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Oil and Gas Energy News Update

Wednesday, July 20, 2011

Oil & Gas Post - All News Report for Wednesday, July 20, 2011

Wednesday, July 20, 2011

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Commodity Corner: Oil Settles Higher on Bullish Stocks Data

- Commodity Corner: Oil Settles Higher on Bullish Stocks Data

Wednesday, July 20, 2011
Rigzone Staff
by Matthew V. Veazey

The price of light sweet crude oil gained 64 cents Wednesday to settle at $98.14 a barrel on news of a larger-than-expected drop in U.S. oil stocks. The Brent benchmark gained $1.09 to end the day at $118.15 a barrel.

The U.S. Energy Information Administration reported Wednesday that the country's commercial crude oil inventories fell nearly 1.1 percent last week to 351.7 million barrels. The 3.8 million-barrel draw was well above analysts' expectations. For instance, a Platts survey of analysts projected a draw of only 1.3 million barrels.

WTI futures fluctuated from $96.80 to $99.02 during Wednesday's session. The Brent contract peaked at $118.56 and bottomed out at $117.06.

Americans from the Upper Midwest to the South to the East Coast are seeking air-conditioned relief from high heat and humidity. Triple-digit heat indices are common throughout the eastern half of the country, and such conditions are expected to continue into next week. In spite of the sweltering heat, natural gas futures edged downward Wednesday to $4.50 per thousand cubic feet.

Front-month natural gas traded within a range from $4.43 to $4.60.

Gasoline futures ended the day higher at $3.15 a gallon—the intraday high. The intraday low for gasoline was $3.10.

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Quetzal Updates Ops in Colombia

- Quetzal Updates Ops in Colombia

Wednesday, July 20, 2011
Quetzal Energy Ltd.

Quetzal provided the following update on operations in Colombia

The long term production testing of Canaguay #1 is continuing with the well currently producing approximately 500 barrels of oil and 150 barrels of water. The optimal production rate for the Mirador reservoir and facilities will be determined by the results of the long term production test.

Quetzal has a 25% working interest and is acting as the operator of the Canaguaro block and the Canaguay #1 well.

Block 27

A follow-up 54 square kilometer 3D seismic acquisition program has been completed in the south eastern portion of the block, and is currently being interpreted. The Company has defined drilling locations on three separate Block 27 structures, based on the interpretation of 3D seismic. Potential follow-up development drilling locations have been identified on several of these structures. Interpretation of the 3D seismic is continuing and several additional geological features are being studied as potential drilling locations.

Lengthy delays in the issuing of block environmental permits continue to adversely effect the operations of both large and small oil companies in Colombia. Quetzal has waited approximately 8 months for the Block 27 environmental permit. It is anticipated that permit will be granted during the 3rd quarter of 2011. Construction of drilling locations is scheduled to begin as soon as the required environmental permit is received. A two to three well drilling program is planned to commence approximately one month after location construction begins. The wells have a planned depth of approximately 10,000 feet and will test prospective oil bearing intervals in the Carbonera, Mirador and Une Formations.

Quetzal has a 50% paying interest in the block and is acting as operator.

Block 21

An 83 square kilometer 3D seismic survey has been competed on Block 21 and is currently being interpreted. Several geological features are being studied as potential drilling locations. The Company plans to drill 2 wells during the 4th quarter of 2011 or the 1st quarter of 2012.

Quetzal has a 50% paying interest in the block and is acting as operator.

Block 36

The acquisition of 109 square kilometers of 3D seismic on Block 36 has been completed and is being processed. Drilling of one 15,000 foot well is scheduled for 2012.

Quetzal has a 20% paying interest in the block.

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Newfield All Smiles over Uteland Butte HZ Play

- Newfield All Smiles over Uteland Butte HZ Play

Wednesday, July 20, 2011
Newfield Exploration Co.

Newfield Exploration provided a comprehensive update on its Uinta Basin oil development programs. The update follows the May 2011 closing of two acreage acquisitions for approximately $300 million. Combined, the two transactions added approximately 70,000 net acres. Newfield today owns interest in approximately 250,000 net acres in the Uinta Basin where its average working interest is more than 70%. Multiple oil-productive geologic targets exist across the acreage and an active drilling campaign is underway.

"We have a proven growth history in the Uinta Basin," said Lee K. Boothby, Newfield's Chairman, President and CEO. "We have been growing our oil production and reserves in the region since our entry in 2004. It's clearly an oil play where we have a competitive advantage. We drill 'best in class' wells, operate substantially all of our operations and have the personnel in place today to increase our activities cost effectively. We plan to aggressively develop our 6,000-plus well inventory of oil locations."

"We are excited about the potential of our new Uteland Butte horizontal oil play, as well as the early successes in our Wasatch development. These two new oil plays provide some of the highest return projects in our drilling portfolio today. We will optimize our drilling programs and continue to grow our domestic oil production in 2012. Over the last two years, we have effectively demonstrated our ability to shift people and capital to projects that yield both growth and returns."

For 2012, Newfield plans to increase its operated rig count in the Uinta Basin from an historic five-rig count to at least eight rigs. The Company expects 2012 Uinta Basin daily production will grow at least 25% over 2011. The increased play options combined with fewer permitting constraints will allow Newfield to significantly increase its future growth in production and reserves from the basin.

The Company's net resource potential in the Uinta is estimated today at more than 700 million barrels of oil (MMBO) equivalent. In addition to the shallow Green River oil play, Newfield today provided results from recent drilling in deeper oil objectives prevalent throughout the Company's acreage. A table summarizing the plays and their net resource potential is included within this release.

Uteland Butte

Recent transactions have added acreage north of the Company's traditional area of drilling -- Monument Butte. This area is referred to as the "Central Basin." Uteland Butte is a new horizontal oil play being developed by Newfield from 6,000' – 9,000' (total vertical depth, or TVD) and is prevalent across Monument Butte and the Central Basin – or approximately 80% of Newfield's total acreage in the basin. Portions of the play are geopressured and are expected to result in higher production rates and estimated ultimate recovery (EUR).

During the last year, Newfield has drilled six horizontal wells in the play. All of the wells to date have been drilled in the Monument Butte field. Initial gross 24-hour production rates from the Company's most recent wells have averaged 24-hour initial production (IP) of approximately 500 barrels of oil equivalent per day (BOEPD), or more than six times the IP rate of a traditional, vertical Green River well.

Based on an estimated inventory of at least 1,800 locations (160-acre spacing), Newfield's net resource potential associated with the Uteland Butte formation is nearly 300 MMBO equivalent. The Company estimates that the wells will have an average gross EUR of approximately 300,000 BO equivalent and can be drilled and completed on average for approximately $2.8 million.

Newfield plans to complete an additional four horizontal wells in the Uteland Butte play in the second half of 2011. In 2012, the Company plans to drill more than 30 horizontal wells in the play.


