Oil & Gas Post - All News Report for Monday, August 08, 2011

Monday, August 08, 2011

• Commodity Corner: WTI, Brent Futures Plummet
• RBG Scores Chevron QA/QC Inspection Contract
• Clough to Sell Offshore Marine Business
• Basic Energy's Rig Utilization Falls
• Oil Futures Land At Lowest In Almost 9 Months
• Contango On Schedule for Vermilion Production
• Key Completes Acquisition of Edge, Summit Oilfield Services
• Rowan Gets Go-Ahead for Share Repurchase Program
• Enbridge Energy to Add Cryogenic Natural Gas Processing Plant
• Iraq Oil Ministry Qualifies 41 International Firms for New Bid Round
• Baker Hughes Lands Gig at Lukoil's West Qurna Field
• Iran Discovers Another Gas Field Worth $133B
• Gulfsands Flows Rate of 5516 bopd at Khurbet East Well
• Noble Briefs New Contracts, Contract Extension for Rigs
• ATP Primes Bit for Shimshon Prospect Offshore Israel
• Max Petroleum Confirms Oil Pay at Uytas Field
• Statoil, Partners Hit Significant Oil Pay in North Sea
• Total Makes Major Gas Find in Barents Sea
• ONGC In Talks to Sell Indian Ocean Deepwater Stakes
• Chariot Sells Stake in Namibia Block to BP
• Max Petroleum Discovers Oil in East Kyzylzhar
• Range Successfully Drills First Development Well in Trinidad
• Heritage Commences Drilling in Kurdistan

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Commodity Corner: WTI, Brent Futures Plummet

- Commodity Corner: WTI, Brent Futures Plummet

Monday, August 08, 2011
Rigzone Staff
by Matthew V. Veazey

On the first trading day after Standard & Poor's downgraded the United States' long-term credit rating from AAA to AA+, the WTI settled at its lowest point in nearly nine months.

Light sweet crude oil lost $5.57 to end the day at $81.31 a barrel—just six cents higher than the Nov. 23, 2010, settlement price. Concerns that the U.S. is slipping into a double-dip recession have dampened expectations about oil demand. Equity markets also sustained significant losses Monday. The Dow Jones Industrial Average fell 5.55 percent while the S&P 500 declined nearly 6.7 percent.

The Brent futures price also plunged Monday but to a somewhat more modest degree than the WTI. It ended the day at $103.47, marking a $5.63 decline from Friday.

The WTI peaked at $85.73 and bottomed out at $80.17 while the Brent traded within a range from $102.88 to $106.92.

Also reflecting fears about slumping demand was the price of gasoline for September delivery, which lost 4.1 percent to end the day at $2.69 a gallon. Front-month gasoline traded within a range from $2.80 to $2.67 Monday.

September natural gas remained relatively steady Monday, losing less than one cent to settle at $3.935 per thousand cubic feet. Natural gas peaked at $3.97 and bottomed out at $3.855.

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RBG Scores Chevron QA/QC Inspection Contract

- RBG Scores Chevron QA/QC Inspection Contract

Monday, August 08, 2011
RBG

RBG has been awarded a three year contract to provide Chevron North Sea Limited with global QA/QC (quality assurance/quality control) inspection services. RBG have provided similar inspection services to Chevron since 2002.

The contract involves the provision of both full time and ad-hoc quality personnel, including principal and senior QA/QC inspectors, which deliver expert third party vendor inspection services for Chevron onshore and offshore, across the UK, Continental Europe, Americas and Asia-Pacific.

The experienced RBG team supports new build works and servicing of equipment for Chevron's drilling, completion, subsea and topside activity and supports Chevron in ensuring that the work is carried out in accordance with the required industry standards and meets the company's specifications. Activities can range from witnessing the manufacture of pipe being produced at pipe mills in Japan to inspecting wellheads fabricated in Europe and North America.

Doug Bolton, RBG's quality services manager, said, "We are very happy to have been awarded this significant three-year contract. Since 2002, we have developed an excellent working relationship with Chevron and I am confident that the high quality of work carried out by our embedded team of inspectors was a significant factor in securing this contract award. We look forward to continuing our work with Chevron over the next three years.

"We have experienced a notable rise in vendor inspection activity in recent years and our truly international reach means we can provide a cost-effective service that ensures product quality and timely delivery."

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Clough to Sell Offshore Marine Business

- Clough to Sell Offshore Marine Business

Monday, August 08, 2011
Clough Ltd.

Clough has agreed to sell its offshore Marine Construction Division to SapuraCrest Petroleum Berhad (SapuraCrest), a company listed on the Malaysian stock exchange, for gross proceeds of approximately AUD 127MM in cash. The companies have entered into a conditional Master Sale and Purchase Agreement with certain conditions precedent.

Clough's offshore Marine Construction Division includes the derrick lay barge, Java Constructor, and associated marine construction equipment. Also included will be Clough's interest in the Clough Helix Joint Venture, which operates the chartered Normand Clough vessel, and its investments in specialist engineering businesses, OFI and Peritus. Relevant contracts including the Chevron Gorgon Domestic Gas pipeline project are proposed to be novated.

Post transaction the division will continue to operate from Perth with a continuing focus on both the Australian and regional markets. Clough will continue to provide a number of back office services to the business for a period of two years.

The sale will see Clough exit the asset intensive offshore marine construction market. Clough CEO, John Smith said, "While Clough has enjoyed a long history of successfully executing marine construction projects, it is a sector where significant capital investment is required to compete with the larger regional and global players. Our results have been lumpy in this division and consistency requires scale, flexibility of assets and broad geographic coverage. We believe SapuraCrest will bring these characteristics and we wish them and the skilled workforce who will transfer every success for the future. Opportunities abound in the Australian gas and mineral sectors. Our strategy remains that of Engineering led EPC and this transaction leaves Clough with significant net cash and with capacity for further investment."

