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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BOEMRE Confirms Fatality at Platform Offshore Tx.

- BOEMRE Confirms Fatality at Platform Offshore Tx.

Wednesday, August 17, 2011
BOEMRE

The Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) has confirmed that agency personnel responded on August 16 to a report of a fatality at Energy Resource Technology's High Island (HI) Block A557 Platform A. This is an oil and gas production platform approximately 75 miles offshore Texas, in about 224 feet of water.

According to the operator's report, an incident occurred early on the morning of August 16 during a crane lift in which a large piece of equipment was being loaded from the platform to a workboat. An apparent failure of the boom hoist cable led to a collapse of the crane, which set off a series of events in which the crane's harness struck and fatally wounded an employee. There was no production ongoing at the time of the accident.

BOEMRE inspectors traveled to the platform yesterday and have begun an independent investigation into the cause of the accident.

"This was a tragic accident. Our thoughts and prayers are with the family of the deceased employee, as well as his colleagues and friends. This incident provides the most dramatic possible reminder of what is at stake as we work with industry to ensure the highest safety standards on offshore facilities and do everything possible to minimize the risk of such accidents," said BOEMRE Director Michael R. Bromwich.

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GM Confirms A123 Systems Awarded Contract For Future Batteries

- GM Confirms A123 Systems Awarded Contract For Future Batteries



Aug 11, 2011

GM (NYSE:GM) announced today that the company has awarded a production contract to A123 Systems (NASDAQ:AONE) for batteries to be used in future GM electric vehicles to be sold in global markets.

Micky Bly, an executive director at GM said, "GM is committed to offering a full line of electrified vehicles - each of which calls for different battery specifications. We work with a variety of battery developers and A123's advanced Nanophosphate lithium ion technology offers ideal performance capabilities for a future electrified vehicle application."

The specific vehicles and brands will be announced at a later date.

This contract win is being attributed as a driver of A123's stock move, with shares up about 42% so far today.

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TAG Confirms O&G Discoveries in Taranaki Basin

- TAG Confirms O&G Discoveries in Taranaki Basin

Thursday, August 11, 2011
TAG Oil Ltd.

TAG Oil reported that strong test results confirm new oil and gas discoveries in the Sidewinder-2 well and the Cheal-C1 well, both located in the Taranaki Basin, New Zealand.

Lower Mt. Messenger Oil Discovery in Sidewinder-2 Well

TAG has completed isolated flow testing on oil-and-gas-bearing zones discovered in the Sidewinder-2 well. These additional productive zones were encountered in the shallower Urenui Formation and in the lower Mt. Messenger Formation, below the main Sidewinder gas zone discovery, which tested at stabilized rates of 8.8 million cubic feet per day (~1467 BOE per day).

Of particular importance are the oil-bearing sands Sidewinder-2 discovered in the lower section of the Mt. Messenger Formation (~1800m), where the Company recovered significant volumes of light oil during recent swab testing. Technical data suggests that this oil zone can produce at rates consistent with other established Mt. Messenger oil wells in the immediate area. These oil-bearing Mt. Messenger sands are interpreted to be widespread in the Sidewinder permit area and will be a primary target in future exploration wells.

TAG will proceed to commercialize oil production from the lower Mt. Messenger zone and will acquire artificial lifting equipment that will best suit the overall Sidewinder exploration and development strategy.

Also of interest in Sidewinder-2 is the gas discovered in the shallow Urenui Formation (~1400m). The Company tested clean, dry natural gas at rates ranging from 1 to 2 million cubic feet of gas per day (167- 333 BOE's per day) utilizing various choke sizes. Production from the Urenui Formation zone can be commercialized by comingling with the main Sidewinder gas zone.

TAG CEO Garth Johnson commented, "We continue to achieve excellent exploration results which indicate that TAG has potentially discovered a large oil and gas field at Sidewinder. In addition to the prolific main gas zone discovered, there are now two significant high-impact discovery zones to pursue in this acreage. This new Mt. Messenger oil discovery will add high net-back oil production to the ~5000 BOE's of behind pipe awaiting commissioning of the Sidewinder production facilities."

