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Oil and Gas Energy News Update

Wednesday, August 3, 2011

Oil & Gas Post - All News Report for Wednesday, August 03, 2011

Wednesday, August 03, 2011

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Commodity Corner: WTI Nears $91; Brent Approaches $113

- Commodity Corner: WTI Nears $91; Brent Approaches $113

Wednesday, August 03, 2011
Rigzone Staff
by Matthew V. Veazey

The September WTI contract price tumbled two percent Wednesday after the U.S. Energy Information Administration reported that commercial crude oil inventories increased last week.

Light sweet crude oil fell to $91.22 a barrel before ending the day at $91.93. The intraday high was $93.75. The EIA on Wednesday reported that oil stocks increased by one million barrels last week to 355.0 million barrels. The July 29, 2011, figure was three million barrels lower than the corresponding figure last year. Analysts surveyed by Platts had anticipated a larger build in EIA's latest report, predicting a two million-barrel week-on-week increase in inventories.

Brent futures fell more dramatically Wednesday, losing $3.23 to settle at $113.23 a barrel. The contract peaked at $115.98 and bottomed out at $113.09 during the midweek session.

Thanks to a moderating temperature outlook from the Midwest to the Northeast for the next two weeks, cooling demand in these power-hungry regions is expected to remain at normal levels. Not surprisingly, natural gas for September delivery lost 6.5 cents Wednesday. Natural gas settled at $4.09 per thousand cubic feet after trading within a range from $4.07 to $4.18.

Front-month gasoline plunged 3.6 percent Wednesday to settle at $2.93 a gallon. The September contract fluctuated from $2.92 to $3.02.

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Walter Energy Earnings Miss Q2 Estimates

- Walter Energy Earnings Miss

Aug 3, 2011

Walter Energy (NYSE:WLT) reported adjusted Q2 EPS of $2.36, missing analyst estimates of $4.07. Revenues for the quarter rose 88.3% to $773.00 million, missing consensus estimates of $927.16 million.

Joe Leonard, interim chief executive officer said, "Walter Energy continues to execute on its long-term strategic plan to grow its met coal production base, highlighted by the acquisition of Western in April and our execution of lease agreements on 68 million metric tons of Blue Creek coal reserves in May."

Walter Energy is currently below its 50-day moving average (MA) of $117.23 and below its 200-day MA of $118.62. In the last five trading sessions, the 50-day MA has remained constant while the 200-day MA has risen 0.4%.

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Energy Transfer Equity Misses Estimates For Q2

- Energy Transfer Equity Misses Estimates For Q2

Aug 3, 2011

Energy Transfer Equity (NYSE:ETE) reported adjusted Q2 EPS of $0.30, missing analyst estimates of $0.37 per share. Revenues for the quarter rose 45% year-over-year to 1.62 billion, below consensus estimates of $1.81 billion

Mike Bradley, president and chief executive officer of Regency said, "Regency delivered strong results in the second quarter of 2011, fueled by our acquisition activity over the last year and volume growth in south and west Texas in our Gathering and Processing segment."

Energy Transfer Equity (NYSE:ETE) has a potential upside of 21.4% based on a current price of $40.7 and an average consensus analyst price target of $49.4.

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Delmar Awarded Mooring Contract by Noble

- Delmar Awarded Mooring Contract by Noble

Wednesday, August 03, 2011
Delmar Systems Inc.

Delmar Systems was awarded a contract by Noble Energy EG, Ltd. to supply an eight-leg preset mooring system for use in Noble Energy's Aseng Development off the coast of Equatorial Guinea, West Africa. Delmar provided Noble Energy a full compliment of
mooring equipment including Delmar's patented OMNI-Max™ anchors and Delmar Subsea Connectors (DSCs). All equipment has been successfully delivered to Noble Energy EG's yard in Equatorial Guinea.

The patented Delmar OMNI-Max anchor is a gravity-installed vertically loaded anchor (VLA) that offers unique performance characteristics not found in other deepwater anchor foundations. The OMNI-Max anchor is capable of being loaded in any direction 360° around the axis of the anchor. This anchor technology offers a great benefit in the design of mooring systems that reduces risk to subsea infrastructure in the event of station-keeping damage or failure. This proven anchor concept has been deployed and retrieved on over 150 anchor locations.

The Delmar developed and patented DSC is used with MODUs (mobile offshore drilling units) and permanent mooring installations to allow single vessel deployment of anchors and mooring lines. The DSC provides for easy connect/disconnect capability with the use of a standard ROV.

"We are pleased that Noble Energy EG has chosen our mooring technology for their project. Our patented technologies have proven themselves as the safest, most efficient mooring solutions used in the offshore mooring industry," said Delmar's Executive Vice President, Brady Como.

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Oasis Appoints New CFO

- Oasis Appoints New CFO

Wednesday, August 03, 2011
Oasis Petroleum Inc.

Oasis Petroleum announced the appointment of Michael Lou as Executive Vice President and Chief Financial Officer. Previously, Mr. Lou served as Senior Vice President Finance for Oasis. In his new role, Mr. Lou will expand his focus on financial strategy and execution and continue as a member of the Oasis senior leadership team.

Announcing Lou's promotion, CEO Thomas B. Nusz, said, "Michael has made significant contributions to the Company since he joined in 2009. He was instrumental in our highly successful Initial Public Offering and provides invaluable strategic insight as a member of our leadership team."

Mr. Lou has fourteen years of experience in the oil and gas industry. Prior to joining Oasis, he served as Chief Financial Officer of a private oil and gas company and a Director and Vice President in several top-tier investment banking firms. Mr. Lou holds a Bachelor of Science in Electrical Engineering from Southern Methodist University.

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Simba Granted PSC for Kenya Block

- Simba Granted PSC for Kenya Block

Wednesday, August 03, 2011
Simba Energy Inc.

Simba has been granted a Production Sharing Contract (PSC) by the Ministry of Energy, Republic of Kenya for Block 2A, comprising 7,801.72 square kilometers in northeast Kenya.

"We are delighted in having been awarded this PSC from the Republic of Kenya's Energy Ministry. This is a major achievement for the Company and further supports our strategy to pursue underexplored and overlooked onshore basins in Africa. While we remain very close to finalizing other PSC applications elsewhere, Block 2A's PSC provides our shareholders a very significant boost in near term upside exploration potential for the Company. It has been a lot of work to get to this point so we are extremely pleased," remarks Robert Dinning, President & CEO.