The sale is subject to satisfaction of a range of conditions precedent, including SapuraCrest obtaining Malaysian Central Bank and shareholders' approval, the consent of relevant clients and partners, the transfer of certain marine construction division staff, and Clough receiving approval from its debt funders. It is anticipated that satisfaction of these conditions precedent will take up to three months. As a result, completion of the sale is currently expected to occur in Q2 of the 2011/12 financial year.

The Marine Construction Division reported an underlying loss of AUD 7.6MM in the 6months to December 31, 2010 after reporting underlying earnings of AUD 24.1MM in the year ended June 30, 2010. Based on current estimates, the one off profit on the sale is expected to be approximately AUD 8MM. The net increase in cash held by Clough will be approximately AUD 50MM after full repayment of Clough's debt facility with RBS and allowing for cash held by the division.

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Basic Energy's Rig Utilization Falls

- Basic Energy's Rig Utilization Falls



Aug 8, 2011

Basic Energy Services Inc.(NYSE:BAS) reported Monday that its July well servicing rig utilization rate fell slightly to 73% from 74% in the prior month.

The number of well servicing rigs stayed unchanged at 412 as of July 31, but rig hours fell to 69,000 from 73,600 the month before.

The count for drilling rigs remained at 10, but drilling rig days climbed to 279 from 256 in June. Drilling utilization rose to 90% from 85% in June.

Basic's fluid services truck fleet increased to 871 by the end of the period from 838 at the end of June.

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Oil Futures Land At Lowest In Almost 9 Months

- Oil Futures Land At Lowest In Almost 9 Months



Aug 8, 2011

Crude-oil futures on Monday settled at their lowest since late November as fear gripped markets following Standard & Poor's announcement late Friday to cut the U.S. debt ratings.

Crude for September delivery tumbled $5.57, or 6.4%, to $81.31 a barrel on the New York Mercantile Exchange -- the biggest one-day drop for a most-active oil contract since early May.

Oil had fallen 9.2% the previous week.

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Contango On Schedule for Vermilion Production

- Contango On Schedule for Vermilion Production

Monday, August 08, 2011
Contango O&G Corp.

Contango announced that it is still on schedule for production to begin at its Vermilion 170 (Swimmy) discovery in September 2011 at an estimated rate of 15 million cubic feet equivalent per day (Mmcfed), net to Contango. We currently have 11 wells, producing approximately 77 Mmcfed, net to Contango.

The exploration plan (EP) for our Ship Shoal 121/134 (Eagle) prospect was submitted to the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) on March 3, 2011 and approved on July 11, 2011. We submitted our application for permit to drill on July 29, 2011 and are hopeful it will be approved in September 2011. Depending on permit approval and rig availability, we expect to spud this well in the September/October 2011 time frame. We will have a 100% working interest in this wildcat exploration prospect and have budgeted approximately $25.0 million to drill this well. We have also invested another $6.0 million in leases associated with Eagle. We have $120 million in net available cash, no debt, and $40 million of unused borrowing capacity.

Kenneth R. Peak, Contango's Chairman and Chief Executive Officer, said, "We are preparing to expend a budgeted $31.0 million of dry hole risk capital on our Eagle prospect. This is a significant capital commitment and risk for the Company, but one we believe is justified, both by the potential of the prospect and our capital position. Contango is an approximate 40% tax payer and thus has a built-in partner – the Federal Government - that 'shares' in our after-tax dry hole capital risk. Assuming a dry hole – and the probabilities are that Eagle will be a dry hole – we would incur a projected $31.0 million write off, both for GAAP accounting and income taxes. The income taxes that we would otherwise owe, however, would be reduced by approximately $12 million. Thus, a dry hole at Eagle would reduce our net, out of pocket, after-tax cash investment to $19 million. With an on-hand cash balance of $120 million and no debt, this is a financial loss - though painful – that we can afford to take. Should Eagle be a discovery, however, we will have a 65% net revenue interest in what we believe would likely be an oil discovery with a prospect size – net to Contango – of 7 to 10 million barrels."

Mr. Peak continued, "In addition to our Eagle prospect we have another four exploration ideas that we believe will mature into drillable prospects over the next 18 - 24 months. We are preparing an EP on our South Timbalier 75 farm-in prospect (Fang) which we plan to submit to the BOEMRE and, upon receiving all regulatory approvals, would expect to drill in early 2012. This prospect has an estimated $25.0 million in dry hole costs to the 100% working interest. Of our remaining three prospects, one is our Birdy prospect (Ship Shoal 121), and the other two are exploration ideas we are hopeful will mature and drill in 2012. The preliminary estimated dry hole costs of these remaining three prospect ideas are an estimated combined $50.0 million. Thus, we are managing our cash position in preparation to commit approximately $100 million to wildcat exploration ideas, or a net $60 million in after-tax risk capital, over the next 18 - 24 months. Should we have exploration success on any of our prospects, we will have the opportunity to invest significantly more capital to bring any discoveries to full production.

"The investment thesis for Contango is easy to summarize: Approximately 300 Bcfe in reserves as at June 30, 2011, 15.7 million shares both outstanding and fully diluted, $120 million in cash, no debt, 12 producing wells, five prospect ideas, no hedges and eight employees."

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Key Completes Acquisition of Edge, Summit Oilfield Services

- Key Completes Acquisition of Edge, Summit Oilfield Services

Monday, August 08, 2011
Key Energy Services Inc.

