Oilex Makes Progress at Cambay Well

- Oilex Makes Progress at Cambay Well

Wednesday, June 22, 2011
Oilex Ltd.

Oilex advised that the Cambay-76H horizontal well was directionally drilled as planned to casing point at 1,595 meters.

• Report date: June 21, 2011
• Status: Preparing to drill 8 ½" hole
• Past Week's Operations: 
  • Drilled 12 ¼" hole from 601 meters to 1,595 meters
  • Set 9 ⅝" casing to 1,594 meters
  • Tested BOP
• Objectives: Cambay Eocene "tight" reservoir Y Zone
• Kick off point for deviation: Approximately 1,100 meters
• Planned Total Depth (TD): Approximately 2,885 meters
• Days to TD: Approximately 35 days on a trouble free basis

Cambay Eocene Tight Reservoirs

The Company is making progress in unlocking the potential of the Cambay "tight" Eocene reservoirs that extend across the 161 km2 Cambay Production Sharing Contract ("PSC") area in onshore Gujarat, India. The Company intends to evaluate and exploit these reservoirs using horizontal drilling and fracture stimulation technology that has been developed and proven in North America.

The Cambay-76H "proof of concept" horizontal well will evaluate the production potential of the Y Zone interval of these "tight" reservoirs. An 8 stage fracture stimulation program will be conducted and after well clean-up, it is anticipated that a long term production test will be performed to determine flow rates, quality of hydrocarbons and commercial viability.

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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Apache Boosts 1Q Production by 25%

Apache Boosts 1Q Production by 25%

Thursday, April 28, 2011
Apache Corp.

Apache reported production of 732,000 barrels of oil equivalent (boe) per day and earnings of $1.1 billion, or $2.86 per diluted share, for the three-month period ending March 31, 2011. These compare with production of 586,000 boe per day and net income of $705 million, or $2.08 per diluted share, for the same period in the prior year.

"Apache is beginning the year with a solid, strong performance," said G. Steven Farris, chairman and chief executive officer. "Despite a number of challenges, our diversified portfolio of assets delivered exceptional earnings and operating results. Liquids production increased 57,000 barrels to 358,000 barrels per day, which enabled Apache to achieve stand-out earnings and cash flow as a leading beneficiary of rising oil prices."

Higher oil prices and production from new wells drilled during the quarter and assets acquired during 2010 combined to increase revenues to $3.9 billion, up from $2.7 billion last year. Cash from operations before changes in operating assets and liabilities* increased 43 percent from the prior year to $2.2 billion. Excluding certain items that management believes affect the comparability of operating results, Apache reported adjusted earnings* of $1.1 billion in first quarter 2011 compared with $712 million in the year-earlier period. On a per-share basis, adjusted earnings were $2.90 in the first quarter compared with $2.10 per diluted share in the prior-year period.

Liquid hydrocarbons represented 49 percent of production and 77 percent of revenues. Approximately 60 percent of the company's oil production came from operations outside North America and received in excess of a $10 premium per barrel compared with domestic production benchmarked to West Texas Intermediate prices.

On the operational front, the company achieved several milestones. These include:

• Apache's most prolific development well in the Forties field (North Sea), which came online at approximately 11,800 barrels of oil per day.
• In the Permian Basin, Apache is operating 24 rigs, up nearly five-fold from a year ago. Targeting primarily oil objectives, Apache drilled 110 wells including 15 horizontals during the first quarter.
• Since drilling the first-ever horizontal Hogshooter well last year, Apache has drilled six wells into this oil-rich segment of the Anadarko basin's Granite Wash formation. To date, every well has tested in excess of 1,000 barrels of oil and 2 million cubic feet of gas per day.
• The company's first operated deepwater production in the Gulf of Mexico with start-up at the Balboa field.
• Offshore Australia, Apache's Zola discovery well encountered 410 feet of net gas pay.
• In Egypt, Apache operated 22 rigs during the quarter, drilling 33 wells, including the company's first wells in the Tayim development lease in West Kalabsha producing from deeper Paleozoic pay. Apache's production remained online throughout the quarter, increasing sequentially from the previous three months.

"We continue to strengthen our land position, both in North America and internationally. Our LNG initiatives, Kitimat in Canada and Wheatstone in Australia, are steadily progressing toward project sanction with their respective joint venture partnerships," Farris said.

"Apache's opportunity set has never been more robust. We have a deep backlog of exploitation opportunities across our portfolio. In addition to our legacy plays in core areas, we have other potentially large-scale, long-life assets such as deepwater, LNG, and unconventional plays that can provide lasting, long-term value to our shareholders."

Range Boosts Production in 1Q 2011

Range Boosts Production in 1Q 2011

Tuesday, April 19, 2011
Range Resources Corp.

Range provided an operations update. First quarter production volumes averaged 545.5 Mmcfe net per day, a 17% increase over the prior-year period and 1% higher than fourth quarter 2010. The record production marked the Company's 33rd consecutive quarter of sequential production growth. Production was 79% natural gas, 16% natural gas liquids (NGLs) and 5% crude oil. Targeted drilling to the liquids-rich portion of the Marcellus Shale play in Pennsylvania and the Midcontinent regions drove the production growth. First quarter 2011 production was 16% NGLs versus 12% for first quarter of 2010.

The Company also announced that its preliminary first quarter 2011 commodity price realizations (including the impact of cash-settled hedges and derivative settlements which would correspond to analysts' estimates) averaged $5.46 per mcfe. This represents a 2% decrease from the prior-year period, but a 2% increase as compared to the fourth quarter 2010. Preliminary first quarter production and realized prices by each commodity are: natural gas – 429.9 Mmcfe per day ($4.40), natural gas liquids – 14,338 barrels per day ($47.96) and crude oil – 4,924 barrels per day ($81.35).

