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Oil and Gas Energy News Update

Thursday, July 14, 2011

Oil & Gas Post - All News Report for Thursday, July 14, 2011

Thursday, July 14, 2011

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Commodity Corner: Oil Down on Bernanke Comments

- Commodity Corner: Oil Down on Bernanke Comments

Thursday, July 14, 2011
Rigzone Staff
by Saaniya Bangee

Oil futures plummeted Thursday after Federal Reserve Chairman Ben Bernanke stifled expectations of the Federal Reserve providing additional monetary aid. During the Fed's semiannual policy report, Bernanke explained that as of now, the central bank would not be releasing further funds.

The news sent the dollar soaring. A stronger greenback pressures oil prices making the dollar-denominated commodities more expensive for foreign buyers.

Easing the drop in prices, the U.S. Labor Department reported that the number of claims for unemployment benefits decreased by 22,000—the lowest in three months. In spite the decrease, application levels remain above 400,000, representing a weak job market.

In early trading, crude futures rose as high as $98.88 a barrel, before settling at $95.69 on the New York Mercantile Exchange (NYMEX).

Front-month Brent ended the August contract at $118.32 a barrel on the ICE Futures exchange. The intraday range for Brent crude was $117.73 to $119.40 a barrel.

Meanwhile, natural gas for August delivery lost 2.9 cents to end Thursday's session at $4.36 per thousand cubic feet. According to the U.S. Energy Information Administration, natural gas inventory grew by 84 billion cubic feet. Prices peaked at $4.41 and bottomed out at $4.25 Thursday.

Reformulated August gasoline blendstock also traded lower, settling at $3.12 a gallon. Gasoline futures traded between $3.094 and $3.159 Thursday.

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Welltec Inks Major Contract with Petrobras

- Welltec Inks Major Contract with Petrobras

Thursday, July 14, 2011

Welltec has signed a major contract in Brazil with Petrobras; contract value will be in excess of $15MM for a duration of up to 4 years. Welltec has been selected as the primary service provider for electric line tractor conveyance as well as for a wide portfolio of mechanical intervention services including milling, cleaning, plug setting and sliding sleeve manipulation. These services will allow Petrobras increased flexibility in planning and executing their land as well as their offshore and subsea activity with a higher degree of safety and certainty through the application of Welltec's unique, high precision, robotic technologies.

According to Jorgen Hallundbaek, Chief Executive Officer, Welltec, "We worked diligently with Petrobras to finalize this agreement and both parties are excited about beginning the work. Petrobras have often recognized our capabilities as the premier tractor conveyance company but have also come to realize the value our mechanical intervention services enabled on electric line can provide them. Using Welltec can dramatically reduce the footprint, the number of lifting operations and the rig up time at the well location versus conventional heavier intervention methods. This contract provides Welltec with a great platform to further its expansion in an important, rapidly expanding, deep water market."

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Department of Energy Grants DTE Energy $5.4M

- Department of Energy Grants DTE Energy $5.4M

Jul 14, 2011

DTE Energy (NYSE:DTE) received a $5.4 million federal grant through the Clean Energy Coalition to fund the conversion of more than 170 gasoline-powered fleet vehicles to use compacted natural gas.

The grant that was awarded to Clean Energy Coalition's Green Fleets program by the U.S. Department of Energy under the American Recovery and Reinvestment Act also pays for the building of two new CNG fueling stations and the refurbishment of 11 others across the state of Michigan.

DTE Energy has a potential upside of 1.3% based on a current price of $50.08 and an average consensus analyst price target of $50.71.

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A Close Bond Built on Friendship - And Oil

- A Close Bond Built on Friendship - And Oil

Thursday, July 14, 2011
The Washington Post
by Juan Forero;Adam Liebendorfer

Something wasn't quite right, Hugo Chavez recounted. And the Venezuelan president's mentor, 84-year-old Fidel Castro, noticed straight away.

"What's wrong with you?" Castro asked. The Cuban leader urged Chavez to stand up and looked him over with what the Venezuelan populist called Castro's "eagle eyes." "Where's the pain?"

Castro then "began to question me, like a father questions a son," Chavez said in his account of their meeting in Havana last month; he said he "confessed" his ailments as if he were Castro's patient.

At the Cuban revolutionary's insistence, Chavez then went under the scalpel to remove a malignant tumor. Later, Castro brought peanut butter he himself had made and gabbed with a recovering Chavez about world affairs. "Fidel is like a saint," Chavez told Cuban state television.

The outsize role that Castro has played in Chavez's ordeal with cancer has brought into sharp relief not only the personal, even paternal nature of their relationship, but also how vital Chavez's health is to Cuba's archaic communist system.

The links the two leaders have forged are based on heartfelt kinship, Chavez's government says. But the Cubans also have a lot riding on Chavez, who on Wednesday announced that he may undergo chemotherapy or radiation treatments. Since taking office in 1999, Chavez has shipped tens of billions of dollars in subsidized oil to the island.

"For the Cubans, this is not just an ideological friend and ally - he's a lifeline for the island economy," said Moises Naim, a Venezuelan who is a senior associate at the Carnegie Endowment for International Peace in Washington. "It's a matter of regime survival to ensure that a Cuban-friendly government is in power in Venezuela."

The friendship between the two men, who are separated by 28 years in age but share ideological affinities that include antipathy for the United States, has periodically been on display over Chavez's 12 years in power.

In 1999, before Castro's own health began to deteriorate, the two played baseball together before 55,000 spectators, appeared on Chavez's "Hello President" TV show and even sang folk songs (Chavez has the upper hand as a crooner).

In 2002, when Chavez was briefly ousted, Castro marshaled the support of Latin American presidents to help weaken the coup plotters who had seized power. More recently, as U.S. diplomatic cables made public by WikiLeaks show, Cuban intelligence officers operating in Venezuela have directly provided information to Chavez, unfettered by Venezuelan officers.

The bond is so tight, in fact, that Chavez's former common-law wife, Herma Marksmen, told American diplomats that Chavez confides in only two people, Castro and his elder brother, Adan.

Here in Venezuela, some of the trappings of Cuba's system are clearly evident: a powerful state propaganda apparatus; the state seizure of companies; the spread of fervent, pro-government neighborhood groups; and the use of the military slogan "Fatherland, socialism or death!"

But in spite of the revolutionary partnership, Venezuela clearly plays the more important role. With huge oil reserves, it replaced the benefactor to Cuba that was lost with the Soviet Union's breakup two decades ago. The 100,000 barrels of oil Cuba receives each day literally keep the lights on, particularly vital now as the Cuban government tinkers with economic liberalization measures to stay afloat.

"So if, let's just say the Venezuelan subsidy ended for whatever reason, Cuba would have a pretty short window - probably weeks, no more than a month or two - to make some very, very severe adjustments," said Brian Latell, a former CIA analyst and the author of "After Fidel: The Inside Story of Castro's Regime and Cuba's Next Leader."

So Chavez's ailment, made public in a carefully orchestrated speech from Havana, was quickly felt across Cuba, which had already seen Castro hand over the presidency to his brother, Raul, in 2006 after being sidelined by an intestinal illness.