The Sidewinder oil and gas discoveries are located in TAG Oil's Petroleum Exploration Permit 38748 (TAG 100%) in the Taranaki Basin, New Zealand.

Cheal-C1 Testing Confirms Oil Discovery

TAG also reports that testing of the Cheal-C1 exploration well confirms the oil and gas discovery in the Cheal "C" area. Cheal-C1 intercepted oil-and-gas-bearing sands in the Mt. Messenger Formation producing substantial volumes of light oil during swab testing along with clean, dry gas at rates between 1.5 million to 3 million cubic feet per day.

Artificial lifting equipment is now being acquired to establish daily oil production rates, however the Company estimates production capabilities from Cheal-C1 to be similar to TAG's Cheal-B4ST well. This well tested 360 barrels of oil + 240 thousand cubic feet of gas per day.

The Cheal-C1 well also encountered strong oil shows within a 73-meter-thick section of sandstone within the deeper Moki Formation. The Moki zone was tested but commercial flow rates were not achieved. TAG's technical interpretation indicates that Cheal-C1 penetrated a "transitional zone" where oil migrated through the contacted zone into a large structural closure, updip from the Cheal-C1 penetration. Given the extensive oil shows recorded while drilling coupled with the excellent reservoir quality interpreted from electric logs, TAG will plan a new well that will directly target the Moki Formation prospect, drilled from a more optimal location on the structure.

TAG CEO Garth Johnson said, "I'm pleased to achieve such positive results from the Cheal-C1 well, significantly expanding the Cheal development area. We expect to commercialize the Cheal-C1 discovery in conjunction with appraisal drilling included in our next drilling campaign, scheduled to start in September 2011."

The Cheal oil and gas discoveries are located in TAG Oil's Petroleum Mining Permit 38156 (TAG 100%) in the Taranaki Basin, New Zealand.

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Fitch Confirms NRG Rating

- Fitch Confirms NRG Rating



Aug 9, 2011

Fitch Ratings on Tuesday confirmed its noninvestment-grade "B+" overall credit rating for wholesale power company NRG Energy Inc.(NYSE:NRG).

The credit rating agency also gave its "BB+" rating to NRG's new first line facilities and affirmed its "BB" rating on the company's unsecured notes. The outlook is stable.

Fitch pointed to the diversity of NRG's power plants in terms of size, fuel location, along with its improved business risk profile, strong liquidity position and historically conservative hedging strategy, as grounds for the ratings.

Fitch said it expects NRG's credit metrics to bottom out in 2013 and for its solid liquidity profile to allow it to navigate a continued drop in commodity prices.

NRG Energy has a potential upside of 28.7% based on a current price of $21.24 and an average consensus analyst price target of $27.33.

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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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Petrobras Confirms Continuity of Accumulation in Guara Area

- Petrobras Confirms Continuity of Accumulation in Guara Area

Monday, August 01, 2011
Petrobras

Petrobras has completed drilling of the second extension well in Guará area, 3-SPS-82A (3-BRSA-923A-SPS), located in the Santos Basin pre-salt.

Informally known as Guará Sul (South Guará), the well was drilled 5.7 km south of wildcat discovery well (1-SPS-55). In a water depth of 2,156 m, Guará Sul is located 315 km off the coast of the state of São Paulo. Including the wildcat well, this is the third well in the Guará area.

Preliminary analyses confirm satisfactory conditions of the reservoir and its lateral continuity. The monitoring of pressures compared to those from the discovery well, currently undergoing Extended Well Test (EWT), verified the hydraulic communication of the reservoir between both wells. This scenario indicates a good perspective of production for this accumulation.

Cable test in the pre-salt reservoirs demonstrated the presence of light oil around 27º API. Formation tests still have to be executed to assess the reservoir's productivity.