Block 2A overlies the southern tip of the Mandera Basin while the southwest corner of the block extends into the Anza Basin. Block 2A also has excellent potential for significant oil and gas discoveries as evidenced by the following evaluation highlights:
  • The Mandera Basin is Permo-Triassic to Tertiary in age with a sediment thickness of 10,000 meters. Potential source rock interval is mid Jurassic-Lower Cretaceous and comparable with the larger Mandera-Lugh basin in Ethiopia and Somalia
  • Only four wells have been drilled in the Mandera basin with oil shows encountered at 40-44m in the Tarbaj stratigraphic well drilled by Total
  • In the Anza basin lower Cretaceous reef structures have been mapped with a potential reservoir thickness of 300m-500m. Source rock is likely Lower Cretaceous. The eleven wells drilled in the Anza Basin have encountered oil shows and/or gas shows
  • Present 2D seismic coverage, although regional in nature, identified numerous structures and a major stratigraphic pinch-out. The limited seismic coverage available indicates a stable stratigraphic sequence with some very good exploration leads
  • Remaining of exploration interest to the Company is the flank of the basement high structure where two AMOCO wells drilled in 1987 (ELGAL#1 to 1,280 meters in Permian Karroo and ELGAL#2 to 1,908 meters in Triassic Karroo) were plugged and abandoned as no reservoir rocks were encountered
  • The area of the block overlying the Mandera basin is of particular interest as the analysis of the oil from the seeps at Tarbaj although severely biodegraded indicate a source rock maturity for the Mandera basin which is well within the oil window

The Company will immediately begin re-interpretation of all available existing data, as well as initiate baseline environmental work, to support the design and planning of a new seismic acquisition program.

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Bering IDs New Prospect in Permian Basin

- Bering IDs New Prospect in Permian Basin

Wednesday, August 03, 2011
Bering Exploration Inc.

Bering has identified a new prospect through its exclusive partnership with Glaux Oil & Gas, LLC (Glaux) that covers 500,000 acres in the Permian Basin. This new prospect of approximately 640 acres has potential gross reserves of 950,000 barrels of oil and, based upon today's prices, equates to $88 million dollars of gross revenues or $3.50 per share. There is no guarantee that this prospect will be successful or that these numbers will be achieved due to production and/or price fluctuations. Bering is currently conducting its technical assessment and once satisfactorily completed will begin leasing the mineral rights. Bering expects to initially retain a100% working interest.

This prospect was the first identified as a result of its recently announced three year exclusive exploration agreement with Glaux for the development of numerous leads and prospects in approximately 500,000 gross acres in West Texas using a proprietary aeromagnetic survey. Once leased, Bering will use other advanced oil finding technologies such as telluric and seismic to identify well locations.

The Permian Basin is one of the largest and most active oil basins in the United States, with the entire basin accounting for approximately 19 percent of total U.S. oil production. The Permian Basin remains a significant oil-producing province and contains an estimated 30 Billion barrels of remaining mobile oil and has the biggest potential for additional oil production in the country, containing 29% of estimated future oil reserve growth. Through increased use of enhanced-recovery practices the Permian Basin can have a substantial impact on U.S. oil production.

"We are excited to have our initial prospect generated by Glaux and expect to begin the leasing phase later this month," stated Steven Plumb, VP of Finance of Bering. "Our exclusive relationship with Glaux has provided us with this quality prospect that has been identified using unique and exciting technologies."

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Double Eagle Petroleum Briefs 2011 Exploration, Development Plans

- Double Eagle Petroleum Briefs 2011 Exploration, Development Plans

Wednesday, August 03, 2011
Double Eagle Petroleum Co.

Double Eagle Petroleum announced an update to its 2011 drilling program and is providing guidance on its 2012 expected drilling programs. The Company's development program will be focusing on its two major development fields, the Atlantic Rim CBM and the Pinedale Anticline. The major exploration projects are the Niobrara oil shale target in the Atlantic Rim and the Main Fork Unit in north east Utah. Total estimated capital spending for 2011 projects will be approximately $30 million.

2011 Field Development

In 2011, the Company will be increasing its total net well count in the Catalina CBM Unit 25% by drilling approximately 14 gross (13 net) coal bed methane (CBM) wells in this unit to add to the existing 70 gross (51 net) CBM producing wells. Twelve of these wells are in an exploratory area and the Company will have a 100% working interest in these wells. The Company will have a 73% working interest in the two development wells in the existing unit participating area.

Anadarko will be drilling 25 exploration wells in the newly formed Spy Glass Unit which includes the Sun Dog and Doty Mountain participation areas. The exploration wells for 2011 were required by the Spy Glass Unit agreement. The Company will have no interest or costs associated with these wells, but the data obtained will be valuable in determining the nature and extent of the CBM field, which will aid future field development.

The approved Atlantic Rim Environmental Impact Study allows for a total 1,800 CBM wells and 200 conventional (non-coal bed methane) wells. Double Eagle, together with Anadarko Petroleum, are the operators of various units in the Atlantic Rim and as of June 30, 2011 a total of 400 CBM wells have been drilled (no conventional wells). Currently, the Company has 123 approved CBM drilling permits and Anadarko has approximately 30 approved CBM drilling permits for future drilling in the Atlantic Rim.

Also, Double Eagle will participate in the drilling of 16 (gross) new production wells in the Mesa Unit on the Pinedale Anticline, which is an increase of 10 (gross) wells from the initial estimate provided by the operator of the Mesa Units, QEP. The Company has an estimated 8.5% working interest in these planned wells.

2011 Exploration Projects

The Company also plans to drill one Niobrara Oil Shale well in which Double Eagle will have an estimated working interest of 93%. The Company initially planned two Niobrara exploratory wells but due to certain lease holders in the area not cooperating in drilling plans, the Company determined that the best location and opportunity to gain formation knowledge was to drill in a section which the Company controlled. The Company is awaiting final permit approval for this well.

The Company also is evaluating further development of the Main Fork Unit Project (formerly known as Christmas Meadows/Table Top Unit). The Company previously drilled the Table Top Unit #1 well in 2007. The Company is working with a major integrated oil and gas company that has option farm-in rights to advance further unit delineation, assist with costs related to seismic, environmental analysis and, if necessary, an exploratory well. Assuming the farm-in right is exercised; Double Eagle will have a 12%-16% working interest after payout.

Prior seismic data has been reprocessed and a LIDAR (Light Detection and Ranging) survey has been conducted. Preliminary development well locations, pipelines and roads have been identified as part of a full field development environmental impact study being conducted by the USFS. In 2011, surveying and associated archeological and biological studies are being conducted along with a source test in preparation for a potential 2D seismic acquisition program in 2012.

2012 Development Projects

Looking ahead into 2012, the Company's initial plans are to continue development in our two main fields. In the Atlantic Rim, the Company plans to drill 14 new CBM production wells in the Catalina unit, 25 new CBM wells in the Anadarko operated Doty Mountain Unit and, depending upon the results of the initial test well, several Niobrara wells. In the Pinedale Anticline, the Company anticipates 16 new wells to be drilled in 2012. The Main Fork Project is expected to proceed as mentioned above.