The Wasatch formation is being developed throughout the Central Basin and is prospective at depths of 9,000' – 11,000' TVD. This is a southerly extension of the giant Altamont Bluebell field which has cumulative production to date of more than 400 MMBO equivalent. Over the last year, eight vertical wells have been drilled on Newfield's acreage. Recent vertical wells have average gross 24-hour IP rates of more than 1,000 BOEPD.

Newfield estimates that the net resource potential for this play is more than 45 MMBO equivalent. To date, the Company has identified approximately 380 locations (320-acre spacing) with expected average EURs of more than 260,000 BO equivalent. Gross completed well costs vary by geologic depth and are estimated to range from $1.2 – $3.3 million. The Company believes significant upside exists with future application of horizontal drilling and completion technology and through increased drilling density, which could double the expected net resource potential.

The Company expects to complete an additional 25 wells in the Wasatch in the second half of 2011. In 2012, Newfield expects to drill at least 50 wells in this play.

Green River

Newfield has been actively developing the shallow Green River formation since entering the Uinta Basin in 2004. Approximately 2,100 wells have been drilled to date on the Company's acreage. Newfield's Green River oil play is economically productive across at least 165,000 net acres.

The Company estimates that more than 4,000 undrilled locations remain to ultimately develop the Monument Butte field on 20-acre spacing and the Central Basin acreage on 40-acre spacing. Substantially all of the Company's acreage at Monument Butte is located on acreage under Bureau of Land Management jurisdiction. At the current pace of drilling activity, this equates to more than a 10-year inventory. To date, Newfield has drilled more than 300 wells on the Central Basin acreage and, with additional data, believes the area could be prospective for future waterflood and 20-acre development. Current resource estimates do not include the potential for 20-acre spacing or secondary recovery in the Central Basin.

Newfield estimates that the Green River formation has net remaining resource potential of approximately 360 MMBO equivalent (includes developed and undeveloped waterflood potential only in Monument Butte). At year-end 2010, Newfield had proved reserves in the Green River formation of approximately 140 MMBO equivalent.

Gross production from the Uinta Basin has grown from approximately 7,000 BOPD to approximately 22,000 BOPD today. Green River wells are today being drilled and completed in four to five days for approximately $930,000 gross. The wells have a gross EUR of approximately 75,000 BO equivalent. Since the Company's 2004 entry into the Monument Butte field, expected recovery of oil in place has increased from about eight percent to 16% or more. Newfield expects to drill about 300 wells in the shallow Green River in 2011. For 2012, Newfield expects to drill 250 – 300 wells as additional resources are allocated toward the new Uteland Butte and Wasatch plays.

Infrastructure Investments

Newfield is investing approximately $75 million into field infrastructure projects in 2011 – nearly matching the Company's cumulative investment in infrastructure from 2004-10. As development drilling has moved northeast and into deeper geologic horizons, the gas:oil ratio has increased. As a result, additional compression and enhanced gathering infrastructure is now required to accommodate the increased gas production. Once fully operational, the new facilities will allow for increased oil production from these areas. The Company expects to invest about $100 million into infrastructure projects in 2012 to accommodate long-term oil growth objectives from the Uinta Basin.

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Edge's Drilling Program Delayed Due to Wet Weather

- Edge's Drilling Program Delayed Due to Wet Weather

Wednesday, July 20, 2011
Edge Resources Inc.

Edge Resources provided the following operational update in response to the recent flooding and extremely wet weather in the area of Eckville, Alberta, where the Company currently operates the majority of its producing natural gas wells.

Eckville has recently made news headlines because of heavy rains and flooding in and around the town. While the Company is disheartened by the loss and damage to property in and around Eckville, Edge is pleased to announce that none of its production or current operations have been adversely affected by the flooding.

The Company had hoped to initiate its summer 2011 drilling program this week; however, the extremely wet conditions have delayed the initiation of this program as well as delayed additional completion and tie-in activities in the area. The Company expects that it will be in a position to move a drilling rig into the area in August, with the help of warmer, drier weather.

In the meantime, the Company will continue with preparatory, regulatory and pre-construction administrative work for these and additional projects.

Brad Nichol, President and CEO of Edge commented, "It is devastating what has happened to the residents in the Eckville area. Edge has always employed a strategy of utilizing local contractors and supporting the local economy in its operations, so the flooding is more than just a newspaper headline to us. Some residents have reported that this was the worst storm in 45 years, which resulted in the closure of highways and bridges."

Edge's main producing natural gas property is approximately 30 km west of Eckville, near the town of Leslieville, Alberta.

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Petrominerales Finalizes Stake in Ocensa Pipeline

- Petrominerales Finalizes Stake in Ocensa Pipeline

Wednesday, July 20, 2011
Petrominerales Ltd.

Petrominerales has closed its previously announced acquisition of a five percent interest in the Oleoducto Central S.A. ("Ocensa") crude oil pipeline from Total E&P Holdings, for a purchase price of US $281 million.

The 830 kilometer Ocensa pipeline starts onshore at the Cusiana and Cupiagua fields and terminates at the port in Covenas on the Caribbean coast of Colombia. The Ocensa pipeline is presently running at capacity, transporting approximately 560,000 barrels of oil per day ("bopd") from the Llanos Basin, representing sixty percent of the current total oil production in Colombia.

Petrominerales expects to transport crude oil through the Ocensa pipeline commencing September 1, 2011, providing us with strategic access to transportation infrastructure. This acquisition is expected to lower our transportation costs compared to trucking for a significant portion of our Llanos basin production, especially in the near term given the limited existing transportation infrastructure in Colombia. In addition, increasing the volume of our oil transported by pipeline reduces risks associated with trucking oil and our exposure to escalating trucking costs.

The expansion of our infrastructure base through this acquisition enhances our marketing flexibility by improving our access to international crude oil markets and pricing, having the potential to further strengthen our netbacks. Along with our 9.65% interest in the Bicentenario pipeline (OBC), this acquisition supports our long-term corporate objectives by securing strategic transportation capacity for our growing base of production, including our heavy oil opportunities. The acquisition of an interest in Ocensa aligns with Petrominerales' corporate objective of continuing to be the highest netback producer in Colombia.

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Williams Declares Dividend

- Williams Declares Dividend

Wednesday, July 20, 2011
Williams Cos. Inc.

Williams' board of directors has approved a regular dividend of $0.20 per share on the company's common stock, payable Sept. 12, 2011, to holders of record at the close of business on Aug. 26.

The company has paid a common stock dividend every quarter since 1974.

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Strategic O&G Appoints New President

- Strategic O&G Appoints New President

Wednesday, July 20, 2011
Strategic O&G Ltd.