Petrobras is the operator of the consortium for the exploration of block BM-S-09 (45%), in partnership with the BG Group (30%) and Repsol Sinopec Brasil (25%). The consortium gives continuity to the activities foreseen in the Guará Evaluation Plan.

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Petrobras Confirms Commercial Potential of Lula Well

- Petrobras Confirms Commercial Potential of Lula Well

Friday, July 08, 2011
Petrobras
by SubseaIQ

Petrobras announced that well 9-RJS-660, located in Lula field, registered the Company's highest volume of production for May, reaching an average production of 28,436 barrels of oil per day (bpd). This well is the first to produce on a commercial basis in the Santos Basin pre-salt.

This result confirms the high potential of Brazil's pre-salt reservoirs, and, if we consider oil and natural gas production, the volume reached 36,322 barrels of oil equivalent per day (boed).

The well is interconnected to FPSO Cidade de Angra dos Reis and is the first of six production wells to be connected to the FPSO. Besides this well, a gas injection well is already connected to the platform, which, since the beginning of April 2011, reinjects produced gas into the reservoir through 9-RJS-660. Two injection wells are also planned, of which one will be of water, and the other will alternate injection of water and gas.

The FPSO Cidade de Angra dos Reis is expected to be producing around 100 thousand bpd throughout 2012.

The consortium developing the production in block BMS-11, where Lula field is located, is composed of Petrobras, which is the operator, with a 65% stake, BG Group, with 25%, and Galp Energia, with 10%.

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PetroNeft Confirms 2P Reserves in Western Siberia

- PetroNeft Confirms 2P Reserves in Western Siberi

Wednesday, July 06, 2011
PetroNeft Resources plc

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

Highlights

• Kondrashevskoye No. 2 sidetrack well confirms 2P reserves
• Lineynoye 206 contains thickest oil pay encountered to date
• Lineynoye/West Lineynoye has materially thicker pay and extends significantly further north than originally anticipated
• Several new oil bearing structures are now likely to the north of Lineynoye/West Lineynoye

License 61 Exploration/Delineation program

The Kondrashevskoye No. 2 sidetrack has been drilled down dip from the Kondrashevskoye No. 2 well and penetrated the oil water contact in the objective J1-1 sandstone interval at -2,465 m true vertical depth ("TVD"). The reservoir interval of 3 meters in the sidetrack section was slightly thicker than in the vertical well with the top meter of the reservoir oil bearing.

Based on the results, the well has most likely confirmed the existing independent Ryder Scott 2P reserves of 8.1 mmbo attributed to the field and we will now update the reserves with the Russian State Reserve committee in preparation for field development. The exact timing of development will depend upon how the economics of this field compares with other nearby fields, most notably Arbuzovskoye.

Production casing has been run and cemented in the well so it can be used when the field is developed. The drilling crew is in the process of moving to the potentially high impact Sibkrayevskaya exploration prospect which will commence drilling shortly.

License 61 Development program

The Lineynoye 206 development well drilled from Pad 2 to the north contained 21.9 meters of gross sandstone with 18.5 meters of net pay which is the thickest net pay interval encountered to date in the drilling program. The reservoir interval was completely saturated with oil and confirmed an oil-down-to of -2,437.5 m TVD, some 15 meters deeper than the previously mapped structural spill point of the field to the north.

The results of this and other recent Pad 2 wells have shown that the northern part of the Lineynoye field has materially thicker pay and extends significantly further north than originally anticipated. This has positive implications for reserves and productivity in this region of the field and for the likelihood of several new structures north of Lineynoye/West Lineynoye to be oil bearing.

Dennis Francis, Chief Executive Officer of PetroNeft Resources plc, commented, "We are pleased to have proved reserves for economic development at Kondrashevskoye and will incorporate this discovery along with Arbuzovskoye in our 2012 development planning. Pad 2 drilling continues to be very encouraging with the thickest oil pay encountered yet indicating an increased probability that oil has migrated north from the Lineynoye/West Lineynoye field into the various structures contained in the undeveloped Emtorskaya High area."

