

Investor sentiment brightened later Friday, however, amid reports that Italy's government plans to take steps to jump-start economic growth. The economic liberalization program reportedly includes measures such as amending the country's constitution to require a balanced budget, loosening certain employment rules, and accelerating the pace of entitlement reform.

Also giving oil a boost Friday was a U.S. Labor Department report stating that non-farm payrolls increased by 117,000 last month, beating economists' expectations. Also, the agency announced that the official unemployment rate edged downward in July by 0.1 percentage point to 9.1 percent.

The WTI peaked at $86.88 Friday. The September Brent contract price gained $2.12 to end the day at $109.37 a barrel. It fluctuated from $105.69 to $109.90.

Natural gas for September delivery ended the day flat at $3.94 per thousand cubic feet. It traded within a range from $3.90 to $3.98.

September gasoline climbed nearly seven cents to end the day at $2.805 a gallon. The front-month contract peaked at $2.82 and bottomed out at $2.68.

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About to Buck The Trend

- About to Buck The Trend

Friday, August 05, 2011
Rigzone Staff
by Trey Cowan

Looking back to the second quarter, the jackup dayrate trend is down 2 percent to $106k/day versus 1Q11 rates. Floaters on the other hand did not experience any change in pricing from one quarter to the next, holding steady at $378k/day.

Commodity jackup dayrates suffered the most, down 5.6 percent to an average of $70k/day during 2Q. Standard jackup rates fell 2.2 percent to 96k/day and premium jackup rigs fell at the slowest pace of 1.6 percent to $135k/day, all on a quarter-over-quarter basis.

While the chart shows an ongoing downward trend, the future actually looks good for jackup rate improvement, based on recent activity. Jackup rates for July improved 1 percent to $107k/day, up $1,000 from June's average of $106k/day. When looking at capabilities and water depths served, premium jackups grew at a faster pace (3 percent to 139k/day) during the month. We continue to hear commentary pointing to a bifurcated marketplace with higher demand for premium rigs relative to standard 300' rigs or commodity rigs that serve in 250' waters or less.

Based on contracts already booked, dayrates for premium jackups are likely to improve 8 percent during the second half of 2011. This compares favorably to 4 percent overall growth in dayrates anticipated for jackups, which translates into an average increase of 5,000/day for jackups during the second half of 2011.

Looking solely at the rig counts, global offshore activity improved during the month of July when compared to June. There are now 543 rigs under contract around the world, up ten from last month (as both floaters and jackups added 5 rigs-a-piece to their respective rolls). The overall fleet size also grew during the month by a net five rigs (3 floaters and 2 jackups) to 756 rigs marketed globally.

Permitting in the Gulf of Mexico Year to Date

In water depths of less than 500 feet, there have been 41 "New Well" permits issued by the BOEMRE year-to-date. "Revised New Well" permits number 64 that have been issued since January 3rd 2011. The average pace for New Well and Revised New Well permit approvals appears to be 15 per month in shallow waters. In water depths of more than 500 feet there have been 12 New Well permits issued by the BOEMRE year-to-date. Since Jan. 3, 52 Revised New Well permits have been issued by the BOEMRE. Thus, the average pace for New Well and Revised New Well permit approvals for deepwater projects is 9 per month.

To put all this into perspective, combine the two averages together and you see that the BOEMRE is averaging 24 approvals per month. This is an anemic pace considering that the inspection staff of the BOEMRE is ~50 individuals and growing. That means at the current staff levels the BOEMRE's inspectors are approving either a "New Well" or "Revised New Well" at a pace of one every two months.

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UTEC Mobilizes MV Calypso Star Offshore AU

- UTEC Mobilizes MV Calypso Star Offshore AU

Friday, August 05, 2011
UTEC Survey Australia Pty Ltd.

UTEC Survey Australia has mobilized the 24-meter geophysical survey catamaran, MV Calypso Star, on a long term basis to support geophysical survey operations in North and North West Australia.

The vessel is currently performing survey operations to Oil & Gas clients in the Timor Sea with expected completion in late August 2011 in Exmouth.

The Calypso Star is equipped with an array of geophysical survey equipment, including a high resolution R2Sonics multibeam echo sounder coupled with a DMS3-05 motion sensor, Edgetech 4200 Digital Side scan sonar, reflection seismic and onboard processing capabilities.

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EOG CEO: Boosts Asset Sale Target to $1.6B, from $1B

- EOG CEO: Boosts Asset Sale Target to $1.6B, from $1B

Friday, August 05, 2011
Dow Jones Newswires
by Ryan Dezember

EOG Resources Chief Executive Mark Pappa said Friday the oil and gas explorer is increasing the amount of cash it hopes to raise by selling assets this year in order to offset rising oilfield service costs.

The assets being sold "are primarily mature long-lived domestic gas properties and other acreage," Pappa told investors during a conference call to discuss EOG's second-quarter results. Those properties are scattered in east Texas, the mid-continent and in the Gulf of Mexico.

Houston-based EOG posted a profit of $295.6 million, or $1.10 a share, up from $59.9 million, or 24 cents a share, a year earlier. Excluding hedging impacts, write-downs and other impacts, per-share earnings rose to $1.11 from 18 cents.

Revenue jumped 89% to $2.57 billion on a 13% increase in output and oil prices that climbed 37%.

Analysts polled by Thomson Reuters expected a per-share profit of 79 cents and revenue of $2.01 billion. Shares rose 6.22% to $97.86 in early Friday trading.

While EOG's oil and natural-gas liquids production rose in the second-quarter, natural-gas output was about 1% lower to an average of 1,615 million cubic feet per day. EOG has stressed its shift to oil production in recent quarters due to an oversupply-induced natural-gas price slump.

"We're not interested in growing North American gas volumes at current prices unlike most other companies," Pappa said, adding that EOG will drill in natural-gas basins only where necessary to preserve leases.

By mid-year, EOG had completed $944 million worth of gas-asset sales and has another $271 million in deals pending, Pappa said. The divesture target should be reached by the end of the year.

About $400 million of the extra $600 million being raised will be spent on rising oilfield-service costs, Pappa said.

Beyond raising money to cope with oil-patch inflation, Pappa said EOG plans to open a Wisconsin sand mine in the fourth quarter, which will supply sand proppant for "most of our North American resource plays."

Proppant is a crucial component in hydraulic fracturing, a process in which water, sand and chemicals are forced deep underground to crack open energy-bearing rocks, including shales, so that oil and natural gas can seep out. The sand, or proppant, wedges into the resulting fissures to hold them open. Proppant, which comes in grades ranging from raw sand to manufactured ceramic spheres, is in tight supply worldwide.

