Det norske Hits Pay in Norwegian Sea

- Det norske Hits Pay in Norwegian Sea

Tuesday, September 13, 2011
Det norske oljeselskap ASA

Det norske oljeselskap ASA, operator of PL 482, is in the process of completing exploration well 6508/1-2 on Skaugumsåsen. The well is located about 10 kilometers south of the Norne field in the Norwegian Sea.

The well encountered an 18 meter gas column and a 23 meter oil column.

Preliminary estimates of the discovery indicate recoverable volumes of 1 million Sm3 oil equivalents. Further studies are necessary in order to determine if the discovery is economically viable.

This is the first exploration well in license 48, which was part of the Awards in Predefined Areas (APA) 2007.

Well 6508/1-2 was drilled by the semisubmersible Aker Barents rig.

Partners in PL 482 include: Det norske (65 percent and operator), Petoro 20 percent and Skagen44 AS 15 percent.

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Americas Petrogas, Gran Tierra Hit Oil Pay in Argentina

- Americas Petrogas, Gran Tierra Hit Oil Pay in Argentina

Monday, September 12, 2011
Americas Petrogas

Americas Petrogas announced Monday that it, along with its co-venturer, Gran Tierra Energy, have made a new significant discovery of oil (1,023 barrels of oil equivalent per day) in the 1st of the three exploration wells on the Rinconada Norte block located in the Neuquen Basin of Argentina (Americas Petrogas Argentina S.A. is operator).

The RN x-1004 well flowed a total combined test rate of approximately 944 barrels (150 m3) per day of oil and 13,360 m3 per day of gas (79 barrels of oil equivalent per day) for a total of approximately 1,023 barrels of oil equivalent per day from two intervals tested separately in the Precuyo formation. This well also flowed 43 barrels (5 m3) per day of water or a 4% water cut.

From the depths of the zones tested (982-992 meters and 1022-1032 meters) and electric logs information, the Company estimates an oil column thickness of approximately 60 meters or 197 feet. The oil is 29.6 degrees API, sweet light crude similar to crude oil produced from the equivalent formation in Americas Petrogas' Medanito Sur block. This well has been completed and the service rig will now move on to the next two wells, which have already been drilled, logged and production casing has been installed. Americas Petrogas' wholly-owned Argentina subsidiary, Americas Petrogas Argentina S.A., is the operator of the Rinconada Norte block, holding a 65% working interest, while Gran Tierra Energy, through its Argentina subsidiary, holds a 35% working interest.

Commenting on this most recent discovery, Guimar Vaca Coca, Managing Director of Americas Petrogas Argentina S.A., stated, "We are very excited about this new find on the first well of this three-well exploratory drilling program because of the strong production rates and possibility of significant commercial reserves. We are also optimistic about the prospects for the remaining two wells."

The Rinconada Norte block is currently under an Exploitation concession, which will allow Americas Petrogas and Gran Tierra Energy, with previous approvals from the authorities, to move ahead with development activities in the near term. The Company anticipates building test production facilities in the fourth quarter of 2011. This drilling program on Rinconada Norte represents the initial phase of Americas Petrogas' previously-announced drilling plans for 2011-2012 (see press release of June 3, 2011).

The Rinconada Norte block (approximately 96 sq.km or 37 sections) is located immediately south of and adjoins Americas Petrogas' Medanito Sur block in La Pampa Province in the eastern region of the Neuquen Basin of Argentina.

Barclay Hambrook, President & CEO of Americas Petrogas, stated, "We are very pleased with this discovery and Americas Petrogas is well-funded to accelerate and expand its planned capex program in order to increase production and reserves."

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Total Hits Gas Pay in Caspian

- Total Hits Gas Pay in Caspian

Friday, September 09, 2011
Total S.A.

Total on Friday announced a major gas discovery in the Caspian Sea in the Absheron block offshore Azerbaijan.

The Absheron X-2 well has encountered more than 500 feet of cumulated net gas pays within high quality sands on the northern flank of a major 270 square kilometers structure. Reservoirs are expected to extend over the entire northern part of the structure.

The well's first results confirm a potential of several trillion cubic feet of gas and associated condensates.