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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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Lundin Confirms Avaldsnes Extension

- Lundin Confirms Avaldsnes Extension

Monday, June 27, 2011
Lundin Petroleum AB

Lundin announced that the first appraisal well, 16/3-4 has confirmed the extension of the Avaldsnes field to the south-east of the 16/2-6 discovery well in PL501 on the Norwegian Continental Shelf (NCS). The well was successfully tested and a comprehensive logging and coring program has been acquired.

Avaldsnes was confirmed as an oil discovery by the Lundin Norway operated well 16/2-6 in 2010 and is located approximately 25 km east of the Lundin Norway operated Luno discovery.

The first appraisal well 16/3-4 was drilled approximately 6.5 km south-east of the discovery well and has proved an oil column of 13,5 meters in excellent quality sandstone of Jurassic age. A high net to gross has resulted in net pay at the appraisal location in excess of that at the discovery well. The data acquired confirms excellent reservoir properties, with average porosity of approximately 30 percent and multi-Darcy permeability. The average production rate was in excess of 5,500 barrels of oil equivalent per day through a restricted choke size of 60/64 inch.

The well will now be side-tracked to confirm the lateral continuity of the reservoir towards the west.

The well will then be plugged and abandoned. The total depth of the well is 2020 meters.

Ashley Heppenstall, President & CEO of Lundin Petroleum commented, "We are very pleased with the results of the first Avaldsnes appraisal well which encountered oil bearing reservoir of thickness and quality which is better than the discovery well. We will now sidetrack the appraisal well to provide information regarding the lateral continuity of the reservoir towards the part of the structure we had assumed in our previous resource estimates was non- hydrocarbon bearing. We will update our Avaldsnes resource estimates following the sidetrack and second appraisal well."

Lundin Norway is using the semi submersible drilling rig Bredford Dolphin to drill the well. The rig will start drilling the second appraisal well on Avaldsnes, 16/2-7, immediately after 16/3-4.

Lundin Norway is the operator with 40 percent interest. Partners are Statoil Petroleum AS with 40 percent interest and Maersk Oil Norway AS with 20 percent interest.

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Shoal Point Confirms Oil in Green Point Shales

- Shoal Point Confirms Oil in Green Point Shales

Tuesday, June 21, 2011
Shoal Point Energy Ltd.

Shoal Point has received the preliminary results of a petrophysical analysis from NuTech Energy Alliance Ltd ("NuTech") for the 3K-39 well in the Green Point Shales in the near offshore Newfoundland which has confirmed a thick section of producible unconventional light oil.

Significant hydrocarbon shows were encountered over a gross interval between the surface casing shoe at 400 meters measured depth and current drilled depth of 1745 meters.

The analysis of the 3K-39 logs reflects NuTech's previous analyses of unconventional potential in the Green Point Shales from the Shoal Point 2K-39 and Long Point M16 wells. It shows a similar thick section of hydrocarbon pay and, for the first time, have enabled interpretation of an abundance of fractures throughout the borehole.

This analysis will be updated once studies on core collected in the well are complete and assimilated. Approximately 26 meters of core is being shipped to Houston for 3D image analysis, which will provide valuable information on porosity, permeability and hydrocarbon saturations, as well as images of the internal geometry of fractures. Other core-based studies including rock properties, pyrolysis, and porosity-permeability are being concluded and incorporated in the data set.

A series of open-hole tests are being conducted, prior to completion and stimulation to assess the natural producibility of the formation; these tests are warranted by the high proportion of naturally fractured rock, (seen in core and the NuTech log analysis), the possibility of zones of naturally occurring ("conventional") porosity and permeability and of the presence of oil shows throughout the borehole. These shows include (1) gas chromatography, indicating the presence of liquids over roughly 70% of the drilled section, (2) blue-white fluorescence (indicating light oil) in drill cuttings and cores, particularly after application of a solvent, and (3) mobile, visible oil in fractured core.