Key Energy completed the previously announced acquisition of Edge Oilfield Services and Summit Oilfield Services. Total consideration for the transaction was $307.6 million, consisting of approximately 7.5 million shares of Key common stock and $189.7 million in cash, which includes $26.3 million to reimburse Edge capital expenditures, net of working capital adjustments.

Edge primarily rents frack stack equipment used to support hydraulic fracturing operations and the associated flow back of frack fluids, proppants, drilling and completion fluids, and oil and natural gas. It also provides well testing services, rental equipment such as pumps and power swivels, and oilfield fishing services.

Key's Chairman, President, and CEO, Dick Alario, stated, "We are excited to complete this transaction and welcome the Edge employees to Key. We expect Edge to increase our exposure to the horizontal well completion markets, and we hope to leverage our broad U.S. infrastructure to facilitate expansion of this high quality business in the coming years. We anticipate Edge's business will be accretive to Key's margins and earnings beginning this year, and we will provide additional guidance for Key's full-year 2011 results including Edge at a later date."

Edge's CEO, Darrell Brewer, stated, "We are happy to have reached this milestone in our company's history and become a part of Key. Our employees and I look forward to continued strong growth as part of the Key family."

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Rowan Gets Go-Ahead for Share Repurchase Program

- Rowan Gets Go-Ahead for Share Repurchase Program

Monday, August 08, 2011
Rowan Companies Inc.

Rowan's board of directors has authorized the Company to repurchase up to $100 million in shares of its common stock.

Matt Ralls, Rowan's President and Chief Executive Officer, commented, "This share repurchase program is an expression of confidence in Rowan's long-term future and ability to continue to create shareholder value."

This program is effective immediately. Repurchases under this program will be made through the open market or in privately negotiated transactions. These repurchases may be commenced or suspended from time to time without prior notice.

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Enbridge Energy to Add Cryogenic Natural Gas Processing Plant

- Enbridge Energy to Add Cryogenic Natural Gas Processing Plant



Aug 8, 2011

Enbridge Energy Partners (NYSE:EEP) announced that it will construct a 150 million cubic feet per day cryogenic natural gas processing plant on its Anadarko gas gathering system near Wheeler, Texas.

The $230 million Ajax plant--strategically located to serve the rapidly Granite Wash play will add much-needed gas processing capacity to the Patnership's

Anadarko system is expected to be in-service by early 2013.

Enbridge Energy Partners (NYSE:EEP) has a potential upside of 25.8% based on a current price of $26.35 and an average consensus analyst price target of $33.14.

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Iraq Oil Ministry Qualifies 41 International Firms for New Bid Round

- Iraq Oil Ministry Qualifies 41 International Firms for New Bid Round

Monday, August 08, 2011
Dow Jones Newswires
AMMAN
by Hassan Hafidh

The Iraqi oil ministry has qualified some 41 international companies to compete for 12 exploration blocks in the next bidding round which is scheduled to be held in January, the ministry said in statement Monday.

Iraq, which sits on the world's third largest oil reserves, has estimated that the new blocks would add some 10 billion barrels of oil to Iraq's current reserves of 143 billion barrels, and some 29 trillion cubic feet of gas to its current reserves of 112.6 trillion cubic feet.

Among the companies qualified by the ministry for the licensing auction are some of the world's oil majors such as BP, Shell, ExxonMobil, Lukoil, Total, China National Petroleum Corp., or CNPC, Eni, Occidental Petroleum Corp. (OXY) and Chevron.

The list also includes nine Japanese firms. They are, among others, INPEX, Japan Oil, Gas and Metals National Corp., or JOGMEC, Mitsui Oil Exploration Co. Ltd, JX Nippon Oil & Gas Exploration Corp., or JX-NOEX, Itochu, Mitsubishi, and Japan Petroleum exploration Co. Ltd, known as Japex.

Two Arab companies are listed by the ministry. They are Mubadala Oil & Gas of the United Arab Emirates, and Kuwait Energy of Kuwait.

The ministry said the chosen companies are among 50 firms who submitted applications and documents to take part in the bidding round, scheduled to be held in January next year.

Many of the listed companies have won deals to upgrade Iraq's vast oil and gas fields. Baghdad has held three bidding rounds in the past two years to auction off 15 of the country's most prized oil and gas fields.

Three of the announced blocks are located in the western Anbar province while two others are shared by the Anbar, Nineveh and Najaf governorates. The sixth is in Nineveh governorate in northern Iraq. These six are believed to contain gas resources, oil ministry officials said.

The remaining five blocks, believed to contain crude oil resources, are located in other governorates including Basra, Dhi Qar (Nassiriyah), Muthanna (Samawa), Babil, Najaf, Wasit and Diyala provinces, the officials said.

The size of the blocks range from 5,500 square kilometers to 9,000 square kilometers, they added.

Iraq needs to boost gas production and build more gas-fired power plants to increase its power output, currently at 6,500 megawatts, which represent less than half the country's needs.

Although international companies would prefer production-sharing contracts for exploration blocks, Iraqi oil officials said the deals would be based on a service contract, which means winning companies will be paid a flat fee for their services rather than be given a share in the resources. But it would be slightly different from the 20-year service contract offered in the previous three bidding rounds, they said.

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

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Baker Hughes Lands Gig at Lukoil's West Qurna Field

- Baker Hughes Lands Gig at Lukoil's West Qurna Field

Monday, August 08, 2011
Baker Hughes Inc.

Lukoil has awarded Baker Hughes a two-year contract to provide full drilling and completion services for 23 wells in the West Qurna field in southeast Iraq, 50 kilometers (31 miles) west of Basra.