"This discovery could be very significant in terms of resources," said Total's Senior Vice President Exploration, Marc Blaizot. "It is the result of Total's bolder exploration strategy aimed at exploring high risk/high reward prospects both in prolific and frontier basins particularly in high pressure, deeply buried reservoirs. Our geoscientists and drillers have all the skills to make other discoveries in similar environments like the United Kingdom, Brunei, Malaysia or Egypt where new permits have been recently awarded to Total."

The well is currently at a depth of approximately 6,550 meters. Drilling will continue to explore further deeper objectives that look attractive. The well will then be tested to better confirm the reservoir potential.

The Absheron discovery is located in 500 meters of water, 100 kilometers south east of Baku, some 25 kilometers north east of the Shah Deniz gas and condensate field.

Total subsidiary, Total EP Absheron is the operator of the Absheron license with a 40% equity. The partners are SOCAR (40%) and GDF SUEZ (20%).

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Coastal's Bua Ban North A-05 Encounters Net Pay

- Coastal Bua Ban North A-05 Encounters Net Pay

Wednesday, September 07, 2011
Coastal Energy Co.

Coastal Energy announced the successful results of the Bua Ban North A-05 well and provides an operations update.

The Bua Ban North A-05 well was drilled to a total depth of 5,650 feet TVD. The well encountered 81 feet of gross sand and 35 feet of net pay in the Miocene reservoir with 27 percent average porosity. The well tested the Miocene reservoir on the eastern flank of the Bua Ban North A field. The oil water contact in the well was seen at 3,770 feet. The results of the A-05 well add an additional 1,200 acres to the structural closure area. The Company is planning to drill five to six additional evaluation wells at Bua Ban North before moving the rig to G5/50.

The Bua Ban North B-02, B-03 and B-04 wells have all been completed and tied into the production facilities. The aggregate production rate from Bua Ban North B is approximately 8,200 bopd. Average production at Songkhla A is approximately 4,000 bopd, with production currently being constrained due to a temperature issue. The Company is installing additional cooling units to remedy this issue and restore production to 6,500 bopd. The installation is expected to be complete in approximately two weeks.

Aggregate offshore oil production is averaging 13,700 bopd, and total Company production is averaging 15,800 boepd.

Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "We are very pleased with the results of the Bua Ban North A-05 well. This well was drilled as far north as possible to test the presence of hydrocarbons between Bua Ban North A & B. We have several locations identified which are further south and up to 200 feet structurally higher which we plan to test with the upcoming wells.

"Total production from Bua Ban North B has come in above our expectations and the wells continue to perform better than expected. We are working to resolve mechanical production issues at Songkhla and expect to restore production to previous levels in the coming weeks.

"We expect production facilities to be on location at Bua Ban North A in late October."

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PA Resources Confirms Additional Gas Pay Offshore Denmark

- PA Resources Confirms Additional Gas Pay Offshore Denmark

Friday, August 26, 2011
PA Resources AB

The sidetrack of the recent gas discovery at the Broder Tuck prospect in License 12/06 offshore Denmark has confirmed additional hydrocarbon column while sample analyses from the initial exploration well have indicated a higher than expected condensate content.

Bo Askvik, President and CEO at PA Resources, commented, "We are pleased to have confirmed additional hydrocarbons with the sidetrack and to be able to update on the condensate content of the gas, which exceeds our expectations and adds value to the find. This is an exciting discovery for PA Resources and we now look forward to the Lille John exploration well."

The initial Broder Tuck exploration well (5504/20-4), located approximately 10 kilometers south of Gorm Field in the Danish part of the North Sea, encountered hydrocarbon pay in the primary Middle Jurassic target during July. The well has now been sidetracked to a location approximately 680 meters from the initial well, where the Middle Jurassic sandstone again contained hydrocarbons, albeit less well developed than in the initial wellbore. The 2011 drilling program has therefore established a gross hydrocarbon column of at least 360 meters from the crest of the structure down to the base of the Middle Jurassic sandstone in this sidetrack.

Ongoing sample analyses from the initial exploration well have now confirmed the discovered hydrocarbons to be a high quality gas with condensate of approximately 44º API gravity at a ratio of approximately 80-90 barrels of condensate per million standard cubic feet of gas.