Supplying much of its own proppant should save EOG some $400 million a year and help reduce the cost of drilling a well in its prolific Eagle Ford wells in south Texas by about $1 million, executives said.

EOG has also signed an agreement for a 70,000-barrel-a-day rail off-loading facility in St. James, La., that will allow it to transport most of its crude oil from the Eagle Ford and North Dakota's Bakken Shale around Cushing, Okla., where congestion has depressed oil prices this year, to the Gulf Coast, where crude oil fetches a premium.

The Louisiana off-loading facility should be able to start taking shipments in the first quarter of 2012 and will enable EOG to take advantage of the difference in regional oil prices, Pappa said.

Pappa, who turns 65 next month, also said Friday that he will remain as CEO for the next 18 months "and, when I do retire, my successor will be a long-tenured EOG employee."

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

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Gulfmark to Drill 1st Eagleford Shale Well

- Gulfmark to Drill 1st Eagleford Shale Well

Friday, August 05, 2011
Gulfmark Energy Group Inc.

Gulfmark Energy announced its wholly owned subsidiary, Gulfmark Resources, Inc., has filed for drilling permits with the Texas Railroad Commission and intends to drill its initial test well on its 4,261 acre Kiefer Lease in Zavala County, Texas, upon permit approval. The Kiefer lease is situated in the northwestern portion of the oil window of the Eagleford Shale trend of South Texas. Gulfmark intends to drill vertically through the Escondido, Olmos, San Miguel, Austin Chalk and Eagleford Shale formations and will evaluate results by open hole logs and core samples. The Company's primary objective is to penetrate the Eagleford Shale and plans to drill horizontally approximately 3,000 to 4,000 feet upon reaching this prolific shale play.

Michael Ward, President and CEO, stated, "With recent discoveries within the Eagleford Shale formation, we are very excited to begin our development drilling program and increase our shareholder value. With success through the drill bit, we hope to expand our horizons and fully exploit the resources that lie within our leasehold."

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Norse Sets Sights on NY Shale Development

- Norse Sets Sights on NY Shale Development

Friday, August 05, 2011
Norse Energy Corp. ASA

Norse announced a reallocation of corporate resources to focus on Marcellus and Utica Shale development.

In anticipation that rules allowing the use of high volume hydraulic fracturing to develop natural gas resources in the state of New York will soon be in place, Norse Energy has elected to immediately suspend Herkimer drilling. This will preserve cash for potentially more profitable Marcellus and Utica Shale planning, permitting and development.

Subsequent to release of the draft SGEIS on July 8, 2011, Norse Energy filed its first application for a permit to drill a shale well in New York State using high volume hydraulic fracturing. The permit is expected to be issued when final SGEIS regulations are in place. This strategy transition is expected to facilitate rapid and efficient development of the Company's Marcellus and Utica Shale resources.

"With the SGEIS public comment period expected to begin soon, now is the right time to re-focus the company on the development of shale resources across our extensive acreage position in New York State," said Mark Dice, Chief Executive Officer.

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Keppel Lands OGX Deals

- Keppel Lands OGX Deals

Friday, August 05, 2011
Keppel Corp. Ltd.

Keppel Shipyard has secured two contracts worth a total of S$146 million to convert a Floating Production Storage and Offloading (FPSO) unit as well as to fabricate and integrate an external turret mooring system for an existing FPSO unit.

The first contract is from Single Buoy Moorings Inc (SBM) for the conversion of the Very Large Crude Carrier (VLCC) M/T Concorde Spirit into a FPSO facility, to be named FPSO OSX-2. SBM had been engaged by OSX Brasil to supply the FPSO, which is expected to be completed in the second quarter of 2013 and will be deployed in the OGX Petroleo e Gas Participacoes S.A. (OGX) field in Campos Basin, offshore Brazil.

Keppel Shipyard's work scope on FPSO OSX-2 comprises refurbishment and life extension works, accommodation block extensions for 80 personnel, a new flare tower, a new internal turret mooring system and topside module supports, as well as the installation and integration of topside modules. Work on the vessel is expected to commence in September 2011.

Mr. Tony Mace, Chief Executive Officer of SBM Offshore said "Since 2001, Keppel has been our preferred partner and we are pleased to award another FPSO conversion to them. I look forward to continue with this partnership as we build up our FPSO fleet."

Mr. Nelson Yeo, Managing Director of Keppel Shipyard, said, "We are glad for another opportunity to collaborate with our long-time customer SBM and to support OSX. Committed to safe and value-added services, we will work closely with all stakeholders of FPSO OSX-2 towards a successful conversion project."

Other ongoing projects between Keppel Shipyard and SBM include the fast-track modification and upgrading of the FPSO Cidade de Anchieta and the conversion of the FPSO Cidade de Paraty, which will subsequently proceed to Keppel FELS Brasil's BrasFELS for installation and integration of topsides. Keppel Shipyard is also undertaking modification and upgrading work on OSX's first vessel, FPSO OSX-1.

Keppel Shipyard's second contract is for the fast-track fabrication and integration of an external turret mooring system for Rubicon Offshore International Pte Ltd (Rubicon Offshore).

FPSO Rubicon Intrepid is currently engaged in the production of Galoc Field, west of Palawan Island, the Philippines. Fabrication of the turret is expected to be completed and integrated to the FPSO in the fourth quarter of this year.

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

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Entek Updates Ops in Niobrara Shale Oil Proj. Appraisal Program

- Entek Updates Ops in Niobrara Shale Oil Proj. Appraisal Program

Friday, August 05, 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 has reached its total depth of 7,500 ft. Wire-line logs have been run and the well has been successfully cased and cemented ready for completion.

Preliminary interpretation of wire-line logs and correlation to offset wells show that the Niobrara section in this well contains significant potential pay zones (benches), as expected. In addition the Frontier Sandstone exhibits hydrocarbon saturation and is also being considered as a pay zone for fracture stimulation and completion.

The fracture stimulation program is currently being designed with Halliburton and is expected to start in August 2011.

The rig has been released and is currently mobilizing to the next location as the completion and fracture stimulation program is being designed for the Battle Mountain 14-10L well. Entek holds a 55% interest in the Green River Basin Joint Venture (GRBJV) with Emerald Oil & Gas NL 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.

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National Fuel Deems Marcellus JV Unlikely

- National Fuel Deems Marcellus JV Unlikely

Friday, August 05, 2011
National Fuel Gas Co.