Under the terms of the contract, Baker Hughes will provide engineering and project management for the turnkey drilling and completions scope of the project. Baker Hughes will supply drilling services, formation evaluation, casing and tubing running services, completion tools and services, wellbore intervention services, and wireline logging as well as perforation operations. Baker Hughes also will contract all third-party services, equipment, personnel, tools and materials required for the project, including the provision of up to five drilling rigs and three workover rigs.

Some of the wells will be drilled directionally, targeting the Mishrif formation, with step outs of up to 3,000 meters (9,842 feet). The wells are closely spaced, so the operation will employ a cluster (pad) drilling technique. The five drilling rigs and three workover rigs will be mounted on skids for fast, efficient rig moves.

Baker Hughes is well positioned in Iraq to execute the West Qurna project. In 2010 Baker Hughes opened a 120,000 square-meter (1.3 million square-feet) operations base in Basra to serve the Iraq oil and gas industry. The base includes a workshop to support a wide range of Baker Hughes products and services. The facility also houses chemical blending capabilities and inventory, as well as bulk drilling fluids storage for quick response to customers' requirements.

In addition to the LUKOIL drilling and completions award, Baker Hughes manages and operates drilling and workover rigs in the Zubair field for an international oil company. Baker Hughes also has a strategic alliance with the South Oil Company to support the development of Iraqi wireline capabilities; and supplies electrical submersible pumping (ESP) systems and services—including real-time remote monitoring and automation capabilities to optimize production—to three major international operators.

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Iran Discovers Another Gas Field Worth $133B

- Iran Discovers Another Gas Field Worth $133B

Monday, August 08, 2011
TEHRAN
Dow Jones Newswires

Hydrocarbon-rich Iran has discovered another gas field with reserves of 495 billion cubic meters, valued at $133 billion, the oil ministry's SHANA news service quoted an oil official as saying Monday.

"The new gas field has in spot reserves of about 495 billion cubic meters (17.5 trillion cubic feet) valued at $133 billion and is located east of Assalouyeh," National Iranian Oil Company (NIOC) managing director Ahmad Qalebani said.

Assalouyeh, in the southern province of Bushehr, is the base for developing Iran's offshore South Pars field which Tehran shares with Qatar.

It holds an estimated 14 trillion cubic meters of gas (500 trillion cubic feet) or about eight percent of the world's total.

The Islamic republic, which has divided South Pars into 28 phases, has proven gas reserves of 33 trillion cubic meters second largest in the world after Russia.

Iran consumes almost all of the 600 million cubic meters per day of gas it produces, but hopes to double production and export 250 million cubic meters a day to its neighbors and Europe from 2015 by developing the giant South Pars field.

Tehran also announced Monday an increase of 17 million cubic meters in phase 10 of South Pars, SHANA reported.

"Gas production in phase 10 of South Pars has increased by 17 million cubic meters," said Moussa Souri, director of Pars Oil and Gas.

But the South Pars development has been delayed amid a lack of investment in a country faced with severe gas needs of its own and because of difficulties in procuring the required technology.

Iran's vital energy sector is one of the key areas targeted by world powers in sanctions imposed against Tehran for pursuing its controversial nuclear program.

Most Western and European energy firms have withdrawn or put on hold their investments in the country's energy sector.

Iran is the second largest producer within Organization of Petroleum Exporting Countries at 3.7 million barrels per day, and has oil reserves of around 155 billion barrels.

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

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Gulfsands Flows Rate of 5516 bopd at Khurbet East Well

- Gulfsands Flows Rate of 5516 bopd at Khurbet East Well

Monday, August 08, 2011
Gulfsands Petroleum plc

Gulfsands provided an update on operations in Syria.

Flow Testing of Khurbet East 19H ("KHE-19H")

The Khurbet East 19H ("KHE-19H") well has achieved a flow rate of 5516 barrels of oil per day ("bopd") on production test with an oil gravity of approximately 26 degrees API, similar in quality to the oil produced in the central portion of the Khurbet East Field. This production rate was obtained during a 2 hour main flow period under a 48/64th inch choke size and with an average wellhead pressure of 132 psi and with no associated production of formation water. The choke size was subsequently reduced to 32/64th inch, after which the well was flowed for a further 3 hours at an average rate of 3828 bopd, at an average wellhead pressure of 210 psi and with no production of water. The test was then terminated due to all available oil storage tank capacity being filled. The 67 meter horizontal productive section of this well is located in a sidetrack drilled in a south-southeasterly direction from the original KHE-19 vertical hole.

The oil flow rate of 5516 bopd from KHE-19H is the highest yet measured from any well within the Khurbet East field. This well has demonstrated that excellent reservoir quality exists from the central portion of the field all the way to the northern limit of the field.

Commissioning of Khurbet East Sub-station Production Facility

The oil processing capacity for the Khurbet East Field has been increased by approximately 3000 bopd after the construction and commissioning of a new oil processing sub-station ("EFP 2") with a design capacity of approximately 3000 bopd and located approximately 1.8 kilometers west of the Khurbet East Early Production Facility ("EPF"). At this new facility, gas is separated from the produced oil and the stabilized crude is pumped into storage tanks located within the EPF complex followed by subsequent delivery into the Khurbet East export pipeline. Well KHE-19H has been tied into the new sub-station and is estimated to be producing at a rate of more than 2900 bopd on a restricted choke.

As a result of these operational and construction activities, Block 26 oil production facility capacity is now more than 24,000 bopd. The reconciled production rate achieved at the expanded facilities as of 6th August, 2011 was 24,054 bopd, comfortably achieving and exceeding the Company's previously announced year-end 2011 production target of 24,000 bopd.