Following plugging and abandonment of Broder Tuck, the Ensco 70 rig will shortly move to drill the second exploration well in this program, Lille John, some 8 kilometers to the south.

The following companies participate in License 12/06: PA Resources UK Limited (64%), Nordsøfonden (Danish North Sea Fund) (20%), Danoil Exploration A/S (8%) and Spyker Energy APS (a wholly-owned subsidiary of Spyker Energy Plc) (8%).

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Anadarko Hits Gas Pay Offshore Mozambique

- Anadarko Hits Gas Pay Offshore Mozambique

Monday, August 22, 2011
Anadarko Petroleum Corp.

Anadarko announced that its Barquentine-2 appraisal well, located in Mozambique's Offshore Area 1 of the Rovuma Basin, encountered more than 230 net feet (70 meters) of natural gas pay in high-quality Oligocene-age reservoirs. Barquentine-2 was the first appraisal well in the Windjammer, Barquentine and Lagosta complex, which is estimated to hold a minimum of 6 trillion cubic feet (Tcf) of recoverable natural gas resources.

"Our first appraisal of the Barquentine discovery matched our expectations, confirming our seismic modeling and providing confidence in our geologic interpretation of this world-class accumulation," Anadarko Sr. Vice President, Worldwide Exploration Bob Daniels said. "We've also taken a major step toward the development of these substantial resources by awarding contracts for pre-FEED (front-end engineering and design) work for a prospective LNG (liquefied natural gas) plant. We have significant ongoing exploration and appraisal programs in the Rovuma Basin and look forward to advancing this important project that can provide long-term benefits for the people of Mozambique."

The Barquentine-2 appraisal well was drilled to a total depth of approximately 13,500 feet (4,100 meters) in approximately 5,400 feet (1,650 meters) of water using drillship Belford Dolphin. The results of the Barquentine-2 appraisal well, which is located approximately 2 miles (3 km) east-southeast of the Barquentine-1 discovery well, also indicated that the Oligocene reservoirs are in static pressure communication between the wells. The drillship is now being mobilized to the south to drill the Camarão exploration well, which also will serve as an appraisal to the Windjammer discovery.

As mentioned, a subsidiary of Anadarko and co-owners in the Offshore Area 1 awarded contracts to KBR and Technip to perform pre-FEED studies for an LNG plant in Mozambique. The pre-FEED studies are designed to help the partnership further assess the viability of developing an LNG facility to produce and process natural gas from the region.

Anadarko is the operator of the 2.6-million-acre Offshore Area 1 with a 36.5-percent working interest. Co-owners in the area include Mitsui E&P Mozambique Area 1, Limited (20 percent), BPRL Ventures Mozambique B.V. (10 percent), Videocon Mozambique Rovuma 1 Limited (10 percent) and Cove Energy Mozambique Rovuma Offshore, Ltd. (8.5 percent). Empresa Nacional de Hidrocarbonetos, E.P.'s 15-percent interest is carried through the exploration phase.

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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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Lundin Hits Gas Pay Offshore Malaysia

- Lundin Hits Gas Pay Offshore Malaysia

Thursday, August 04, 2011
Lundin Petroleum AB

Lundin has made a second gas discovery with the Cempulut-1 well that was drilled in Block SB303, offshore Sabah, East Malaysia.

Cempulut-1 was drilled with the Offshore Courageous rig in a water depth of approximately 75 meters. The well was drilled to a total depth of 1,095 meters.

The Cempulut-1 well intersected a large Late Miocene carbonate reef with excellent reservoir properties.

The gross total vertical pay thickness encountered is approximately 50 meters. The deeper targeted oil leg however proved to be water bearing.

An extensive data acquisition program was completed including pressure measurements, sampling and a mini flow test.

The data recovered from the well will be analyzed further in order to determine a range of resource estimates.

Ashley Heppenstall, President and CEO of Lundin Petroleum commented, "This is the second gas discovery made by Lundin Petroleum in SB303 and the third in the contract area which also contains the Titik Terang discovery. All three discoveries are in close proximity to one another and with additional undrilled leads and prospects also in the block a clear opportunity to evaluate the potential for a cluster development now exists."

The rig will now move to drill the Batu Hitam prospect, in PM308A, the third well in Lundin Petroleum's five well drilling campaign in Malaysia in 2011.