Commenting on the announcement, John Pinkerton, Range's Chairman and CEO, said, "Despite the unusually cold weather conditions we incurred in the first quarter, we were able to reach the mid-point of our production guidance. Adjusting for the weather related downtime, we would have exceeded the high end of our guidance. Our operating teams did an outstanding job battling some of the most brutal weather conditions we have experienced in many years. Looking ahead, due to the terrific drilling results so far this year, combined with the progress of the infrastructure projects, we are well on track to reach our production growth target for the year. In addition, the Barnett sale is on schedule to close at the end of the month."

Marcellus Shale Division

We exited the first quarter at approximately 260 Mmcfe per day net from the Marcellus Shale, up from approximately 200 Mmcfe per day at year-end 2010. During the first quarter, the Marcellus Division brought online 26 horizontal wells in southwest Pennsylvania, 15 of which were located in the liquids-rich area of the play. The initial production rates of the 15 new wells averaged 7.4 (6.3 net) Mmcf per day of natural gas and 452 (384 net) barrels of NGLs and condensate per day or 10.1 (8.6 net) Mmcfe per day. An additional 16 wells were completed in southwest Pennsylvania during the first quarter that are awaiting connection to the gathering system. In northeast Pennsylvania, Range brought on its first five wells in Lycoming County at a combined initial production rate of 45 (39 net) Mmcf per day in mid-February.

Due to the outstanding performance of its existing wells combined with the initial performance of the newly connected wells, Range's Marcellus production has temporarily outgrown the existing infrastructure. In southwestern Pennsylvania, the third expansion of the gas processing facilities has been completed and is in the testing phase. This 200 Mmcf per day of additional processing capacity is expected to commence operation in May. With this expansion, Range's total processing capacity will expand to 350 Mmcf per day. Later in the third quarter, Range's processing capacity is scheduled to increase again to 390 Mmcf per day. In northeast Pennsylvania, the next expansion of the Lycoming County gathering system is scheduled to be completed late in the third quarter which will tie in an additional 20 wells.

Range has entered into two memorandums of understanding exploring options to sell ethane from the liquids-rich area in southwest Pennsylvania. Range plans to complete firm ethane sales agreements in the next 12 months covering a significant portion of its projected ethane production.

Midcontinent Division

First quarter activity for the Midcontinent Division focused on drilling operations in several key areas. One rig remains active in the Texas Panhandle, where two Granite Wash wells and one vertical St. Louis exploratory well are undergoing completion. Range's original horizontal St. Louis Lime well continues to perform above expectations. After 12 weeks of production, the well has produced more than 1.0 Bcfe with current rates still at 13.0 Mmcf of natural gas and over 900 barrels of liquids per day or 18.4 (5.6 net) Mmcfe per day. Activity in the Ardmore Basin Woodford play continues with four wells in various stages of completion. Production from these liquids-rich completions is expected to reach sales by the end of the second quarter. One operated rig is currently running in the play, along with additional non-operated activity. Drilling also continues in the Mississippian Lime play of northern Oklahoma with one operated rig and one non-operated rig in the Woodford "Cana" Shale play of the Anadarko Basin.

Appalachian Division

During the first quarter of 2011, the Appalachian Division continued to focus on tight gas sand and coal bed methane (CBM) drilling projects on its 350,000 (235,000 net) acres in Virginia. All of this acreage is either owned or held by production allowing for discretionary drilling with no lease expiration issues. In 2011, Range plans 50 tight gas sand wells, 15 CBM wells and 15 horizontal wells targeting the Huron Shale, Berea and Big Lime formations in Virginia. For the first quarter, the division drilled 5 (4.5 net) vertical tight gas sand wells and one CBM well in the Nora field. Also in the quarter, Range performed 8 recompletions of behind-pipe pays to continue to maximize production on existing wells.

Southwest Division

In the first quarter the Southwest Division drilled its first Penn Shale well in the Conger Field of West Texas where Range has approximately 91,000 net acres. The well has a lateral length of 4,000 feet and will be completed with a multi-stage fracture treatment later in the second quarter.

Buccaneer Spuds 1st Alaskan Well

Buccaneer Spuds 1st Alaskan Well

Monday, April 18, 2011
Buccaneer Energy Ltd.

Buccaneer announced the Kenai Loop # 1 well spud on Friday, April 15, 2011. This is a milestone for the Company as it is the first well drilled by the Company in Alaska and comes just over 12 months since the initial acquisition of leases in Alaska was finalized.

At 8:00 AM Monday, April 18, drilling operations for the well had been successful in reaching 3075 feet, the designed surface casing point, preparations are being made to log this surface interval. On completion of logging surface casing will be set before commencement of drilling the next interval.

The next interval includes the Beluga Formation, one of several target objectives for the well. The Total Depth (TD) of the Kenai Loop # 1 well is 10,500 feet. The well is currently on schedule and expected to take approximately another 20 days to reach TD.

Salamander Sees Gas Shows at Thai Well

Salamander Sees Gas Shows at Thai Well

Friday, April 15, 2011
Salamander Energy plc

Salamander provided the following update on its Thai drilling operations in Block L15/50, onshore Northeast Thailand, and Block B8/38, Gulf of Thailand.

Dao Ruang-2 well, Block L15/50

Dao Ruang-2 ("DR-2") drilling operations at the Dao Ruang-2 location have been completed. Following an openhole drill stem test ("DST") the well failed to flow at a sustained commercial rate and is in the process of being temporarily suspended for potential re-entry at a later date. Drilling now moves to the second location of the two well program, as originally planned, targeting an independent fault network in the structure.

The DR-2 well was drilled to a depth of 2,212 meters true vertical depth sub-sea ("m TVDSS") into the eastern flank of the Dao Ruang structure, targeting a swarm of faults and fractures identified from high resolution 3D seismic. The well intersected a number of fracture zones with associated gas shows and experienced gas influx associated with a fault system around 1,840 m TVDSS. Gas shows were seen all the way to TD, with no sign of water, demonstrating a significant gas column in the Dao Ruang structure.

An openhole DST was undertaken across an interval between 1,008 - 2,211 m TVDSS. The section was tested following an acid wash, however only sub-commercial flow rates were recorded, indicating very low permeability formation and a limited open, connected fracture network at the DR-2 location.