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GlassPoint Snags PDO Contract

- GlassPoint Snags PDO Contract

Wednesday, August 03, 2011

Building on the launch of its solar enhanced oil recovery (EOR) project with Berry Petroleum earlier this year, GlassPoint Solar announced the award of a contract to build a 7 MW solar EOR system for Petroleum Development Oman (PDO), the national oil company of Oman. PDO, the largest producer of oil and gas in the Sultanate, will use the GlassPoint system at an existing thermal EOR project in southern Oman. The goal of solar EOR is to reduce the amount of natural gas burned for thermal EOR, releasing gas for higher value applications, including power generation, desalination, industrial development and export.

"After extensively researching solar EOR solutions, we've identified GlassPoint as the most promising technology for this pilot," said Dr. Syham Bentouati, PDO Corporate Technology Advisor. "GlassPoint's solar steam generators have the potential to release valuable natural gas for use in higher-value applications within the Sultanate."

The solar EOR facility will use concentrated thermal energy from the sun to produce low-cost, emission-free steam that will be fed directly into PDO's existing steam distribution network. Spanning more than four acres, the GlassPoint system will produce 11 tons of high temperature (312 ˚C), high pressure (1,450 psi) steam per hour. The completed project will be 27 times larger than the GlassPoint solar EOR system installed at Berry Petroleum's 21Z oil field in Kern County, California, USA.

Built specifically to withstand the harsh environmental conditions of the Gulf region, GlassPoint's unique single transit trough (STT) technology encloses lightweight reflective mirrors inside a glasshouse structure to protect the system from dirt, dust, sand, and humidity. In sunny regions, GlassPoint's solution can reduce the amount of natural gas used for EOR by up to 80 percent.

"It is an honor to be selected as the solar EOR solution for PDO, the preeminent leader in enhanced oil recovery techniques in the region," said Rod MacGregor, GlassPoint CEO and President.

"As part of our commitment to maintain a long-term presence in the Sultanate we have established a local company that will hire Omani professionals and help spread knowledge of state-of-the-art solar technology throughout the Sultanate," continued MacGregor.

Steamflooding is a well-proven and effective EOR technique, but it requires massive amounts of natural gas to generate steam. Gas scarcity throughout the Middle East puts the region's EOR operations in direct competition with industrial development. Oman, specifically, has experienced a surge of economic growth and industrial development in the past two decades, drawing the country's gas reserves to higher value applications. Using solar instead of gas for EOR would enable other gas dependent industries to continue to flourish.

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Endeavour Makes Headway in US, UK in 2Q11

- Endeavour Makes Headway in US, UK in 2Q11

Wednesday, August 03, 2011
Endeavour International Corp.

Endeavour reported adjusted EBITDA for the second quarter of 2011 was $7.6 million compared to $13.1 million in the second quarter of 2010 and $4.1 million in the first quarter of 2011. On a GAAP basis, net loss was $15.6 million for the second quarter of 2011 as compared to net income of $0.6 million for the same quarter in 2010.

Business Highlights:
  • North Sea:
    • Commenced drilling operations at Bacchus
    • Agreement of commercial terms for the processing and transportation of the Greater Rochelle production on the Scott Platform
    • Contracts awarded for the pipeline and umbilical's for the development of Greater Rochelle area
  • U.S. Onshore:
    • Announced the acquisition of 50,000 net acres in Marcellus Shale with existing production and pipeline infrastructure
    • 8 gross wells brought on production through July in Louisiana and East Texas
    • 4 additional gross wells completing or drilling in Louisiana
  • Financial:
    • Increased available capital in July resulting in cash on hand of approximately $245 million

"During the second quarter financial results were as expected, while we made substantive progress on our U.K. development projects and our U.S. Haynesville unconventional gas play. Adding to this progress, our announced strategic acquisition of acreage and infrastructure gives us exposure to 1.0 to 1.3 trillion cubic feet of gross recoverable natural gas resource potential in the Marcellus area. We are confident that the balanced portfolio can deliver significant growth in both oil and natural gas production in the near-term," said William L. Transier, chairman, chief executive officer and president. "During July, the Company enhanced its flexibility and growth potential by adding approximately $100 million in available liquidity in addition to funding the $110 million needed for the Marcellus acquisition. The additional capital provides the resources to take advantage of opportunities for growth from existing and emerging parts of our portfolios, while also providing liquidity in case of any unforeseen events."

Operational Update

North Sea

The drilling of the three planned development wells is underway in the Bacchus field in Block 22/06a in the Central North Sea. Production from the development is expected to begin in the fourth quarter. The Company has a 30% working interest in the field.

In the Greater Rochelle area, the Company awarded two contracts for the design and fabrication of components for the subsea development that will link production for processing and transport to the nearby Scott platform. The contract for the drilling rig for the development will be finalized during the third quarter. Endeavour is operator and holds a 44% ownership interest in the Greater Rochelle development which is now comprised of Blocks 15/26b, 15/26c and 15/27.

U.S. Onshore

Endeavour will assume operated interests in leasehold, producing wells, pipeline and related facilities held by SM Energy Company and its minority partners in McKean and Potter Counties. The transaction increases Endeavour's leasehold interest in the Marcellus shale to approximately 93,000 gross (68,000 net) acres with more than 300 identified drilling locations in McKean and Cameron counties alone. The purchase will strengthen the Company's position in one of the most active and low-cost U.S. shale plays and provides significant production and reserve potential. The transaction is expected to close in the fourth quarter. In the Company's existing Marcellus acreage in Cameron County, two horizontal wells are waiting on completion, while the existing Daniel Field gathering infrastructure is being expanded.

During the quarter, Endeavour brought six gross wells on production in its Haynesville and Cotton Valley plays in Louisiana and East Texas, respectively. In July, production commenced from two additional gross wells with four other wells currently completing or drilling.

In the Montana Heath shale oil play, the Company and its partners expect to launch drilling operations on four vertical wells in the third quarter. In the Alabama Devonian shale gas play, Endeavour has successfully drilled and cased a horizontal re-entry of a previously drilled vertical pilot well. This well is anticipated to be completed and tested by the fourth quarter.

Financing Update

During the second quarter, the Company completed the redemption of all of its outstanding $81.25 million of 6% Senior Notes due 2012. The Notes were exchanged at 100% of principal amount plus accrued and unpaid interest.

In July, Endeavour closed on its private placement of $135 million aggregate principal amount of 5.5% convertible senior notes due 2016, including the full exercise by the initial purchasers of their option to purchase an additional $15 million principal amount of the offering. The Company intends to use the net proceeds of the offering primarily to fund its announced acquisition of operated interest in the Pennsylvania Marcellus shale play. Endeavour also expanded its credit facility by $75 million under the terms of its Senior Term Loan.

In addition, the Company entered into a letter of credit facility agreement with Commonwealth Bank of Australia in the amount of pounds Sterling 20,600,000 (approximately $33 million). Associated with the letters of credit was the release of the restrictions on approximately $33 million of cash.

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US Senator Pressures Regulators to Extend Drilling Leases

- US Senator Pressures Regulators to Extend Drilling Leases

Wednesday, August 03, 2011
Dow Jones Newswires
by Tennille Tracy

Sen. David Vitter (R., La.) is trying to pressure the Obama administration into extending hundreds of oil-drilling leases in the Gulf of Mexico.