Strategic O&G announced that Mr. Gurpreet Singh Sawhney has been appointed President of the Company. Mr. Sawhney is a professional engineer with over 18 years of experience in the oil industry. Mr. Sawhney has been the Vice-President Business Development with Strategic Oil & Gas Ltd. since March 1, 2009. As President of the Company, Mr. Sawhney will be reporting directly to Arn Schoch, CEO and Chairman of the Board.

From 1993 to 1996, Mr. Sawhney worked with PanCanadian Petroleum Ltd., as a reservoir simulation specialist, before leaving to found and manage Reservoir Modelling & Management Ltd. (Res Mod Man) a consultancy group providing reservoir management services to numerous domestic and international clients, including Pan-Canadian Petroleum, Norcen Energy, Husky Energy, Vermilion Energy, Anadarko Petroleum, British Gas, Verenex Energy, Capitol Energy, Highpine Oil and Gas, Daylight Energy and Wave Energy. Mr. Sawhney has worked on over 100 oil and gas field development projects. Mr. Sawhney has assisted with successful projects like the Wayburn CO2 Flood, the Dixonville Montney Waterflood and the Lower Shaunavon Horizontal Well Resource play.

Mr. Sawhney holds a B.Eng. degree in Chemical Engineering from Panjab University, India, and an M.Sc. and an MBA, both from the University of Calgary, Canada.

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EDS Names Marcellus Manager

- EDS Names Marcellus Manager

Wednesday, July 20, 2011
Environmental Drilling Solutions LLC

Environmental Drilling Solutions (EDS) has named Jake Garber Region Manager for Marcellus Shale operations.

Garber has more than 14 years experience in the solids control business and most recently served 10 years as MI Swaco's Gulf Coast Environmental Services Area Manager.

"Jake provides additional senior management within our company as we position ourselves for continued growth in the various shale plays and offshore markets," said Chad Hollier, EDS President. "His experience in facilitating new technologies along with sales and customer support make Jake a strong asset for the company's continued growth."

Garber earned a Bachelor of Science in Geology from the University of Louisiana at Lafayette. He is currently a member of the American Association of Drilling Engineers (AADE), Society of Petroleum Engineers (SPE) and the American Petroleum Institute (API).

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T.D. Williamson Sets Up Shop in Western AU

- T.D. Williamson Sets Up Shop in Western AU

Wednesday, July 20, 2011
T.D. Williamson Inc.

T.D. Williamson has opened a new office in Perth, Western Australia, in a strategic move to offer customers its full range of products and services. Located on St. George's Terrace in the heart of downtown Perth, it serves as the administrative and engineering services center for all offshore operations currently being conducted in Western Australia and Victoria, and for supporting future operations in Papua New Guinea and New Zealand.

Operations carried out offshore, particularly on the gas-rich province of the North West Shelf, are managed from the new Perth office. To ensure that customers receive superior service, TDW draws personnel and equipment support from TDW's operational facilities in Melbourne, Singapore and Norway. By establishing a dedicated team of engineering and technical specialists in Perth, TDW offers enhanced service and prompt, professional customer service.

Gearing up in Western Australia

Since 2004, TDW has been active in the Western Australia market, completing numerous SmartPlug® pipeline pressure isolation operations offshore on the North West Shelf and in the Bass Strait in southeast Australia. Recently, the company completed a successful pipeline pressure isolation operation to facilitate a valve change-out at a metering station where gas is exported to the domestic consumer market. TDW has also been retained to carry out several high level engineering studies for future pipeline isolations and to provide Emergency Pipeline Repair Systems (EPRS) for new major gas pipeline networks. Engineering studies are often completed several months - or years - before the actual offshore execution. Customers will benefit from the fact that engineers are based locally and readily accessible to meet to discuss solutions.

"With the number of new field developments in the Australian market, we are aware that the demand for SmartPlug pressure isolation services and other services we offer will continue to rise, and that we must be prepared to meet that demand," said Tony Hawkins, Country Manager – Australia for TDW." Our pipeline pressure isolation services are ideally suited to help pipeline operators maintain existing pipeline networks, and to service developments that are currently under construction and following completion. With the combined efforts of our permanent teams in Perth, Melbourne and New Zealand, supported by the offshore team in Norway, we are fully prepared to meet the offshore pipeline pressure isolation needs of operators throughout the region," he added.

Expanding network in Asia Pacific

The new Perth office is the latest addition to TDW's network of facilities in the Asia Pacific region. Last fall TDW opened a 7,500-square-meter Engineering and Manufacturing Center in Savli near Vadodara, India. The new center was established to support India’s pipeline network, which is expected to double during the next three or four years as gas finds and the expansion of the energy market drive infrastructure growth.

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Quetzal Elects Not to Spin Out Guatemalan Assets, Updates Ops

- Quetzal Elects Not to Spin Out Guatemalan Assets, Updates Ops

Wednesday, July 20, 2011
Quetzal Energy Ltd.

Quetzal has elected to not proceed with the previously announced plan of arrangement to spin out its Guatemalan assets to its shareholders through the creation of a separate publicly traded company. The board of directors will review several strategic alternatives to maximize shareholder value of its Guatemalan assets. In addition, the Company has withdrawn its request to approve Quetzal's stock option plan due to a lack of shareholder support. The board of directors will examine compensation alternatives that will enable the Company to continue to attract, retain and motivate highly talented employees.

Guatemala Update

A work-over was conducted on Atzam #2 and the well is producing approximately 40 barrels of 32 degree API oil and 420 barrels of water per day. The oil is trucked to Guatemala City and sold to end users who blend the oil with refined products and use the blend to fire furnaces or power diesel engines. The Company has recently sold loads of oil at prices in excess of WTI plus 20 dollars per barrel. The water is transported by pipeline and injected into the Atzam #1 water disposal well at minimum cost.

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American Petro-Hunter Adds Acreage in South Oklahoma

- American Petro-Hunter Adds Acreage in South Oklahoma

Wednesday, July 20, 2011
American Petro-Hunter Inc.

American Petro-Hunter has executed a Purchase and Sale Agreement which entitles American Petro-Hunter to acquire a 40% Working Interest in a minimum of 3,000 acres of lands in South-Central Oklahoma. The Company has designated the new acreage as the "South Oklahoma Project."

The acreage covers highly prospective Mississippi Limestone targets which, through detailed sub-surface geological mapping and extensive engineering, show Mississippi targets similar and analogous to the recently discovered oil and gas reservoir now being exploited at the North Oklahoma Project. Based on the commercial success of the NOM-1H horizontal well, and the Company's recently announced development plan for the Northern project area which includes an additional 11 horizontal wells, the new South Oklahoma Project offers considerable opportunities to increase the Company's presence in this increasingly important and highly productive region. Additional lands may be acquired and added to the 3,000 acres as leasing is ongoing.