The MB Century 26 rig will now be mobilized to the Dao Ruang-3 ("DR-3") drilling location. The DR-3 well will target a separate fracture set on the northern flank of the Dao Ruang structure with a different orientation to those seen in DR-2, providing a greater chance of encountering an open fracture network and an opportunity to test at a commercial flow rate.

The DR-3 well will be drilled to a planned depth of 1,900 m TVDSS and is expected to spud within the next 8 days. The well is forecast to take 45 days to drill on a dry hole basis.

Salamander has a 50% interest in, and is operator of, Block L15/50.

James Menzies, Chief Executive Officer of Salamander Energy, said, "While it is disappointing that we did not encounter commercial gas at our first Dao Ruang location, it is clear from drilling that there is a significant gas column in the structure. The two well program was originally designed to target two independent fault networks in different orientations, and we expect to spud the second well in a matter of days."

Circle Oil Hits Gas Pay in Morocco

Circle Oil Hits Gas Pay in Morocco

Friday, April 15, 2011
Circle Oil plc

Circle Oil announced that the KSR-11 exploration well has been drilled, logged and successfully tested in the Sebou Permit, Rharb Basin, Morocco.

The Company confirms a gas discovery in the Main Intra Hoot target and secondary targets available for future testing in the Mid and Base Guebbas sands. The well tested gas at a sustained rate of 4.0 mmscf/d on a 16/64" choke from the Intra Hoot. The perforated Intra Hoot zone of 17.9 meters at 1,761.2-1,779.1 meters MD has a calculated net gas pay of 11.6 meters.

The Base Guebbas zone of 37.7 meters at 1,636.0-1,673.7 meters MD has a calculated net gas pay of 5.5 meters. The Mid Guebbas zone of 22.8 meters at 1,464.1-1,486.9 meters MD has a calculated net gas pay of 4.1 meters. The Guebbas Zones will be tested at a later date following production and depletion of the Intra Hoot producing zone.

The well is being completed as a potential producer.

A full technical evaluation of all the results of the well is underway. This will allow for future planning as a precursor to further assessment of the resource, including conducting an extended well test to give a more complete estimation of the reserves.

The drilling rig is now being demobilized to end the 2010-2011 drilling campaign. Work is underway for consolidation of the results of this campaign together with planning for the next drilling campaign. The preparations for Circle's third Moroccan drilling campaign include the acquisition of a new 3D seismic survey over areas of Circle's permits not previously covered by 3D seismic.

In parallel, recent engineering testing of underground crossings of public transport infrastructure have been successfully completed as part of the construction preparation for the new 8-inch pipeline. Work on the pipeline is progressing in line with management's expectations.

The Sebou permit lies to the north-east of Rabat in the Rharb Basin in Morocco. The Rharb Basin is a foredeep basin located in the external zone of the Rif Folded belt. The concession agreement, in which Circle has a 75% share and ONHYM, the Moroccan State oil company, has a 25% share, includes the right of conversion to a production license of 25 years, plus extensions in the event of commercial discoveries.

Prof. Chris Green, CEO, said, "I am very pleased to be able to report that we have yet again continued our drilling success in Morocco's Rharb Basin. The KSR-11 well has been completed and, when required, will be available for future production. We tested this well at a small restricted choke size and it still achieved a good flow rate with very quick pressure build up. The second drilling campaign has been very successful and we have increased our ability to both supply gas and incrementally increase our resources in line with the business plan for the area. Everyone has worked hard to achieve this result and it is definitely appropriate to thank staff and our service companies for their efforts and also to thank ONHYM for their continuing support to our endeavors."

Major Gas Find at Apache's Zola Well

Major Gas Find at Apache's Zola Well

Thursday, April 14, 2011
OMV

OMV announced Apache has discovered gas on the North West Shelf of Australia in the Zola-1 exploration well. This represents one of the largest gas discoveries by the company. Zola-1 is located in the WA-290-P exploration permit and is around 100 km from the Western Australian coast. The discovery well Zola-1 and the subsequently drilled sidetrack appraisal well Zola-1/ST-1 have confirmed the existence of sandstone layers with 130 m of net gas pay in an area south of the giant Gorgon gas field. New 3D seismic data will be acquired to further assess the potential of the discovery.

The sidetrack appraisal well to the original Zola-1 discovery well was drilled down to a total depth of 4,713 m (true vertical depth). An extensive wireline measurement and pressure testing program confirmed the presence of gas within several high quality sands of the target Triassic Mungaroo Formation. The well and sidetrack were drilled in a water depth of 285 m and encountered 130 m of net gas pay. Both will be plugged and abandoned as per plan.

In order to further assess the development potential of Zola, OMV and its partners in WA-290-P, Apache (operator), Santos, Nippon Oil Exploration and Tap Oil, have agreed to acquire a new high resolution 3D seismic survey over the permit, which is likely to commence mid 2011.

Jaap Huijskes, member of the OMV Executive Board responsible for Exploration and Production (E&P), stated, "Zola-1 is one of OMV's biggest gas discoveries and is the result of a successful and safely carried out exploration and appraisal drilling campaign. We are very
proud of OMV's exploration activities in Australia, which have culminated in this significant discovery on the North West Shelf. The next step will be to further appraise the gas discovery, including the acquisition of a new 3D seismic survey."
Balanced international E&P portfolio

In 2010, OMV's oil and gas production was 318,000 boe/d and its proven reserves were about 1.15 bn boe at year-end. In its core countries in Romania and Austria, OMV is focusing on reducing the natural decline and on enhancing the recovery rates from mature fields. Future growth is expected to come via new field developments, exploration and acquisitions internationally. OMV intends to grow the existing portfolio to and beyond critical mass, on a production per country basis, and is looking to find new growth areas within the Caspian, Middle East and North Africa regions where OMV can leverage on its existing E&P exposure.

WA-290-P Joint Venture

* OMV Australia: 20%
* Apache (operator): 30.25%
* Santos: 24.75%
* Nippon Oil Exploration: 15%
* Tap Oil: 10%

Statoil Strikes Oil Offshore Brazil

Statoil Strikes Oil Offshore Brazil

Thursday, April 14, 2011
Statoil

A new oil find has been made by Statoil immediately adjacent the Peregrino field in the Campos Basin offshore Brazil.