Today at the quarterly earnings teleconference of National Fuel Gas Co., Chief Executive Officer David F. Smith will make the following statement about the possibility of a joint venture (JV) involving the Marcellus Shale assets of its subsidiary Seneca Resources Corporation:

"That brings me to an update on a potential joint venture. Our future growth prospects – and the fact that we're not capital constrained or up against a schedule of lease expirations – sets a pretty high bar. As a result, while we have been relatively close with two different parties over the last two or three months, we ultimately chose not to consummate either of those particular transactions. While they were good and serious offers – we determined that they just weren't good enough. And while discussions do continue with a few potential partners, as we've said in the past, unless a Joint Venture enhances shareholder value, unless it produces significant advantages above and beyond our existing robust plans for growth, which as I said is a pretty high bar, we will simply move forward on our own. At this point that's the likely outcome.

"With or without a JV, our prospects are compelling. We have the resources – financial and human – and the assets to deliver exceptional value to our shareholders for years to come."

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Chrysler and Dodge Recalls 300,00 Minivans

- Chrysler and Dodge Recalls 300,00 Minivans

Aug 5, 2011

Chrysler has recalled just under 300,000 2008 Dodge Caravan, Chrysler Grand Voyager, and Chrysler Town and Country minivans due to air bags that inadvertently deploy, according to Consumer Reports.

The car company announced the leak in the air conditioning and heating system may cause the occupant restraint control module to fail, which could lead to an air bag deployment without warning or illumination of the air bag warning light.

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Broadwind Energy Missed Q2 Estimates

- Broadwind Energy Missed Q2 Estimates

Aug 5, 2011

Broadwind Energy (NASDAQ:BWEN) reported a Q2 loss of $0.04 per share, wider than consensus estimates for a loss of $0.01 per share. Revenues for the quarter rose 17% year-over-year to $39.3 million, missing consensus estimates of $46.7 million.

Peter C. Duprey, president and chief executive officer, said, "We are continuing to make progress with the business transformation. With three sequential EBITDA positive quarters behind us, we feel good about the operational momentum we have gained. Our Tower business had a 48% increase in revenue in a difficult market, and in our Gears business, sales to industrial customers exceeded wind customers. Our Gearing and Services businesses had new orders well in excess of sales; our enhanced focus on sales and diversification efforts are starting to have an impact. While we continue to face a challenging wind energy market, we remain focused on the diversification of our customer base and the expansion of our services business where we have strong core competencies."

Broadwind Energy has a potential upside of 150% based on a current price of $1.2 and an average consensus analyst price target of $3.

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Magnum Hunters Acquires Acreage in Williston Basin

- Magnum Hunters Acquires Acreage in Williston Basin

Friday, August 05, 2011
Magnum Hunter Resources Corp.

Magnum Hunter's wholly owned subsidiary, Williston Hunter ND, LLC, has entered into a Purchase and Sale Agreement ("PSA") with a privately-held company ("Seller") for all of the Seller's operated working interest ownership in oil and gas mineral leases and 191 wells on approximately 15,500 gross acres located within four counties of the Williston Basin of North Dakota. Gross production from the properties is approximately 833 BOE per day. Total proved reserves attributable to the acquired properties are estimated at 2.6 million barrels of oil equivalent. Magnum Hunter presently owns an approximate 47% working interest in these oil and gas properties. Upon closing of this transaction, Magnum Hunter will own an approximate 95% working interest in these properties. The effective date of the transaction is April 1, 2011. Magnum Hunter intends to close the purchase transaction on or before August 18, 2011.

Magnum Hunter will pay to the Seller a total purchase price of $57 million, to be paid at closing in the form of $55.0 million in cash and $2.0 million in Magnum Hunter restricted common stock. The number of shares of Magnum Hunter common stock will be determined based on the volume weighted average price of the Company's common stock during the five trading days prior to closing. Magnum Hunter intends to fund the cash portion of this purchase through existing liquidity and borrowings under the Company's senior credit facility. Additionally, the Seller will retain an overriding royalty interest in certain of the properties in various amounts not to exceed 2%. No existing debt of Seller will be assumed by Williston Hunter in connection with the closing of the acquisition.

The PSA between Williston Hunter and the North Dakota based privately-held Seller was negotiated pursuant to a Settlement Agreement between Magnum Hunter and the Seller as a result of certain lawsuits pending in the United States District Court for the District of North Dakota (Northwestern Division). The agreed upon settlement between the parties will resolve all outstanding claims. The parties will file stipulations with the District Court for dismissal, with prejudice, of the two pending civil actions upon the PSA's final closing.

Management Comments

Mr. Glenn Dawson, President of Williston Hunter, commented, "We are pleased to announce this final agreement to acquire these Williston Basin properties where we have been a minority owner for years. With this 'bolt on' transaction, we will be establishing an operating base in North Dakota which has been a primary objective as we continue to grow our presence in the Williston Basin. Our game plan in 2011 is to continue our geological and engineering evaluation of these properties so that we will be in a position to prudently develop these assets beginning early next year."

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ExxonMobil, Pertamina Gain Ground in Banyu Urip Field Development

- ExxonMobil, Pertamina Gain Ground in Banyu Urip Field Development

Friday, August 05, 2011
ExxonMobil Corp.

ExxonMobil said that the development of the Indonesian Banyu Urip field in the Cepu block in East Java has achieved a major milestone with the award of the first of five engineering, procurement and construction contracts for work on major facilities at the development.

ExxonMobil's Mobil Cepu Ltd. (MCL) is operator of the Cepu block with 45 percent interest. The other co-venturers are Pertamina with 45 percent interest and four local government companies holding the remaining 10 percent interest.

"This is a major milestone in the development of the Banyu Urip field," said Neil Duffin, president of ExxonMobil Development Company. "Based on appraisal drilling, we've increased estimates of the recoverable resource under full development to 450 million barrels. This multibillion dollar project continues to benefit from the strengths of both Pertamina and ExxonMobil and provides the foundation for a strong partnership between the two companies, as well as with the local government companies."

Full field development is planned to produce 165,000 barrels of oil per day from facilities that include 49 wells on three well pads, a central processing facility, and a 60 mile (95 kilometer) pipeline to transfer the processed oil to a 1.7 million barrel floating storage and offloading (FSO) unit in the Java Sea. Tankers will load crude oil from the FSO for transport to domestic and world markets.

Construction is targeted to be completed in 36 months and the start-up of full field production is expected afterwards, pending regulatory approvals.

Early oil production on the Banyu Urip development commenced in 2009 from facilities with demonstrated capacity of greater than 20,000 barrels per day. Duffin said, "The excellent performance of the early production wells and facilities adds economic value to the overall project and is supportive of the Government of Indonesia's priorities to safely and effectively develop the Cepu Block oil and gas resources."