Currently, the Company and engineers have identified 5 key areas under the 3,000 acres which, if developed on 160 acre spacing, could allow future development of 18 additional locations for horizontal wells. Over the next several months, targets will be refined and prioritized with plans to spud the first well in late 4Q or early 2012. The Northern and Southern project development strategy aims for synchronized operations with new drilling commencing every other month, thus ensuring a continuous area wide drilling program throughout the next 24 to 36 months.

Company President Robert McIntosh stated, "By adding these new South Oklahoma projects to our asset base, the Company forecasts the regional drilling of up to 29 horizontal wells in the future which, based on the results we have seen to date, will give American Petro-Hunter a key presence in the emerging Mississippi play and demonstrates that growth by the drill bit is a formula for success in Oklahoma."

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Hydrocarbons Identified at Mart's Nigeria Well

- Hydrocarbons Identified at Mart's Nigeria Well

Wednesday, July 20, 201
Mart Resources Inc.

Mart Resources and its co-venturers, Midwestern O&G (Operator of the Umusadege field in Nigeria) and Suntrust Oil provided an update on the UMU-8 well in the Umusadege field.

The UMU-8 well has reached a final total drilling depth of 8593 feet. Open hole wireline logs have been run with results indicating a total of 16 hydrocarbon bearing sands. The well logs indicate a cumulative gross pay of approximately 385 feet in the 16 sands encountered by the well.

All of the UMU-8 well's primary objectives, including the IX, XI, XIIa, XIIb, and XV sands were hydrocarbon bearing sands based on well log interpretation with results indicating gross oil pay of 32 feet, 14 feet, 39 feet, 26 feet and 11 feet respectively. 9 5/8" production casing has successfully been run and cemented.

The next phase of operations will include perforating the five sands and the installation of completion equipment consisting of a dual tubing string (3 1/2 inch and 2 7/8 inch) configuration. The 3 1/2 inch tubing will have the XV, XIIa and XIIb sands completed and the 2 7/8 inch tubing will have the XI and IX sands completed allowing for future multi-zone production. After the completion equipment is installed, testing on the five individual sands will be conducted. While the dual string will allow for completion and testing of the five sands, it is anticipated that only two sands will initially be produced at any given time.

By way of update, negotiations with the operator of the export pipeline to increase export capacity for the Umusadege field are ongoing and have not yet been finalized. Mart and its co-venturers are continuing to evaluate new pipeline and export options to provide an alternative for future production capacity.
Chairman's Comment

Wade Cherwayko, Chairman and CEO of Mart, said, "Initial interpretation of the logs for the UMU-8 well indicate the primary objective sands are hydrocarbon bearing, including the XI and XV sands that have no proved or probable reserves assigned to them. If testing of the XI and XV sands is successful, the Umusadege field reserves could be increased from previously disclosed reserve estimates."

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Russia and Total to Invest $38B in Arctic Gas Production

- Russia and Total to Invest $38B in Arctic Gas Production

Wednesday, July 20, 2011
Deutsche Presse-Agentur (dpa)

Russia and the French energy giant Total will jointly invest 38 billion dollars in a liquefied natural gas project in the Arctic, Prime Minister Vladimir Putin said Wednesday.

The plan calls for the construction of an Arctic Sea terminal in Russia's Yamal Peninsula which would, once completed in 2018, allow France to receive annually 15.5 million tonnes of liquefied gas by tanker, Interfax reported.

"Thanks to the project Russia's presence in the market for liquefied natural gas (LNG) will expand," said Putin at a Moscow press conference.

Russia's government had previously approved Total's purchase of a 20.5 percent stake in Yamal SPG.

Yamal SPG is owned by Russia's largest private gas producer, Novatek. Total in April purchased a 12 percent stake of Novatek.

Novatek holds a production license to some of the richest gas fields in North West Siberia. The region according to estimates contains some 1.3 trillion cubic meters of gas and nearly 52 million tons of gas condensate.

The Yamal peninsula is a remote Arctic territory of permafrost, tundra, swamp and pine forest. Its remoteness and harsh conditions makes energy development costly.

Copyright 2011 dpa Deutsche Presse-Agentur GmbH

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Range Production Up Despite Barnett Sale

- Range Production Up Despite Barnett Sale

Wednesday, July 20, 2011
Fort Worth Star-Telegram, Texas
by Jack Z. Smith

Despite selling virtually all its Barnett Shale properties in North Texas in April, Range Resources expects to "have fully replaced all of the Barnett production" by the end of the third quarter, CEO John Pinkerton said in an update released in advance of the company's second-quarter earnings report.

Pinkerton said the Fort Worth-based natural gas and oil producer can boost production because of "excellent drilling results in the Marcellus Shale and Mid-Continent regions."

The company has been among the leading producers in the Marcellus natural gas field in Pennsylvania and has benefited from robust oil and gas production in the Mid-Continent region, which includes Texas and Oklahoma.

Range lost production equivalent to more than 100 million cubic feet of natural gas per day by selling its Barnett Shale properties effective April 29. But Range said its second-quarter production volume still averaged the equivalent of 508 million cubic feet of natural gas per day, an 8 percent increase over the second quarter of 2010.

Production for the second quarter of this year was 76 percent natural gas, 17 percent natural gas liquids and 7 percent crude oil, Range said in the operations update issued late Monday. The company is scheduled to report second-quarter results Monday.

Range said it received an average price equivalent to $5.63 per 1,000 cubic feet of natural gas for its second-quarter production, an 11 percent increase over a year earlier. Average prices were $4.63 per 1,000 cubic feet for natural gas, $50.07 per barrel for natural gas liquids and $80.42 per barrel for oil.

Pinkerton said Range is on track to achieve its goal of achieving net production equivalent to 400 million cubic feet of natural gas per day in the Marcellus Shale by year's end.

Based on the performance of 103 Marcellus Shale horizontal wells that began producing in 2009 and 2010, Range is projecting that the estimated ultimate recovery, or lifetime production, from these wells will average the equivalent of 5.7 billion cubic feet of natural gas per well, including about 4 billion cubic feet of gas and 281,000 barrels of liquids (natural gas liquids and crude oil).

The estimated recovery per Marcellus horizontal well is two to three times the estimated lifetime production of many typical wells in the Barnett Shale.

Copyright (c) 2011

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Buccaneer's Kenai Loop Reserves Exceed Expectations

- Buccaneer's Kenai Loop Reserves Exceed Expectations

Wednesday, July 20, 2011
Buccaneer Energy Ltd.

Buccaneer announced an initial Proven and Probable Reserve of 38.3 BCF (4.8 MMBOE) at 100% owned Kenai Loop. These booked Reserves substantially exceed the Company's pre drill assessment of approximately 5.0 – 10.0 BCF.

Ralph E. Davis completed an independent reserve assessment of the Kenai Loop project. Ralph E. Davis is a respected consulting firm providing independent reservoir engineering, geological, technical and financial services to the domestic and international energy industry since 1924.