An exploration well drilled in the Peregrino South structure a few kilometers south of Peregrino has encountered oil in sandstones of the Carapebus geological formation.

A significant gross oil column of 130 meters has been proven in the well and further work will be performed to confirm the volumes.

The drilling operation is still ongoing to penetrate deeper reservoir units and explore additional upside potential below the main reservoir unit.
Significant upside

"The results confirm the significant potential in the Peregrino area and underline the beliefs we have had in the upside,” said Tim Dodson, executive vice president for Exploration in Statoil.

"The well verifies the upside potential and will together with the Peregrino Southwest discovery from 2007 play an important role in further development of the Peregrino area."

"The results will indeed be implemented into our plans for further development of the field," said Kjetil Hove, head of Statoil's Brazil activities and vice president in the company's Development and Production International business area.

Following the completion of the Peregrino South well, one additional appraisal well in the Peregrino Southwest structure will be drilled to conclude the overall size of the new development.
Peregrino start-up

Oil production from the Peregrino field started last week and will gradually ramp up to a plateau of 100,000 barrels of oil equivalent per day, making Statoil an important long-term operator and partner in Brazil's growing oil and gas industry.

The initial development of the field is estimated to contain 300 to 600 recoverable million barrels of oil equivalents, and the new discovery will add additional volumes going forward.

Drilling of the well is being carried out by the Blackford Dolphin rig at a water depth of 120 meters.

Operated by Statoil, the Peregrino field is 85 kilometers off the Brazilian coast from Rio de Janeiro. In May 2010 Statoil sold a 40% stake of the Peregrino field to the Sinochem Group. Statoil holds 60% ownership and the operatorship of the field and Sinochem the remaining 40%. The closing of the transaction is pending governmental approvals.

Mainland Locates Multiple Pay Zones at Burkley-Phillips Well

Mainland Locates Multiple Pay Zones at Burkley-Phillips Well

Wednesday, April 13, 2011
Mainland Resources Inc.

Mainland reported that further review and analysis of the Core results and Log data for the Burkley-Phillips #1 well indicates that the well hosts multiple potential pay zones including the Bossier Shale, Knowles Lime, Cotton Valley and Haynesville shale intercepts, and in addition has the potential for oil within the Tuscaloosa sandstones.

Mike Newport, President of Mainland Resources stated, "This new data is vitally important to Mainland as we design the production plan at Buena Vista. For instance, this new data revealing what we know as the Deep Bossier Shale is very important as it demonstrates the Burkley-Phillips has a strong potential to be an economically viable project for us."

"Deep Bossier Shales generally have high production rates, so that we can expect greater longevity in the wells that have strong potential for production from other zones, such as the Knowles and Cotton Valley," Newport added.

The analysis of the data has indicated that the primary pay zone is a Deep Bossier Shale, which is within a greater than 2000 foot Bossier Formation interval that was encountered at approximately 19,960 feet. Special Core analysis performed on core cut within the Bossier in the well, suggests that the rock properties of the shales are similar to high productivity Bossier wells in Northwest Louisiana and East Texas. These observations, combined with natural fracturing and very high pressures in excess of 20,000 psi, suggest that the well could have very strong production rates in the Bossier Zone.

The Bossier Section consists of interbedded sandstones, siltstones and shales within a naturally fractured, high-pressure environment. Petrophysical analysis suggests that some of the sandstones have very good conventional porosity. Typical, in these types of formations, production rates are high.

Good porosity is also observed within approximately 70 feet of the overlying Knowles Lime in the Burkley-Phillips #1 well. Petrophysical analysis, as well as exceptional mud gas shows observed while drilling this unit, indicate the potential for excellent gas production within this interval.

Mainland and its working interest partners control in excess of 17,800 net acres or 28 sections on the Buena Vista prospect area where the Burkley-Phillips #1 well was drilled to 22,000 feet, cored and logged. Upon successful completion of its proposed merger with American Exploration, Mainland would own 92% of the 28 sections in the Buena Vista prospect. As recently announced, core analysis has determined that gas in place in the Buena Vista prospect could be up to 500 BCF/section based on the cored interval.

LNG Energy to Sell Ok. Acreage

LNG Energy to Sell Ok. Acreage

Wednesday, April 13, 2011
LNG Energy Ltd.

LNG Energy's subsidiary, BWB Exploration, has entered into an agreement to sell all of its working interest in approximately 2,800 net acres of oil and gas lease holdings in Carter County, Oklahoma to an undisclosed buyer for approximately US $5,180,000 in cash subject to final adjustments. The sale is expected to close on or before May 2, 2011.

"We continue to focus on our core areas in Poland and Papua New Guinea. This disposition follows our recent acquisition in Poland where we acquired about 180,000 net acres and now have exposure to a 1.1 million acre gross position in the Polish Baltic Basin," commented Dave Afseth, President & CEO of LNG.
Poland Operational Update

The second well being drilled, Lebork S-1 on the Slupsk Concession has been drilled to 3,517m, with 227m of open hole core already taken. It is anticipated that the drilling and logging will be completed in the next week. The core will be analyzed over the coming weeks. The majority of the analysis of the sidewall cores from the Wytowno S-1 well are expected to be received back from the subcontractor in May 2011. The 1st well on the Starogard concession is expected to be spudded in June 2011.

LNG is a Canadian exploration and development company focused on developing oil and gas reserves in Papua New Guinea, Poland and the US. LNG holds a 100% interest in approximately 5.5 million acres of prospective oil and gas properties in Papua New Guinea. LNG has a 50% net interest in approximately 360,000 gross acres of prospective shales in Poland together with Realm Energy (BVI). LNG also has a 20% net interest in approximately 734,000 gross acres of prospective shales in Poland together with BNK Petroleum Inc., Sorgenia E&P S.p.A., and Rohol-Aufsuchungs Aktiengesellschaft, and a 100% net interest in BWB Exploration, LLC ("BWB"), which holds approximately 2,800 acres of oil and gas leases in Carter County, Oklahoma and an estimated 28,757 acres of leases in the Black Warrior Basin of Mississippi and Alabama. LNG shares trade on the TSX Venture Exchange under the symbol "LNG".