Lundin Petroleum holds a 75 percent interest in SB303 through its subsidiary Lundin Malaysia BV. Lundin Malaysia BV's partner is PETRONAS Carigali Sdn Bhd with a 25 percent interest.

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Eni Hits Hydrocarbon Pay Offshore Ghana

- Eni Hits Hydrocarbon Pay Offshore Ghana

Thursday, July 28, 2011
Eni S.p.A.

Eni has made a new hydrocarbon discovery offshore Ghana through the Gye Nyame 1 well, which is located in the OCTP block 50 km off the Ghanaian shoreline.

The well, which was drilled in 519 meters of water, was drilled to a total depth of 3,349 meters and encountered significant thickness of gas and condensate sands with excellent reservoir characteristics. Oil mineralization was also discovered in the underlying sands. Its significant potential will be further assessed through a delineation program.

The discovery is located 16 km east of the Sankofa gas discovery, and confirms the important role of this block in the development of non-associated gas resources in Ghana.

Eni has already begun talks with the Ministry of Energy and the partner organization, GNPC (Ghana National Petroleum Corporation), aimed at fast-tracking the development of Sankofa which will contribute to the valorization of the gas on the domestic market, thus contributing to the ambitious growth targets of the country.

Thanks to the discovery of Gye Nyame, Eni can now also study important development and production synergies. By consolidating gas volumes of the two discoveries, this development opens up opportunities for exploiting the international market for liquefied gas, through offshore facilities of which Eni has significant knowledge and appropriate technology.

Eni, through its subsidiary Eni Ghana Exploration and Production Limited, is the operator of the OCTP license with a 47.22% interest. Other partners are Vitol Upstream Ghana Limited, with a 37.78% stake, and state company GNPC with a 15% stake. GNPC has a back-in option for an additional 5% of the license.

Eni is also finalizing the farm in to the Keta block as operator with a 35% stake. The block is located offshore the eastern coast of Ghana, bordering Togalese waters, where Eni acquired two exploration licenses in 2010. Partners in the Keta Block Joint Venture are Afren Energy Ghana Ltd., wholly owned subsidiary of Afren plc, with a 35% stake, Mitsui E&P Ghana Keta Ltd. with 20% and GNPC with 10%.

Eni has been present in Sub-Saharan Africa since the early 1960s and is currently operating in Angola, Nigeria, Togo, Ghana, Republic of Congo, Gabon, Democratic Republic of Congo and Mozambique. Eni's operated production in the area is around 450,000 barrels of oil equivalent per day.

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O&G Pay Identified at Victory Energy's Jones County Well

- O&G Pay Identified at Victory Energy's Jones County Well

Monday, July 25, 2011
Victory Energy Corp.

Victory Energy, through its partnership with Aurora Energy Partners, announced that its Tx. Jones County, Nassau #1 well has reached target depth of 5,325 feet and is now entering completion.

Mudlog and multiple drillstem tests (DSTs) indicate the presence of two oil and gas pay zones exceeding fifty feet in thickness with several others measuring between ten and twenty feet in thickness. A seventy-foot (gross) oil and gas Pennsylvanian age formation will be the focal point of this initial completion. The targeted formation is expected to produce both oil and gas.

With a successful completion, the well will be production tested to determine rate, gas-to-oil ratio and pressure. An assessment of the type and size of production facilities will be determined by testing. Due to the high gas cut encountered during drilling, a gas delivery line is already being assessed.

This multiple pay zone discovery offers the opportunity for additional development and drilling on held acreage. The company, through its partnership with Aurora Energy Partners, holds a working interest of no less than 1.5 percent and up to 2.5 percent for each acreage block acquired.

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PA Resources Hits Gas Pay in Danish North Sea

- PA Resources Hits Gas Pay in Danish North Sea

Tuesday, July 19, 2011
PA Resources AB

PA Resources' subsidiary PA Resources UK Limited announced initial results of the Broder Tuck exploration well (5504/20-4), located approximately 10 kilometers south of Gorm Field in the Danish part of the North Sea.

Following some initial drilling problems, the well was drilled as a vertical well to a total depth of 3,658 meters below mean sea level in layers of Lower Jurassic/Triassic age.