Operations have been made difficult by the tectonized and fractured nature of the reservoir and therefore considerable effort and time has gone into keeping the borehole open and in good condition for coring, logging and testing, which has been the principal cause for the delay in operations to date. However, this is a positive sign for the potential producibility of the resource.

The company now expects to proceed to running casing within a number of days and to retain the well for future re-entry and re-completion as a potential producing well.

George Langdon, President of Shoal Point, commented, "Like any first well in a new basin or new play, the operation has met with challenges related to the nature of the rocks. However, the really good news is that, along with very thick matrix pay sections identified now in several wells by our petrophysical specialists, we are seeing a new and important element - pervasive natural fracturing, recognized on various scales - from very fine "spider-web" geometry, all the way up to large scale faults and fractures seen in the field. This fracturing should provide a natural permeability network to complement the artificial stimulation of the formation, which like all resource plays, will be an important part of its development. Operations are continuing on the well to maximize data recovery, and it is expected that the well will be completed shortly."

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Credo Confirms New Oil Field in Kansas, Updates Ops

- Credo Confirms New Oil Field in Kansas, Updates Ops

Tuesday, June 14, 2011
Credo Petroleum Corp.

Credo, with significant assets in the North Dakota Bakken, Kansas, Nebraska, the Texas Panhandle and Oklahoma, provided an operations update.

Marlis E. Smith, Jr., Chief Executive Officer, stated, "Our oil focused growth strategy is firmly on course with our horizontal drilling in the North Dakota Bakken and Texas Panhandle, combined with our shallow drilling plays in Kansas and Nebraska. Credo is adding high value oil production from new drilling as oil continues to command a three to one price advantage over natural gas.

"This press release updates our oil drilling operations, and highlights what we believe is a new field discovery in Kansas where Credo owns 47%. Based on our statistical success rates in Kansas and Nebraska, Credo is retaining increasingly larger interests in both drilling plays. In Kansas, most of our recent wells were drilled with interests averaging around 50%, and we are drilling with interests ranging from 50% to 70% in Nebraska. Our objective is to make each new discovery more meaningful to Credo through larger ownership interests."

Excellent Drilling Success Continues in Kansas

The Company has just added three new producing wells, two of which are higher-ownership wells, in its Kansas shallow oil play. The new wells bring the total number of company wells drilled in the play to 79, of which about 40% have been completed as producers.

The Company has recently completed its first confirmation well to a new field discovery in Kansas. Seismic analysis indicates that the new field may ultimately contain four to six wells in the Lansing Kansas City formation. The 4,100 foot well was swabbed during completion operations and tested at the rate of 240 BOPD (barrels of oil per day). A pumping unit is being installed. The Company expects that, on pump, the well will initially produce about one-half its swab rate. Additional development drilling is scheduled for this summer. The Company owns a 46.5% working interest.

The Company has also completed two other new producers in Kansas. One of the wells initially tested at 50 BOPD from the Lansing Kansas City formation. Credo owns a 75% working interest and is the operator. The seismic survey is currently being evaluated for offset drilling potential. The second new well was also initially tested at 50 BOPD from the Lansing Kansas City formation. The Company owns a 12.5% interest in the well.

Nebraska Drilling Program Off to a Strong Start

In southwestern Nebraska, the Company has completed three of its first five wells for a 60% success rate. The Company owns a 70% interest in all of the wells and is the operator.

The Nebraska drilling play is an extension of the Company's Central Kansas Uplift drilling play. To date, Credo has assembled approximately 35,000 net acres in southwestern Nebraska. A significant inventory of drilling prospects has already been generated and assembled utilizing a combination of detailed subsurface geology and advanced 3-D seismic technology to identify highly economic shallow oil targets. The Company is continuing to aggressively generate and lease additional prospects. Drilling commenced in the second quarter of 2011 and targets the Lansing Kansas City formation at about 4,000 feet. The Company has retained between a 50% and 70% working interest in the play in order to participate significantly in what it believes will be a very successful project.