Venezuelan oil allows Raul Castro to "buy time in the face of citizen discontent," Yoani Sanchez, the author of the Havana-based blog Generation Y, wrote this month, while the loss of Chavez "could hasten Raul's own downfall."

While some Cuba experts disagree with such a dour scenario, there is no doubt that Fidel Castro made sure Chavez got the best of care.

When the surgery was over, Castro brought treats such as lamb and tilapia. He was so pleased by Chavez's recovery, the Venezuelan president recalled, that Castro appeared "luminous, joyous, optimistic."

Chavez, who returned to Caracas last week, has yet to reveal what kind of cancer he has. But speaking on Cuban television, he was emphatic about Castro's role.

"If not for Fidel," Chavez said, "who knows where or in what labyrinth I would be in now."


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'Fracking' Has EPA Seal of Approval

- 'Fracking' Has EPA Seal of Approval

Thursday, July 14, 2011
Mclatchy-Tribune News Service.
by Andrew P. Morriss

Natural gas is clean and cheap compared to other forms of energy. Over the last few years, U.S. and world natural gas reserves have soared - U.S. reserves are up by over a third - as we've discovered how to apply the technique known as fracking to unleash gas trapped in deep underground shale formations.

Fracking involves pumping a mixture of water, sand and chemicals under pressure into underground formations, releasing the gas trapped there. Some of the material pumped in returns to the surface; some remains underground where it props open the fractures created in the formation.

The technique has been in use in the United States since the 1940s and it has been used around the world for decades in both oil and gas production. What is new is its effectiveness as methods are refined and the extent of the areas where it can be used cost effectively.

This has revolutionized America's energy picture. Shale gas made up just 1 percent of our gas supply in 2000; today it represents 25 percent.

In the early 2000s, plans were under way to build liquefied natural gas terminals to import natural gas from the Middle East. Today we are retrofitting our ports to allow us to export it. Natural gas prices have fallen to a quarter of their 2000 price, in large part as a result of this dramatic increase in supply.

As we discover new shale formations with recoverable gas, we face some difficult technical and legal issues. The liquid residue can pose risks to ground water and pumping pressurized liquid into the ground can affect neighbors' properties.

However, thus far fracking's dangers are mostly theoretical. Earlier this year EPA Administrator Lisa Jackson - certainly no friend to the hydrocarbon energy industry - told Congress that there had been "no proven cases where the fracking process itself has affected water."

"We have in place a national regulatory system to protect ground water and well developed principles of property law that protect neighbors," she testified. "We don't need more rules, just consistent application of those we have already."

Indeed, all forms of energy production involve side effects. Consider these examples:
  • Wind and solar energy production require extensive use of rare earth minerals. Almost all of these minerals are imported from China where their production often triggers environmental disasters. The British Daily Mail's investigation into rare earth production for renewable energy earlier this year quoted Greenpeace China as saying "There's not one step of the rare earth mining process that is not disastrous for the environment."
  • Ethanol poses serious threats to water in the Midwest, both from its water-intensive production draining aquifers faster than they recharge and from groundwater pollution from increased fertilizer use in growing corn.
  • Nuclear plants require disposal of long term radioactive wastes. Coal plants emit both conventional pollutants and greenhouse gases, while mining risks lives and the environment.

Unless we are willing to drastically reduce our energy use - and so diminish our access to energy-intensive goods like pharmaceuticals and computers - we cannot reject every advance in energy production.

And unlike renewable energy firms such as General Electric and Archers Daniels Midland, the natural gas industry doesn't have its hand out asking for subsidies. Making sure we do not shut down development of our natural gas reserves with ill-considered regulatory measures is critical to our energy future.

(C) 2011 Mclatchy-Tribune News Service.. All Rights Reserved

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Shell Seeks Best Drilling Sites in Butler, Lawrence Gas Fields

- Shell Seeks Best Drilling Sites in Butler, Lawrence Gas Fields

Thursday, July 14, 2011
Knight Ridder/Tribune Business News
by Timothy Puko, The Pittsburgh Tribune-Review

Bill Langin is playing a giant game of Battleship in Butler and Lawrence counties, using a drill rig to plot targets in the Marcellus shale.

Langin is in charge of Appalachian exploration for Royal Dutch Shell plc, which holds the mineral rights to about 100,000 acres in the two counties and more land in northern Pennsylvania. About a year ago, Shell bought East Resources Inc. of Marshall for nearly $5 billion, and the company just finished drilling its first well in this part of the state.

Langin, 34, of Moon is not a wildcatter looking to drill in the sweetest spots he can find. His job is to drill in outlying areas, looking for data, zoning in on targets he cannot see. He asks: Where can Shell drill in its Appalachian holdings and profit?

"Sometimes (the testing) works; sometimes it doesn't. It's kind of sketchy, so the only way you can really gauge the production is once you drill a well," said Langin, a Luzerne County native and Ivy League graduate who spent most of his career working on projects in the Gulf of Mexico and off the shore of Brazil.

His team of 12 geologists and engineers does radiation testing, taking thousands of feet of core samples from underground and reviewing production data from other wells. To answer questions that data cannot, they drilled an 8,600-foot exploration well in Little Beaver, Lawrence County. Its rig is 142 feet tall, twisting thousands of feet of steel pipe into the earth. At the bottom, the well reaches out 5,000 feet sideways into the next town.

The work in this fringe area of the Marcellus shale fairway is part of escalating drilling in Butler and Lawrence counties. Shell also is tapping into the Utica shale, a gas-rich layer that is deeper and extends beyond the Marcellus formation.

Shale gas extraction in Pennsylvania remains under a spotlight, and corporations such as Shell, Exxon Mobil Corp. and Chevron Corp. moved into the region a year ago, buying big stakes. The companies have different ways of estimating potential quantities of gas, experts said.

"They're not just looking at their own land. They're evaluating all of it," said Anthony Ingraffea, professor of civil and environmental engineering at Cornell University. "Eventually it's going to be the last four or five (companies) standing, and Shell plans to be one of those."

Shell plans to bring in a drill rig dedicated to the region next year. If things go well, it could add nine more. The company will spend two to four years determining how rich the land is with gas, and whether to drill here before tapping other oil and gas fields around the world, Langin said.

Shell continues to lease land in Butler and Lawrence counties, adding about 30,000 acres to the 70,000 it bought from East last year, Langin said. Its big-picture exploration methods not only help the company gauge and manage holdings, but help its officials to decide where to lease land, said Badie Morsi, director of the University of Pittsburgh's Petroleum Engineering Program.

It's difficult to determine how much gas the Marcellus shale will produce in a given location. Pressure and natural fractures vary, Morsi said, meaning drillers can only approximate reserves.

"It's very difficult to make generalizations," Morsi said. "It depends upon your luck. You're shooting in the dark at 10,000 feet. It's not a known thing where you go in and grab it."

It's common for multinational corporations such as Shell to take the time for advance work, Morsi said. If they drill edge areas first, the production there can indicate how much gas is inside the circle, he said.

That helps companies to plan efficiently for infrastructure costs, such as pipelines and compressor and processing stations, Langin said. They know the gas is there, but they must figure out how much is there and how hard it is to extract -- then they can determine how high gas prices must be before drilling would be profitable.