Proven (1P) Proven & Probable (2P) Proven & Probable & Possible (3P)
Gas - BCF 31.5 38.3 51.6
Oil Equivalent- MMBOE 3.9 4.8 6.5

The above Reserves were calculated using subsurface mapping, pressure and flow rates data attained from KL #1 well. The current Reserves include only two sand packages at 9,700 feet and 10,000 feet. An average drainage area of 340 acres was used to calculate the Reserves and the Company expects that a second well will be required to drain the entire 340 acres. The Company's mapping indicates the two sand packages have a total closure area of 1,600-2,000 acres.

The Proven Reserves have a Future Net Income of US $127.9 million and a Net Present Value (NPV) of US $73.6 million. Assumptions used in the NPV calculation include:
  • Two wells producing at 5.0 mmcfd;
  • A gas price of US $5.71 / mcf;
  • A pipeline tariff of $0.21 / mcf;
  • Operating Costs of US $15,000 per month; and
  • A discount rate of 10%.

The KL # 1 well was drilled to a depth of 10,680 feet and intersected 26 separate gas zones totaling 645 feet of gross pay. The Company elected to perforate and test only the 9,700 and 10,000 feet sands (which totaled 87 feet of gross pay) due to rig availability constraints. The remaining 24 zones totaling 558 feet of gross pay are yet to be tested and do not form part of the Reserves assessment.

Kenai Loop is 100% owned by Buccaneer with total acreage under lease of 8,988 acres.

Near Term Work Plan

The Company expects to spud the second well at Kenai Loop this quarter. The second well will be drilled from the same location as KL # 1 and will have two primary objectives:
  • a step out well to test and possibly extend the known aerial extent of both the 9,700 and 10,000 feet sands. If successful this will effect an increase in the current Proven and Probable Reserves; and
  • to test the sands below 10,000 feet and specifically those at approximately 10,600 feet intersected in KL # 1. These sands appear similar to the 9,700 and 10,000 sands. If this or other objectives are successful then it is expected Proven and Probable Reserves will be increased.

Further details on the commencement date of this well will be made once rig contracts have been executed.


Director of Buccaneer Energy, Dean Gallegos said, "This is a very significant result. We expect that further drilling at Kenai Loop will yield additional increases to booked Reserves. These increases would be based on both the current two pay zones and zones below10,000 feet.

"Clearly, there is substantial upside from the remaining 24 zones (totaling 558 feet of gross pay), which are yet to be tested.”

"As part of the Buccaneer's 3 prong strategy, the Company has planned an aggressively drilling program for the development of the Kenai Loop field and expects to drill additional wells in the next 12 months.

"We anticipate placing the Kenai Loop field into production by the end of 2011."

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Santos to Steer Eastern Star Gas

- Santos to Steer Eastern Star Gas

Wednesday, July 20, 2011
Santos Ltd.

Santos has reached binding agreements to give effect to:
  • the acquisition of 100% of the outstanding ordinary shares in Eastern Star Gas Limited (ESG); and
  • the subsequent sale of a 20% working level interest in ESG's permits in the Gunnedah Basin, northern New South Wales, for A$284 million to TRUenergy Holdings Pty Ltd (TRUenergy).

Pursuant to these transactions, Santos will assume operatorship and own 80% of ESG's coal seam gas (CSG) permits with TRUenergy owning the remaining 20%.

The acquisition of ESG will be conducted via a recommended Scheme of Arrangement (Scheme) under which ESG shareholders will receive 0.06803 Santos shares for every ESG share held.

Based on Santos' closing price of A$13.23 on July 15, the transaction values ESG at A$0.90 per ESG share or A$924 million, and represents a 3P reserves multiple of A$0.50 per gigajoule.

The acquisition of ESG builds on Santos' existing interests in the Gunnedah Basin. Following completion, Santos will have the largest natural gas reserves position in NSW, with 1,216 PJ of 2P reserves and 2,238 PJ of 3P reserves.

TRUenergy, a leading energy retailer with significant power generation interests in Eastern Australia, represents an ideal partner to develop ESG's permits in joint venture with Santos.

Santos is one of Australia's largest domestic natural gas producers and has a long track record of working with local communities to safely and sustainably produce natural gas.

Santos Chief Executive, David Knox, said, "This transaction represents the next major step in Santos' eastern Australia gas strategy and positions the company to meet the expected increase in demand for natural gas from both domestic power generation and export LNG markets."

"The acquisition of ESG is a unique opportunity to consolidate our Gunnedah Basin interests and establish the leading position in Australia's next major natural gas province."

"Santos has been working in regional Australia for more than 50 years, including 15 years exploring for and developing coal seam gas."

"Santos is committed to developing the coal seam gas industry in the Gunnedah Basin without impacting the important role the region plays as an agricultural producer. The growth of the natural gas industry in the Gunnedah Basin will bring new jobs and additional investment to local communities across the region," Mr. Knox said.

Proposed Acquisition of ESG

Santos and ESG have entered into a Scheme Implementation Deed (SID) under which it is proposed that Santos will acquire all of the issued and outstanding ordinary shares of ESG, other than the shares already held by Santos and TRUenergy.

Santos currently owns approximately 20.9% of the issued and outstanding ordinary shares of ESG and TRUenergy owns approximately 3.8%.

Proposed Joint Venture arrangements with TRUenergy

Santos has entered into a series of binding arrangements with TRUenergy, which give effect to:
  • the sale by TRUenergy of its 39 million shares in ESG to Santos at A$0.90 per share resulting in proceeds of approximately A$35 million; and
  • the acquisition by TRUenergy of a 20% interest in ESG's CSG permits and a pro rata share of other assets previously owned by ESG for approximately A$284 million

resulting in net cash consideration to Santos of approximately A$249 million. The sale will take effect on the second business day following completion of the Scheme.

The cash proceeds from TRUenergy fully cover Santos' anticipated incremental capital expenditure to fund its share of the ongoing development of the Gunnedah Basin to the end of 2014.

The agreements with TRUenergy are conditional on the successful completion of the Scheme and regulatory approvals.

Mr. Knox said, "Santos welcomes TRUenergy, one of Australia's largest integrated energy companies, as our joint venture partner in developing this major natural gas province."

TRUenergy's Managing Director, Richard McIndoe, said, "We are pleased to become joint venture partners in the Gunnedah Basin with Santos. With such a qualified partner developing and operating the field, TRUenergy can focus on its core strengths of power generation and retailing with confidence that our equity gas will be available when we need it in the future."

Santos' position in the Gunnedah Basin

Santos first acquired interests in the Gunnedah Basin in 2007, and in 2009 acquired a 20% holding in ESG and a 35% equity interest in various exploration permits operated by ESG.