Block 26 Drilling Operations

Gulfsands drilling operations in Syria Block 26, using the Crosco E-401 and E-501 drilling rigs, are continuing as planned on the Yousefieh East and Safa exploration prospects. The results of these exploration drilling operations will be the subject of a future news release.

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Noble Briefs New Contracts, Contract Extension for Rigs

- Noble Briefs New Contracts, Contract Extension for Rigs

Monday, August 08, 2011
Noble Corp.

Noble has been awarded a contract for the semisubmersible rig Noble Paul Romano and received a contract extension on the semisubmersible rig Noble Max Smith, two rigs located in the Gulf of Mexico. In addition, the Company has been awarded a contract for the jackup rig Noble George Sauvageau operating in the Southern sector of the North Sea.

The Noble Paul Romano has been awarded a six well, approximately 180-day contract by Gujarat State Petroleum Corporation Ltd. (GSPC) for operations offshore Egypt at a dayrate of $325,000, excluding mobilization revenues. The rig, which has been idle in the U.S. Gulf of Mexico since June 2010, is expected to commence the new contract in October 2011, following mobilization to an initial drilling location in the Eastern Mediterranean Sea. The contract could be extended for up to four optional wells. The Noble Paul Romano is a Noble EVA 4000, conventionally moored deepwater semisubmersible rated to operate in water depths of up to 6,000 feet.

Also, the Noble Max Smith, operating offshore Mexico for Pemex Exploracion y Produccion (PEMEX), has received a five-month extension of its current contract. The extension commenced in August 2011 at a dayrate of $380,000. The Noble Max Smith is a Noble EVA 4000, conventionally-moored deepwater semisubmersible capable of operating in water depths of up to 7,000 feet. The rig has operated offshore Mexico since August 2008.

In addition, the Company reported that the semisubmersible rig Noble Driller commenced its full operating dayrate of $383,000 on August 1, 2011 and has mobilized to an operating location in the U.S. Gulf of Mexico. The rig is under contract through June 2013.

Finally, the Noble George Sauvageau has been awarded a one-year contract by Wintershall for operations in the Southern sector of the North Sea at a dayrate of $115,000. The rig is now firmly committed through 2012.

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ATP Primes Bit for Shimshon Prospect Offshore Israel

- ATP Primes Bit for Shimshon Prospect Offshore Israel

Monday, August 08, 2011
ATP O&G Corp.

ATP O&G announced an operations update for its properties in the Gulf of Mexico, the North Sea and Offshore Israel. Company-wide production continues to be 24-25 MMBoe/d.

Clipper

ATP commenced well operations with the Diamond Ocean Victory drilling vessel at the Green Canyon (“GC”) Block 300 (“Clipper”) #2 ST#1 during the second quarter of 2011. In July 2011, ATP successfully completed and flow tested the well at 45.6 MMcf per day plus condensate of 4,656 Bbls per day. The well is scheduled to be placed on production in the middle of 2012 after completion of the pipeline and tie-back to existing infrastructure.

After completion of the GC #2 ST #1, the Diamond Ocean Victory will move to the GC #4 well, re-enter and sidetrack the well to the targeted oil zone. All required permit applications have been submitted to the BOEMRE.

ATP operates Clipper and presently owns a 100% working interest.

Gomez Hub

During June 2011, ATP completed and returned to production the Mississippi Canyon (“MC”) Block 711 #5 well bringing to six the number of wells producing at Gomez. The development drilling plan (“DOCD”) for MC 711 #9 and MC 711 #10 were deemed submitted to the BOEMRE on June 8, 2011. Upon approval of the DOCD and the well permits, ATP expects to commence drilling at MC 711 #9 and #10 with first production expected mid-2012. The exploration plan has also been submitted for MC Block 710, a block immediately adjacent to MC 711 which displays similar seismic and technical characteristics to MC Block 711. Original proved reserve estimates of the Gomez Hub accounted for 14.8 MMBoe. Since commencement of production through June 2011 the Gomez Hub has already produced gross volumes of 24.8 MMBoe (66% oil).

ATP operates the deepwater Gomez Hub, has a 100% working interest in MC 711, 710 and 755, a 75% working interest in MC 754 and owns 51% of the ATP Innovator through a partnership with GE.

Telemark Hub

The MC Block 941 A-1 (#3) continues to produce as expected from the commingled C and D sands. Since inception, October 2010 through June 2011, the well has produced gross volumes of 2.8 MMBoe (85% oil and 15% gas). Based on the strong performance of the #3 well to-date, ATP expects to recover from the #3 and #4 wells all of the reserves that were initially projected from the C and D sands. Current water production of approximately 950 barrels per day is from the D sand which is to be expected since the downdip well, originally drilled by Vastar, was wet. Water cut is expected to increase until the D sand in the well, which represents less than 2% of the total proved and probable reserves of the Telemark Hub, is depleted, at which time the D sand sleeve will be closed. The ATP Titan, the floating production facility that services the Telemark Hub, has the capacity to process 25,000 Bbls of oil/day, 50 MMcf of gas/day and 15,000 Bbls of water/day.

Currently the MC Block 941 A-2 (#4) well is being completed; productive intervals in the C and D sands have been perforated and independently frac-packed. All remaining permits to complete this well have been approved, and remaining operations include running tubing, reconfiguring to allow flow testing the well and turning the A-2 to sales. First sales from the MC Block 941 A-2 are expected in the third quarter.