Texas-based Range Resources also has holdings in Butler County. It tapped the first successful Marcellus well more than six years ago in Washington County, and being first on the scene brought competitive advantages, spokesman Matt Pitzarella said.

Instead of expanding in new territory, the company is concentrating on Washington and Lycoming counties, where shale formations hold gas and other marketable resources, Pitzarella said.

Range touts research from global financial services firm Morgan Stanley that says those Marcellus areas could turn a 10 percent initial profit, even with natural gas prices as low as $3 per million British thermal units (Btus) on the New York Mercantile Exchange. Natural gas futures for August delivery closed Friday at $4.2 per million Btus.

"It's not that we don't like those areas (north of Pittsburgh), but we're focused on where we believe our highest rate of return is," Pitzarella said.

Copyright (c) 2011, The Pittsburgh Tribune-Review

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Nextraction Increases Position in Provost Viking Play

- Nextraction Increases Position in Provost Viking Play

Thursday, July 14, 2011
Nextraction Energy Corp.

Nextraction has substantially increased its leasehold position in the Provost Viking A oil pool by 92%, increasing its net acreage position from 1.625 to 3.125 sections (1040 acres to 2000 acres). Nextraction acquired one section at a 100% working interest (640 acres net to Nextraction) at a cost of $701,584, and one section at a 50% working interest (320 acres net to Nextraction) at a cost of $401,088. The two newly acquired sections are contiguous to each other and are one mile from the Company's existing 50/50 joint venture acreage, allowing for the potential to use existing infrastructure. The acquisition essentially doubles the Company's drilling inventory of horizontal locations up to 36 wells. Nextraction has identified 21 locations on 400 meter spacing whereby the Company could drill at least 4 wells owning 100% interest, and own a 50% interest in 17 locations (resulting in a further 8.5 net wells). In addition, another 15 locations may be drilled at a 50% interest (7.5 net wells), should down spacing be warranted.

The acreage is also prospective for light oil production from the Dina formation that is approximately 150 meters below the Viking formation. A historical well on the acreage produced 18 Mbbls of oil from the Dina formation.

The Company is also pleased to announce that it participated in the successful re-completion of a well on its existing acreage. The well had not been previously fracture stimulated, so the well was fractured using the same technique the Company plans to use on its first horizontal well. Prior to re-completion of the well in mid-June, it produced three barrels of oil per day and is now currently producing 29 barrels of light oil per day, a ten-fold increase. Payout is projected at three months.

The Company is encouraged by the results of the frac as it confirms the high productivity potential of the Company's acreage. The well has been producing for two years and is located directly between two wells that have cumulatively produced 520 Mbbls to date and continue to produce 20 bbls per day of oil. Reservoir pressure measured after completion was near original pressure, suggesting little depletion. The high production rates from the well are consistent with the high pressure and indicate good quality reservoir, as expected. The Company is currently drilling its first horizontal well in the pool offsetting these wells and plans to multi-stage fracture this first horizontal well in the Viking zone in the coming days. The Company also plans to drill a second horizontal well on this joint venture acreage in the third quarter of 2011.

Mark S. Dolar, President & CEO of Nextraction, commented, "We value the Crown leases acquired yesterday as a strategic asset to our Company's growth. We believe the acreage to be very prospective for a multi-well development program and will expand our ability to focus on developing the Viking formation for value added reserves. With our experience and expertise in developing the Viking sand by horizontal drilling and multi-stage fracturing, we see this project as an excellent way to add significant oil reserves as we move towards our goal of being 80% light oil weighted by the end of this year."

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InterOil Completes Well at San Luis Field

- InterOil Completes Well at San Luis Field

Thursday, July 14, 2011

InterOil has completed the second well, 13164D, on the San Luis Field in Peru. The well is producing 795 BOPD through a 5/16" choke. This is significant higher than the estimated 350 BOPD.

Well 13164D encountered a separate segment on the San Luis Field, with several oil bearing sands in the Salina Mogollon Formation. Pressure data support the interpretation of a new segment and show no sign of depletion from neighboring wells. This pay-zone is thicker than any of the zones drilled so far on the San Luis Field. San Luis will be further evaluated in order to map out the additional potential this segment can have for future drilling. The full potential of this new segment will be better understood after 2-3 months of production.

Drilling of the third well, 13157D, is ongoing. The well will be drilled as an appraisal well to the San Luis Field in a North Eastern position and is expected to be completed in the beginning of August.

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Magnum Hunter Sees 133% Increase in Reserves

- Magnum Hunter Sees 133% Increase in Reserves

Thursday, July 14, 2011
Magnum Hunter Resources Corp.

Magnum Hunter announced a 133% increase in the quantity of the Company's estimated total proved reserves at June 30, 2011 as compared to December 31, 2010. The present value of estimated future cash flows, before income taxes, of the Company's estimated total proved reserves as of mid-year 2011, discounted at 10% ("PV-10"), also increased 141% as compared to six months ago at year-end 2010.

Magnum Hunter's total proved reserves increased by 17.8 million barrels of oil equivalent (Boe) to 31.2 million Boe (55% crude oil & ngl; 50% proved developed producing) as of June 30, 2011 as compared to 13.4 million Boe (51% crude oil & ngl; 44% proved developed producing) at December 31, 2010. The Company's reserve life (R/P ratio) was approximately 17.3 years as of June 30, 2011.

The Company's PV-10 at June 30, 2011 increased by $250 million or 141% to $428 million from $178 million at December 31, 2010. Under new SEC guidelines, the commodity prices used in the December 31, 2010 and June 30, 2011 PV-10 estimates were based on the 12-month unweighted arithmetic average of the first day of the month price for the periods January 1, 2010 through December 31, 2010, and July 1, 2010 through June 30, 2011, respectively, adjusted by lease for transportation fees and regional price differentials. For crude oil and ngl volumes, the average West Texas Intermediate posted price of $89.96 per barrel at June 30, 2011, was up 13% from the average price of $79.43 per barrel at December 31, 2010. For natural gas volumes, the average price of the Henry Hub spot price of $4.20 per million British thermal units ("MMBTU") at June 30, 2011 was down (4%) from the $4.37 per MMBTU at December 31, 2010. All prices were held constant throughout the estimated economic life of the properties.

Note: PV-10 is a non-GAAP financial measure and should not be considered as an alternative to the standardized measure of discounted future net cash flows as defined under GAAP; see "Non-GAAP Measures: Reconciliation to Standardized Measure" below for the Company's definition of PV-10 and a reconciliation to the standardized measure.

The Company's June 30, 2011 total proved reserves of 31.2 million Boe reflect an organic growth of 6% from the Company's pro forma proved reserves of 29.4 million Boe as of December 31, 2010, when including the proved reserves related to the Company's acquisition of the assets of NGAS Resources, Inc. and NuLoch Resources, Inc., which occurred on April 13, 2011 and May 3, 2011, respectively. Magnum Hunter's first half of fiscal year 2011 organic extensions and discoveries from drilling activities replaced the Company's estimated production through June 30, 2011 by a factor of four times. When including the first six months of fiscal year 2011's property acquisition activities, the replacement of production factor for the first six months of fiscal year 2011 increased by approximately 20 times.

The estimates of Magnum Hunter's total proved reserves as of December 31, 2010 and June 30, 2011 were prepared by the Company's third-party engineering consultants.

