Aminex Drills Ahead Offshore Tanzania

- Aminex Drills Ahead Offshore Tanzania

Friday, August 26, 2011
Aminex plc

Aminex reported progress on the Nyuni-2 exploration well, currently being drilled from Nyuni Island off the coast of Tanzania in the Indian Ocean.

Nyuni-2 was spudded on June 17 using the Caroil Rig-6, to target Lower Cretaceous age Neocomian sandstones, similar to those found in Aminex's nearby Kiliwani North gas field and in the producing Songo-Songo gas field. The well is being drilled from a pad on Nyuni Island at an angle of 30 degrees from vertical, to target a bottom hole location approximately 1,200 meters SE of the surface location. Planned measured total depth is 3,325 meters from the rotary table on the rig.

With the exception of an 8 day period when the rig was shut down due to a requirement to replace damaged equipment, drilling operations have made satisfactory progress to date and 9 ?" casing is now being run to the current total measured depth of 2,945 meters. Once the well has been safely cased to this point, drilling will resume towards its target. The result of the well will be announced at the earliest opportunity.

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Imperial Drills Ahead at Green Tide SWDF

- Imperial Drills Ahead at Green Tide SWDF

Thursday, August 25, 2011
Imperial Resources Inc.

Imperial announced that the operation to deepen the disposal well at the Company's Green Tide Salt Water Disposal Facility ("SWDF") continues to be drilled ahead vertically from the sidetrack.

As of 18:00 local time on August 24, 2011 the well was at 5,700 feet drilling ahead toward the target formation. To date no major issues have been encountered. The Company anticipates it will reach a total depth of 7,500 feet (approximately 500 feet into the Ellenburger formation) at which point the aim will be to set casing and cement from the bottom of casing back up to 5,700 feet. Once completed, the current rig will be released and replaced by a smaller workover rig which will attempt to drill further into the Ellenburger formation to reach some high porosity strands within the formation to enable maximum potential disposal capacity.

Subject to success, commercial disposal operations are expected to start immediately targeting full disposal capacity of 15,000 barrels per day as quickly as possible. At full capacity, the Company believes the Green Tide SWDF has the potential to generate significant cash flow at relatively low operating costs.
The Green Tide SWDF

The Green Tide SWDF is conveniently located for the disposal of large volumes of salt water generated from essential fracture stimulation operations on Barnett Shale gas wells. There are approximately 6,000 such Barnett wells within 20 miles of the SWDF.

Imperial plans to reopen Green Tide to dispose of up to 15,000 barrels of salt water a day. The Company's acquisition and development of the low run-time Green Tide assets and disposal permit is expected to save in excess of $5,000,000, compared to a new build cost.

Green Tide is one of two key projects identified as transformational for Imperial (the other being the Company's Oklahoma project).

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Aurora Drills Ahead at Tx. Alwan West Prospect

- Aurora Drills Ahead at Tx. Alwan West Prospect

Thursday, August 11, 2011
Victory Energy Corp.

Victory, through its partnership with Aurora Energy Partners, announced that its Alwan West (#1 Goff Mineral Trust) prospect well was spud on August 2, 2011 and is currently drilling ahead at 5,097 feet.

Prior to reaching the proposed target depth of 7,100 feet, all three target sands (first Yegua, Frio and second Yegua) will be tested. All three sands are anticipated to be reached and tested in the coming days. These sands do not require a fracking procedure to be productive. Anticipated completion after a successful testing generally occurs in less than two weeks.

The lease area is surrounded on all sides by gas condensate production and a delivery pipeline is within 1,000 feet of the well.

Alwan West lies on strike between two Yegua fields, Lost Fork (one mile west) and AVO Grande (3,000 feet east). Lost Fork has produced over 42 BCF, while AVO Grande has produced 7 BCF of natural gas. Both of these fields are stratigraphic traps, as is the Alwan West prospect. This area produces from the Frio and Yegua (Oligocene) formations.

This prospect's potential reservoir covers an area of 175 acres and has a reserve potential of 8.5 billion cubic feet (BCF) of natural gas and 43.75 thousand barrels of gas condensate.