The MC Block 942 #2 well, which is already drilled to approximately 12,000 feet, will be drilled to total depth upon approval of the drilling permit by the BOEMRE and following the completion of the MC Block 941 A-2 well. ATP plans to complete drilling the well in the fourth quarter and expects first production by year-end.

ATP operates the deepwater Telemark Hub with a 100% working interest and owns 100% of the ATP Titan and associated pipelines and infrastructure.

UK North Sea

During the second quarter, the work on the Octabuoy floating production facility continued in the shipyard. Hull construction is on schedule and completion is expected early in 2012. Platform topsides are under construction in China (the utility module) and the US (the processing module). Upon completion of the processing module it will be shipped to China to be joined with the utility module. The hull and topsides will then sail to Norway for final commissioning and on to the Cheviot field in the North Sea where production is expected to begin in 2014.

In addition to Cheviot, ATP is working on its Skipper and Blythe projects in the UK North Sea. At Skipper, an oil project, an appraisal well to test production rates is scheduled for next year. At Blythe, predominately a gas project, discussions are ongoing to determine the most economic offtake route for the gas from this field. Development at Blythe is expected to commence in 2013. Skipper is located in the central UK North Sea in water depths of approximately 300 feet. Blythe is located in the Southern Gas Basin in water depths of approximately 100 feet. ATP operates both Skipper and Blythe and has a 50% working interest ownership in each.

Israel Expansion

During June 2011, through its subsidiary ATP East Med B.V., ATP acquired interests in three deepwater licenses in the Mediterranean Sea offshore Israel. ATP will operate its licenses, Shimshon, Daniel East and Daniel West, with a working interest of 40%. In the Mediterranean Sea, ATP licenses relate to exploratory prospects where drilling has occurred nearby and hydrocarbons have been discovered by others. ATP capital investment in the Mediterranean Sea is expected to be minimal for the remainder of 2011 as ATP prepares its exploratory and development plans for drilling in 2012.

ATP East Med, as operator of the licenses, has assumed the drilling contract with Transocean Drilling Israel Ltd. for the Sedco Express drilling unit at the Shimshon location where it anticipates initial drilling during the second quarter 2012. ATP expects to spend between $24 and $29 million during 2012 related to the initial exploratory well on the Shimshon license for its 40% working interest.

ATP notes that Isramco Negev, its partner in Shimshon, on March 6, 2011 reported that it received an independent reservoir engineering evaluation from Lockwood & Associates estimating gross potential natural gas reserves at Shimshon. According to Isramco Negev, "Lockwood & Associates considers the calculated assessment of the total geological and geophysical exploration probability of success of 20 percent to be reasonable. Lockwood said its high estimate was for 3.4 TCF, the low estimate was 1.5 TCF and its best estimate was 2.3 TCF."

Additional information on the Daniel East and Daniel West licenses will be provided as drilling and exploration plans are approved. ATP East Med is also party to two other licenses in offshore Israel which are awaiting approval by the Israeli Ministry of National Infrastructure. ATP continues to evaluate acquiring other licenses in the Mediterranean Sea.

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Max Petroleum Confirms Oil Pay at Uytas Field

- Max Petroleum Confirms Oil Pay at Uytas Field

Monday, August 08, 2011
Max Petroleum plc

Max Petroleum announced that the UTS-2 confirmation well in the Uytas Field in Kazakhstan has reached a total depth of 820 meters, with electric logs indicating 12 meters of net oil pay in the Cretaceous section at depths ranging from 108 to 148 meters, consisting of three sandstone reservoirs of excellent quality with porosities ranging from 25% to 34%. The Company also identified an additional six meters of net oil pay in Jurassic reservoirs at depths of approximately 350 meters. Significant oil shows were recorded continuously from depths of 36 meters to 150 meters, which appear to confirm the oil column seen in the original UTS-1 discovery well. Consequently, the Company extensively cored the UTS-2 well over the interval from 39 meters to 160 meters to allow further study of reservoir properties within this vertical column, with results from the coring analysis expected by early fourth quarter 2011. The core analysis will also be used to evaluate the potential of additional lower-quality reservoirs present in the Cretaceous in this interval that have not been included here as net pay. Furthermore, Cretaceous reservoirs above 80 meters that were not evaluated on electric logs due to their shallow depth may be tested in this well or subsequent wells pending the final core analysis.

The Company is currently running production casing in the well, which will be completed and tested using a workover rig after obtaining the requisite governmental approvals. Test results will be announced as soon as practicable. The Company plans to drill two additional appraisal wells in the field during August 2011 and acquire a high-fold 3D seismic survey over the Uytas structure in October 2011, in order to facilitate preparation of a long-term appraisal and development program for the field.

Robert B. Holland, Executive Co-Chairman, commented, "We are pleased with the successful confirmation of our Uytas discovery, with results in line or better than the original discovery well. We are conducting core analysis and additional technical studies to better define the potential of this discovery, and identify production techniques to maximize future oil recovery from the field given Uytas' unique shallow setting."

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Statoil, Partners Hit Significant Oil Pay in North Sea

- Statoil, Partners Hit Significant Oil Pay in North Sea

Monday, August 08, 2011
Statoil

Statoil and partners Petoro, Det norske and Lundin have made a high-impact oil discovery on the Aldous Major South prospect (PL 265) in the North Sea.

Well 16/2-8, drilled by the Transocean Leader drilling rig, has identified an approximately 65-meter oil column in Jurassic sandstone. The acquired data confirm that this is a reservoir of excellent quality.

Statoil has previously described the well as a high-impact well, and the result confirms Statoil's belief in the exploration potential on the Norwegian continental shelf in line with what was communicated at the Capital Markets Day event in New York in June.