Affiliates and predecessor companies of ExxonMobil have operated in Indonesia for more than 100 years. ExxonMobil is actively working on exploration and development opportunities to increase its participation in Indonesia's oil and gas industry. The company supports long-term and sustainable community initiatives around its areas of operation. ExxonMobil's investment in Indonesia since 1968 is more than US $19 billion (190 trillion rupiahs).

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Velocious Bags Gorgon Gig

- Velocious Bags Gorgon Gig

Friday, August 05, 2011

Velocious has secured a contract to deliver intricate tooling components and associated services for use in subsea work on the Chevron-operated Gorgon Project off the north-west coast of Australia.

Velocious is currently designing and fabricating Buckle Initiation components and tooling which will become an integral part of the Project's offshore operations and subsea pipeline buckle mitigation methodology. Velocious is also providing other hardware and onshore services for Gorgon.

The work is split between delivering directly to the Gorgon Project and to contractor DOF Subsea which has subcontracted considerable scope to Velocious.

The Gorgon Project is operated by an Australian subsidiary of Chevron and is a joint venture of the Australian subsidiaries of Chevron (approximately 47 percent), ExxonMobil (25 percent) and Shell (25 percent), Osaka Gas (1.25 percent), Tokyo Gas (one percent) and Chubu Electric Power (0.417 percent).

It is one of the world's largest natural gas projects and the largest single resource natural gas project in Australia's history, containing resources of about 40 trillion cubic feet of gas.

Velocious CEO Brett Silich said the contract represented a major breakthrough for Velocious, which specializes in providing innovative subsea engineering products and services.

"Our appointment reflects an ongoing commitment to product development and innovation to meet the subsea engineering requirements of major international clients," Mr. Silich said.

"Chevron has presented our business with an opportunity to play a role in its flagship Asia Pacific project. The agreement forms the next stage of a professional relationship, but the onus is now on us to continue to offer innovative, high quality solutions as the Gorgon Project progresses."

"Chevron was prepared to give our local content services a genuine chance and the results have been great for both parties," Mr. Silich said.

"We worked closely with them on some challenging development work for the Gorgon Project subsea pipelines and, within that successful process, they identified us as worthy of showcasing to the wider oil and gas community.

"The whole experience has been an integral part of our development and we remain extremely grateful for the opportunity presented to us."

Velocious continues to step out from the crowd and apply the latest and greatest technology to overhaul traditional ways to solve subsea problems. The company has taken on some incredibly complex subsea challenges against tight deadlines and the results have been spectacular.

The company strives to convince clients that departure from the many established and often dated subsea industry norms can bring rich rewards.

In response to internal and client demand for appropriately skilled people, Velocious has also established a dedicated personnel wing and using its most experienced oil and gas specialists to train and develop local employees from scratch.

"We are living proof that with the right people and motivation to succeed local content can compete with the best and win," Personnel Recruitment Director Rob Gallacher said.

"Aggressive major project schedules mean local companies must rapidly develop skills and capability to ensure current capability isn't considered a long-term issue that can only be solved by using non Australian options."

Velocious has already established a WA graduate assistance program and expects the first related thesis outputs targeting remotely dredging subsea sediments and closed loop torque verification and control to be completed in the very near future.

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PPL Corporation EPS In Line With Estimates, Beats Revenue For Q2

- PPL Corporation EPS In Line With Estimates, Beats Revenue For Q2

Aug 5, 2011

PPL Corporation (NYSE:PPL) reported Q2 adjusted EPS of $0.45 in line with analyst estimates. Revenues for the quarter were $2.49 billion, better than consensus estimates of $2.26 billion.

James H. Miller, PPL's chairman and chief executive officer said, "We're on track to achieve our forecasted 2011 earnings from ongoing operations despite extended unplanned outages to replace turbine blades at both of our Susquehanna nuclear units. We expect to mitigate the impact of the Susquehanna outages with strong performance from our U.K. business and positive results in other aspects of our competitive supply business."

PPL (NYSE:PPL) has a potential upside of 13.3% based on a current price of $26.53 and an average consensus analyst price target of $30.06.

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Monterey Oil Shale Seen as Next Wave of U.S. E&P Efforts

- Monterey Oil Shale Seen as Next Wave of U.S. E&P Efforts

Friday, August 05, 2011
Rigzone Staff
by Karen Boman

California's Monterey shale oil play could become the next wave of U.S. exploration and production as high oil prices, and the sale of non-core assets by major oil and gas operators, has opened the door for smaller oil and gas companies to pursue the play.

Oil has been produced from the Monterey shale since the early 1900s, but the major oil companies who first explored for oil in California initially focused much of their exploration efforts on the state's heavy oil fields. Drilling wells in the state's heavy oil fields was economic; thus, majors did not have the incentive to explore the deeper Monterey shale with inexpensive oil to develop. The fact that exploration acreage has mostly owned or leased by major oil companies or controlled by government entities meant there was little room for smaller oil and gas companies to enter California.

However, the sale of non-core assets has opened the door for smaller operators to enter the market, and the shift by oil and gas companies towards liquids plays from natural gas due to strong oil prices has prompted companies to pursue emerging oil shale plays.

Early last month, the U.S. Energy Information Administration (EIA) estimated in its report, Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays, that the Monterey/Santos play in southern California holds 15.4 billion barrels of shale resources; the Bakken and Eagle Ford are the next largest shale oil plays at approximately 3.6 billion barrels and 3.4 billion barrels of oil respectively. The Monterey shale is the primary source rock for the conventional oil reservoirs found in the Santa Maria and San Joaquin basins in southern California.

Besides oil prices and sale of non-core assets by majors, the state government's interest in creating jobs and revenue within California also is helping to create an environment conducive for Monterey shale oil development, said Global Hunter Securities analyst Phil McPherson, adding that the governor has increased funding for the state's Division of Oil, Gas and Geothermal Resources and increased the number of permits issued.

The need to reverse the two decades of declining oil production within the state is driving the need for new oil production to be brought online. Enhanced oil recovery techniques are being used at historic fields such as Kern River and Midway set to maintain production, but with a mature basin, there is only so much that can be done, McPherson said. California, the third largest U.S. oil producing state, produced 555,000 b/d of crude oil in February of this year, EIA reports.

As a result of these factors, McPherson sees significant potential in the Monterey shale, and while drilling results have been mixed to date, McPherson notes that the Barnett shale took 15 years to figure out and the Bakken oil play four to five years before drilling efforts found success. "Companies pursuing the Monterey shale are still learning the science and the lay of the land," McPherson said.