The reserve potential is based on 50 feet of reservoir sand, one million cubic feet per acre-foot of natural gas and five barrels per million cubic feet of gas condensate. These reserve estimates are for the first Yegua sand only, which is the primary objective, and do not include potential in the secondary objectives.

The Alwan West prospect is located in far western Wharton County, Texas, near the Jackson County line. Victory Energy acquired the prospect, which includes a 5 percent working interest (WI) and a 3.8 percent net revenue interest (NRI), from Miramar Petroleum, Inc. of Corpus Christi, Texas, who will be the operator and who also owns a significant working interest in the well.

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Abraxas Looks Ahead to 'Active' 2011 Drilling Program

- Abraxas Looks Ahead to 'Active' 2011 Drilling Program

Tuesday, August 09, 2011
Abraxas Petroleum Corp.

Abraxas provided an operational update and issued production guidance for 2011.

Rocky Mountain – North Dakota / Montana

In McKenzie County, North Dakota, Abraxas drilled the Stenehjem 27-34 1H to a total measured depth of 16,504 feet, including a 5,965 foot lateral in the middle Bakken formation, and completed the well with a 17-stage fracture stimulation. The well was placed on production in late June and in 44 days the well has produced (on a restricted choke) 20,000 barrels of oil, 32.2 MMcf of wellhead gas which yields 2,700 barrels of natural gas liquids and 23.3 MMcf of residue gas for a total of 26,500 barrels of oil equivalent, or an average of 600 barrels of oil equivalent per day. For the past three days, the well averaged 615 barrels of oil equivalent per day on a 21/64-inch choke with 750 psi of flowing pressure. Abraxas owns a 79% working interest in this well.

In various counties in North Dakota and Montana, fourteen non-operated horizontal wells, targeting the Bakken or Three Forks formation, in which Abraxas owns a working interest are currently in progress or recently placed on-line. Seven gross (0.35 net) wells went on production in June or July, three gross (0.08 net) wells have been fracture stimulated and are currently cleaning up, one gross (0.36 net) well is waiting on completion, one gross (0.01 net) well is currently drilling and two gross (0.05 net) wells are waiting on a drilling rig. Since January 2010, Abraxas has elected to participate in 19 gross (1.00 net) non-operated wells in the Bakken / Three Forks play.

In McKenzie County, North Dakota, two gross (0.11 net) non-operated horizontal wells targeting the Mission Canyon have been drilled, completed and are currently waiting on production facilities. Early production testing of these wells has yielded flow rates in excess of 1,000 barrels of oil per day each.

In early July, Abraxas announced the purchase of a drilling rig that is in the process of being refurbished. After completion, the rig will be mobilized to McKenzie County, North Dakota and it is anticipated that the rig will begin drilling on the first pad site in October.

Rocky Mountain - Wyoming

In Campbell and Niobrara Counties, Wyoming, a two well oil development program is scheduled to begin this fall. One of these horizontal wells will target the Niobrara formation and one will target the Turner formation. Abraxas owns a 100% working interest in each of these wells.

South Texas – Eagle Ford

Abraxas currently owns a 41% equity interest in Blue Eagle, a joint venture between Abraxas and Rock Oil Company, LLC. On June 29, 2011, Rock Oil contributed an additional $11 million to the joint venture and Blue Eagle purchased approximately 2,487 net acres in McMullen County, Texas in the oil window of the play.

In DeWitt County, Texas, Blue Eagle's first well, the T-Bird 1H, continues to outperform expectations and is currently producing 930 barrels of oil equivalent per day, which is comprised of 185 barrels of condensate, 300 barrels of natural gas liquids and 2.7 MMcf of residue gas. The well has produced approximately 230,000 barrels of oil equivalent during its first 180 days on production. Blue Eagle owns a 100% working interest in this well.

In DeWitt County, Texas, Blue Eagle participated in a non-operated horizontal well with its 43.9% working interest. The Matejek Gas Unit 1 was drilled to a total measured depth of 17,865 feet, including a 3,600 foot lateral, and completed with a 14-stage fracture stimulation. The well is currently shut-in waiting on pipeline hookup which is expected to be completed later this month.

In Atascosa County, Texas, the Grass Farms 1H is currently drilling the lateral at a total measured depth of 13,150 feet towards a total measured depth of 13,380 feet, including a 6,000 foot lateral. A fracture stimulation date has been secured for this well in September, a month later than originally anticipated. Blue Eagle owns a 100% working interest in this well.