In an announcement Wednesday, Vitter said he would block the nomination of a top official to the U.S. Interior Department until the department extends drilling leases set to expire this year.

Vitter contends the Interior Department adopted policies in the wake of the Deepwater Horizon oil spill that hampered drilling activity. As a result, he says companies should be allowed to operate for more time on their existing leases.

Vitter says there are more than 300 offshore leases in the Gulf of Mexico that are set to expire this year.

"If these leases are allowed to expire, they will revert to the federal government, killing jobs and cutting off potential revenue from exploration and production," Vitter said in a statement.

A spokesman for the Interior Department called the senator's move "perplexing" because the department has already taken steps to grant lease extensions. In June, for example, the Interior Department outlined a basic set of the criteria under which it would grant extensions.

"Sen. Vitter's request is perplexing, and we expect that he will lift his hold since we took action on this a month-and-a-half ago," spokesman Adam Fletcher said.

Vitter has been one of the most vocal critics of the administration's decision to impose a temporary ban on deepwater drilling in the wake of the oil spill. He has also complained about the pace of new permitting in the months since the ban was lifted in October.

Earlier this year, Vitter blocked the nomination of Daniel Ashe as director of the Fish and Wildlife Service until the Interior Department issued 15 deepwater exploration well permits. Vitter has since lifted his hold and Ashe has been confirmed to the post.

This time around, the senator is putting a hold on the nomination of Rebecca Wodder to become the assistant secretary for fish, wildlife and parks at the Interior Department.

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

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Petrohawk Bumps 2Q Production by 15%

- Petrohawk Bumps 2Q Production by 15%

Wednesday, August 03, 2011
Petrohawk Energy Corp.

Petrohawk announced its second quarter 2011 operational and financial results, including significant growth in production, revenues, and cash flows.

Production for second quarter averaged 943 Mmcfe/d, a 15% quarter-over-quarter increase. Second quarter total production was 85,803 Mmcfe, of which approximately 89% was natural gas, 7% was crude oil or condensate, and 4% was natural gas liquids. Revenues for the quarter were $595 million, a 21% increase over first quarter 2011 and a 69% increase compared to the same period one year ago. The Company realized 92% of the average NYMEX oil price, 97% of the average NYMEX natural gas price, and 47% of the NYMEX oil price for natural gas liquids during second quarter.

Cash flow from operations before changes in working capital was $302 million for the quarter, or $0.99 per fully diluted common share, compared to $246 million, or $0.81 per fully diluted common share for the first quarter 2011, and $163 million, or $0.54 per fully diluted common share for the same period one year ago. Net income for the quarter, after adjusting for selected items (primarily related to the non-cash impact of derivatives), was $57 million, or $0.19 per fully diluted common share (see Selected Item Review and Reconciliation table for additional information). Before excluding selected items, the Company reported net income of $104 million, or $0.34 per fully diluted common share for the quarter.

Cash operating costs (including lease operating expense, workover expense, taxes other than income, gathering and transportation expense, and general and administrative expense) were $1.69 per Mcfe for the quarter, compared to $1.56 per Mcfe for first quarter 2011 and $1.64 per Mcfe for the same period one year ago. General and administrative expense of $0.50 per Mcfe, compared to $0.45 per Mcfe in first quarter and $0.65 per Mcfe for the same period one year ago, reflected advisory fees associated with the Kinder Morgan Energy Partners L.P. transaction (discussed below) as well as a legal settlement paid during the quarter. Lease operating expense was $0.16 per Mcfe for the quarter, compared to $0.17 per Mcfe for the prior period and $0.29 per Mcfe during the second quarter of 2010. Taxes other than income increased from $0.16 per Mcfe for the first quarter 2011 to $0.20 per Mcfe for the second quarter. Gathering and transportation expense for oil and gas increased from $0.69 per Mcfe for the prior period to $0.75 per Mcfe, and depletion expense, a non-cash item, was $2.20 per Mcfe for the quarter compared to $2.06 per Mcfe for the first quarter of 2011.

During the second quarter, Petrohawk spent approximately $621 million on drilling and completions, $239 million on leasehold acquisitions, primarily in the Permian region, and $77 million on gathering and treating infrastructure, primarily in the Eagle Ford Shale. At June 30, the Company's revolving credit facility had an outstanding balance of approximately $559 million.

On July 1, Petrohawk completed the sale of its remaining interest in KinderHawk Field Services LLC and a 25% interest in EagleHawk Field Services LLC to affiliates of Kinder Morgan Energy Partners, L.P. This transaction netted pre-tax proceeds of approximately $836 million, which were used to pay down the Company's revolving credit facility and as working capital for general corporate purposes.

Haynesville Shale

During the quarter, the Company averaged 11 operated rigs and drilled 21 operated wells, with net production in the field averaging 684 Mmcfe/d. Sixty-seven non-operated Haynesville Shale wells and 3 Bossier Shale wells were drilled during the quarter. Non-operated activity exceeded expectations during the quarter, in terms of both activity level and capital expenditures, primarily due to the transition to full section development by some operators during the quarter. Petrohawk expects that lower rig counts publicly announced by many industry partners point to lower activity levels in the Haynesville Shale during the second half of the year. Petrohawk is currently operating six rigs and has two dedicated frac fleets in the Haynesville Shale.

The Company achieved an overall cost reduction trend in Haynesville Shale completions during the quarter. Savings of approximately $600,000 to $800,000 per well were accomplished largely as a result of changes in well design that require two fewer frac stages per well, lower overall sand requirements per well, and improved pricing for resin coated sand. During the quarter Petrohawk averaged slightly less than 45 days spud to spud, more than 5 fewer days than during the preceding quarter. Significant additional improvements are expected as the Company moves toward pad drilling and full section development toward the end of 2012.

Improvements in water handling and usage have contributed to more flexibility in water sourcing in the Haynesville Shale. Approximately half of all Petrohawk-operated wells in field have been completed with 20% recycled water. Year to date, the Company has pumped approximately over 2 million gallons of recycled waste water on well completions in the Haynesville Shale.

Eagle Ford Shale

The Black Hawk area (DeWitt County, Texas) continues to produce excellent results. A majority of Petrohawk-operated wells were produced on a constrained basis due to transportation infrastructure limitations. During the quarter, Petrohawk averaged nine operated rigs in the Black Hawk area, with 25 operated and one non-operated wells drilled. Net production from Black Hawk averaged 73 Mmcfe/d, comprised of 22% natural gas, 62% condensate and 16% natural gas liquids. Transportation infrastructure issues for the Company are moderating in the area with the addition of a dedicated truck fleet. Modifications to facilities at the Company's Point Comfort barge facility are nearly complete and the facility is expected to begin operating during the third quarter.