Preliminary volumes are estimated to be between 200 and 400 million barrels of oil equivalent (boe) for this part of the structure in PL 265, and Statoil expects additional upside in the license both north and south of the discovery.

Aldous Major South is located west of Lundin's Avaldsnes discovery (license PL 501), where Statoil has a 40% stake, and some 35 kilometers south of the Statoil-operated Grane field.

Well 16/2-8 indicates the same oil-water contact as in the Avaldsnes discovery well, which suggests the likelihood of communication between the two structures. The Avaldsnes discovery encountered a 17-meter oil column. Statoil will update its total resource estimate for the area when the wells are completed and the data analyzed.

"Aldous Major South is a considerable oil discovery in one of Statoil's core areas. Together with the Avaldsnes discovery this may allow for a new stand-alone development in the North Sea. As the largest resource owner our priority is to find the optimal solution for the area, adding maximum value to all partners," said Gro G. Haatvedt, Statoil's senior vice president for Exploration on the Norwegian continental shelf.

After completing this well Transocean Leader will start drilling the Aldous Major North well. This well also has a considerable volume potential.

The partnership is planning two appraisal wells in PL 265 next year and Statoil has secured rig capacity for this.

The result of the ongoing drilling of the Lundin-operated well (well 16/2-7) in the Avaldsnes structure will help further clarify the area’s potential.

Aldous Major South is located in license 265. Statoil is the operator and has a 40% interest. The other partners are Petoro (30%), Det norske oljeselskap (20%) and Lundin (10%).

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Total Makes Major Gas Find in Barents Sea

- Total Makes Major Gas Find in Barents Sea

Monday, August 08, 2011
Norwegian Petroleum Directorate

Total EP Norge AS, operator of production license 535, has completed the drilling of wildcat well 7225/3-1. The well, which proved gas, was drilled in the Barents Sea, about 250 kilometers north of Melkoya.

The primary exploration target for the well was to prove petroleum in Triassic reservoir rocks (Snadd and Kobbe formations). The secondary exploration target was to prove petroleum in the Middle Jurassic (Sto formation), Triassic (Havert formation) and Permian (Bjarmeland formation).

Gas was proven both in intervals from the Jurassic and the Triassic: in the Kobbe formation with a 400-meter interval in rocks of varying reservoir quality, and in the Havert formation in two intervals of 80 and 90 meters, respectively, in poorly developed reservoir rocks. Gas was also encountered in the Sto and Snadd formations.

Preliminary estimates place the size of the discovery between 10 and 50 billion standard cubic meters (Sm3) of recoverable gas.

A successful formation test has been carried out in the upper part of the Kobbe formation. The maximum production rate was 180 000 Sm3 gas per flow day through a 44/64-inch nozzle. The gas contains only small amounts of CO2, H2S and N2. The results from the well will be included in the ongoing evaluation of "Norvarg" to establish the size and extent of the gas discoveries.

The well was drilled in 376 meters of water and is the first exploration well in production license 535. The license was awarded in the 20th licensing round in 2009.

The well was drilled to a vertical depth of 4150 meters below the sea surface, and was terminated in the Orn formation in Permian rocks. The well will now be permanently plugged and abandoned.

Well 7225/3-1 was drilled by West Phoenix, which will now go on to drill for Statoil Petroleum AS on the Troll field in the North Sea.

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ONGC In Talks to Sell Indian Ocean Deepwater Stakes - FT

- ONGC In Talks to Sell Indian Ocean Deepwater Stakes - FT

Monday, August 08, 2011
Dow Jones Newswires

India's Oil & Natural Gas Corp. (ONGC) is talking to Shell, BG Group and Eni to sell stakes in its Indian Ocean deepwater developments, the Financial Times reported Sunday, citing ONGC's chairman AK Hazarika.

ONGC is already co-operating with Shell, BG and Eni in a number of other blocks, and talks had been under way for some time. ONGC seeks a partner on the technical front to expand the development of its 85 deepwater blocks in the Indian Ocean, Hazarika said in the report available on the FT website, without giving a deadline for the deal.

The company was willing to give away up to 30% of its assets in exchange for technical expertise, Hazarika said, according to the report.

Shell and BG declined comment, while Eni didn't respond, the FT said.


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

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Chariot Sells Stake in Namibia Block to BP

- Chariot Sells Stake in Namibia Block to BP

Monday, August 08, 2011
Chariot O&G Ltd.

Chariot announced that its wholly-owned subsidiary, Enigma Oil & Gas Exploration (Pty) Limited, has entered into a farm-out agreement with BP, whereby BP will acquire a 50% share of Chariot's equity interest in Southern Block 2714A (License 20). As announced on June 28, 2011, Petrobras has elected to take up operatorship and retains a 50% stake in the block.

Under the terms of the agreement, BP has committed to cover Chariot's cost of drilling the first exploration well, as well as past costs incurred.

Block 2714A is located in the Orange Basin offshore Namibia and covers an area of 5,481km². The Nimrod prospect is situated within this license and is the largest of Chariot's prospects. With this farm-out, Chariot will continue to pursue its drilling campaign within this license area whilst sharing in the costs, risks and rewards of exploration. Funds received and retained through this deal will be used in further exploration and appraisal work.

This agreement remains subject to the full approval of the Ministry of Mines and Energy in Namibia. It includes standard representations and warranties given by both parties and other conditions precedent.

Paul Welch, Chief Executive of Chariot, said, "We are delighted to enter into this farm-out agreement with BP whose global expertise of deep water exploration and related petroleum systems is exceptional and whose contribution to our campaign going forward will be invaluable. It is a pleasure to welcome another major oil company as a partner.