Petro Vista Reaches TD at Morichito Well

Petro Vista Reaches TD at Morichito Well

Wednesday, April 13, 2011
Petro Vista Energy Corp.

Petro Vista announced that the Morichito-5B well in Colombia has reached total depth and production casing is being run to evaluate oil and gas shows encountered in the Tertiary Carbonera and Mirador and Cretaceous Guadalupe, Gacheta, and Ubaque formations.

This Morichito-5B was drilled from the Company's original M-5 (2010 discovery) drilling pad and deviated approximately 1200 feet to the southwest of the original well. The well was drilled to a total depth of 6855 feet in the Paleozoic. During drilling mud-log shows were encountered in the Carbonera C7, Mirador, Guadalupe, Gacheta, and Ubaque formations. Subsequent petrophysical analysis of electric logs indicated multiple potential pay zones.

The Carbonera C7 zone is equivalent to and six feet structurally high to the 5900 foot zone in the Morichito M-5 well which swabbed at a rate of 375 barrels of oil per day of 23 degree API oil with no water cut (see news release dated March 25, 2010).

A decision has been taken with partners Green Power Corporation and Golden Oil Corp. to run 7" production casing and test at least two zones. The Company expects testing to commence approximately May 1st and take 15-20 days to complete. Assuming success and the receipt of necessary permits, this well will be placed on a long-term production test along with the existing M5 discovery well on which a work-over rig is being mobilized with testing to commence approximately April 28.

The Morichito-5B well was drilled as a deeper pool wildcat and fulfills the company's Phase V contract commitment with the Colombian National Hydrocarbon Agency (ANH).

BPZ Concludes Seismic Work at Peru Blocks

BPZ Concludes Seismic Work at Peru Blocks

Tuesday, April 12, 2011
BPZ Resources Inc.

BPZ Resources provided an update to its operations in northwest Peru.

Production

For the first quarter ended March 31, 2011, total production was approximately 381,000 barrels of oil (4,233 barrels of oil per day, "bopd") from the offshore Corvina and Albacora fields in Block Z-1. This compares to total production of 414,000 barrels of oil (4,500 bopd) in the fourth quarter of 2010. The lower production in first quarter was due to shutting in well A-14XD in the Albacora field on January 24, 2011.

Albacora and Corvina Permits

Authorization for interference testing along with associated gas flaring covering a four month period beginning June 1, 2011, has been received from the Ministry of Energy and Mining of Peru for Albacora. The permits are for the Company's A-14XD, A-9G, and A-13E oil wells, with the latter two having been drilled by a previous operator, which are all currently shut-in at the Albacora platform. As a result, workovers will first be conducted on the A-9G and A-13E wells, with an estimated start in May 2011. Each well is expected to be opened at various intervals, both on an individual basis and simultaneously, during the four-month period to test reservoir connectivity of the sands that were producing at the A-14XD well. Upon completion of the interference testing, the Company plans to open previously untested zones in each of the three wells. However, in order to produce from those new zones, we must request authorization to flare associated gas until the injection equipment is installed at the Albacora platform which is currently scheduled for year-end 2011.

At Corvina, the permanent production facilities including the compressor are operating at expected efficiency levels. The Company has received approval to maintain the wells open while the compressor undergoes scheduled maintenance during the current calendar year. As a result of obtaining the authorization for interference testing at Albacora, the snubbing unit will not be moved to the Corvina platform as originally planned as it will first be used to complete the Albacora workovers.

The additional production from the interference testing at Albacora is expected to offset the anticipated lower than forecasted production from Corvina due to the delay in performing workovers on certain Corvina wells. As such, the Company maintains the previously provided total production guidance of approximately 4,000 bopd for the year 2011.

Seismic Surveys

Block XXIII

The 3-D seismic survey covering approximately 370 square kilometers in the northern section of onshore Block XXIII was completed in January 2011. The 3-D seismic survey was conducted to better delineate the Mancora gas play and the potential oil prospectivity in the Heath formation. To further delineate the oil potential of Block XXIII, in October 2010 we completed a 2-D seismic covering 312 kilometers in the southern section where we are following the trend of the adjacent Talara basin oil fields. Processing is expected to be completed by mid-year 2011.

Block XXII

In March 2011, a 258 kilometer, 2-D seismic survey was completed that covered several oil leads following the trend of nearby oil fields in adjacent blocks. Processing is also expected to be completed by mid-year 2011.

Block Z-1

The Company is continuing the process aimed at securing the permit to acquire the offshore 3-D seismic survey in Block Z-1. The public audiences were completed in January, 2011 and the governmental agencies are finalizing their review. We remain optimistic about obtaining the required seismic permit by the end of the second quarter.

Block XIX - Pampa la Gallina

We have been granted a 45-day deferral on drilling the Pampa la Gallina (PLG) onshore well due to contractor delays in completing the rig refurbishment. This defers the commitment deadline to drill and log the PLG well to mid July 2011. The Company may also request an extension of up to six months beyond the July deadline.

Standby Costs and Other Income

As previously disclosed, the Petrex-09 rig formerly utilized at the Corvina field is being refurbished and upgraded at no cost to the Company in order to enhance its capability in preparation for drilling an exploration well in the onshore PLG prospect in Block XIX. Reduced standby rates for the rig are being charged to the Company during the refurbishment and will continue until the rig is utilized.

Also as previously disclosed, the Petrex-18 rig, formerly utilized at the Albacora field, is under lease to another operator through November 15, 2011. The Company plans to resume drilling at Albacora after the 3-D seismic survey on offshore Block Z-1 is completed and the data is processed and interpreted.

Accordingly, standby costs for calendar year 2011 are expected to range between $10 million and $12 million. However, the Company intends to continue to pursue opportunities to further reduce these standby costs such as subleasing the Petrex-09 rig to another operator while not being utilized by the Company.