West Texas

In Nolan County, Texas, the Spires 126 2H was drilled to a total measured depth of 9,000 feet, including a 2,000 foot lateral, and completed open hole and un-stimulated. The well was recently placed on-line and during the first 20 days of production, the well averaged 125 barrels of oil equivalent per day, which was comprised of 47 barrels of oil, 46 barrels of natural gas liquids and 210 Mcf of residue gas. Abraxas owns a 100% working interest in this well.

In Coke County, Texas, the Sadie #2A was drilled to a total vertical depth of 6,425 feet and is waiting on completion and the Sadie #1B is currently drilling below 4,600 feet towards a total vertical depth of 6,500 feet. These two delineation wells are targeting the Canyon Sands. Abraxas owns a 100% working interest in these wells.

In Reeves County, Texas, Abraxas previously announced that it acquired an additional 640 net acres, for a total of approximately 3,000 net acres, in the emerging Wolfbone play. Two wells directly adjacent to our acreage are currently being drilled by the industry.

Canada - Pekisko

In Alberta, Canada, the Twining 6-11 was drilled to a total measured depth of 8,900 feet, including a 3,025 foot lateral, and is waiting on completion and the Twining 6-12 recently reached total measured depth of 9,150 feet, including a 3,380 foot lateral. These two wells are targeting the Pekisko formation. Canadian Abraxas owns a 100% working interest in each of these wells.

Guidance

For July, Abraxas produced approximately 4,160 barrels of oil equivalent per day up from an average of 3,845 barrels of oil equivalent per day for the second quarter. Abraxas expects production for 2011 to average 4,000 – 4,200 barrels of oil equivalent per day, including its equity interest share of Blue Eagle's production, which would generate an exit rate for 2011 between 4,700 and 4,900 barrels of oil equivalent per day.

Comments

"We've been busy! It is a refreshing change to get back to a very active drilling program. So far, we are quite pleased with the results of our operated (and non-operated) wells and we hope to continue this success throughout the year. The purchase of the drilling rig will enable us to be quite active in the Williston Basin on an operated basis and in an efficient manner for years to come," commented Bob Watson, Abraxas' President and CEO.

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Kodiak Drills Ahead in Williston Basin

- Kodiak Drills Ahead in Williston Basin

Thursday, August 04, 2011
Kodiak O&G Corp.

Kodiak O&G announced its second quarter 2011 financial and operational results. The Company also provided an interim operations update on its Williston Basin drilling and completion activities.

Highlights Include:

• 2Q 2011 Earnings of $8.2 Million, Before Unrealized Derivatives Gain
• Oil & Gas Sales of $22.1 Million, a 261% Increase
• Equivalent Sales Volumes 238,000 BOE, a 149% Increase
• Adjusted EBITDA of $13.7 Million, 377% Growth
• Two New Bakken Well Completions in McKenzie County, N.D.

Second Quarter 2011 Financial Results

The Company reported net income for the second quarter 2011 of $14.0 million, or $0.08 per basic and diluted share, compared with net income of $621,000, or $0.01 per basic and diluted share, for the same period in 2010. Included in the second quarter 2011 net income calculation are unrealized derivative gains of $5.8 million attributed to the non-cash change in the value of derivatives utilized for commodity price risk management. Excluding the effect of unrealized derivative gains, a non-cash credit, Kodiak would have reported adjusted net income (a non-GAAP measure) of $8.2 million for the second quarter 2011, or $0.05 per basic share and $0.04 per diluted share.

For the quarter-ended June 30, 2011, the Company reported oil and gas sales of $22.1 million, as compared to approximately $6.1 million during the same period in 2010, a 261% increase and a Company record. Crude oil revenue accounted for approximately 97% of second quarter 2011 oil and gas sales, and crude oil constituted 94% of sales volumes for the quarter. Kodiak posted a 157% increase in oil sales volumes and a 72% increase in gas sales volumes for an overall 149% increase in quarter-over-quarter equivalent sales volumes of 238,000 barrels of oil equivalent (BOE).