"It has been a key strategic objective for us to farm down our assets in order to facilitate exploration drilling, retain capital and mitigate risk; we are very pleased to have made progress towards this. We look forward to proving up the potential of our assets alongside our partners, as we seek to deliver long-term value to our shareholder."

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Max Petroleum Discovers Oil in East Kyzylzhar

- Max Petroleum Discovers Oil in East Kyzylzhar

Monday, August 08, 2011
Max Petroleum plc

Max Petroleum announced that the KZIE-1 exploration well in the East Kyzylzhar I prospect has reached a total depth of 1,620 meters, with electric logs indicating 17 meters of net oil pay in two Jurassic sandstone reservoirs at depths ranging between 987 and 1,251 meters. Reservoir quality appears excellent with porosities ranging from 20% to 30%. The Company is running production casing in the well, which is expected to be completed and placed on test production in approximately 60-90 days.

Robert B. Holland, Executive Co-Chairman, commented, "We have now made five field discoveries since we renewed our post-salt exploration program in January 2010, with another three post-salt prospects to test this quarter alone. We are well positioned to execute on our exploration program regardless of macro market conditions and look forward to continue generating significant value for our shareholders in the very near-term."

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Range Successfully Drills First Development Well in Trinidad

- Range Successfully Drills First Development Well in Trinidad

Monday, August 08, 2011
Range Resources Ltd.

Range announced that in the two months since completing its Trinidad acquisition, the Company has successfully drilled its first development well on the Morne Diablo Block.

As part of the initial 21 well drilling program, the MD 247 well was drilled to a total depth of approximately 900 ft using the Company's own drilling rig and personnel. Despite the shallow depth, open hole logs indicate the presence of roughly 145 ft. of net oil pay in the shallow Forest Formation, an established producing horizon on the block. Casing is currently being run in the well in preparation for production testing next week.

Added Peter Landau, Range's Executive Director, "The successful drilling of the MD 247 well indicates that Range's aggressive program to increase production and cash flow in Trinidad is on track and the first pay zone size has exceeded expectations. As previously announced, we will be adding a second and third rig to the remaining 20 well 2011 drilling program in order to begin exploitation of deeper producing reservoirs. The MD 247 well is only the beginning for us in Trinidad, but represents an important milestone for Range as our first internationally operated well, drilled and completed by the Company's own operations team using our own equipment."

The Company looks forward to keeping our shareholders updated as our drilling program continues in Trinidad, Georgia, Texas, and Puntland, in what will be an exciting period for Range with wells being drilled on all four the Company's assets in the coming months.

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Heritage Commences Drilling in Kurdistan

- Heritage Commences Drilling in Kurdistan

Monday, August 08, 2011
Heritage Oil plc

Heritage Oil has commenced drilling the Miran West-3 well in the Kurdistan Region of Iraq ("Kurdistan").

Highlights

• The Miran West-3 well has commenced drilling with the primary objective of appraising the Miran West structure
• The well is targeting both the Jurassic and Cretaceous reservoir formations encountered in the Miran West-1 and Miran West-2 discovery wells
• The deviated well path, determined from the recent 3D seismic survey, targets the flanks of the structure to optimally intercept networks of open fractures
• It is intended that multiple reservoir intervals will be tested and evaluated as the well is drilled to a target depth of c.4,400 meters
• The well is expected to take approximately seven months to drill and test
• The commencement of drilling of the Miran West-3 well represents the beginning of a multi-well appraisal and exploration program, using the first of two rigs scheduled for back to back drilling on the Miran Field

Miran West-3 Well

Drilling of the Miran West-3 appraisal well has commenced. The well is targeting reservoir sections encountered in discovery wells with the primary objective of appraising the Jurassic and Cretaceous reservoir formations in the Miran West structure. Management estimates gross in-place volumes for the Miran West structure to have a P90-P50 range of 6.8-9.1 TCF of gas, with an upside P10 gas potential of 12.3 TCF. This is in addition to the estimated P50-P90 range of 42-71 MMbbls of condensate and 53-75 MMbbls of oil.

The Miran West-3 location and well trajectory provides a c.4.3 kilometer appraisal step out from the Miran West-2 Jurassic reservoir penetration. The planned well path targets the flanks of the structure. The well bore will be orientated and inclined to optimally intercept open fracture networks associated with multiple faults identified on recently acquired 3D seismic data. This well will also appraise the Cretaceous oil and gas reservoirs discovered in the Miran West-1 and Miran West-2 wells, further enhancing knowledge of the Miran structures.

Drilling of the Miran West-3 well is expected to take approximately seven months with key reservoir intervals being tested as the well is drilled.

After drilling and testing, it is intended that this rig will move to drill the Miran West-4 appraisal well. A second rig is being sourced to drill the planned Miran East-1 exploration well, with drilling expected to commence before year end, at which time there will be two rigs operating in the Miran Field.

3D Seismic Program

The Miran 3D seismic program is now approximately 90% complete. The significant improvement in seismic data quality over the Miran Field is encouraging and assists greatly with the selection of well locations. Initial interpretation of the first tranche of data acquired has highlighted increased resource potential, in particular for the Miran East structure. This potential will be targeted by the Miran East-1 exploration well to be drilled before year end.

Tony Buckingham, Chief Executive Officer, commented, "The spudding of Miran West-3 begins our active multi-well exploration and appraisal drilling program in Kurdistan. This first well is principally appraising the Cretaceous and Jurassic discoveries made in the Miran West-1 and Miran West-2 wells. We plan to provide regular announcements during the drilling of this well as the key reservoir intervals will be tested as the well is drilled."

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