The well encountered approximately 17 meters of net pay in high quality sandstones in the primary Middle Jurassic target. The reservoir was cored and an extensive wireline log, pressure and sample suite has been taken for future evaluation, with well site sample analysis showing the reservoir fluid to be gas with some condensate.

The Broder Tuck well has established a gross hydrocarbon column of at least 230 meters from the crest of the structure down to the base of the column encountered in the well. A sidetrack will now be drilled to assess the potential for additional gas volumes down-dip.

The following companies participate in Lenience 12/06: PA Resources UK Limited (64%), Nordsøfonden (Danish North Sea Fund) (20%), Danoil Exploration A/S (8%) and Spyker Energy APS (a wholly-owned subsidiary of Spyker Energy Plc) (8%).

Bo Askvik, President and CEO at PA Resources, commented, "We are delighted to have made this exciting discovery with our first operated well in the North Sea. I would like to congratulate our exploration/operations team on this outcome and to thank our partners for their continued support. We now look forward to the results of the sidetrack."

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Lundin Hits Gas Pay in Barents Sea

- Lundin Hits Gas Pay in Barents Sea

Friday, July 08, 2011
Lundin Petroleum AB

Lundin, operator of production license 438, has completed well 7120/2-3S on the Skalle prospect as a gas discovery. A comprehensive logging and coring program has been acquired.

The well is situated approximately 25 kilometers north of the Snohvit Field in the south western part of the Barents Sea. The primary target for the well was to prove hydrocarbons in reservoir rocks from both the Cretaceous and the Jurassic age. Gas was proven in three separate zones.

The initial gross contingent resource range for the Skalle discovery is estimated at between 88 to 280 billion cubic feet (bcf) (15 to 50 million barrels of oil equivalent (MMboe)). There is a potential for a deeper oil leg in the lower Cretaceous reservoir of Skalle and an upside potential in Skalle substructures.

The results of the well will be further analyzed to determine the appraisal program for the discovery.

Ashley Heppenstall, President and CEO of Lundin Petroleum commented, "The Skalle gas discovery is close to existing infrastructure with upside potential both in nearby substructures and other prospects on the license. We remain confident regarding the oil prospectivity of Lundin Petroleum's Barents Sea acreage."

The well 7120/2-3S is the first exploration well in PL438 and was drilled to a vertical depth of approximately 2,600 meters below sea level.

Well 7120/2-3S was drilled using the rig Transocean Leader, which now will move to PL265 in the Greater Luno Area in the Norwegian North Sea to drill the Aldous Major South exploration well 16/2-8. Statoil ASA is the operator of PL265 and Lundin Petroleum has a 10 percent interest.

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Caza IDs Potential Pay at O.B. Ranch Well

- Caza IDs Potential Pay at O.B. Ranch Well

Thursday, July 07, 2011
Caza O&G Inc.

Caza O&G provided an operational update on the Company's Bongo Property concerning the O.B. Ranch #2 development well in Wharton County, Texas.

Caza, as operator, announced that the O.B. Ranch #2 development well has reached its target depth of 13,210 feet and electric logs have been obtained through the target depth. The logs indicate potential pay in the Frio, Yegua and targeted Cook Mountain formations.

Data from the logs and core samples from the well have confirmed Caza's geologic and seismic modeling, which hypothesized that the O.B. Ranch #1 discovery well (which originally targeted a deeper Wilcox structure) was producing from the fringe of a more extensive Cook Mountain sand package. The O.B. Ranch #2 development well has been drilled closer to what Caza believes to be the center of the Cook Mountain anomaly with the aim of gaining valuable geologic knowledge of the Bongo/Cook Mountain sand and the regional Cook Mountain sand picture, while adding further production to the Company's portfolio.

The O.B. Ranch #2 is in a higher structural position than the O.B. Ranch #1 well, and log and seismic data support thicker, better sorted, potential pay sands with better porosity within the Cook Mountain section than those found in the O.B. Ranch #1. Due to concerns over existing downhole conditions, Caza was unable to run the micro imaging tool used in the O.B. Ranch #1 well, which helps to identify net effective pay. However, the Company was able to run a high resolution triple combination logging tool, which was more than adequate to define lithology and potential pay sections within the wellbore.