Venoco Inc., which has 14 years experience drilling and producing from the Monterey horizon offshore California with its Sockeye and South Ellwood fields, began leasing Monterey shale formation properties onshore in 2006. Venoco Chairman and CEO Tim Marquez said the EIA's report on the Monterey shale confirms much of what the company has said about the Monterey shale potential.

A massive amount of data is available on the Monterey, which has sourced six of the largest U.S. oil fields, with over 17,000 wells having penetrated the Monterey in Venoco's target basins and over 11,000 of those wells tested or produced from the Monterey. The company also has acquired over 1,100 digital logs, with shale-petrophysical analysis on more than 50 of these wells.

Venoco currently is operating one rig in its Monterey shale play and is working to identify and secure up to four additional rigs by year-end 2011. The increase in rigs would be in anticipation of much greater activity in 2012, when the company currently expects it may run six to eight rigs in the play and spud between 50 and 75 primarily vertical wells, as warranted by drilling and production results. The company anticipates that it will spend $100 million, half of its capital budget, on its Monterey shale assets.

Drilling activity next year would be focused on delineation and development wells in the company's Sevier discovery, in the area covered by the company's 3-D seismic shoot with Occidental Petroleum in the San Joaquin Valley and, after completion of an anticipated 3-D seismic survey, in the Salinas Valley. "We are shoring up our development plans for the Sevier discovery and have been in contact with the agencies to ensure we have a clear path forward to develop this discovery," said Marquez. "We currently expect to drill 30 to 40 wells there next year."

Venoco plans to drill three to four additional delineation wells in its Sevier discovery during the second half of 2011. The company also continues to expand its onshore Monterey acreage position, which includes approximately 304,000 gross and 214,000 net acres across the Santa Maria, Salinas Valley and San Joaquin basins, the latter of which includes the Sevier discovery. Venoco has a number of people searching for acquisition and leasing opportunities to acquire additional acreage interest.

Marquez said Venoco has completed and started testing one zone in its Sevier 1-29 sidetrack well during the second quarter. "Because this is a redrill, we have smaller casing in the well which limits our production volumes and presents a challenge to reducing fluid levels. With this constraint, we are encouraged by the peak 24-hour rate of 61 BOE/d from that initial zone. We have two other zones in this well to test once we're finished testing the initial zone."

Venoco has had to revise some of the initial concepts from its Monterey shale production offshore from the Sockeye field, which has two different zones of Monterey that are shallower and less naturally fractured. The company has concluded that drilling vertical wells is a more economic way to tap the Monterey shale and that comes in contact with more gross intervals of oil, said Mike Edwards, vice president of corporate and investor relations at Venoco. Venoco's wells likely will be produced through acidization, in which acid is sent to recover mud from the natural fractures, rather than hydraulic fracturing.

Venoco's current focus is on its Sevier discovery, but the company also sees potential for horizontal wells in its Santa Maria prospect area. The company has drilled vertical wells with initial production rates of 1,000 b/d, and believes that particular zones of the prospect area hold potential for horizontal wells.

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KCA Deutag Furthers Presence in S. East Asia with GTB Acquisition

- KCA Deutag Furthers Presence in S. East Asia with GTB Acquisition

Friday, August 05, 2011
KCA Deutag

KCA Deutag announced it has acquired Global Tender Barges Pte Ltd (GTB) by increasing its shareholding from 10 to 100%.

GTB based in Singapore owns three self-erect tender barges, the Global Emerald, Global Jade and Global Sapphire, which KCA Deutag has operated on behalf of GTB, since early 2008, under a management services agreement providing drilling operations, maintenance, procurement and other services connected with the offshore operations.

The transaction will contribute to KCA Deutag approximately US $115 million of annual revenues with substantial EBITDA and will further strengthen the financial profile of KCA Deutag.

The Global Emerald is currently on contract to Brunei Shell Petroleum until 1Q 2012 and the Global Sapphire to Petronas, Malaysia until 2014. The Global Jade has recently demobilized from a long term contract with Total in Indonesia and is bid on a number of long term contracts. The company is finalizing negotiations with one client and expects to be in a position to announce further contract awards in the coming few weeks.

The acquisition increases the scale of KCA Deutag's mobile offshore drilling units (MODU's) division, supplementing its three owned jackups and its other management contract on Triumph Drilling's self-erect tender rig, the Searex IX. It further strengthens KCA DEUTAG's presence in the strategic South East Asia and Mexican markets.

Holger Temmen, KCA Deutag's Chief Executive Officer commented, "This deal is a natural evolution for KCA Deutag, to acquire the remaining 90% equity, in assets that we have operated successfully on behalf of GTB for the last three and a half years. The three rigs have an excellent order backlog and bidding activity in the barge sector remains high, with a number of exciting long term opportunities in South East Asia and West Africa that may also justify investing in newbuild units. We are particularly pleased to be strengthening our relationship with three strategically important clients with whom we already have existing operations.

"South East Asia is attracting very large investments from our major oil company clients and provides exciting growth opportunities for companies in the oilfield services sector. KCA Deutag wish to substantially grow its presence in the region, both in the offshore, land drilling and engineering sectors. In addition to our barge activities, we currently operate our land rig T201 for Brunei Shell Petroleum and are currently executing a Front End Engineering Study for the drilling facilities on Woodside's Browse Field development offshore Western Australia for which we also hope to compete for the long term operations and maintenance contract."

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EOG 2Q Earnings Climb on Production Increase

- EOG 2Q Earnings Climb on Production Increase

Friday, August 05, 2011
EOG Resources Inc.

EOG Resources reported second quarter 2011 net income of $295.6 million, or $1.10 per share. This compares to second quarter 2010 net income of $59.9 million, or $0.24 per share.

Consistent with some analysts' practice of matching cash flow realizations to settlement months, and making certain other adjustments in order to exclude one-time items, adjusted non-GAAP net income for the second quarter 2011 was $299.2 million, or $1.11 per share. Adjusted non-GAAP net income for the second quarter 2010 was $44.9 million, or $0.18 per share. The results for the second quarter 2011 included a $226.2 million, net of tax ($0.84 per share) impairment of certain non-core North American natural gas assets, gains on property dispositions, net of tax, of $105.2 million ($0.39 per share) and a previously disclosed non-cash net gain of $189.6 million ($121.4 million after tax, or $0.45 per share) on the mark-to-market of financial commodity contracts. During the quarter, the net cash inflow related to financial commodity contracts was $6.3 million ($4.0 million after tax, or $0.01 per share). (Please refer to the attached tables for the reconciliation of adjusted non-GAAP net income to GAAP net income.)