In Hawkville Field (LaSalle and McMullen Counties, Texas), Petrohawk averaged five operated rigs and drilled 15 operated wells and two non-operated wells during the quarter. Net production in the field averaged 129 Mmcfe/d, comprised of 67% natural gas, 14% condensate and 20% natural gas liquids. Well performance in Hawkville Field has continued to improve as a result of the expanded implementation of HiWAY frac technology, deployed by two dedicated Schlumberger hydraulic fracturing fleets. Petrohawk and Schlumberger are experimenting with variations in the HiWAY design, including higher sand volumes and fiber concentrations, in an attempt to optimize well performance for each area of the Eagle Ford trend. In addition, the Company is testing new frac designs in both the Hawkville Field and Black Hawk area with its Halliburton dedicated hydraulic fracturing fleet.

Results in the Red Hawk prospect in Zavala County, Texas, failed to meet minimum expectations during the quarter. As a result, capital spending at Red Hawk will be terminated and capital budgeted for 2011 will be reallocated to other operating areas.

Permian Region

Petrohawk is currently operating four rigs in the Permian region, all concentrated in the Delaware Basin where the majority of the Company's leasehold is located. An initial vertical well in Culberson County, Texas tested approximately 1.0 Mmcf/d of 1250 BTU gas from the Wolfcamp formation. Total depth was reached on the Company's first horizontal Bone Springs well in Reeves County, Texas. A completion date for this well has been set for early August. A commingled Wolfcamp and Bone Springs vertical completion in Reeves County is planned with a completion date expected in mid-August. The Company is also currently drilling the lateral portion of its first horizontal Wolfcamp well in Culberson County with a planned completion date of mid-August. In addition, the Company is undertaking necessary infrastructure construction in order to market all products with minimum delays as wells come online.

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Lundin Reports Strong 2Q Results, Boosts Output Forecast

- Lundin Reports Strong 2Q Results, Boosts Output Forecast

Wednesday, August 03, 2011
Lundin Petroleum AB

Lundin reported for the six month period ended June 30, 2011

Six months ended June 30, 2011
  • Production of 32,300 boepd up 13% from the first six months 2010
  • Profit after tax of MUSD 130.3 up 526% from the first six months 2010
  • EBITDA of MUSD 505.3 up 96% from the first six months 2010
  • Operating cash flow of MUSD 390.3 up 52% from the first six months 2010
  • Net debt down to below MUSD 120 from MUSD 410 at year end
  • Five exploration discoveries, four in Norway and one in Malaysia
  • Ten Norwegian licenses awarded in the 2010 Norwegian licensing round, six as operator
  • Operated license awarded in Barents Sea in the 21st Norwegian licensing round
  • Operated Gurita block awarded in the Natuna Sea, offshore Indonesia

Second Quarter ended June 30, 2011
  • Production of 31,100 boepd
  • Profit after tax of MUSD 76.9
  • EBITDA of MUSD 266.9
  • Operating cash flow of MUSD 196.7
  • Three exploration discoveries – Skalle and Earb South discoveries in Norway and Tarap discovery in Malaysia
  • Appraisal well confirmed extension of the Avaldsnes discovery
  • New operated block PM307 awarded in Malaysia
  • Brynhild field plan of development (formerly called Nemo) submitted

Comments from C. Ashley Heppenstall, President and CEO

Lundin Petroleum achieved excellent results in the second quarter of 2011 with increased profitability and cash flow. What is extremely pleasing however, is the continued exploration success. I have always highlighted that the major valuation creation for our company will be achieved through increasing our oil and gas resources, and the best way to do that is through exploration.

Lundin Petroleum produced a net result for the first six months of MUSD 130.3. The strong production coupled with oil prices achieved of well over USD 100 per barrel resulted in operating cash flow of MUSD 390.3 and EBITDA of MUSD 505.3. Despite our significant exploration and development investment program net debt during the first half of the year has reduced from MUSD 410 to below MUSD 120.

The positive exploration news has continued during the second quarter with further discoveries at Skalle in PL438 in the Barents Sea, Earb South in PL505 in the northern Norwegian north Sea and Tarap in Block SB303 offshore East Malaysia. In addition the results of the first Avaldsnes appraisal well were extremely encouraging confirming the extension of the Avaldsnes field to the south east. We have now achieved five discoveries from our first five exploration wells this year following the Tellus and Caterpillar discoveries during the first quarter.

Our business is continuing to grow and I am confident we will continue to increase shareholder value. We are generating strong cash flow and profitability from our existing production which is outperforming, our development projects are proceeding well and our exploration success continues.

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Gazprom Neft 2Q Earnings Soar to $1.17B

- Gazprom Neft 2Q Earnings Soar to $1.17B

Wednesday, August 03, 2011
OAO Gazprom Neft

Gazprom Neft published on its website its consolidated financial results in accordance with US GAAP for 1H 2011.

Increased sales volumes and higher crude and petroleum prices drove the Company's revenue up by 39% to $21.341B in 1H 2011 compared to 1H 2010 (2Q 2011 revenue of $11.476B is 43% higher than in 2Q 2010).

Earnings before interest, income tax, depreciation and amortization (EBITDA) in 1H 2011 comprised $4.945B or 58% higher than in H1 2010 due to an increase in refining throughput, product mix optimization and improved market conditions. In 2Q 2011 EBITDA increased by 60% to $2.478B compared to 2Q 2010.

Net income in 1H 2011 increased by 74% to $2.604B versus 1H 2010 driven primarily by growth in EBITDA. 2Q 2011 resulted in $1.167B in net income (56% higher than in 2Q 2010).

The increase in net income resulted in a 6% growth in net cash provided by operating activities 1H 2011 compared to the same period of 2010 or $2.512B. Net cash provided by operating activities reached $1.891B in 2Q 2011 or 28% higher than in 2Q 2010.

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Record Pace Seen for Floating Production Systems

- Record Pace Seen for Floating Production Systems

Wednesday, August 03, 2011
Rigzone Staff
by Karen Boman

Growth in world oil demand, strong oil prices and concerns over supply disruption are among the factors driving growth in the floating production market, according to a recent report by the International Maritime Associates (IMA).

Fourteen floating production units have been ordered over the past four months - including the world's first floating liquefied natural gas (FLNG) vessel – a record pace reflecting strong underlying market drivers, according to IMA. The 1.5 percent to two percent growth in global oil demand per year means that new sources of oil supply need to be developed. To develop these resources, oil and gas companies are increasing their deepwater exploration and production spending.

Jim McCaul, head of IMA, said, "Few if any business sectors can match the dynamism, growth predictability and investment attractiveness of the floating production market."

At $3 billion, the Prelude FLNG is the most expensive floating production unit ordered to date. Other orders include nine floating production storage offloading vessels (FPSOs) - including one purpose-built unit, six units converted from trading tanker hulls and two modification/redeployments - two production spars and two purpose-built floating storage regasification units (FSRUs). Total value of the 14 construction contracts exceeds $11 billion.