Texas Panhandle Horizontal Oil Production Continues to Increase

In the Texas Panhandle, the Company owns an average 33% working interest in about 3,000 gross acres. As previously reported, the Company's first horizontal well was drilled to a vertical depth of 7,600 feet and has an approximate 4,000-foot horizontal lateral. The well is producing oil from the Tonkawa formation, and Credo owns a 22% working interest. Fracture stimulation fluids are continuing to be recovered. The well is currently producing approximately 180 barrels of oil equivalent per day (BOEPD) and has produced approximately 22,500 barrels of oil equivalent (BOE) in six months.

Also as previously reported, the Company's second horizontal Tonkawa well was also drilled to a vertical depth of 7,600 feet and encountered sloughing shale about 2,400 feet into the projected 4,000-foot lateral. Because the well had previously encountered good quality sand and very good shows, the decision was made to cease drilling operations at about 2,400 feet and set pipe. The well was hydraulically fractured and, is recovering frac fluid with a steadily increasing oil cut. Currently the well is producing approximately 100 BOEPD and has produced approximately 4,500 BOE in two months. Credo is the operator and owns a 32% working interest.

North Dakota Bakken Drilling Expected to Escalate in the Second Half

Credo has leased approximately 8,000 gross (6,000 net) acres on the Ft. Berthold Reservation containing about 50 initial drillable spacing units, however, it is expected that more than one well will be drilled on many spacing units. The Company's interests range up to 51% depending on the size of the spacing unit. The Company's acreage is generally located south and west of Parshall Field and is in the vicinity of considerable Bakken drilling and development activity. The Reservation has become a "hot spot" in the play and drilling activity is rapidly escalating.

The Company has drilled and completed a total of seven Bakken producers on its acreage. All of the wells are high rate producers. Credo expects to drill at least nine additional Bakken wells during 2011. The Company's interest in six of the nine additional wells will range from 12% to 20%.

As previously reported, the Company has added four horizontal Bakken wells on the Ft. Berthold Reservation. While Credo's working interests in the wells are small, ranging from 1% to 3%, the Company's share of initial production from the four wells is approximately 140 BOEPD. One of these wells, the Enerplus Ethan Hall, reported an initial production rate of 3,732 BOEPD, which is the highest initial rate of any Credo Bakken well drilled to date and ranks among the highest rates in the play.

"Credo intentionally chose not to operate wells in the Bakken play due to the drilling volume required to assure timely field services and favorable contracts," Smith said. "The downside of not being the operator is that we do not have substantial control over when wells are drilled. Nevertheless, we believe that the advantages to Credo of participating with larger operators far outweigh the disadvantages. Some operators have told us they are experiencing drilling delays due to a harsh winter in North Dakota followed by extremely wet spring conditions."

Calliope Activity on the Increase

Credo remains committed to monetizing its patented Calliope Gas Recovery System. During March 2011, Calliope was successfully installed on the Carmella State well located in Harper County, Oklahoma. Calliope has eliminated downtime due to liquid loading, and increased production to a steady rate of 150 thousand cubic feet per day (Mcfd). Credo is the operator of the well and owns an 85% working interest. Final paperwork is currently in progress to purchase another well for Calliope, and the Company is actively pursuing other acquisition opportunities. Calliope also continues to generate interest from new players with fresh ideas as rapidly growing international companies seek innovative solutions to capture energy reserves.

MANAGEMENT COMMENT

"The new oil producers highlighted in this press release are excellent examples of the Company's ability to discover and develop oil reserves at very moderate costs. One of the benefits of an active drilling program is that an occasional 'bell-ringer' comes in. Not only will the volume of oil from the high-rate, high-ownership Kansas wells be impactful to Credo, it adds even more value by setting up offset drilling opportunities.

"I am also pleased that we are again making some real progress on our Calliope Gas Recovery System. We have dedicated new resources to generating Calliope activity which are beginning to pay off.