In addition, we have reached an agreement to charter to that same operator our BPZ-02 barge that supports the Petrex 18 drilling rig, as well as the Don Fernando construction barge, and are working on the possibility of chartering the Company's floating production, storage and offloading (FPSO) barge, the Namoku, as well. Rental income from these vessels is expected to offset related costs.

President and CEO, Manolo Zuniga commented, "We are very pleased that the seismic work on Blocks XXII and XXIII was completed as planned. This work will allow us to better map the oil and gas leads in these blocks." Mr. Zuniga continued, "The progress we are making on all our growth initiatives has been made possible by our close working relationship with the Peruvian authorities. We are appreciative of the spirit of cooperation that has been established and we look forward to continuing to partner together. Indeed, strong partnerships contribute greatly to the goals we have set for our Company."

RAM to Test Productivity of Osage Play

RAM to Test Productivity of Osage Play

Monday, April 11, 2011
RAM Energy Resources Inc.

RAM updated on activity in its Mississippian oil play in Osage County, Oklahoma. Approximately $5.4 million, or 15%, of RAM's 2011 capital expenditure budget totaling $35 million is allocated to the company's 56,320 acre concession, a part of the broad Mississippi Chat / Mississippi Solid / Arbuckle oil play in the region. Interpretation of the first phase of 3-D seismic, acquired in 2010, and initial drilling results indicated that a substantial portion of the acreage surveyed could be prospective. Although the Mississippi Chat has been the company's primary objective to date, the company's practice is to drill through the Chat and through the Mississippi Lime formation in order to gather additional science for future development. The initial wells drilled have encountered Chat zones 40-70 feet thick and porosities ranging from 20% to 35%. Similarly, initial wells have drilled through Mississippi Lime zones of 100 feet, or more, in thickness with a porosity range similar to the 5% to 15% range of porosities experienced by other operators in the western portions of the play.

"We are encouraged with the initial results from our Osage concession and have allocated a large proportion of our capital budget to test the productivity of the area. The combination of rig availability, relatively low drilling cost per well and ample infrastructure in the area allows us to aggressively pursue the play in the coming year," said Larry Lee, CEO of RAM.
Stepped up Pace of Drilling Planned in Osage Mississippian Exploration Play

Following the drilling of the company's three initial vertical wells in the concession during 2010, the company drilled the Farmland #1 during the first quarter 2011, targeting the Mississippi Chat formation. Currently the company is evaluating cores taken from the well. Also during the first quarter 2011, the Surber #3-SWD, a salt water disposal well, was drilled to service existing and future producing wells in the area. In the Surber #2-Twin, drilled during the first quarter near the Surber #3 SWD, core samples have been taken and casing set. RAM is awaiting the evaluation of the core data prior to completing.

The Rickets #3 well and the Surber #1 well, which were drilled to the Mississippi Chat formation late in 2010, have been fracture stimulated in order to test the impact of the slick water frac technique on reservoir permeability, thus advancing the science and knowledge associated with completion techniques in the area. Completion of the salt water disposal well facilitated the ability to fracture these and other planned wells in the area. The company has spud the next well in the series, the Surber #2-27, approximately one section to the west of the Surber #2-Twin. This offset to the Surber #1 and Surber #2-Twin is an exploration well targeting the continuation of the Mississippi Chat formation through seismic identification and sample cuttings from a previously drilled well by another operator. In mid-April the Farmland #2-16, an exploratory well, is scheduled to spud, also targeting the Mississippi Chat. The well, located approximately 2 sections northwest of the Surber #2-Twin, has been permitted and the location built. Immediately following the drilling of this well, the rig is scheduled to move to the location of the Christiansen #3-2. This exploration well is scheduled for a spud date later in April. The well targets the Arbuckle formation and will evaluate the Mississippi Chat and Lime formations. Two wells initially planned for the fourth quarter, the Surber #1-35 and the Rickets #1-35, are now likely to be drilled late in the second quarter as a result of rig availability. The drilling permit application process is underway for both of these wells. The location of the wells is anticipated to be immediately south of the successful Surber #1 well drilled in late 2010 which recorded an initial production rate of 80 barrels of oil per day (BOPD) in the Mississippi Chat formation.

Subsequently, in the third quarter 2011, the company plans to drill the Farmland #1-20 exploration well located southwest of the Farmland #2-16. At the northern boundary of RAM's initial seismic survey, the company plans to drill three wells; the Kendrick #1-27, the Stuart #1-28 and the Jones #1-33. These three exploration wells are designed to test the productivity of the Mississippi Chat and Lime formations in this unexplored part of the concession. If commercial potential exists, then RAM is likely to also drill another salt water disposal well to service these and potentially other future wells in this area of the lease. Archeological studies are proceeding on these wells which are precursors of the drilling permitting process.

In May 2011 the company plans to initiate acquisition of a second round of 3-D seismic on its Osage concession adjoining that of its first round of seismic acquisition. This second phase of 3-D seismic acquisition is planned to cover an additional 19,840 acres in the company's concession and is anticipated to add additional drilling prospects principally for 2012 and beyond when interpreted, later in 2011.
Advantaged Revenue Stream

Within the broad Mississippian play, the portion of the area covering RAM's Osage concession appears to yield primarily oil. Accordingly, commercialization of the company's acreage could add significantly to RAM's already above-industry-average mix of oil and oil-price driven natural gas liquids (NGL) in its hydrocarbon mix. The proportion of crude and NGLs as a percent of total BOE produced rose to 66% in December 2010 (adjusted to exclude assets sold in December 2010). Similarly, based on RAM's proved reserves at year-end 2010, oil and NGLs accounted for 64 percent of total proved reserves.

TD Reached at Premier's Ca Rong Do Appraisal

TD Reached at Premier's Ca Rong Do Appraisal

Monday, April 11, 2011
Premier Oil plc

Premier announced that the CRD-2X appraisal well in block 07/03 Vietnam has been drilled to a TD of 3785 meters MDRT, appraising the Miocene sands discovered in 2009 with the CRD-1X well.