Current order backlog consists of 53 production floaters, a net increase of six units since March. This extends the buildup in backlog that began in the second half of 2009. Twenty-eight units utilize purpose-built hulls, 25 are based on converted tanker hulls. Twenty units are being built for leasing operators, 33 directly for field operators.

In the report, IMA identifies 196 projects in the bidding, design or planning stage that potentially require a floating production or storage system. These projects are declared discoveries or planned develop where a floating production or storage system is being considered as the development option.

Of the 196 planned projects, 53 are in the bidding or final design stage. Major hardware contracts for these projects are likely to be awarded within the next 12 to 18 months. Another 143 floating projects are in the planning or study phase. Major hardware contracts for these projects are likely in the 2013 to 2018 timeframe.

Brazil is the most active region for future projects, with 50 potential floater projects in the planning cycle. Southeast Asia is second with 37 projects, followed by West Africa with 36 projects, Northern Europe with 22 projects, Gulf of Mexico with 17 projects and Australia with 11 projects.

Currently, 256 floating production systems are in service or available worldwide; FPSOs comprise 62 percent of this inventory. The balance of the fleet is comprised of production semis with 17 percent; nine percent is tension leg platforms; seven percent is production spars; and five percent is production barges and FSRUs. Of the total production floater inventory, 11 units are currently off field and available for reuse – making the effective utilization rate of 95.7 percent.

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Spectra Energy Reported Mixed Q2 Results, Top Line Up Over 11%

- Spectra Energy Reported Mixed Q2 Results, Top Line Up Over 11%

Aug 3, 2011

Spectra Energy (NYSE:SE) reported Q2 EPS of $0.42, ahead of consensus estimates of $0.40 per share. Revenues for the quarter rose 11.8% year-over-year to $1.19 billion, missing consensus estimates of $1.23 billion.

The company expects 2011 EPS to exceed the stated target of $1.65, vs. consensus estimates of $1.76 per share.

Spectra Energy has a potential upside of 13.4% based on a current price of $26.45 and an average consensus analyst price target of $30.

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PetroFrontier Spuds Southern Georgina Basin Well

- PetroFrontier Spuds Southern Georgina Basin Well

Wednesday, August 03, 2011
PetroFrontier Corp.

PetroFrontier has spudded its first well, "Baldwin-2", in the Southern Georgina Basin in the Northern Territory, Australia. PetroFrontier began drilling Baldwin-2 on the morning of Wednesday August 3, 2011, Australian Central Standard Time.

Baldwin-2 is located in the southwestern part of EP 103 in the Southern Georgina Basin. PetroFrontier has a 100% working interest in EP 103 and is the operator. The primary target in Baldwin-2 is the unconventional Basal Arthur Creek "hot" shale, with conventional secondary targets being the Hagen Member and Dolomitic Shoal above the Basal Arthur Creek "hot" shale and the Thorntonia located just below. Management believes that the Arthur Creek "hot" shale is potentially analogous to the Bakken play found in Saskatchewan, Canada and North Dakota, USA. PetroFrontier has re-evaluated existing wellbores on its lands and believes the unconventional Basal Arthur Creek "hot" shale is prospective for hydrocarbons over most of its land holdings. PetroFrontier's capital program for 2011 continues to focus on exploratory drilling opportunities around these existing wellbores.

Baldwin-2 will be air drilled vertically to an estimated depth of 900 meters to test the Thorntonia formation for prospective hydrocarbon shows. The well will then be extensively logged, plugged back and deviated horizontally for approximately 1,000 meters into the Basal Arthur Creek shale. This is expected to take approximately three weeks, at which time PetroFrontier will suspend the well temporarily and move to drill the MacIntyre-2 well, located in the northeastern corner of EP 127. Once it is drilled, MacIntyre-2 will be frac'd and completed using multi-stage open hole techniques. The rig and frac crew will subsequently return to Baldwin-2 to conduct a similar completion program on that well.

According to a report (the "Ryder Scott Resource Report") prepared by Ryder Scott Company Canada (independent oil and natural gas reservoir engineers), dated November 1, 2010, the unrisked, undiscovered, prospective (recoverable) resource, based on a best (P50) scenario, for the unconventional Basal Arthur Creek shale zone in EP 103 and EP 127 may contain approximately 13.2 billion barrels and 2.7 billion barrels (gross) of oil respectively.

The Ryder Scott Resource Report on the resource potential of the Southern Georgina Basin describes the prospective (recoverable) portion of "Undiscovered Resources", as defined by the Canadian Oil and Gas Evaluation Handbook and does not represent an estimate of reserves. The Ryder Scott Resource Report is compliant with National Instrument 51-101 "Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.

Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. Prospective resources are presented as unrisked prospective oil resources. The term unrisked means that no geological risk (play risk) has been incorporated in the hydrocarbon volume estimates.

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Petro Vista Commences Testing at Morichito Discovery

- Petro Vista Commences Testing at Morichito Discovery

Wednesday, August 03, 2011
Petro Vista Energy Corp.

Petro Vista provided the following operational update.

Morichito Block, Colombia - M5 Discovery

The Company has commenced testing from the previously announced Morichito discovery in Colombia. The M-5 well was re-entered and now has flow rates of up to 700 barrels of 22.5 degrees API crude oil per day utilizing a hydraulic jet pump from perforations in the lower Carbonera C7 zone at 5900-5902 feet. The well is currently being shut in for pressure buildup which will determine long term optimal production rate.

Originally drilled in March 2010, the M-5 previously tested two zones in the Carbonera C7 Formation and identified a third potential pay zone in the Carbonera C1 from logs and sidewall cores.

The third zone, a Carbonera C1 sand, exhibited good porosity and oil shows in sidewall cores but was not tested and will be evaluated at a later date.

Currently installed early production infrastructure has storage capacity of 2,000 barrels of crude. The infrastructure and includes four test tanks and two frac tanks with a total capacity of 3,000 barrels primary three-phase crude separation and emergency flare systems. Once the test and the pressure build up have been completed, the Company expects to commence operations intended to establish long-term production including upgrading the access road, which is expected to be completed before year-end.

Morichito Block, Colombia - M5B Exploration / Appraisal Well

Also as previously announced, the Company has drilled a second well (M5B) on the Morichito structure which had good oil shows and indications of petrophysical pay in several zones including the Carbonera C7 zone productive downdip. Due to a failed cement job, the well was not able to be properly tested. Discussions are underway with the cementing contractor to either redrill or sidetrack this well at the contractor's cost. Testing of these prospective zones will be commenced once this has been completed.

The Company currently holds a 50% participating interest in the Morichito discovery.