"We are looking forward to a very active second-half of the year with our aggressive oil drilling in Kansas and Nebraska, combined with our horizontal oil drilling in the North Dakota Bakken and the Texas Panhandle. Credo's drilling schedule should be especially active in the North Dakota Bakken, where we expect to drill at least nine new Bakken wells with working interests ranging from 12% to 20%."

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Ithaca Confirms Reserves at Cook Field

- Ithaca Confirms Reserves at Cook Field

Monday, May 16, 2011
Ithaca Energy Inc.

Ithaca announced that further to the announcement of the Sale and Purchase Agreement ("SPA") with Hess:

• The Company has been informed that Hess has received an exercising notice in relation to the existing Maclure field coventurers' rights to pre-empt the Maclure part of the Transaction
• Sproule has completed its Reserves Audit Opinion on the Cook field and considers Management's view of combined remaining Proved plus Probable ("2P") reserves of 5.75 million barrels of oil equivalent ("mmboe") net to Ithaca as at January 1, 2011 to be reasonable
• Adjusted consideration of US $62.5 million and the transfer from Ithaca to Hess of a 10% interest in three Southern North Sea exploration blocks

As announced on April 4, 2011, Ithaca entered into the SPA to acquire interests in the Cook oil field ("Cook") and Maclure oil field from Hess and to transfer certain blocks to Hess. Subject to completed documentation being executed by Hess and any pre-empting parties, the interest in the Maclure field will be removed from the Transaction and the consideration will be adjusted accordingly such that Ithaca shall acquire a 28.46% non-operated interest in only Cook from Hess. The effective date of the Transaction remains January 1, 2011.

The Company commissioned Sproule to undertake an independent audit of Management's estimate of remaining oil and gas reserves in the Cook field. Management estimate that the acquisition of the Cook interest will increase the Company's remaining 2P net reserves by 5.75 mmboe from 46.05 to 51.80 mmboe and this estimate has been considered reasonable by the findings of the audit. The audit was performed in accordance with the Canadian Oil and Gas Evaluation Handbook ("COGEH") reserves definitions and evaluation practices and procedures as specified by National Instrument 51-101 ("NI 51-101").

Based on 5.75 mmboe of 2P reserves remaining in Cook, the acquisition is priced at 10.87 USD per boe. Management anticipates that average production from Cook for 2011 to be approximately 1,900 boepd net to Ithaca.

The Transaction is anticipated to complete in 3Q 2011 and is subject to DECC and co-venturer approvals. At completion, the consideration will be subject to normal industry adjustments to reflect the income and costs incurred since the effective date.

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Petroamerica Confirms Significance of Balay-2 Well

Petroamerica Confirms Significance of Balay-2 Well

Monday, May 09, 2011
Petroamerica Oil Corp.

Petroamerica Oil Corp. is pleased to announce that the Balay-2 ST1 appraisal well flowed from two perforated intervals in the Upper Mirador, 2,620 barrels of 26 degree API oil per day with 9.3% bulk sediment and water ("BS&W") that is probably mainly completion fluid, under electro-submersible pump. The Balay-2 ST1 well also defined a deeper oil-down-to in the Upper Mirador reservoir. Additionally, 145 barrels of heavy oil (13 degree API, waiting on laboratory confirmation) and water (10-16% BS&W) was recovered from the Barco Formation. No hydrocarbons were recovered from tests carried out in the Une and Gacheta reservoirs.

Nelson Navarrete, President and CEO, commented on the Balay-2 ST1 drilling result, "this is significant in terms of proving up recoverable oil volumes in the Balay structure, and more importantly, moving the project one step closer towards a commercial development."

The Balay discovery was announced on March 11, 2010 and the Balay-1 discovery well has been on long-term production test since July 14, 2010, producing more than 285,000 barrels of 28 degree API oil from the Upper Mirador Formation, with no measurable water (0.22% BS&W). The forward plan is to put the Balay-2 ST1 well on long-term test together with the Balay-1 well. A third well, Balay-3, is planned for the fourth quarter 2011 to appraise the northern extent of the Balay discovery.