Resource Potential

The Company's internal engineering team has evaluated the resource potential of Magnum Hunter's existing undeveloped lease acreage position in our three unconventional shale plays. The undeveloped acreage evaluated includes 652,419 gross acres and 347,547 net acres to Magnum Hunter's ownership interest.

The current number of total new drilling locations in Magnum Hunter's inventory today is approximately 4,000 of which 1,350 are identified drilling locations in these three unconventional resource plays, net to the Company's interest. The net unrisked resource potential of 462 million barrels of oil equivalent is approximately 48% crude oil and natural gas liquids

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Nexen's 2Q Profit Up; Production Hit by Buzzard Maintenance

- Nexen's 2Q Profit Up; Production Hit by Buzzard Maintenance

Thursday, July 14, 2011
Nexen Inc.

Nexen reported second quarter 2011 operating and financial results, led by strong oil prices, high netbacks, and a portfolio weighted towards unhedged, Brent-priced oil. We generated cash flow from operations of $598 million ($1.13/share) and net income of $252 million ($0.48/share). Production of 204,000 barrels of oil equivalent per day (boe/d) reflects maintenance activities at our Buzzard platform in the UK North Sea which are expected to be completed in August. In light of our production in the first half of the year, we now expect company-wide production before royalties for the year to average between 210,000 and 230,000 boe/d.

During the quarter, we achieved several milestones. Our Usan project remains on track, with the floating production and storage offloading vessel (FPSO) enroute to site. The project is expected to achieve first oil in the first half of 2012. In our oil sands business, Long Lake production increased 9% over the first quarter and generated positive cash flow for the quarter. In June, we processed 45,000 barrels per day (bbls/d) of proprietary and third- party bitumen volumes (28,900 bbls/d and 16,100 bbls/day respectively) achieving approximately 65% of upgrader capacity. We continued to advance various initiatives for resource development to fill the upgrader. We also continued our industry-leading execution in our shale gas business with the drilling of a nine-well pad. We began fracking and completion activities during the quarter, and first production from this pad is expected in the fourth quarter. We also commenced drilling an 18-well pad.

Our exploration efforts advanced in the Gulf of Mexico. We received a drilling permit for our Kakuna exploration well and commenced drilling late in June. Our partner, Shell, received a drilling permit for an appraisal well to follow up our Appomattox discovery.

"While we are disappointed with the downtime at Buzzard, we are making steady progress in all areas of our business. We continue to focus on developing our attractive opportunity portfolio and are advancing our near-term and longer-term value contributors to our business," said Marvin Romanow, President and Chief Executive Officer.

"The Gulf of Mexico is a key component of our significant resource potential, and we are excited to be back to drilling," continued Mr. Romanow. "We've spent the past several years building an attractive prospect inventory in the Gulf, and the value of the opportunity in this area was highlighted by the Appomattox discovery last year. Along with the North Sea and West Africa, the Gulf is expected to be integral to growing our conventional business for many years to come."

  • Financial
    • Cash flow from operations of $598 million ($1.13/share) and net income of $252 million ($0.48/share).
    • Oil and gas operations generated a cash netback of $59.87/boe ($42.76/boe after tax).
    • Achieved our first quarterly positive cash flow at Long Lake.
    • Net debt decreased approximately 50% from a year ago. It is expected to increase in the second half of the year as our capital program is weighted more towards the latter half of the year as we increase our drilling activities.
  • Production
    • Production of 204,000 boe/d (180,000 boe/d after royalties) was impacted by Buzzard's unscheduled maintenance and interruptions to a third-party operated natural gas export pipeline which constrain oil production to minimize gas flaring. We also had unscheduled downtime at Syncrude.
    • At Long Lake, production increased 9% over the prior quarter to 27,900 bbls/d gross (18,100 bbls/d net to Nexen).
  • Project Advancements
    • Received drilling permits for the Appomattox appraisal well and Kakuna exploration well in the deepwater Gulf of Mexico. Commenced drilling the Kakuna well and brought in Statoil USA E&P Inc. as a partner on a promoted basis.
    • Continued industry-leading pace of drilling at our shale gas operations in the Horn River. We have strong interest in our joint venture process.
    • Advancing various projects to develop high quality resource to fill the Long Lake upgrader, including acceleration of development of a portion of the Kinosis lease.
    • Successfully ran the Long Lake upgrader at approximately 65% of capacity, with an on-stream factor of 96% during June.
    • Continued drilling on pads 12 and 13 at Long Lake, and converted several pad 11 wells from circulation to production.
    • Usan FPSO set sail for location offshore Nigeria, West Africa.

Our portfolio weighting towards unhedged, Brent-priced oil contributed to strong cash flow in the quarter. Brent averaged US$117.36 per barrel, a premium of US$14.80 per barrel over WTI. Our approach to hedging allows us to benefit when prices rise, while giving us some protection if prices decline below certain levels. Higher realized crude oil prices, which averaged $110.28 per barrel, partially offset lower production from temporary downtime at Buzzard and Syncrude and natural declines in Yemen. Also contributing to cash flow was our Long Lake operation, which generated its first positive quarterly cash flow of $6 million as compared to a loss of $19 million in the first quarter. Higher production, prices and upgrader throughput contributed to this positive cash flow.

Net income increased from the prior quarter. The first quarter included the impact of the UK tax rate change which resulted in an accrual for higher income taxes of $336 million. This was partially offset by a $299 million after-tax gain on the sale of Canexus.

Net debt has declined about 50% over the past year following our successful asset disposition program and a stronger Canadian dollar. This amount is expected to rise in the second half of the year due to the timing of our capital spending and working capital changes. Capital investment is expected to increase in the latter half of the year with the increased drilling in the Gulf of Mexico, the North Sea and for Canadian shale gas and oil sands.

The Buzzard field continues to be our largest producing asset and typically contributes 85,000 to 95,000 boe/d net to Nexen. Production in the quarter averaged 114,000 boe/d (49,000 boe/d net to Nexen). This reflects unscheduled maintenance to repair the cooling system and interruptions to a third-party operated natural gas export pipeline which constrain oil production to minimize gas flaring. While the repair work proceeded on schedule, production was lower than expected due to the gas export restrictions. Production is expected to be back to full rates in August.

We utilized Buzzard's downtime to bring forward maintenance work originally scheduled for September. Further maintenance work will be advanced to August when the third-party operated Forties pipeline system undergoes a one-week shutdown. As a result, the September shutdown will not be required.

Yemen production reflects natural field declines following the completion of development drilling activities as we near the end of the primary contract term in December of this year, and by the two-day shutdown during a labour strike. This was the longest disruption in our Yemen operations since production began in 1993. Following a successful restart, the facility quickly returned to normal production. We remain confident that we can continue to manage our operations during the current period of uncertainty in the country. Safety and security continue to be our primary focus.

Unscheduled maintenance on the LC Finer and the Vacuum Distillation Unit impacted Syncrude production. The repairs have been completed and production subsequently returned to full rates.