In addition to the permits held by ESG, Santos' other Gunnedah Basin assets (for which it is already operator) include:
  • 25% of PELs 1 and 12 (Santos can increase its interest to 65% via farm-in);
  • 15% of PEL 456 (Santos can increase its interest to 50% via farm-in); and
  • 100% of PELs 450, 452 and 462.

Assumption of operatorship and majority interest in the various CSG permits will allow Santos to undertake coordinated development of its Gunnedah Basin acreage.

Santos Vice President Eastern Australia James Baulderstone said, "Santos will develop our coal seam gas business working in cooperation with farmers and existing rural businesses in the region, continuing our 50-year track record of building beneficial partnerships with landowners and local communities."

"We are aware of a number of important issues raised by local farmers and other land users concerning the longer term development of the Gunnedah Basin, one of which is the proposed Narrabri to Wellington pipeline. We are confident we can address community concerns in that regard and we will be explaining these plans to the community in the near future, once we have completed our review of Eastern Star's plans."

"We also look forward to ESG staff joining Santos and the important role they will play in developing our assets in NSW," Mr. Baulderstone said.

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DMTI Unveils New Business Unit

- DMTI Unveils New Business Unit

Wednesday, July 20, 2011
Delta Marine Technologies Inc.

Delta Marine Technology, Inc. (DMTI) has opened a new business unit, Construction Division. Previously known for its work in offshore environments, DMTI has begun constructing oil & gas gathering pipelines using a combination of prudent engineering, extensive construction backgrounds, and innovative techniques. DMTI has been awarded a construction contract with Ballard Natural Gas, Inc. to install more than 15,500 feet of 4" pipe to tie its De Zavalla #1 well to a 12" gas transmission pipeline owned and operated by Kinder Morgan Texas Pipeline, LLC. This new pipeline right-of-way (ROW) will lie entirely within a heavily populated and industrialized region of Channelview, Texas. Construction will involve both trenching and directional drilling (HDD) depending conditions encountered along the ROW.

Work began on July 12th and it is anticipated that the project will be completed in three weeks using the approach being employed by DMTI. This target represents a 50% reduction in Ballard's construction schedule and easily achievable if no delays are due to unforeseen weather conditions occur. The net result will be that the well will begin producing income for its owners much sooner than expected. In addition to the construction, the project includes the design and installation of a cathodic protection system along with complete pigging, hydro-testing, and drying until the pipeline meets a -20 F Criteria prior to commissioning the system.

DMTI's Onshore Construction Division will be actively gearing up to be able to handle some of the similar needs for other companies. This business unit will be based out of DMTI's offices in Montgomery, Texas.

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Australia to Dominate Floating LNG Market through 2016

- Australia to Dominate Floating LNG Market through 2016

Wednesday, July 20, 2011
Rigzone Staff
by Karen Boman

Australia's proximity to growing liquefied natural gas (LNG) demand in Asia, its sizable conventional and unconventional gas resources, stable fiscal regime and accessibility to international oil and gas companies, are driving LNG development in the Land Down Under.

UK-based energy research and analysis firm Douglas-Westwood reported that Australia will dominate the floating LNG market between 2010 and 2016 with $5.3 billion in projects. Thirty-six million tones per annum (mtpa) of LNG is under construction in Australia, and more than 120 mtpa is being proposed or in the planning stages, a number that keeps growing as companies discover additional gas reserves, according to the International Gas Union (IGU) World LNG Report 2010.

Australia currently produces 20 mtpa of LNG, but this production level could rise to more than 60 mtpa by 2016 and by 2035, a third of all planned production from proposed and sanctioned LNG projects could come from Australia, said Peter Cleary, VP of Corporate Strategy and Development for Santos Ltd.

LNG development in Australia is being driven partly by development of conventional gas reserves and by coal-bed methane gas to LNG projects, IGU noted. LNG projects under construction include Shell's Prelude floating LNG project, Woodside's Pluto project and Chevron's Gorgon LNG project. These projects represent 25 mtpa.

In Australia, the rapid rise of coal seam gas exploration, development and production has resulted in new additions to its supply. The revolution in coal seam methane has resulted in 16 mtpa of LNG supply from coal seam gas being sanctioned in the past year; another project may be sanctioned later this year, said Cleary.

Shell's recently sanctioned Prelude FLNG project will be one of the biggest game changers the industry will see. FLNG will unlock stranded gas fields, making these reserves commercially viable. "At Santos we are confident our Bonaparte LNG venture with GDF Suez will be another pioneering project in this field," Cleary said.

Santos, Australia's largest domestic gas producer, has a unique LNG portfolio consisting of its Darwin conventional gas supply project, a stake in the ExxonMobil-operated LNG project in Papua New Guinea focused on the Hides gas/condensate field, the coal seam gas to LNG project at Gladstone, and the Bonaparte floating LNG project.

Looking forward to the future LNG market, Cleary sees LNG exporters becoming importers, the increasing importance of partnership with national oil companies, increased market liquidity and trade flow complexities, and new technologies enabling the development of coal seam gas, shale gas, floating LNG and regasification and storage.

Historically, Australian coal bed methane, or coal seam gas development, has typically been part of an integrated power generation effort and/or focused on local retail gas distribution. But more recently, the engine of growth for coal seam gas has shifted to Australia, where there are hopes and plans to link the country's well known and readily accessible reserves and resources to the expected strong demand growth for gas in Asian markets, according to a Ernst & Young report, Coal seam gas: broadening the energy mix.

However, expanded coal seam gas supplies in Australia will face intense gas-on-gas competition, not only from other Australia gas/LNG projects but from other Southeast Asia sources as well as from the Middle East and Russia, Ernst & Young noted.

Australia LNG Project Update

Australia currently is the fifth largest LNG exporter worldwide, and the Australian oil and gas industry is seeking to make Australia the world's first or second largest LNG exporter by 2020, the Australian Petroleum Production and Exploration Association (APPEA) said.

At present, Qatar is the largest LNG exporter with approximately 77 mpta, nearly four times that of Australia's LNG export capacity. While a number of projects are planned for Australia, the majority of these projects will have to move forward if Australia were to replace Qatar as the top LNG exporter. Australia-based LNG projects also face challenges from the isolation of prospective sites, which makes sourcing difficult, environmental issues, aboriginal land rights and political issues. Westwood noted that the Greater Sunrise LNG project is being held back because the Timor Leste government wants an onshore plant rather than FLNG.

Shell in May made the final investment decision for its plans to produce gas from the Prelude field via an FLNG facility. Prelude is located in the Browse Basin, northeast of Broome Western Australia, in water depths of approximately 820 feet. According to APPEA, the country currently has two producing LNG developments, including the North West Shelf and Darwin projects, with three projects under construction in northern Western Australia, Pluto, Gorgon and Prelude, and two in Queensland - Queensland Curtis and Gladstone LNG.