Petroamerica Oil Corp., through its wholly owned subsidiary, Petroamerica International Corp., holds a 15% participating interest in the Balay block for which it received its approval from the ANH (Colombian National Hydrocarbon Agency) earlier this year. Petrobras is the operator with a 45% participating interest and the other partners are CEPSA COLOMBIA S.A. and Sorgenia, each holding a 30% and 10% participating interest, respectively.

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Total Confirms Gas Discovery in Bolivia

Total Confirms Gas Discovery in Bolivia

Wednesday, April 27, 2011
Dow Jones Newswires
by Geraldine Amiel

French oil major Total Wednesday confirmed it made a new gas discovery in Bolivia but declined to give further detail about the discovery and its potential.

Earlier Thursday, Bolivia's state news agency ABI reported that Total and Argentina's Tecpetrol, a unit of the Techint group, had struck gas in the Bolivian lowlands.

ABI also said that Bolivian president Evo Morales is slated to announce the results later Wednesday at an event to celebrate the find at the Aquio block in Santa Cruz province.

The companies have invested $70 million over the past 16 months to drill to a depth of 6,300 meters in search of the fuel, according to ABI.

Production capacity at the Aquio and Ipati blocs is currently estimated at 6.5 million cubic meters a day, which is likely to be doubled or to even reach 18 million cubic meters a day, also according to ABI.

Petrobras Confirms High Productivity in Guara

Petrobras Confirms High Productivity in Guara

Tuesday, April 12, 2011
Petrobras

Petrobras has completed the formation test in the first extension well of Guará confirming the accumulation's high productivity estimates, located in ultra deep waters, in the Santos Basin pre-salt.

During the test in well 3-SPS-69 (3-BRSA-788), located in block BM-S-9, flow rates of approximately 6 thousand barrels per day of good quality oil (30º API) were confirmed, limited to the capacity of the equipment used. Initial production potential is approximately 50 thousand barrels of oil per day.

Also referred to as Guará Norte, the well is located at a water depth of 2,118 meters, about 305 kilometers off the coast of the State of São Paulo, 15 kilometers northeast of 1-SPS-55 (Guará discovery well).

The formation test of discovery well 1-SPS-55, executed earlier, had already showed similar numbers to the results of Guará Norte well, demonstrating excellent quality of the reservoirs.

At the moment the second extension well, Guará Sul (3-SPS-82A), about 7 kilometers south of the Guará discovery well is being drilled.

The consortium, formed by Petrobras (45% - operator), BG Group (30%) and Repsol Sinopec Brasil (25%), will give continuity to the activities and investments necessary to assess the deposits discovered in this area, as per the Evaluation Plan approved by the National Petroleum, Natural Gas and Biofuels Agency (ANP).

FAR Confirms Kora Drilling Agreement with Ophir

FAR Confirms Kora Drilling Agreement with Ophir

Friday, March 25, 2011
FAR

FAR announced that Detailed Agreements have now been finalized with Ophir confirming the terms of an earlier Heads of Agreement to participate in the drilling of the Kora Prospect via the acquisition of a 10 percent paying interest (8.8% beneficial interest) in the AGC Profond PSC, offshore Senegal and Guinea Bissau. Regulatory approval has been granted by the AGC Joint Authority. The agreements also allow Ophir the right to acquire a 22.5% beneficial interest in FAR's Senegal licences.

The Kora well is targeting a prospect having mean prospective oil resources of 448 million barrels (100% basis, Rocksource estimate). The well will be operated by Ophir using the semi-submersible rig Maersk Deliverer and is expected to spud around 11 April 2011 and take in the order of 24 days. The expected spud date may vary depending upon the timing of release by an existing contractor in Ghana from where the rig will mobilize to the AGC area.

The well location is 285km south west of the port of Dakar in a water depth of 2651m. The planned minimum Total Depth for the Kora well is 4,251mSS (approx. 1,600m below the mudline) although consideration will be given to drilling deeper based on the geology encountered.