Caza is currently running production casing and preparing the O.B. Ranch #2 well for further completion operations in the Cook Mountain. The completion procedure will include a fracture stimulation program, which is scheduled for the end of July, 2011. The initial rate will be announced following completion of the fracture stimulation procedure.

The log data also indicates potential pay in the shallower Frio and Yegua formations at approximately 5,530 feet and 9,000 feet respectively.

Caza currently has a 45.28% working interest and an approximate 33.51% net revenue interest in the Bongo property and wells.

W. Michael Ford, Caza's Chief Executive Officer commented, "We are very pleased with the results of the O.B. Ranch #2 well. The data from this well has confirmed our scientific model and will be instrumental in efficiently developing the Bongo property. Additionally, Caza is beginning to receive the initial data from our proprietary seismic reprocessing in this area, which looks very promising. The Company currently has several exploration prospects under lease that should benefit from this newly gathered data as should Caza's future exploratory prospect development in Wharton County."

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OGX Hits Hydrocarbon Pay in Santos Basin

- OGX Hits Hydrocarbon Pay in Santos Basin

Friday, July 01, 2011
OGX S.A.

OGX has identified the presence of hydrocarbons in the Santonian section of 1-OGX-47-RJS well, in the BM-S-59 block, in the shallow waters of the Santos Basin. OGX holds a 100% working interest in this block.

"This discovery in conventional reservoirs of the Santos Basin contributes significantly to the development of our assets in this region. When combined with the discoveries that we have already made, we will be able to optimize the operational structure of this area by taking advantage of the economies of scale," commented Mr. Paulo Mendonça, General Executive Officer and Exploration Officer of OGX. "Following the drilling campaign, we will intensify both the appraisal process of the several discoveries for this basin, as well as the development of the production model for the region," added Mr. Mendonça.

A hydrocarbon column of approximately 131 meters was encountered in the sandstone reservoirs of the Santonian section with about 51 meters of net pay. This discovery is located 2.9 kilometers from the Natal accumulation which was discovered through the drilling of well OGX-11.

The OGX-47 well, named as Maceió, is located in the BM-S-59 block and is situated approximately 110 kilometers off the coast of the state of Rio de Janeiro at a water depth of approximately 185 meters. The Ocean Quest rig initiated drilling activities on May 24, 2011.

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Beach Hits Oil Pay at Parsons-5

- Beach Hits Oil Pay at Parsons-5

Thursday, June 30, 2011
Beach Energy Ltd.

Beach Energy Ltd. announced Thursday that it has successfully encountered a six-meter oil column at the Parsons-5 development well in the Cooper Basin Western Flank.

Beach had its fifth success in its PEL 92 drilling program with two wells remaining to be drilled. The Parsons-5 well, located 1.3km south of the Parsons-1 discovery well, encountered a six meter oil column.

The Parsons-5 oil column was encountered in the Namur Sandstone reservoir and was consistent with pre-drill expectations. The confirmed updip position with respect to Parsons-2 will result in an upgrade of recoverable oil reserves from the Parsons Field.

Beach will announce a firmer reserve assessment as appropriate data becomes available, but preliminary work suggests that well results from the current drilling program, plus continued strong production performance, will result in an reserve increase in excess of 800,000 barrels for the Parsons Field.

Parsons-5 is expected to be tied in during the second half of the year through the Parsons oil facility. Oil from the Parsons Field is transported from the Western Flank by flowline to Tantanna, from where it is currently trucked to Moomba, and hence not impacted by any flooding in the area.

The next well to be drilled in the PEL 92 program will be the Wheatons-1 exploration well, which is located about 10km to the north of the Parsons Field. Participants in PEL 92 are:

• Beach (Operator) 75%
• Cooper Energy Limited 25%

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Exillon Confirms Oil Pay at Exploration Well 4

- Exillon Confirms Oil Pay at Exploration Well 4

Wednesday, June 29, 2011
Exillon Energy plc

Exillon announced preliminary results from Exploration Well 4 (EWS-10274), located in West Siberia.

Exploration Well 4 was designed to test an area between the EWS I and EWS II fields. Preliminary results of wire line logging confirmed the presence of 6.7 meters of effective net oil pay in an area that has not been previously studied. These results have expanded the management's understanding of the outline of the EWS fields in a manner which may support further reserve growth.