At Long Lake, bitumen production averaged 27,900 bbls/d gross (18,100 bbls/d net to Nexen), up 2,300 bbls/d from the first quarter. Production is increasing as a result of higher steam injection following the hot lime softener (HLS) scheduled maintenance, well optimizations and the continuing ramp-up of the new pad 11 wells. Production at the end of June was approximately 30,000 bbls/d and we expect production from Long Lake to continue to increase into the mid-30,000 bbls/d range by year-end.

Unit operating costs temporarily increased in the first half of this year due to planned and unplanned maintenance, along with initiatives to increase upgrader reliability and improve well performance. The first quarter included planned maintenance of the first HLS unit. The second quarter included planned maintenance on the second HLS unit and a cogeneration unit, as well as unplanned maintenance on the sulphur recovery units and gasifiers. The third HLS unit and second cogeneration unit are scheduled to undergo maintenance in August. Despite this increase in operating costs, the facility generated positive cash flow for the quarter due to higher production and prices, and increased upgrader throughput from Long Lake and third-party sourced bitumen.

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Proposed Shale Gas Development Stirs Passions in Poland

- Proposed Shale Gas Development Stirs Passions in Poland

Thursday, July 14, 2011
by Joao Peixe

Energy-poor Poland is about to embark upon using hydraulic fracturing to develop the country's natural gas reserves. The practice is controversial in many countries, including the U.S., because of its potential impact on the environment, particularly groundwater. Many municipalities and counties in the U.S. have adopted stringent regulations as a result.

Poland's Petrolinvest has formed a joint venture, Silurian-Hallwood, with the U.S.-based Hallwood Energy to begin shale gas extraction after funding is raised, Rzeczpospolita newspaper reported.

Silurian-Hallwood is currently attempting to raise $90-100 million, of which, $20-25 million will come from private investment with the remaining $70-75 million from an initial public offering (IPO) prior to the company being listed on London's Alternative Investment Market (AIM) later this year.

Author Jacek Skorupski observed, "Shale gas is a matter of a political nature. If we treat it like any other investment, we will be faced with mounting difficulties."

Deputy Environment Minister Jacek Jezierski ambiguously noted, "We will be able to say whether amendments to provisions regulating shale gas extraction are needed once we perform a professional assessment of its environmental impact, not an emotional one. Poland intends to control this process, not to ban it."

Marek Kryda of the Institute of Civil Affairs emphasized, "It is necessary to look after issues related to property expropriation and lease. We can already see irregularities at the stage of test drilling."

(Joao Peixe is Deputy Editor with The original article appears here.)

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How Dependent Is the U.S. on Foreign Oil? - EIA Reports Current Trends

- How Dependent Is the U.S. on Foreign Oil? - EIA Reports Current Trends

Thursday, July 14, 2011
Rigzone Staff
by Barbara Saunders

The U.S. imported about 49 percent of the crude oil and refined petroleum products that were consumed during 2010, the U.S. Energy Information Administration (EIA) noted in a recent brief on the issue.

About half of these imports came from the Western Hemisphere, EIA said, adding that U.S. dependence on foreign petroleum has declined since peaking in 2005.

Canada is the United States' leading crude oil supplier, EIA reported.

Consumption, Production and Import Patterns

The U.S. consumed 19.1 million barrels per day (MMbd) of petroleum products during 2010, making it the world's largest petroleum consumer, EIA said.

How Dependent Is the U.S. on Foreign Oil? – EIA Reports Current Trends

The U.S. was third in crude oil production at 5.5 MMbd. But since crude oil alone does not constitute all U.S. petroleum supplies. " . . . [B]ecause crude oil expands in the refining process, liquid fuel is captured in the processing of natural gas, and there are other sources of liquid fuel, including biofuels," EIA observed, reporting that these additional supplies totaled 4.2 MMbd in 2010.
How Dependent Is the U.S. on Foreign Oil? – EIA Reports Current Trends

In 2010, the U.S. imported 11.8 million barrels per day (MMbd) of crude oil and refined petroleum products. The U.S., however, also exported 2.3 MMbd of crude oil and petroleum products during 2010, so net imports (imports minus exports) equaled 9.4 MMbd, EIA noted.

Petroleum products imported by the United States during 2010 included gasoline, diesel fuel, heating oil, jet fuel, chemical feedstocks, asphalt, and other products. Still, most petroleum products consumed in the United States were refined here. Net imports of petroleum other than crude oil were 2 percent of the petroleum consumed in the United States during 2010, according to EIA.

About Half of U.S. Petroleum Imports from Western Hemisphere

Of the total crude oil and petroleum product imports, 49 percent came from the Western Hemisphere (North, South, and Central America, and the Caribbean including U.S. territories) during 2010. About 18 percent of U.S. crude and imports of crude oil and petroleum products come from the Persian Gulf countries of Bahrain, Iraq, Kuwait, Qatar, Saudi Arabia, and United Arab Emirates. The U.S.' largest sources of net crude oil and petroleum product imports were Canada and Saudi Arabia, EIA said.

How Dependent Is the U.S. on Foreign Oil? – EIA Reports Current Trends

Reliance on Petroleum Imports has Declined

U.S. dependence on imported oil has dramatically declined since peaking in 2005, EIA emphasized.

"This trend is the result of a variety of factors including a decline in consumption and shifts in supply patterns," EIA said, continuing: "The economic downturn after the financial crisis of 2008, improvements in efficiency, changes in consumer behavior and patterns of economic growth, all contributed to the decline in petroleum consumption. At the same time, increased use of domestic biofuels (ethanol and biodiesel), and strong gains in domestic production of crude oil and natural gas plant liquids expanded domestic supplies and reduced the need for imports."

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Williams Raises Bid for Southern Union to About $5.6B

- Williams Raises Bid for Southern Union to About $5.6B

Thursday, July 14, 2011
Dow Jones Newswires
by Ben Lefebvre

Williams Cos. raised its bid for Texas pipeline company Southern Union to about $5.6 billion in cash in the latest round of a takeover battle with Energy Transfer Equity.

Williams latest bid tops Energy Transfer's previous $5.1 billion cash-and-stock offer and its own previous bid of $5 billion in cash. The two companies have been competing to merge with Southern, with the winner of the competition expected to become the country's largest natural-gas pipeline company.

Williams said it hopes to have an agreement hammered out with Southern by Tuesday, which it maintains is enough time to share business data with Williams and hold the necessary management meetings to get approval.

"It's fairly simple as to what we have to offer," Williams Chief Executive Allan Armstrong said in an interview. "We don't think the decision process is real complex."

Representatives of Southern and Energy Transfer were not immediately available to comment.

Williams all-cash bid might be simple, but in the end it might not be as compelling as the company is portraying, said Morningstar equities analyst Jason Stevens said. Morningstar values Energy Transfer's cash-and-stock offer at $46 a share--higher than William's $44 a share offer--because of tax benefits and dividends the stock portion of the deal would offer. A merger with Southern might also force Williams to sell some of its pipeline assets in Florida to win over antitrust regulators, Stevens said.

"They'd have to sell their premiere assets," Stevens said. "It's just not as compelling an offer."

It might be difficult for Williams to go any higher than its current 10% premium to Energy Transfer's current offer, said BMO Capital Markets analyst Carl Kirst.

"Williams paying more than $44 would start facing investor blowback given the premium involved," Kirst said in an investors note.