The well was deepened from the preliminary TD of 3109 meters MDRT to evaluate the Oligocene which was not tested by the CRD-1X well. Two drill stem tests of the hydrocarbon bearing sands in the Oligocene section have been conducted. The first zone tested flowed gas and condensate at rates of 9.7 mmscfd and 870 bopd respectively through a 40/64 inch choke. The second zone tested flowed gas and condensate at rates of 17 mmscfd and 1730 bopd respectively through a 56/64 inch choke.

The well will now be sidetracked to further evaluate the distribution of hydrocarbons in the Miocene sands.

Simon Lockett, Chief Executive Officer, commented, "We are encouraged by the hydrocarbon flow rates from the Oligocene section in Ca Rong Do, which in addition to the previously proven Miocene reservoirs, provide further exploration upside across the area. We look forward to the result of the sidetrack well which will provide additional data to determine the hydrocarbon distribution in this part of the Ca Rong Do structure."

Statoil's Sleipner Delineation Delivers Gas Pay

Statoil's Sleipner Delineation Delivers Gas Pay

Friday, April 08, 2011

Norwegian Petroleum Directorate

Statoil, operator of the Sleipner Vest field in production licenses 29 and 46, has completed the delineation of the gas/condensate discovery 15/9-B-1 (Beta Vest).

The discovery was proven during the autumn of 2009 in Middle Jurassic reservoir rocks (the Hugin formation) about 1.5 kilometers west of the Sleipner Vest field and four kilometers from the Sleipner B platform. The 15/9-B-1 discovery well was drilled to the south on the top of the Beta Vest structure and there was uncertainty regarding the distribution of petroleum north and west on the structure. Before the appraisal wells were drilled, the operator's resource estimate for the discovery was between six and ten million standard cubic meters (Sm3) of recoverable oil equivalents.

The purpose of the wells was to delineate the 15/9-B-1 discovery. Three appraisal wells, 15/9-B-8, -8A and -8D, were drilled about two kilometers north of the discovery well. B-8, which was drilled at the bottom of the structure, encountered a 29-mete oil column and a 12-meter gas column in the Hugin formation. B-8A, deeper in the structure, was water-filled. B-8D, towards the top of the structure, encountered a 117-meter gas column in the Hugin formation. Two appraisal wells, 15/9-B-8B and -8C, were drilled in the southern end of the structure near the 15/9-B-1 discovery well. B-8B, near the top of the structure, encountered a 53-meter gas column in the Hugin formation, while B-8C, further down on the structure, was water-filled.

None of the wells were formation-tested, but data acquisition and sampling were conducted. The preliminary size of the discovery has been estimated at 13 million Sm3 recoverable oil equivalents. The gas has a gas/condensate ratio of about 2000 Sm3/Sm3 and a CO2-content of at least 14 per cent, which is higher than in the Sleipner Vest field. The discovery is being prepared for production via the Sleipner Vest field.

Production licenses 29 and 46 were awarded in the 2nd and 3rd licensing rounds in 1969 and 1976, respectively. 15/9-B-8 was drilled to a vertical and measured depth of 4000 and 6692 meters below sea level, respectively, and was terminated in the Skagerrak formation in the Upper Triassic. 15/9-B-8A, -8B, -8C and -8D were drilled to vertical depths of 3899, 3701, 3856 and 3700 meters, respectively, as well as measured depths of 7418, 6417, 7107 and 5724 meters below sea level respectively, and were all terminated in the Hugin formation. Water depth at the site is 108 meters. Four of the wells have been plugged and abandoned, while 15/9-B-8D at the top of the Beta Vest structure will be a development well.

The wells were drilled by the West Epsilon drilling facility, which is connected to the Sleipner B platform. Over the course of the spring, the rig will be demobilized and prepared for drilling development wells at the Gudrun field where Statoil Petroleum AS is the operator.

Ophir to Take Reins of Block Offshore Tanzania

Ophir to Take Reins of Block Offshore Tanzania

Thursday, April 07, 2011

Ophir Energy plc

Ophir announced that a subsidiary has entered into agreement with Ras Al Khaimah Gas Tanzania Ltd (RAKGas) to acquire a 70% interest and Operatorship of a Production Sharing Agreement (PSA) over an area designated as the East Pande Block in Tanzania. Completion of this agreement is subject to standard Government consents.

The East Pande license lies in the coastal region of southern Tanzania covering an offshore and onshore area in excess of 7,500km2. The block lies immediately to the west of Blocks 1, 3 and 4 in which Ophir has a 40% interest. Ophir has recently drilled the first deepwater wells offshore Tanzania resulting in three significant gas discoveries. The maximum water depth in the East Pande block is approximately 2,000m. The PSA was awarded to RAKGas in 2006.

In late 2010 RAKGas acquired approximately 1,800 line kilometers of 2D seismic data in the offshore section of the block. The data indicates the continuous nature of the geology between East Pande and the prospective Ophir acreage to the east. Subject to partner and Government consent, Ophir intends to acquire a new 3D seismic survey in the offshore section of the block.

Under the terms of the farm in agreement, Ophir will fund 100% of the cost of the 3D seismic survey and will reimburse certain back-costs. In the event that Ophir elects to drill, RAKGas will be carried through the drilling of the first exploration well.

Ophir and RAKGas are also partners in the Berbera PSA in Somaliland.

Ophir's New Business Director Jonathan Taylor commented, "We are delighted to extend our partnership with RAKGas to the East Pande project and to further deepen our relationship with the Government of Tanzania. With our recent exploration discoveries in Blocks 1 and 4, immediately adjacent to East Pande, we are well placed to build on this success and undertake a fast-track exploration campaign to pursue the petroleum potential of this exciting project."

Breitling Spuds 1st Shallow Gas Field in Ok.

Breitling Spuds 1st Shallow Gas Field in Ok.

Thursday, April 07, 2011

Breitling O&G Corp.