Woodside Energy in late June signed a Native Title Agreement that would establish the Browse LNG Precinct near James Price Point north of Broome in Western Australia. The agreement will allow Woodside to proceed with development of its Browse LNG project. Meanwhile, the first LNG cargo delivery from Woodside's Pluto LNG project will take place in March 2012; the scheduling delay has been attributed to slower than expected progress on the commissioning of the onshore gas plant, seven weeks of direct weather delays and an allowance for an increased contingency. The revised estimate is expected to result in an A$900 million increase in cost to a total of A$14.9 billion (100% project). This estimate includes arrangements with customers affected by the delay.

Japan-based Inpex has received environmental approval from the Australian government for its Ichthys LNG project, paving the way for a final investment decision in this year's fourth quarter. The proposed project includes a subsea production system, semisubmersible central processing facility, a floating production, storage and offtake vessel located in the Ichthys field in the Browse Basin, approximately 124 miles offshore the northwest coast of Western Australia. Onshore gas processing facilities will be located at Blaydin Point, near Darwin. A 549-mile subsea gas pipeline will link the offshore and onshore facilities. Ichthys is expected to product 8.4 million tones of LNG and 1.6 million tones of LPG (liquefied petroleum gas) per year.

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Uganda's Oil Potential Arouses International Interest

- Uganda's Oil Potential Arouses International Interest

Wednesday, July 20, 2011
by Charles Kennedy

The French Ambassador to Uganda has said that the exploration for oil in the country is a key opportunity for Uganda's government to press ahead with its development agendas.

Speaking during celebrations to mark the French National Day in Kampala, Ambassador Aline Kuster-Menager said, "Exploitation of the country's oil resources offers a unique and key opportunity for Uganda to boost its development with new and substantial financial resources," The Monitor reported.

Recent discoveries of vast oil reserves, particularly the oil rich Albertine Graben, with estimated reserves of at least 2.5 billion barrels of oil, mean Uganda is set to become a key oil producer on a part with other African oil producing nations, such as neighboring Sudan, Angola, Nigeria and Equatorial Guinea. Some estimate place the Albertine Graben reserve as high as six billion barrels of recoverable oil.

On the basis of such reserves, government analysts estimate that Uganda will be able to support production of over 100,000 barrels of oil per day for the next two decades.

To exploit these resources, the government has signed several leasing contracts with international companies. The French energy giant Total has been granted a large chunk of the rights of exploitation in the Albertine Graben.

The Tullow Oil exploration has already confirmed Albertine Graben reserves of 2.5 billion barrels of oil. As hydrocarbons have been encountered in 51 out of the 55 wells drilled by Tullow Oil, the developments have put Uganda's discovery rate at 92.3 percent.

(Charles Kennedy is Deputy Editor of The original article appears here.)

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Lukoil Takes Stake in Block Offshore Sierra Leone

- Lukoil Takes Stake in Block Offshore Sierra Leone

Wednesday, July 20, 2011
OAO Lukoil Holdings

Lukoil has acquired from the private company Oranto Petroleum Ltd. a 49% stake in the Petroleum Agreement for SL-5-11 Offshore Block in the Republic of Sierra Leone (West Africa).

The mandatory exploration program within the framework of the Agreement provides for the drilling of one exploration well before 2013.

The SL-5-11 offshore block with an area of 4,022 sq. km is located in the territorial waters of the Republic of Sierra Leone on the shelf and continental slope of the Atlantic Ocean. The water depth within the Block territory varies from 100 m to 3.3 km. 2D and 3D seismic surveys have been conducted at the block, revealing several promising structures. The block is part of the Sierra Leone - Liberia geological basin, where a number of major oil fields have been discovered during the last two years, thus proving its potential productivity.

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Rowan Parts with Land Drilling Division

- Rowan Parts with Land Drilling Division

Wednesday, July 20, 2011
Rowan Companies Inc.

Rowan has entered into a purchase and sale agreement (the "Agreement") with Ensign United States Drilling (S.W.) Inc., a subsidiary of Ensign Energy Services Inc.("Ensign"), to sell Rowan's land drilling division for $510 million in cash, plus working capital of approximately $30 million. The Agreement is subject only to regulatory approval, which the Company expects to obtain within 60 days.

Matt Ralls, President and Chief Executive Officer, commented, "We are pleased to enter into this agreement with Ensign, as we continue to execute our stated strategy to separate non-core businesses. We expect that our after-tax proceeds, estimated at approximately $370 million, will be redeployed into our offshore drilling business and recently announced deepwater expansion. We believe our high-specification land rig fleet will be a strong addition to Ensign's global fleet of over 300 land rigs, and that our land division employees will have significant opportunities with such a large and well-respected operation. I want to personally thank all of the land division employees for their dedication and service over the years as part of the Rowan family, and wish them the best in their careers with Ensign."

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Europa Charges Ahead in Romania

- Europa Charges Ahead in Romania

Wednesday, July 20, 2011
Europa O&G Holdings plc

Europa provided an update on planned operations in Romania for the coming 6 months.

Europa has received both drilling approval and an extension to the license from the Romanian authorities in order to undertake the deepening of the Barchiz-1 exploration well, situated in the EPI-3 Brates Concession (Europa 100%). The deepening of the well is planned to test the exploration target thought to lie beneath the current 1,450m depth of the well.

Aurelian Oil & Gas, the Operator of the Brodina Concession (Europa 28.75%) in northern Romania, has advised partners that the Voitinel gas discovery appraisal well is due to spud on or around October 1, 2011. Subject to the results of this well, a further well is anticipated to be drilled to test the upside to the play in early 2012.

The 2011 seismic program in Romania is underway, with the EIII-3 Cuejdiu area (Europa 17.5%) acquisition over 70% complete. The EIII-1 Brodina program will follow on from this survey. Both of these seismic programs are concentrating on the underexplored thrustbelt oil play.

Managing Director Paul Barrett said, "these Romanian projects are coming together to create a significant amount of activity for the remainder of 2011 and we hope to exit the year with greater reserves and contingent resources."

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TGS to Launch Seismic Acquisition Offshore Sierra Leone

- TGS to Launch Seismic Acquisition Offshore Sierra Leone

Wednesday, July 20, 2011
TGS-NOPEC Geophysical Co. ASA

TGS will commence acquisition of multi-client 3D seismic data in offshore Sierra Leone later this month. This survey marks over ten years of investment for TGS in the West African region and will add 2,535 km(2) to the existing TGS data library. The new 3D seismic will provide important data for continued exploration on the Sierra Leone segment of the West Africa Transform Margin, where recent discoveries have established that a working hydrocarbon system exists.

The M/V GeoCarribean will acquire the 2011 survey. Data processing will be performed by TGS and available to clients in Q1 2012.