Energy Transfer and Southern Union last week set a deal initially valued at $40 a share, four dollars lower than Williams's latest bid. Energy Transfer also agreed to sell some assets in order for the deal to pass muster with antitrust regulators.

The companies also raised the breakup fee for their agreement to $162.5 million from $92.5 million in the original agreement, another indication that a higher bid was expected. Williams in its latest bid said it would pay the breakup fee and related expenses for Southern.

Both companies had expressed willingness to assume Southern's debt, totaling $3.7 billion.

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

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Key Extends Eagle Ford Footprint with Acquisitions

- Key Extends Eagle Ford Footprint with Acquisitions

Thursday, July 14, 2011
Key Energy Services Inc.

Key Energy has reached a definitive agreement to acquire Edge Oilfield Services and Summit Oilfield Services (collectively "Edge") for consideration of approximately $300 million, consisting of approximately 7.5 million shares of Key common stock and approximately $164 million in cash, which is subject to working capital and other adjustments at closing. Key anticipates funding the cash portion of the consideration from available cash and borrowings under its credit facility. In addition to the $300 million of consideration, Key has also agreed to reimburse or fund up to $40 million of Edge's pre-closing capital expenditures related to Edge's expansion into the Eagle Ford shale, which began generating revenue this quarter.

The closing of this transaction, which is expected to occur this quarter, is subject to customary conditions including the expiration or termination of the waiting period under the Hart-Scott-Rodino Act.

Edge primarily rents frac stack equipment used to support hydraulic fracturing operations and the associated flow back of frac fluids, proppants, oil and natural gas. It also provides well testing services, rental equipment such as pumps and power swivels, and oilfield fishing services. Following the close, Edge's results will be reflected within Key's existing Fishing & Rental Services line of business, which is included in its U.S. reportable segment.

Key's Chairman, President, and CEO, Dick Alario, stated, "Edge's high performance frac stack equipment enjoys strong growth opportunities, particularly in unconventional shale markets. Furthermore, its high revenue and profit per employee fits with our overall investment strategy and should prove beneficial, especially in today's tight labor market."

Alario continued, "Edge's existing business currently generates an annual EBITDA run rate of approximately $65 million. With the expansion into the Eagle Ford that is already underway, Edge believes its EBITDA run rate will be approximately $80 million by year-end 2011. We anticipate Edge's business to be accretive to Key's margins and earnings beginning in 2011. With Edge's experienced oilfield industry veterans, we intend to aggressively expand Edge's service offerings across Key's existing infrastructure, particularly in emerging unconventional shale markets."

Edge's CEO, Darrell Brewer, stated, "We look forward to becoming a part of Key, a high quality, industry leading company, where we can better leverage our business potential via Key's extensive U.S. footprint and financial resources and where our employees will continue to enjoy a bright future."

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Odfjell, Ross to Merge Companies

- Odfjell, Ross to Merge Companies

Thursday, July 14, 2011
Odfjell Drilling AS

Odfjell announced the merger between Odfjell Well Management (OWM) and Ross Offshore (RO). Ross Offshore acquires the two Odfjell Drilling companies Odfjell Well Management AS and Odfjell Well Management Consultants AS. The name of the combined company will be Ross Offshore.

The combination of Odfjell Well Management and Ross Offshore will provide clients with a spectrum of services from qualified professionals to assuming the role as the "in-house" drilling and well department. The services of total well management comprise planning, operations, logistics, project-management, cost control, HSE, authority applications and marine management. With this broad service offering, Ross Offshore will be well positioned to serve its clients with the complete value chain.

Drilling activity on the NCS is expected to increase significantly over the next 3-4 years, which supports a strong underlying growth in the well management and the consultancy outsourcing market. Further, there is a growing focus on Carbon Capturing and Storage. The range of growth opportunities in the coming strong market is large, and Ross Offshore has now secured a good position to capture on these opportunities.

Peder Sortland, currently the CEO of Subsea Technology Group (STG) and also in his capacity as the designated CEO of the combined business, expresses satisfaction that the owners of the two companies have agreed to join forces based on sound industrial logic. The merger is strongly supported by the management of RO and OWM as well as STG.

Furthermore, Bjornar Iversen, Executive Vice President of Business Development in Odfjell Drilling, expressed, "By joining forces, this merger will create a focused company positioned to be a leading provider of well management and subsurface competence in Norway with international potential. This enhanced platform will enable us to better serve the needs of our jointed customers and provide them with existing capabilities, a more complete service offering and a broader resource base."

Post the transaction, STG and Odfjell Drilling will, through a joint holding company control approximately 40% each of the combined business whilst the balance will be held by minority shareholders. Prior to this transaction Ross Offshore has been owned 69% by STG. STG is again predominantly owned by the oil and gas specialist private equity investor HitecVision. OWM and its subsidiary OWMC have been owned by Odfjell Drilling Technology Ltd.

The combined business will have revenue of approximately NOK 530 million, and close to 200 employees and consultants. The head office of the combined business will be in Stavanger. The purchase price is not disclosed. The transaction is subject to customary approval by the Norwegian Competition Authority. Expected closing of the transaction is medio August.

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Petro Matad Encounters Hydrocarbons at Davsan Tolgoi Well

- Petro Matad Encounters Hydrocarbons at Davsan Tolgoi Well

Thursday, July 14, 2011
Petro Matad Ltd.

Petro Matad announced that the Davsan Tolgoi-7 well ("DT-7") has reached a total depth of 1,733m in metamorphic rocks below the Tsagaantsav Formation objectives.

DT-7 was drilled as a test of the Uppermost Tsagaantsav and the Lower Tsagaantsav reservoirs of the Davsan Tolgoi Mod Prospect, a fault and fold structural trap consisting of three subsidiary fault blocks.

The well penetrated the Uppermost Tsagaantsav at 1,149m depth, 22 meters high to prognosis. Initial petrophysical analysis has identified three zones of possible net pay totaling 4.8m in thickness and averaging 25% porosity. An additional 18.5m of water-bearing net reservoir with 19% average porosity is distributed between the three zones of moveable hydrocarbons. A similar pattern of alternating oil and water-bearing sandstone reservoirs is common in the Tolson Uul field on Block XIX to the north of Davsan Tolgoi. The three Uppermost Tsagaantsav hydrocarbon zones are being evaluated as candidates for future testing, and additional well locations are being evaluated up to 75m up-dip (higher) to DT-7, where more complete hydrocarbon saturation may be expected.

The Lower Tsagaantsav objective was penetrated between 1,208 and 1,703m depth with minor hydrocarbon saturation at 1,542m depth. 23m of reservoir quality sandstone is distributed between twelve thin zones that average 17% porosity.

Drilling, casing and cementing operations have been completed at DT-7 and the rig has been moved to the new DT-8 location as part of the Company's drilling program to evaluate its inventory of twelve independent prospects in the Davsan Tolgoi area of Block XX.