Block SSJN-5, Colombia

At the SSJN-5 block the operator, SK Energy, has sent Petro Vista the final field report from a 500 square kilometer 3D seismic program completed earlier this year. Processing of the survey is nearing completion. Initial studies indicate the data quality is very good and has confirmed the prospectivity of the area. The Company expects final data to be received by the end of August at which time a final interpretation will be completed. The Company holds a 25% working interest in this license. Petroamerica Oil Corp, which farmed in to half of the Company's original 50% interest in the block in turn for a carry of all costs associated with the seismic program, has until September 9, 2011 to exercise its option to acquire Petro Vista's remaining 25% interest in SSJN-5 for a payment of US$ 3,000,000 and the grant of an option to purchase common shares in the capital of Petroamerica having an aggregate value of US$3 million, with the price per share being 20% higher than the 30 day weighted average closing price immediately prior to date on which Petroamerica exercises its option to acquire the remaining 25% participating interest.

La Maye Block, Colombia

At the La Maye block the rainy season has again affected activities of the operator, New Horizon Energy. Plans to complete the apparent Noelia-1 well discovery that was drilled during the fourth quarter 2009 and to drill the license's Phase II commitment well have been delayed due to significant flooding. The operator has been attempting to test the well, but the area remains flooded. Colombia's Ministry of Environment has notified partners in the license that any further work regarding the required environmental license will only begin once the flooding subsides. The Company holds a 25% working interest in this license.

VMM-13 Block, Colombia

The Company has received confirmation from the Colombian National Hydrocarbon Agency that it will grant the Company's request to nullify the license associated with this area. Initially awarded during the ANH Mini-Round in 2008, all efforts were put on hold when it was discovered there were two national parks covering approximately 75% of the land area and 100% of the prospective area of the license.

Tartaruga Block, Brazil

The Company is awaiting approval by the Brazilian National Hydrocarbon Authority on Petro Vista's application to become a partner in the Tartaruga production license. At the Tartaruga producing field, the operator, UPP Petroleo do Brasil, is finalizing completion of additional production facilities including a new separator that is expected to enhance the productive capability of the field. A special valve has also been installed which will allow constant injection of solvent into the wellbore to inhibit buildup of paraffin which has caused production problems on the 7-TTG-1DP-SES well. Once completed, this well should be capable of producing at least 500 barrels of oil per day consistently.

Additionally, the operator is planning a workover of the older production well in the field, the SES-107D. This well is currently producing a few days per month, but it is expected that the workover will allow daily production at rates of 100-150 barrels of oil per day.

Plans are being developed to drill up to three additional wells in the field, including a deep test of a Serreria pool.

Colombia and Brazil continue to be key focus areas for Petro Vista for production and reserve growth and the Morichito production will compliment the current production from Tartaruga in Brazil. We remain committed to our efforts in Colombia in the Morichito Block as well as our remaining assets.

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Kan Tan IV Under New Management

- Kan Tan IV Under New Management

Wednesday, August 03, 2011
Frigstad Offshore

Effective from June 6, 2011, Frigstad Offshore Drilling (Cyprus) Ltd has entered into a marketing and management agreement for the Kan Tan IV semisubmersible drilling unit with the rig owners, Sinopec Star Petroleum Co Ltd, a subsidiary of the Sinopec Group.

Kan Tan IV is an Enhanced Pacesetter L907 delivered by FELS in Singapore in 1983, capable of operating in up to 2,000ft of water depth and equipped with a 18-3/4 15K BOP.

Frigstad Offshore has taken over full operational and commercial management of the rig from Maersk Drilling who has managed it for 10 years. Since 2001 the rig has operated in Mexico, Trinidad & Tobago and recently Australia and New Zealand where it drilled 11 wells and performed one subsea workover for a consortium of four operators. Kan Tan IV is currently at Keppel FELS in Singapore undergoing maintenance and special periodic survey. Significant investments have been made over the last five years to refurbish and upgrade the rig with e.g. new accommodation, new deck cranes, new shale shakers and new life boats.

The Kan Tan IV is currently being marketed by Frigstad Offshore for drilling contracts.

Established in Singapore in 1989, Frigstad Offshore is an independent drilling contractor offering a complete range of rig- and project management services to the offshore drilling industry. The Frigstad Offshore group has offices in Singapore, Cyprus, Norway and Brazil. Frigstad Offshore is currently managing the construction of two advanced ultra-deepwater semisubmersible drilling rigs, one of them being the Scarabeo 9 the first drilling unit of the Frigstad D90 design.

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Constellation Energy Misses Q2 Estimates

- Constellation Energy Misses Q2 Estimates

Aug 3, 2011

Constellation Energy (NYSE:CEG) reported Q2 adjusted EPS of $0.76, less than the analyst estimates of $0.85 per share. Revenues for the quarter rose 1.5% year-over-year to $3.35 billion, missing consensus estimates of $3.86 billion.

The company lowered its 2011 earnings guidance range by $0.05 to $3.05 to $3.35 per share, reflecting the combined effects of longer-than-expected outages at their nuclear joint venture facilities and the impact of our recent acquisitions in the competitive residential electric market. In light of the pending merger with Exelon, the company is no longer providing earnings guidance for 2012.

Constellation Energy (NYSE:CEG) has a potential upside of 6.3% based on a current price of $37.85 and an average consensus analyst price target of $40.25.

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Dragon Oil Drills Ahead at Lam Well

- Dragon Oil Drills Ahead at Lam Well

Wednesday, August 03, 2011
Dragon Oil plc

Dragon Oil announced the completion and initial testing of the Dzheitune (Lam) 28/158 development well. The well was completed as a single producer by the NIS rig to a depth of 1,786 meters. The initial test result from the well was 2,876 barrels of oil per day ("bopd"). The NIS rig has skidded to the next slot and is in the process of spudding the Dzheitune (Lam) 28/161 well. The Iran Khazar rig and Rig 40 are currently drilling the Dzheitune (Lam) B/159 and 13/160 wells, respectively.

Dr. Abdul Jaleel Al Khalifa, Chief Executive Officer, commented, "I am pleased to report the successful completion and initial testing of the Dzheitune (Lam) 28/158 well. The Group is currently producing at a healthy rate of above 60,000 bopd, which puts us in a comfortable position to ensure meeting our gross production growth target by the end of the year."

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Xcite Submits Field Development Plan for Bentley Field

- Xcite Submits Field Development Plan for Bentley Field

Wednesday, August 03, 2011
Xcite Energy Ltd.

Xcite announced that the final draft of the Field Development Plan ("FDP") for the Bentley field has now been submitted to the Department of Energy and Climate Change ("DECC").

The FDP outlines the proposed development plan for the Bentley field, which addresses the first stage production program in detail and also references the second stage production program, which together encompasses the core area of the reservoir.

The Company will respond to any issues raised by DECC in the coming months, in expectation of achieving approval in due course.

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Oilex: Second Stage in Cambay's Frac Stimulation Program Underway

- Oilex: Second Stage in Cambay's Frac Stimulation Program Underway

Wednesday, August 03, 2011
Oilex Ltd.

Oilex advised that the first stage of the large volume multi-stage fracture stimulation program of the horizontal Cambay-76H well has been completed successfully and the second stage is now underway.

The fracture stimulation program comprises eight stages with two fracture initiation points per stage. After completion of the fracture stimulation program the well will be flowed to surface to remove stimulation fluids from the well bore (well clean-up phase) and then a flow test will be conducted.