Operational Highlights

Total company production increased 13 percent in the first half of 2011 compared to the same period in 2010. Driven by a 60 percent rise in United States crude oil and condensate production during the second quarter, EOG delivered 46 percent total company crude oil, condensate and natural gas liquids production growth versus the second quarter 2010. Leading the crude oil production growth was the South Texas Eagle Ford followed by the Fort Worth Barnett Shale Combo. Also contributing to the increase were newer crude oil and liquids-rich plays such as the Colorado Niobrara, Oklahoma Marmaton, West Texas Wolfcamp and New Mexico Leonard.

"Demonstrating the depth and quality of our portfolio, EOG's crude oil and liquids-rich plays delivered strong, consistent second quarter production results, driving our overall first half 2011 production growth," said Mark G. Papa, Chairman and Chief Executive Officer. "Just as we had forecast, EOG's natural gas production is decreasing due to asset sales and the priority we have placed on developing our outstanding crude oil and liquids investment opportunities."

EOG is on track to achieve its targeted 9.5 percent total company organic production growth for 2011. Total company 2011 crude oil and condensate production is projected to increase by 52 percent, while total company crude oil, condensate and natural gas liquids production is forecast to rise 47 percent over 2010.

Crude Oil and Liquids Activity

Early in its transition to a liquids-focused company, EOG identified the rich oil potential of the South Texas Eagle Ford Shale and amassed a large acreage position in the sweet spot of the crude oil window.

"We are finding that well results across our 535,000 net acre position in the Eagle Ford oil window are remarkably similar. The wealth of drilling, completion and production data at our fingertips is reflected in the steadily rising momentum of our operations and success in achieving more predictable results," Papa said.

As EOG further defines geologic sub-trends and refines completion techniques, the majority of its Eagle Ford wells are being completed to sales at initial production rates in excess of 1,000 barrels of crude oil per day (Bopd). Leveraging this consistency, EOG ramped up its drilling activity from 10 rigs at the beginning of 2011 to its current intensive program of 22 rigs.

In Gonzales County where EOG is actively drilling, the King Fehner Unit #2H, #4H, #5H and #6H wells began initial production at maximum rates ranging from 1,238 to 1,487 Bopd with 1.2 to 1.6 million cubic feet per day (MMcfd) of rich natural gas.

"These are the first Eagle Ford wells that EOG has tested with a tighter spacing pattern. If downspacing proves economically viable, we have the potential to significantly increase our reserves in the Eagle Ford," Papa said.

EOG reported production rates from other successful wells in Gonzales County. The Merritt #4H had a peak initial production rate of 1,361 Bopd with 0.6 MMcfd of rich natural gas. The Steen Unit #1H, #2H, #4H and #6H came online with production rates ranging from 663 to 1,269 Bopd with 0.7 to 1.4 MMcfd of rich natural gas. In its far northeastern acreage where EOG announced success from a fault block earlier this year, the Hill Unit #1H and #3H were completed. They flowed to sales at peak rates of 1,461 and 1,734 Bopd with 1.0 and 1.3 MMcfd of rich natural gas, respectively.

In LaSalle County, the Naylor Jones A #2H, 99 #1H and 96 #1H provided additional confirmation of the consistent quality of EOG's 120-mile acreage trend. The wells, located in the southwestern part of EOG's block, had strong production rates ranging from 997 to 1,153 Bopd with 1.0 to 2.3 MMcfd of rich natural gas. In Karnes County, the heart of EOG's extensive acreage, the Max Unit #1H had a peak initial production rate of 1,591 Bopd with 1.5 MMcfd of rich natural gas. Also in Karnes County, the Braune Unit #1H was turned to sales at an initial rate of 1,611 Bopd with 1.0 MMcfd of rich natural gas. EOG has 100 percent working interest in all 16 of these Eagle Ford wells.

"With the 77 percent crude oil mix of our Eagle Ford acreage position, this large, highly rated resource play has become a significant contributor to fueling EOG's transition to an oil company in a short period of time," Papa said.

EOG announced positive drilling results from a new horizontal crude oil play, the Marmaton sandstone in the Oklahoma Panhandle. In Ellis County where EOG has drilled a series of wells, the Brown 18 #1VH and Opal 31 #1H were completed to sales at production rates of 620 and 1,312 Bopd with 0.7 and 2.6 MMcfd of natural gas, respectively. EOG has 58 and 49 percent working interest in the wells, respectively. EOG has 88 percent working interest in the Fischer 12 #1VH, which began initial production at 508 Bopd, with strong natural gas production. Encouraging well results provide the potential for additional development drilling locations on its 34,000 net acre position. To identify further exploration opportunities, EOG plans to acquire 3D seismic over this acreage.

EOG continues to post excellent drilling results from its 131,400 net acre position in the West Texas Wolfcamp and its 108,000 net acre position in the New Mexico Leonard Shale and Bone Spring Sands plays. The current moderate level of drilling activity is expected to ramp up in 2012 and beyond. Following refinements in completion techniques, recent well results show improvement in crude oil production flow rates.

Drilled and completed in the West Texas Wolfcamp, the University 40-A #0401H began flowing to sales at a maximum oil rate of 935 Bopd with 838 thousand cubic feet per day (Mcfd) of rich natural gas. EOG has 85 percent working interest in this Irion County well. Also in Irion County, the Linthicum M #1H and I #5H had production rates of 809 and 664 Bopd with 892 and 1,178 Mcfd of rich natural gas, respectively. EOG has 75 and 85 percent working interest in the wells, respectively. EOG has 100 percent working interest in the University 9 #2802H, drilled in Reagan County, northwest of its Irion County and Crockett County activity. The well had a peak production rate of 583 Bopd with 254 Mcfd of rich natural gas.

In Lea County, New Mexico where EOG is developing its Leonard Shale acreage, the Caballo 23 #1H was completed at a production rate of 665 Bopd with 1.2 MMcfd of rich natural gas. EOG has 86 percent working interest in the well. In Eddy County, the Elk Wallow 11 St. #4 had a maximum production rate of 735 Bopd with 2.0 MMcfd of rich natural gas. EOG has 75 percent working interest in this Leonard Shale well. Also in Eddy County, EOG drilled the Parkway 23 State #3H in the Bone Spring Sands, which is producing 511 Bopd with 726 Mcfd of natural gas. EOG holds 81 percent working interest in the well.

Since mid-2009, EOG's Denver-Julesburg Basin drilling activity has been concentrated on its 80,000 net acre Hereford Ranch Field in Weld County, Colorado. The Jake 2-01H discovery, which was drilled as a horizontal well targeting the Niobrara formation, began initial production in late 2009 at a first month average rate of 645 Bopd. Since the first quarter 2011, it has been producing at a relatively stable rate of 250 to 300 Bopd. Following the Jake well, the Elmer 8-31H, which was drilled in March 2010 with a short lateral, had an initial average 30-day production rate of 283 Bopd and is currently producing approximately 225 Bopd. Encouraging data from long-term stabilized crude oil production rates indicate that the Niobrara wells will be characterized by lower initial flow rates, but flatter decline curves than other crude oil resource plays.