Breitling has spud the Breitling-Yardeka #1 in McIntosh County, Oklahoma on the northern edge of the Arkoma Basin. The Yardeka #1 is the first well to be drilled in Breitling's newly developed gas field in the Basin. There are two major objectives within the prospect, the Jefferson Sand at 3450' and the Upper Gilcrease Sand at 2300'. Secondary objectives include the Spiro Sand at 2800', The Booch Sand at 1600' and the Bartlesville Sand at 1150'.

The initial test well will be a 3500' Jefferson Sand test. The Jefferson Sand is an excellent reservoir which is found productive on localized structural closures. Subsurface mapping on the Wapanucka Limestone indicates a possible northwest to southeast trending structural ridge over the Breitling-Yardeka prospect. Within this structural ridge there are several structural closures, three of which have produced from the Jefferson.

Management anticipates the well will reach total depth in about 4 days. Well completion and testing on the Breitling-Yardeka #1 well should begin during the third week of April 2011.
Breitling Oil and Gas CEO Chris Faulkner stated, "We have good well control in the area and these shallow sands are productive on all sides of us." Faulkner added, "The field directly to our Southeast has produced over 6 BCF of gas."

Beach Boasts Results for Western Flank Campaign

Beach Boasts Results for Western Flank Campaign

Monday, April 04, 2011

Beach Energy Ltd.

Beach has obtained excellent results from the first two wells drilled of its 16 well operated program in the Western Flank area.

In late February, the Parsons-3 oil development well encountered a 9 meter oil column. This result has now been immediately followed by a second success at Parsons-4, where a 5.5 meter column of oil was encountered in line with pre-drill prognosis. Both wells intersected excellent quality Namur sandstone reservoirs and have been completed for production and early tie-in to the Parsons facility. Following completion and perforation, Parsons-3 flowed over 5000 barrels of oil per day during clean up. No water was produced. This well is expected to be on-line around mid April with Parsons-4 shortly thereafter.

The success at Parsons will increase daily gross production from the PEL 92 area to around 6000 barrels of oil per day (gross). Beach expects to book additional reserves for the Parsons field following these results, the quantity of which is currently being assessed.

Oil from the Parsons field is transported from the Western Flank by flowline to Moomba via Tantanna and thus is not at risk from flooding in the area.

The Ensign #30 rig will now move to the Butlers-2 location. The well to be drilled will appraise the northerly extent of the Butlers oilfield and facilitate development planning and production optimization. A successful result at Butlers-2 has the potential to add up to 2 million barrels of oil (gross).

The Ensign #18 rig is currently moving across the Cooper Creek via the Kudnarri Bridge into PEL 91. The rig is expected to be 100% on location at Hanson-1 by the middle of this week and will commence drilling after a short maintenance and repair period of one to two weeks.

Hanson-1 is the first of a five well exploration campaign for the PEL 91 joint venture.

A further flood pulse is expected in the PEL 91 and PEL 92 areas in mid April, however Beach has established a remote operations base at Gunyah on the western side of the Cooper Creek to enable drilling operations to continue unaffected.

Providence Sells GOM Assets

Providence Sells GOM Assets

Friday, April 01, 2011

Providence Resources plc

Providence announced the immediate sale of its US oil and gas portfolio in the Gulf of Mexico to Dynamic Offshore Resources LLC ("Dynamic") for a consideration of up to $22 million. The consideration comprises an initial cash payment of $15 million, and potentially an additional $7 million deferred cash payment.

This deferred cash payment is dependent on Dynamic reaching certain production levels from any new wells drilled on Ship Shoal 252, 253 and 267 prior to January 2013. Total current production from Providence's Gulf of Mexico portfolio amounts to c. 700 BOEPD.

The proceeds of the sale, which closed on March 31, 2011, are to be applied to a reduction of the Company's Reserve Backed Lending Facility with BNP Paribas. The sale will result in the impairment of the carrying value of the assets, and will necessitate a non-cash write-off to be taken in Providence's 2010 accounts. CIBC World Markets Plc acted as exclusive financial adviser to Providence on this transaction.

Commenting, Mr. Tony O'Reilly, Chief Executive of Providence said, "While the production from the Gulf of Mexico has played an important role in the development of the Company over the past 3 years, it is now less material going forward. With our major multi-year, multi-basin drilling program offshore Ireland starting, combined with our ongoing investment program at Singleton, the investment focus for the Company is now very clear. As such, the opportunity to realise cash from the Gulf of Mexico portfolio, and to deleverage the core business, made sense."

Lexaria: 4 Wells Producing at Belmont Lake Field

Lexaria: 4 Wells Producing at Belmont Lake Field

Thursday, March 31, 2011

Lexaria Corp.

Lexaria announced that for the first time, there are now up to four producing oil wells at the Belmont Lake oil field, and a salt-water disposal well that is connected and operational. The necessary work was completed despite challenging field conditions prior to the seasonal rise in Mississippi River water levels. Some residual infrastructure work will be completed during the next dry season.

The Belmont Lake oil field has now produced over 100,000 barrels of oil.

Lexaria has drilled both oil and gas wells in the region since 2005, concentrating on shallow geologic horizons that are less expensive to exploit than deeper targets. There are a number of geologic target zones from the shallowest all the way to the Tuscaloosa Marine Shale. A 1996 Louisiana State University study estimates that 7 Billion recoverable barrels of oil may exist in this oil shale that in some regions is 400-800 feet thick.

Lexaria holds an option to drill up to 38 exploration wells on roughly 130,000 acres of land in the region, in which it holds a 60% interest. Shallow fields are of primary interest to the Company, in part, because of the history of this region. Some of the shallow oil fields in the area produced by others include:

• 593,000 barrels produced at Ashwood Field
• 730,000 barrels produced at Stamps Field
• 55,000,000 barrels produced at Little Creek Field
• 1,412,000 barrels produced at Freedom field

Lexaria currently holds a 40% gross working interest in the PP-F12-4 and PP-F12-5 directional wells, and a 32% interest in the PP-F12 and PP-F12-3 wells. It holds a minimum 32% interest with the potential for higher interests, in any additional development wells to be drilled at Belmont Lake.