The Cambay-76H "proof of concept" horizontal well is evaluating the production potential of the Y Zone interval of the extensive Eocene "tight" reservoirs in the onshore Cambay Production Sharing Contract ("PSC"), Gujarat, India.
  • Report date: August 2, 2011
  • Status: Conducting fracture stimulation operations
  • Past Week's Operations
    • Rigging up fracture stimulation equipment
    • Testing wellhead equipment, replace faulty high pressure valves
    • Prepare well bore and conduct mini fracture stimulation test prior to first stage large volume fracture stimulation
  • Objective: Cambay Eocene "tight" reservoir Y Zone
  • Total Depth: 2,740 meters including 610 meters horizontal section

The participating interests in the Cambay PSC are:
  • Oilex Ltd (Operator) 30%
  • Oilex NL Holdings (India) Limited 15%
  • Gujarat State Petroleum Corporation Ltd 55%

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Egdon Looks Ahead to Markwells Wood-1 Well Test

- Egdon Looks Ahead to Markwells Wood-1 Well Test

Wednesday, August 03, 2011
Egdon Resources plc

Egdon provided an update on its UK operations and production at its year end of July 31, 2011.

Egdon's production during July 2011 from the Keddington, Kirkleatham and Avington fields was 420 barrels of oil equivalent per day ("boepd").


At the Keddington Oil Field in Lincolnshire, license PEDL005(remainder) (Egdon 75% interest) the Keddington-4 (K4) well was drilled as a re-entry and horizontal sidetrack from the Keddington-1Z "donor" well during April 2011, and a total of 120 meters of the primary reservoir Unit 1 sandstone was encountered along with 65 meters of Unit 2.

As reported in May the K4 well initially free-flowed oil and gas at maximum rates in excess of 200 barrels of oil per day ("bopd") and 518,000 cubic feet of gas per day with no associated formation water. Following "bleeding- off" of the gas pressure the well was put on pumped production using a down-hole sucker-rod pump and stabilized rates of around 75 bopd along with 200,000 cubic feet of gas per day were achieved by the end of June. Indications are that the pump is operating at low efficiency due to the high gas levels in the produced fluids and that the well is capable of delivering higher oil rates with greater drawdown. Options to resolve this are being investigated.

The Keddington-3z well (K3Z), which had been shut-in since March 2011, was put back on free-flow production, along with continued production from K4, from the beginning of July and total oil rates have steadily increased during the month from 120 to 180 bopd (Net Egdon 135 bopd) as the gas pressure in the well has gradually been "bled-off" in a controlled manner and has been constrained by flaring capacity. Average daily production during July was 158 bopd (Net Egdon 118.5 bopd) and 850,000 cubic feet of gas per day (Net Egdon 106 boepd currently being flared).

To date no formation water has been produced from either K3Z or K4 resulting in a decrease in project operating costs.

We continue to pursue the best options for export of electricity from the site to minimize constraints on oil production and are integrating the results of the K4 well into a field model to enable a reassessment of the ultimate reserves for the field.


As previously reported the Kirkleatham gas field in PEDL068 (Egdon 40% interest) achieved first production on April 19, 2011. Following the resolution of a number of residual mechanical and control issues the field has been capable of 24 hour production since mid-May. Availability of the end-user power plant restricted production during June. However, production uptime during July has been high with production averaging 4.24 million cubic feet of gas per day ("mmcfg/d") (Net Egdon 1.7 mmcfg/d or 282 boepd). Levels of H2S have stabilized at 60 parts per million, well below design limitations.

The power plant was shut-in for 7 days for routine maintenance on 30 July during which time down-hole pressure data will be retrieved from the Kirkleatham-4 well for analysis.

It is planned to produce the well at between 3 and 3.5 mmcfg/d (Net Egdon 1.2 to 1.4 mmcfg/d or 200 to 233 boepd) on resumption of production to match expected power output and manage reservoir pressure.


The Ceres field in block 47/9c (Egdon 10% interest) is now in a position to produce following completion of repair work on the damaged Eris umbilical and resolution of hydrate issues in the flow lines. The Ceres field was brought back on stream on June 13, 2011 and was produced with some interruptions until June 26, 2011 when the field was shut-in due to annual maintenance at the Cleeton platform. Egdon have been advised that this shut-down is likely to last for a period of around sixty days with the expectation of a restart of sustained production during September 2011. Production occurred over seven days during June 2011 and average net Egdon gas production for the period was 1.6 mmscfg/d (c. 260 boepd).

Waddock Cross

At the Waddock Cross oil discovery in Dorset license PL090 (Egdon 45%), the site is in the final stages of preparation for commencement of an Extended Well Test. Test operations are expected to start within the next two weeks and to continue for a period of up to six months. The intention is to trial a number of techniques aimed at increasing oil production in this high water cut reservoir to enable a decision to be made over a future development of this field which contains significant in place oil reserves.

Markwells Wood

In West Sussex license PEDL126 (Egdon 10%) we have been advised that well test operations at the Markwells Wood-1 oil discovery are due to commence at the end of August, subject to final DECC approval. The test is planned to last a maximum of 40 days and will include acid stimulation of the reservoir. The outcome of the testing will help in determining the commerciality of the well.


The Avington oil field in Hampshire license PEDL070 (Egdon 26.67% interest following the recently announced sale of 10% interest in the field) continues to produce from the Avington-2z and Avington-3z wells. Net Egdon production for July was 20 bopd.

Dukes Wood/Kirklington

In Nottinghamshire license PEDL118 (Egdon 65% interest) planning consent has been received for oil production at the Dukes Wood-1 well. Egdon are now in the process of securing the environmental permit and DECC field development approval prior to restarting the combined production from Dukes Wood-1 and Kirklington-3Z later in 2011.

PEDL201 Seismic Program

In Leicestershire/Nottinghamshire license PEDL201 (Egdon 50%) Tessla-IMC completed a 19 kilometer 2D seismic program during May 2011 over the Burton on the Wolds Prospect which is located to the south-east of the Rempstone oil field. The processed data is currently being evaluated with a view to a drilling decision during 2012.

PEDL180/182 3D Seismic Program

A contract has recently been signed with Tessla-IMC for the acquisition of a 45 square kilometer 3D seismic survey over the prospective Broughton-Wressle trend in Lincolnshire licenses PEDL180 & PEDL182. On current timing the survey is expected to be completed by the year end.

Commenting on the recent developments, Egdon's Managing Director Mark Abbott said, "We have made further good progress towards our long stated target of 500 boepd and achieved net Egdon production of 420 boepd during July 2011. The resumption of production at Ceres which is currently expected on conclusion of the maintenance shut-down of the Cleeton platform during September, along with the EWT at Waddock Cross should enable us to exceed our production target at this time.

"We also look forward to the commencement of the Markwells Wood-1 well test which will determine if the discovery is commercial."

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