The well encountered the Jurassic reservoir at 1,883 meters, and is currently being drilled deeper to assess the potential for further oil pay within the Pre Jurassic. Testing of the well is expected to be completed by the end of Q1 2012.

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Coastal Confirms Net Pay at Buan Ban North B Field

- Coastal Confirms Net Pay at Buan Ban North B Field

Tuesday, June 28, 2011
Coastal Energy Co.

Coastal Energy announced the results of two wells drilled at the Bua Ban North B field, offshore Thailand.

The Bua Ban North B-08 well was drilled to a total depth of 5,900 feet TVD and encountered 92 feet of net pay with 28 percent porosity and 25 percent water saturation in the Miocene interval. The B-08 well was drilled on the easternmost fault block of the field and successfully appraised the discovery made by the B-03 well. As a result of the B-08 drilling, the lowest known oil was moved 140 feet lower in this fault block.

The B-07 well was drilled as a water injection well and to establish the oil water contact in the field. The B-07 encountered the oil water contact at 3,824 feet, which was in line with the prognosis based upon previous drilling results. Pressure and log data from the B-08 well indicate that the oil water contact may be deeper on the eastern side of the field.

Randy Bartley, Chief Executive Officer of Coastal Energy, commented, "The results of the B-07 and B-08 wells serve as further confirmation of the Miocene trend in the Songkhla basin. Updated mapping based on drilling results indicates that the structural closure at Bua Ban North B is approximately 2,800 acres in size. The positive appraisal of the eastern fault block has major implications for the extension of this field as it has significantly increased the prospectivity along the major eastern Miocene fault which extends over three kilometers between Bua Ban North A & B.

"The drilling rig is going to mobilize to the Songkhla H prospect next, which is a commitment well outside of the two established production areas on G5/43. We will proceed with the installation of the mobile offshore production unit to begin production at Bua Ban North B once the rig is off location."

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PetroNeft Spies Oil Pay at License 61

- PetroNeft Spies Oil Pay at License 61

Wednesday, June 22, 2011
PetroNeft Resources plc

PetroNeft, owner and operator of Licenses 61 and 67, Tomsk Oblast, Russian Federation, provided an update on its operations.

Highlights

• Production currently averaging about 2,500 bopd, primarily from 7 wells
• Autumn production enhancement program planned to re-frac, with larger frac sizes, existing wells on Pad 1 and new wells on Pad 2
• Planned number of wells required from Pad 3 to be reduced recognizing thinner oil pays
• Extension of Lineynoye oil field north of Pad 2 with thicker pay zones expected in the longer term to compensate for reserve and production reductions from Pad 3
• 1Q 2012 production target has been revised to between 4,000 to 5,000 bopd and 2Q 2013 to between 7,000 to 9,000 bopd
• Kondrashevskoye No. 2 sidetrack well progressing, result expected shortly
• Exploration wells at Sibkrayevskaya and Cheremshanskaya, the largest prospects in the 2011 program totaling over 100 million barrels to spud in early July and August respectively

2011 License 61 Development program - Lineynoye oil field

Production drilling continues with one additional well successfully drilled from Pad 3. Preliminary log and survey data for well 336 indicate net oil pay of 1.4 meters with an additional possible oil pay of 5.6 meters which we will need to test to confirm.

License 61 Production

Production is currently about 2,500 bopd with the primary contribution coming from 7 of the 9 wells drilled in 2010. As anticipated the wells have been slowly declining since they were fracture stimulated earlier this year. We have begun water injection/pressure maintenance in the field using the Lineynoye No. 6 well as an injection well; this will help maintain production levels.

We are pleased with the post frac performance of the wells particularly those with the larger size fracs. The initial fracture stimulation program incorporated a range of fracture sizes depending on the individual reservoir characteristics at each well. Without exception, the larger volume fracture stimulations have shown better and more sustained results than the small or mid-sized fracs. We consequently plan to re-frac some existing wells to boost production.

We anticipate a significant production contribution from the new Pad 2 wells following fracture stimulation; a contract has been signed to conduct this operation in late September/early October. Our next production update will be made following this work.