Acreage outside EOG's Hereford Ranch Field was also proven productive during the quarter. Southeast of the Hereford Ranch Field, the Fiscus Mesa 9-10H was drilled and completed to sales at an initial controlled rate of 335 Bopd with 174 Mcfd of natural gas. EOG has 86 percent working interest in the well. West of the Fiscus Mesa well, EOG has 75 percent working interest in the Gravel Draw 9-09H that began production at an initial controlled rate of 277 Bopd with 146 Mcfd of natural gas. Based on long-term well production results from its Hereford Ranch Field and new drilling results and production data, EOG has established the economic potential for crude oil development on 169,000 of its 220,000 net acre Niobrara position.

In the Texas Fort Worth Barnett Combo, EOG's program in Montague County and western Cooke County continues to deliver successful production results with efficiency gains in both drilling and completion operations. In western Cooke County, the Gaedke A Unit #3H and #4H and B Unit #5H, #6H and #7H wells were brought to sales at rates ranging from 338 to 696 Bopd with 807 to 2,152 Mcfd of rich natural gas. EOG has 99 percent working interest in the wells. In Montague County, EOG has 100 percent working interest in the Stoddard A Unit #1H, B Unit #2H, C Unit #3H and D Unit #4H that came online at rates ranging from 777 to 918 Bopd with 1,262 to 2,677 Mcfd of rich natural gas. While EOG's efforts have focused on testing new completion techniques in the sweet spot of its core acreage, an inventory of several years of drilling locations has been identified in the play.

Despite weather challenges in the North Dakota Williston Basin over the last eight to nine months, EOG continued its drilling and production activities, as well as operating its proprietary crude-by-rail transportation system. Although EOG minimized the adverse impact of abnormally wet weather on production goals during the second quarter, completion operations were impacted and area flooding remains an issue.

Drilled with a 9,968 foot long-reach lateral, the Liberty LR #21-36H was completed to sales at a maximum rate of 1,201 Bopd with 1,147 Mcfd of natural gas. EOG has 95 percent working interest in the well. The Fertile #19-29H and #45-29H were both completed in the Bakken formation in Mountrail County. The wells, in which EOG has 38 and 75 percent working interest, respectively, came online at maximum rates of 1,008 and 1,223 Bopd, respectively. In Williams County, EOG has 67 percent working interest in the Hardscrabble 13-3526H, which began flowing to sales at 1,474 Bopd. EOG holds 85 percent working interest in the Clarks Creek 3-0805H, which was completed in the Three Forks formation in McKenzie County at a maximum production rate of 1,384 Bopd.

"EOG's early innovative crude-by-rail midstream investments in the Bakken and Eagle Ford have proven valuable in delivering our crude oil directly to major market hubs given the current lack of available pipeline capacity in these two prolific plays," Papa said. "Our Bakken crude oil rail transportation system was particularly beneficial during the recent North Dakota flooding because it enabled EOG to continue to make crude oil deliveries."

Natural Gas Activity

In North America, EOG's natural gas production decreased 1.6 percent in the second quarter compared to the same prior year period due to reduced drilling activity and natural gas asset sales. In the United States where EOG is employing drilling capital to maintain core leasehold positions, it posted strong operational results from its Marcellus Shale and Haynesville/Bossier Shale natural gas horizontal resource plays. In Canada, EOG's natural gas production decreased due to asset divestitures and the reallocation of capital toward liquids-rich reinvestment opportunities.

Capital Structure

During the second quarter, total cash proceeds from sales of acreage, producing natural gas properties and midstream assets were approximately $684 million. Through the first half of 2011, total cash proceeds from assets sales were $944 million. Based on negotiated purchase and sale agreements and other pending transactions, EOG anticipates property sales for the full year of approximately $1.6 billion, or $600 million higher than the original $1 billion target for 2011. Estimated exploration and production expenditures will range from $6.8 billion to $7.0 billion, including exploration, development and production facilities and midstream expenditures, an increase of approximately $400 million from EOG's previously stated targets.

At June 30, 2011, EOG's total debt outstanding was $5.2 billion for a debt-to-total capitalization ratio of 30 percent. Taking into account $1.6 billion of cash on the balance sheet at the end of the quarter, EOG's net debt was $3.6 billion for a net debt-to-total capitalization ratio of 23 percent. EOG is targeting a net debt-to-total capitalization ratio of 30 percent or less at both year-end 2011 and 2012. (Please refer to the attached tables for the reconciliation of net debt (non-GAAP) to current and long-term debt (GAAP) and the reconciliation of net debt-to-total capitalization ratio (non-GAAP) to debt-to-total capitalization ratio (GAAP).)

"Our well-timed efforts to recreate EOG as a high margin, crude oil-focused company are paying off," Papa said. "On the basis of both per share earnings and cash flow growth, EOG is positioned to be an industry leader for years to come."

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Shell Wins Tentative Approval for Offshore Arctic Drilling

- Shell Wins Tentative Approval for Offshore Arctic Drilling

Friday, August 05, 2011
Knight Ridder/Tribune Business News
by Richard Mauer

Shell cleared a major hurdle Thursday in its effort to begin a two-year drilling program in the Arctic Ocean next summer, receiving a conditional exploration permit from the federal agency that oversees off-shore oil development.

The company said it was buoyed by the morning announcement from the Interior Department's Bureau of Ocean Energy Management, Regulation and Enforcement, just as Interior Secretary Ken Salazar was preparing for an Alaska visit next week at the invitation of Sen. Lisa Murkowski, R-Alaska.

That congressional tour, which will also include Sen. Jack Reed, D-R.I., chairman of the Interior Appropriations Subcommittee, will focus on energy issues.

The exploration permit covers an overall program that would drill four wells over two years in Camden Bay of the Beaufort Sea, due north of the coastal plain of the Arctic National Wildlife Refuge.

But the permit is contingent on many other federal permits and approvals, among them governing air pollution from drill ships and companion vessels, oil-spill response plans, marine mammal protection and specific plans for each of the wells. A Shell spokesman in Alaska, Curtis Smith, said the company has been informed that at least the oil-spill response plan is near conclusion and will be approved next week.

Representatives of several environmental organizations, in a joint telephone news conference from Washington, D.C., said they were disappointed by the decision and were studying whether to challenge it in court. Erik Grafe, an Anchorage-based attorney for Earthjustice, said they had 60 days to file a lawsuit.