The DT-8 well is scheduled to be spud today and is located 700m northeast and 38m lower than the DT-5 well that was drilled in June, and 1.8 km south and 80m higher than the Daqing 19-62 oil well in Block XIX. The well will test a stratigraphic pinch-out of the Uvgan Gol paleovalley reservoir between the thin hydrocarbon-saturated sandstones at DT-5 and the thick oil-producing sandstones of the 19-62 well. On further analysis and comparison of data from the DT-5 and 19-62 wells, a secondary stratigraphic trap objective in Lower Zuunbayan sandstones has been identified and the location of DT-8 is well situated to test this objective. Lower Zuunbayan sandstones are the primary reservoirs in the North Tolson Uul field of Block XIX and if productive at DT-8, they will confirm a new play for the Davsan Tolgoi area.

The Company also wishes to give an update on the progress of the planned well-testing program for Davsan Tolgoi. As of today, 135 truckloads of equipment accompanying the workover rig are waiting at the Chinese side of the border post, 150kms south of Petro Matad's Block XX operations. Mongolian national holidays are in progress, and the border point is due to re-open today. Whilst there is a large back-up of cross-border traffic awaiting that re-opening, Petro Matad and its contractor DQE International are confident that mobilization will continue shortly.

The Company is also well advanced in all other aspects of the extensive testing program. Matters such as explosives for well perforation, permits, extended test equipment and international specialists are all either in place or planned.

In other matters pertaining to Davsan Tolgoi, the Company's geo-scientists are currently completely re-mapping the Davsan Tolgoi 3D survey, using a newly processed set of data that adds new definition and clarity to the model. Additionally, data from the drill holes is being added and used in the assessment as it becomes available. This large undertaking is scheduled to be completed by the end of August.

In the immediate vicinity of Davsan Tolgoi, the recently completed 2D seismic lines have been processed, and are currently being incorporated into the previous 2,700kms of survey, ready to be re-mapped. This is expected to add much greater clarity to the areas adjacent to Davsan Tolgoi, both to the east and the west, and enable the generation of new volumetrics, as well as possibly defining drill targets.

Additionally, the Company advises that the 2D seismic surveys over the three sub-basins in the south of Block XX have now been completed and processed. Early processing results indicate similar depths of basins as those in the northernmost parts of Block XX, near Davsan Tolgoi. Interpretation and collation of the entire 1,300kms of new 2D is proceeding.

Petro Matad CEO, Doug McGay stated, "Once again, it is pleasing to note that we have encountered hydrocarbons in our Davsan Tolgoi drilling program and to have the reservoir formations' prognosis confirmed.

"We are methodically working our way through our portfolio of targets in the Davsan Tolgoi area, having so far encountered hydrocarbons in all but one of the seven wells drilled to date. Our management and exploration team note the less-than-resounding results in DT-5 and DT-7 and the dry hole at DT-6, and conclude that is a statistically anticipated outcome of the type of exploration drilling program needed on such a structure as Davsan Tolgoi. Each of the wells has already given us important information that is being used to refine our geologic model, and hence our drill site selection. This should serve us well not only for the continued drilling of our prospect inventory, but also for the ongoing exploration of the remainder of Block XX.

"Progress is being made with the other aspects of the exploration of Block XX, particularly the complex well-testing program. The re-mapping of the newly re-processed 3D survey will also be an important milestone. The area outside of Davsan Tolgoi is also being methodically explored, and we are looking forward to refining our portfolio of leads and prospects in the immediate vicinity, as well as furthering the more grass-roots exploration of other sub-basins."

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Solimar Doubles Stake in Paloma West Project

- Solimar Doubles Stake in Paloma West Project

Thursday, July 14, 2011
Solimar Energy Ltd.

Solimar has confirmed terms to increase its working interest to 25% (doubling the original 12.5%) in the Paloma West project and is soon to be participating in an appraisal well on the project.

The Paloma Deep -1 appraisal well will be drilled using Nabors Rig #710 which is expected onsite at the end of July supporting commencement of drilling in early August.

The Paloma West project is operated by Neon Energy and covers some 1400 acres all within the structural closure of the Paloma oil and gas field which has produced some 61 million barrels of light oil and 432 billion cubic feet of gas (133 MMBOE) since discovery in the 1930s. The Paloma field is a large anticline structure some 12 miles long by 4 miles wide.

The well location has been chosen using 3D seismic which was acquired after the prior development of the field. The 3D data has been used to help identify favourable reservoir trends within the field closure and all the targeted sandstone reservoirs at the well location are characterised by amplitude anomalies on the seismic. This is believed to support the presence of hydrocarbons and may also be indicative of reservoir quality.

There are seven (7) individual, stacked reservoir targets in the well commencing at approximately 10,000 feet. The well has a planned total depth of 15,500 feet and will take up to 2 months to drill. All the targeted sandstone and shale reservoirs are part of the Miocene age Monterey Formation, the famous oil source and reservoir formation in the southern San Joaquin Basin. The estimated unrisked in place hydrocarbon volumes are up to 300 million barrels OIP and based on an 11% recovery factor (equivalent to the historic recovery from the main producing reservoir of the Paloma field) the targeted recoverable resource is 33 MMBOE. Significant upside to these estimates is possible if higher recoveries are attainable.

The well will drill though a series of shallower Pliocene mostly dry gas reservoirs on the way down that are expected to be depleted by historic production. Some of these sand reservoirs are equivalent to the San Joaquin Formation gas sands that Solimar is attempting to develop at its SELH gas project further to the northwest in the basin. The shallow sands produced 23 Billion cubic feet (Bcf) of gas at Paloma.

The first reservoir to be evaluated will be in the Antelope Shale member of the Monterey which envelopes the main reservoir of the field, the Paloma or Upper Stevens Sandstone. This sand has produced 58 mmbbls and 415 Bcf and is likely to be at least partially depleted at the well location and is therefore considered a secondary target. All the Monterey Formation sandstone reservoirs including the Paloma Sandstone were originally formed as submarine fans derived from the NE and deposited into the deep water basin prevalent in the San Joaquin Basin during the Miocene. The anticlinal structure which traps the hydrocarbons was formed much later and has a
different, NW – SE orientation. So there has been varying sand quality encountered across the field which affected the historic field development, particularly for the Lower Stevens Sandstone reservoirs which were not discovered until 1973.

Only three wells have penetrated to the deeper reservoir levels in the west half of the field area (the most recent being some 26 years ago in 1985) each encountering extensive live oil and gas shows and with two wells flowing oil and gas at low rates.

Solimar believes that the 3D seismic data and modern drilling and completion technologies provide an excellent chance for a successful appraisal of the sandstone reservoirs in the western Paloma oil field. Unlike most of the original field wells that were drilled using water based muds that can react with clays in the reservoir reducing permeability (or ability to flow), the Paloma Deep - 1 will be drilled with a synthetic oil based mud to reduce drill time and minimise formation damage.

With the exception of one old vertical well recompleted for production in the Antelope Shale in 1993, the fractured oil shale potential of the acreage remains untapped. In the context of the escalating production and re development of equivalent rocks in other fields in the area, the fractured oil shales present an exciting opportunity for the new joint venture.

Solimar is increasing its interest via a farmin with Neon. The increased position in the project will be subject only to any consents to assignment of the interests that may be required by the underlying lessors and to completion of Solimar's previously announced private placement to raise A$7 million which will be processed at an EGM on July 29.

The dry hole cost of the Paloma Deep -1 is estimated at US $4.9 million. Solimar will be funding its share from cash reserves and the proceeds of the placement.