The positive results from Pad 2 wells have shown that the northern part of the Lineynoye field has thicker pay and extends further than originally anticipated and this has potentially very positive implications for the ability of structures north of West Lineynoye to be oil bearing. The western portion of the field, particularly in the Pad 3 area, is lower structurally and has thinner pays. As a result we will increase the number of wells drilled from Pad 2 and reduce the number of wells drilled from Pad 3. This will mean fewer wells available for production in 2011, thereby reducing our expected near-term production rate. The overall impact on Lineynoye field reserves is expected to be minimal.

The 1Q 2012 production target for License 61 has been revised to a range between 4,000 to 5,000 bopd and the 1Q 2013 production target to a range between 7,000 to 9,000 bopd. These amendments also incorporate a more conservative initial production estimate for the Arbuzovskoye oil field which we plan to bring on-stream in the second half of 2012.

Exploration / Delineation Program

PetroNeft's high impact 2011 exploration program, which has the potential to more than double our reserves, is targeting over 100 million barrels net to PetroNeft on five prospects in Licenses 61 and 67

License 61 (PetroNeft 100%)

The Kondrashevskoye No. 2 sidetrack well being drilled down dip from the Kondrashevskoye No. 2 well is progressing on schedule and we expect a result in early July.

The second 2011 exploration well will be at Sibkrayevskaya, a prospect of over 40 million barrels. Site preparation and mobilization of the rig and materials and rig-up operations is complete. Drilling should start in July with results expected in August.

The site for the third exploration well, North Varyakhskaya No. 1, has also been prepared and the rig and materials have been moved to the site for a planned spud in August/September 2011 following Sibkrayevskaya.

License 67 (PetroNeft 50%)

The two exploration wells, Cheremshanskaya No. 3 and Ledovoye No. 2a, are located close to existing year-round roads and will be drilled in the second half of the year. We have already mobilized equipment and completed construction of the Cheremshanskaya site and the rig is now being mobilized by barge to a nearby river port. This well is expected to spud in August and is targeting over 60 million barrels net to PetroNeft across three objectives.

Construction of the site for the Ledovoye No 2a well has commenced and we expect to spud in October/November. Ryder Scott have attributed 15 million barrels net to PetroNeft in the Upper Jurassic horizon, however, we will also be testing additional potential in the Lower Cretaceous zone.

Dennis Francis, Chief Executive Officer of PetroNeft Resources plc, commented, "While the results of Pad 2 drilling are encouraging, the Pad 3 drilling results will limit near term production growth. We are currently producing from less than 10% of our current discovered reserves and this year's exploration program has the potential to double these reserves and hence our long term production capability. Further, the experience gained from the drilling program and hydraulic fracturing to date will be applied in this and future developments to deliver improved production performance. We remain confident in the longer term reserve and production potential of Licenses 61 and 67."

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Reliance Hits Gas Pay Offshore India

- Reliance Hits Gas Pay Offshore India

Wednesday, June 22, 2011
Hardy O&G plc

Hardy O&G announced its first gas discovery in the exploration well KG-D9-A2 within the D9 license.

The well KGD9-A2 was drilled to a total depth of 4,881 m MDRT with the objective of exploring the play fairway in the Early and Late Miocene Channel Levee Complex in a water depth of approximately 2,700 m. Three sand reservoirs with a gross thickness of approximately 22 m were encountered and evaluated by wireline MDT. This discovery, named 'Dhirubhai - 54' has been notified to the Government of India and DGH. The potential commerciality of this discovery is being ascertained through more data gathering and analysis. This play fairway is expected to cover a considerable area within the block.

The D9 exploration license is located in the Krishna Godavari (KG) Basin on the east coast of India and presently covers an area of approximately 8,695 km2. Hardy holds a 10 percent participating interest in the license which is operated by Reliance Industries Limited. The license's minimum work program provides for the drilling of four exploration wells.

Commenting on the well results, Yogeshwar Sharma, Chief Executive Officer of Hardy said, "We are encouraged by this discovery which extends the proven Miocene play fairway into the frontier D9 block. The discovery further enhances our understanding of the block's petroleum systems and reinforces our enthusiasm for unlocking its hydrocarbon potential. The D9 joint venture expects to drill the fourth exploration well prior to the end of 2011."

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