Grafe and the others said the federal approval was granted before Shell proved it could clean up an oil spill in the Arctic. They said the drilling program should have been subject to a full-blown environmental impact statement with public comment and additional research, not the more limited environmental assessment that the agency conducted.

The agency found no evidence that Shell's exploration "would significantly affect the quality of the human environment," a key for rejecting the need for an environmental impact statement.

Shell is also seeking authorization to drill in the Chukchi Sea about the same time as in the Beaufort. That application is pending.

Alaska's congressional delegation had been pressing for agency action this year and quickly praised the decision.

"Shell has been working to secure approval of this plan for over five years," Murkowski said in a prepared statement. "This is another positive step forward, and I'm hopeful that they will soon be able to move forward with exploration and production in the Beaufort."

She, U.S. Sen. Mark Begich, D-Alaska, and Rep. Don Young, R-Alaska, said the exploration project would create jobs and, if commercial development followed, could forestall problems with the trans-Alaska pipeline associated with declining oil flow.

Shell first won the Beaufort leases in 2005 and 2007. The company began applying for permits, but the Deepwater Horizon oil spill in the Gulf of Mexico in 2010, and the moratorium on new offshore drilling that followed, set Shell back.

In the aftermath of the spill, Shell bolstered its oil-spill prevention and response capability. On the federal side, one government agency, the Minerals Management Service, was replaced with another, the Bureau of Ocean Energy Management, Regulation and Enforcement. Shell had to resubmit its revised plans.

"Since Deepwater Horizon, BOEMRE has made significant improvements to the regulation and oversight of offshore oil and gas development," the agency said through a spokesman. "Permit applications for drilling projects must meet new standards for well-design, casing, and cementing, and be independently certified by a professional engineer per the new drilling safety rule. All of these improvements and experiences will go into further reviews of oil spill response plans."

In addition to obtaining more spill-response equipment, Shell says it is adapting technology being developed for the Gulf of Mexico that would allow drillers to quickly cap a damaged well or direct oil from a blow-out to tankers on the surface.

Copyright (c) 2011, Anchorage Daily News (Anchorage, Alaska). Distributed by Mclatchy-Tribune News Service.

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Det norske to Spin Bit in Southern North Sea

- Det norske to Spin Bit in Southern North Sea

Friday, August 05, 2011
Det norske oljeselskap ASA

Det norske received Petroleum Safety Authority Norway's (PSA) consent to drill the Ulvetanna prospect, with exploration well 3/4-2S, yesterday. The prospect is located in block 3/4 in production license 356 in the southern North Sea.

The well will be drilled with the jack-up rig Maersk Guardian. Planned start-up is in the end of the third quarter of this year.

The main objective of the drilling is oil in the Ekofisk- and Tor formations. The well will be drilled to a depth of approximately 3,050 meters. Water depth in the area is 51 meters.

Det norske is the operator of the license with a 60 percent stake. Repsol entered the license last year, and has 40 percent stake. The license was awarded in APA 2005.

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BPMigas: ExxonMobil, Partners Need $1.3B to Develop Cepu Block

- BPMigas: ExxonMobil, Partners Need $1.3B to Develop Cepu Block

Friday, August 05, 2011
Dow Jones Newswires
by Deden Sudrajat

ExxonMobil and its partners will need to invest around $1.3 billion to fully develop their oil production facility in the Cepu Block in Java, the head of the Indonesian oil and gas sector watchdog said Friday.

Raden Priyono, the chairman of upstream oil and gas regulator BPMigas, estimated production at the Banyu Urip oil field can reach 165,000 barrels of crude a day at full capacity, compared with the current 20,000 barrels a day.

Exxon has picked a consortium of Samsung Engineering and PT Triparta as a partner for one of its five engineering, procurement and construction contracts in Banyu Urip. The $746.3 million contract was the biggest and the first to be signed. BPMigas' Priyono expects the remaining contracts to be signed later this year.

Mobil Cepu and Ampolex (Cepu) Pte. Ltd., both subsidiaries of Exxon Mobil, have a combined 45% stake in the block, while Pertamina EP Cepu owns 45% and the Cepu Block Cooperation Body, or BKS, holds the remaining 10%.

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

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Apache Resumes Production at Van Gogh

- Apache Resumes Production at Van Gogh

Friday, August 05, 2011
Apache Corp.

Production has resumed at the Apache-operated Van Gogh development offshore Western Australia after the completion of repairs on the Ningaloo Vision floating production, storage and offloading vessel.

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Keppel Secures 3rd Transocean High Specification Jackup

- Keppel Secures 3rd Transocean High Specification Jackup

Friday, August 05, 2011
Keppel Corp. Ltd.

Keppel FELS Limited (Keppel FELS) has secured a repeat order from Transocean Offshore Deepwater Holdings Ltd, a subsidiary of Transocean Ltd. (Transocean) for US $195 million.

Following its order of two jackup rigs from Keppel FELS on February 17, 2011, Transocean is exercising its option to build another high specification jackup rig based on the KFELS Super B Class Bigfoot design for delivery in 3Q 2013.

Mr. Wong Kok Seng, Managing Director of Keppel FELS said, "We are pleased that Transocean has chosen to exercise their option in building another jackup rig to our proprietary design. We have developed a winning collaboration with Transocean over the years through numerous projects. In working with forward thinking customers, we are able to customize innovative products well suited to meet the needs of the market."

Tailored to suit Transocean's requirements, the KFELS Super B Class Bigfoot is designed with larger spud cans, expanding its operational coverage to more places, especially areas where soft soil is predominant. Having larger spud cans enables the unit to operate efficiently while minimizing potential leg penetration problems in soft soil conditions.

With a 1.5 million pound drilling system and a maximum combined cantilever load of 3,200 kips, the Super B Class Bigfoot features immense horsepower during drilling operations. In addition, the rig will be installed with offline stand building features in its drilling system package which allows drilling and the preparation of drill pipes to take place at the same time. The rig is capable of drilling at a 75 feet outreach, allowing for coverage of a larger well pattern.

Keppel FELS and Transocean have shared a long-standing partnership spanning several significant projects. In 2009, Keppel delivered Transocean's Development Driller III, an ultra-deepwater drilling semisubmersible rig built to Keppel's proprietary DSSTM 51 semisubmersible design. Other projects include upgrades and conversions of the Sedco 700-series semis to enable dynamic positioning, and the repair of various Transocean rigs.

The above contract is not expected to have material impact on the net tangible assets or earnings per share of Keppel Corporation Limited for the current financial year.

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