Commenting on the drill program Solimar CEO John Begg said, "It is very pleasing to be announcing another step up in the scale of the Company's assets in the San Joaquin Basin focus area. The Paloma West project perfectly illustrates Solimar's strategy of acquiring
material interests in oil prone assets that have targets in both conventional and unconventional reservoirs. Further, where hydrocarbons have already been discovered. Solimar has the opportunity to be part of the first joint venture to apply modern, off the shelf technologies to evaluate and exploit the assets. The Paloma Deep -1 is an ambitious drill program designed to evaluate a series of targets within part of a known field where the reservoirs have not been adequately tested by the historic drilling. The project provides an exciting opening to a virtually continuous 12 month program of drilling and production testing on the Company's core projects which is well illustrated in the activity schedule accompanying this release. Each of these projects represent stand - alone, technically independent opportunities for growth."

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AGR Receives Contract Extension from Statoil

- AGR Receives Contract Extension from Statoil

Thursday, July 14, 2011

AGR Field Operations has been awarded an extension worth approximately NOK 60 million by Statoil for Inspection and Certification of non-complex lifting equipment. The services will cover Statoil's operations on the NCS, from Snøhvit in the North to Sleipner in the South.

The contract covers 30 offshore installations and 4 onshore facilities. The duration of this extension is 24 months with an option for a further 24 month period worth approximately NOK 60 million in revenue. Including the remaining option, AGR Field Operations estimates the total value to be around 120 MNOK.

Åge Landro, Executive Vice President commented, "We are very pleased with the continued trust shown in our technology and services from Statoil. We have had a successful long term partnership with Statoil across a range of products and services and view this extension as an affirmation of the value we bring to their operations. The geographical coverage and breadth of the workscope under this contract has been challenging and we feel we have managed to deliver both quality and a high standard of service to our customer."

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Manas Begins Second Seismic Survey at Mongolian Blocks

- Manas Begins Second Seismic Survey at Mongolian Blocks

Thursday, July 14, 2011
Manas Petroleum Corp.

Manas announced the commencement of the second seismic survey on the two Mongolian blocks - Zuunbayan-XIV Block and Tsagaan Els-XIII Block - owned by Gobi Energy Partners GmbH.

This year's seismic survey includes up to 1,700 km of 2D seismic. It covers 10 prospective areas over both blocks, which were identified by our integrated interpretation. The program is laid out in 8 phases without any interruption between the phases; however, some phases show interdependencies. Preparation and mobilization has commenced and the acquisition is expected to begin in mid-August. The seismic work will be conducted with vibrators.

Through its wholly-owned subsidiary, DWM Petroleum AG, Manas owns record title to 100% of the issued and outstanding shares of GEP GmbH, though 26% is held in trust for others. GEP GmbH owns 100% of Gobi Energy Partners LLC ("Gobi"), the Mongolian operator of the oil and gas projects on the two blocks. Gobi signed the agreement for Seismic Services with Sinopec Mongolia, a wholly-owned subsidiary of China Petrochemical Corporation (Sinopec Group), on July 12, 2011. Sinopec has extensive seismic experience in this area. Sinopec offers all services from seismic to drilling and drilling related services. Sinopec will use Sercel equipment for the survey. The total cost of the program, including mobilization and demobilization, is projected to be US $4.2 million. Nine companies participated in the tender.

This seismic survey is being carried out in an effort to improve the quality of existing data and increase the chances of success of exploratory wells the company intends to drill upon completion and interpretation of the new data. The first well is anticipated to be spudded in the second quarter of 2012.

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Foster Wheeler, SOCAR Team Up to Form New Company

- Foster Wheeler, SOCAR Team Up to Form New Company

Thursday, July 14, 2011
Foster Wheeler AG

Foster Wheeler announced that a subsidiary of its Global Engineering and Construction Group has signed a Memorandum of Understanding (MoU) to cooperate to form a jointly-owned company with The State Oil Company of Azerbaijan Republic (SOCAR) in the Republic of Azerbaijan.

SOCAR is a state-owned company engaged in the fields of oil and gas exploration, production, transportation and marketing and intends to build an oil, gas processing and petrochemical complex in Garadag, Republic of Azerbaijan.

The new jointly-owned company will focus on providing process, engineering, procurement, construction supervision and project management services associated with the development of the new oil, gas processing and petrochemical complex.

The new entity will provide the same services for upstream, midstream and downstream oil and gas projects developed by SOCAR both in the Republic of Azerbaijan and in other countries.

In line with the principles outlined in the MoU, Foster Wheeler and SOCAR will prepare a joint action plan for the establishment and incorporation of the new company, with its headquarters in Baku.

"Foster Wheeler and SOCAR already have a strong working relationship, including cooperation for the design of the Aegean oil refining facility in Turkey for SOCAR and its joint-venture partner," said Umberto della Sala, Interim Chief Executive Officer, Foster Wheeler AG. "We are very pleased to sign this MoU, which signals our commitment to Azerbaijan and which will take our relationship with SOCAR to a new level. Foster Wheeler will bring to the new joint company its worldwide organization resources, technical expertise and international project execution capability on all of SOCAR's key business areas."

"We consider Foster Wheeler one of the most respected companies in the world and we very much look forward to the formation of this new joint-venture company," added Rovnag Abdullayev, President, SOCAR. "We are confident that Foster Wheeler will be able to inject into the new entity its proven know-how and its recognized capability to deliver successful projects."

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ConocoPhillips to Split Into Two Next Year

- ConocoPhillips to Split Into Two Next Year

Jul 14, 2011

ConocoPhillips (NYSE:COP) announced Thursday that it will be splitting into two companies. The division should take place sometime in the first half of 2012.

James J. Mulva, the ConocoPhillips chairman and chief executive, said in a statement, "We have concluded that two independent companies focused on their respective industries will be better positioned to pursue their individually focused business strategies."

ConocoPhillips has a potential upside of 13.4% based on a current price of $74.4 and an average consensus analyst price target of $84.38.

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Williams Announced It Submitted An Enhanced Proposal To Acquire Southern Union Company

- Williams Announced It Submitted An Enhanced Proposal To Acquire Southern Union Company

Jul 14, 2011

Williams (NYSE:WMB) announced that it submitted an enhanced proposal to acquire Southern Union Company (NYSE:SUG) for $44 per share in cash, for a total enterprise proposal via a letter to the Special Committee of Southern Union's Board of Directors.

The enhanced proposal represents a premium of 10% over the nominal purchase price in Southern Union's recently revised agreement with Energy Transfer Equity (NYSE:ETE), announced on July 5.

Alan Armstrong, Williams' President and Chief Executive Officer said, "Based on the due diligence we have completed to date, we have revised our forecasts and synergy estimates and are pleased to deliver Southern Union an enhanced proposal to acquire the company for $44.00 per share in cash. We are more convinced than ever of the strategic and financial benefits of Williams' acquisition of Southern Union. Our proposal offers more than just premium value and full liquidity to the Southern Union shareholders; it is designed to result very quickly in a merger agreement and provide certainty around financing and regulatory approvals. Williams is offering Southern Union a clear, direct path to the highest value for its shareholders."

The Williams Cos has a potential upside of 27.8% based on a current price of $28.79 and an average consensus analyst price target of $36.8.

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