The survey is supported by industry funding.

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Providence Starts 3D Seismic Acquisition Offshore Ireland

- Providence Starts 3D Seismic Acquisition Offshore Ireland

Wednesday, July 20, 2011
Providence Resources plc

Providence has, on behalf of itself and its partners, commenced operations for its 3D seismic acquisition project in Frontier Exploration License (FEL) 4/08 in the Porcupine Basin, off the west coast of Ireland. Using a vessel supplied by Polarcus Limited, the c. 200 km2 3D survey is expected to run for approximately 15 days. Providence operates FEL 4/08 (32%) on behalf of its partners, Chrysaor E&P Ireland Limited (60%) and Sosina Exploration Limited (8%).

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Matra Completes Workover Well in Sokolovskoe Field

- Matra Completes Workover Well in Sokolovskoe Field

Wednesday, July 20, 2011
Matra Petroleum plc

Matra announced an update on operations in the Sokolovskoe Field, Russia.

The planned workover on well-12 was completed at the end of June by installing a production packer, with the intention of isolating the productive zones in the well. The well was returned to production by swabbing on July 2 and has been on production since that time. During this period the well has averaged 352 bpd with a water cut of around 42% (net 203 bopd).

Fluid loss from the annulus confirmed a leak in the casing/liner system, although installation of the production packer has not stopped water production as intended. Well-12 was drilled through the oil-water-contact ('OWC') and encountered various operational problems during drilling and side-tracking, making definitive analysis difficult. Well performance has been reduced by the presence of water in the tubing and the high viscosity of the resulting oil/water emulsion. At the current time, the source of the water has not been identified and the well will continue on production and to be monitored.

It is planned that future wells will be terminated above the OWC thereby facilitating good cement bonding and zone isolation. The independent study carried out last year by ERC/Equipoise concluded that the Company should encounter better reservoir to the north of the two existing wells where full development of subsurface reefs are expected.

Planning and approvals for the full field 3D seismic survey and the drilling of well-14 are continuing with both operations intended to commence later this year.

Matra's Managing Director, Peter Hind commented, "Well-12 continues to produce commercial quantities of oil and is generating cash flow. The well has also provided us with invaluable data on the structure of the Sokolovskoe Field. Given our improved knowledge from the data, the independently verified study of the field's potential and the forthcoming 3D seismic survey, we look forward to progressing with Well-14 later this year."

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Max Petroleum to Boost Daily Production at Kazakh Field

- Max Petroleum to Boost Daily Production at Kazakh Field

Wednesday, July 20, 2011
Max Petroleum plc

Max Petroleum provided a production update for the Zhana Makat Field.

The ZMA-ET1 well has been connected to temporary production facilities for long-term production testing and is currently producing at a stable rate of approximately 650 bopd barrels of oil per day ("bopd") from perforations in the T4 Triassic reservoir at depths from 1,282 to 1,288 meters. The current production rate has been restricted to 650 bopd while the Company monitors the level of gas production from the well.

The Company has also perforated the ZMA-ET2 appraisal well, successfully flowing 48 degree API oil at an equivalent rate of approximately 450 bopd from perforations in the T5 Triassic reservoir from depths of 1,315 to 1,321 meters during a limited flow-back period. The well will be connected to temporary production facilities and brought onto long-term production testing in August 2011. The Company expects the well to produce at a stabilized rate of approximately 500 bopd.

Michael B. Young, President and CFO, commented, "We are on track to increase aggregate daily production during the current quarter to approximately 3,500 bopd, which is a significant milestone for the Company."

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CNOOC Extends Oil Sands Presence with $2.1B Deal

- CNOOC Extends Oil Sands Presence with $2.1B Deal

Wednesday, July 20, 2011

CNOOC has entered into an Arrangement Agreement to acquire OPTI Canada Inc ("OPTI"). The aggregate value of the consideration of the transaction is approximately US $2.1 billion, which includes aggregate cash consideration of US $1.25 billion payable to the holders of the OPTI shares (US $34 million) and the Second Lien Noteholders (US $1.216 billion). In addition, due to a change in control of OPTI as a result of the transaction, OPTI will be required to offer to repay the holders of its outstanding First Lien Notes (US $825 million in principal amount) pursuant to the indentures governing the First Lien Notes. The transaction will be effected by way of a plan of arrangement through concurrent proceedings under the Companies' Creditors Arrangement Act (Canada) and the Canada Business Corporations Act.

The proposed transaction must be approved by the Second Lien Noteholders at a special meeting that is expected to be held in September,2011. Noteholders representing approximately 55.2% of the principal amount of the Second Lien Notes have executed support agreements pursuant to which, among other things, they have agreed to vote in favour of the transaction.

The proposed transaction is also subject to certain terms and conditions, including, among other things, applicable government and regulatory approvals by the relevant authorities in Canada and the People's Republic of China, and Canadian court approval. The transaction is expected to be completed in the fourth quarter of 2011. Upon completion of the transaction, OPTI will become an indirect wholly-owned subsidiary of the Company, and all of the Second Lien Notes will be transferred or assigned, directly or indirectly, to a subsidiary of the Company. All existing options, warrants and other rights to purchase OPTI shares will be cancelled.

The principal asset of OPTI consists of a 35% working interest in the Long Lake and three other project areas located in the Athabasca region of northeastern Alberta. Long Lake project includes steam assisted gravity drainage ("SAGD") Operation and an Upgrader. Nexen Inc. ("Nexen"), a Canadian-based global energy company, holds the remaining 65% and is the sole operator. The Long Lake SAGD Operation is expected to have through-put rates of approximately 72,000 barrels per day of bitumen at full production. It is anticipated that the Long Lake Upgrader will ultimately produce approximately 58,500 barrels per day of products, primarily Premium Sweet Crude (PSCTM).

As disclosed in OPTI's disclosure documents filed with securities regulatory authorities in Canada, OPTI's working interest share, before royalties, of raw bitumen reserves and resources on its oil sands leases is estimated to be 195 million barrels of proved reserves, 534 million barrels of probable reserves, 1,100 million barrels of contingent resources and 335 million barrels of prospective resources. These reserves and resources are estimated to be sufficient to support approximately 430,000 barrels per day (150,000 barrels per day net to OPTI) of bitumen production.

Mr. Yang Hua, Chief Executive Officer of the Company stated, "The transaction strengthens our Canadian presence in the oil sands business. We believe that upside potential of the assets will facilitate local energy supply and our production growth in the long term.

"We are pleased to expand our presence in the oil sands business after our successful investment in MEG. We believe that the upside potential of the acquired assets will benefit the shareholders of CNOOC Limited."

Mr. Li Fanrong, President of the Company said, "We look forward to working with our new partner Nexen, to optimize value from the Long Lake Project and the three other jointly owned oil sands leases."

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