Adjusted EBITDA, a non-GAAP measure, was $13.7 million for the second quarter 2011, as compared to $2.9 million in the same period in 2010, a 377% increase and another Company record. Kodiak defines Adjusted EBITDA as net income before (i) interest expense, (ii) income taxes, (iii) depletion, depreciation, amortization, and accretion (iv) impairment, (v) non-cash expenses relating to share based payments recognized under ASC Topic 718, (vi) pre-tax unrealized gains and losses on foreign currency, and (vii) pre-tax unrealized gain and losses on commodity price risk management activities. A reconciliation of Adjusted EBITDA to net income is included in the financial tables later in this earnings release.

Kodiak reported record net cash provided by operating activities for the second quarter 2011 of $16.3 million, as compared to $7.2 million in the same period in 2010. The Company reported cash used in investing activities of $116.8 million during the second quarter of 2011, of which approximately $30.6 million was invested for the drilling and completion of wells and for infrastructure in its Williston Basin drilling program. The Company also invested $85.8 million during the second quarter 2011 to acquire an additional 25,000 net acres and producing properties in the Williston Basin which closed on June 30, 2011.

Second Quarter 2011 Expense Analysis

For the quarter-ended June 30, 2011, general and administrative (G&A) expense was $4.2 million, as compared to $2.6 million for the same period in 2010. The increase in total G&A is attributed primarily to the hiring of new personnel as the Company continues to expand its operations. The Company had 52 employees at June 30, 2011, as compared to 27 employees at June 30, 2010. Included in the second quarter 2011 G&A expense is a non-cash, stock-based compensation charge of $947,000 million, as compared to $866,000 for the same period in 2010.

Kodiak's lease operating expense (LOE) for the second quarter 2011 was $4.4 million, as compared to $1.5 million during the same period in 2010. The increase in LOE is attributed to additional production expense associated with a growing number of producing wells. Severance taxes were also higher due to increased oil and gas revenues during the 2011 period, as compared to the 2010 period.

Depletion, depreciation, amortization, and accretion (DD&A) expense for the second quarter 2011 was $4.5 million, as compared to $1.5 million for the same period in 2010. The increase is primarily due to the increase in sales volumes and, to a lesser extent, an increase in the per-unit charge.

Williston Basin Operations Update

Kodiak's four operated drilling rigs are presently drilling ahead on multi-well drilling pads. Two rigs are drilling in McKenzie County, and two rigs are drilling in Dunn County. The Company anticipates that the fifth operated drilling rig will be mobilized to McKenzie County when construction of the rig is completed in the fourth quarter of 2011.

As previously announced, the Company's completion activities are progressing according to schedule, and Kodiak expects to complete or commence completion operations on 10 gross and 7.5 net operated wells in the Williston Basin during the third quarter of 2011, including the Koala wells. In addition, the Company expects to participate in the completion of four gross (2.0 net) non-operated wells in the third quarter of 2011.

Management Comment

Commenting on second quarter 2011 results, Kodiak's Chairman and CEO Lynn A. Peterson said, "Kodiak's second quarter results were the strongest in Company history. We reported robust growth in several of the metrics that we monitor to assess our progress and performance. The results from our Koala project area wells are very encouraging and further demonstrate the productive potential in this prolific area of the Williston Basin. The four Koala wells that we have completed to date are all very strong wells with production established from middle Bakken as well as the Three Forks. The wells were drilled in a manner which continues to test the density of well bores and the communication between reservoirs. Well performance will be monitored over the coming quarters.

"As we look at the anticipated ramp-up in our production, combined with the $160 million of cash obtained from the public offering of common stock, the Company is in its strongest financial position ever. We announced the expansion of our borrowing revolver recently and we anticipate that the facility will continue to expand as we bring additional wells on during the remaining months of 2011 and beyond. We expect to selectively add to our Williston Basin acreage position and expect increased drilling and completion activity in the upcoming quarters. We believe we now have ample liquidity through our cash balances, operating cash flow and access to our credit facilities to fund our expanding drilling program."

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Dragon Oil Drills Ahead at Lam Well

- Dragon Oil Drills Ahead at Lam Well

Wednesday, August 03, 2011
Dragon Oil plc

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

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

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Egdon Looks Ahead to Markwells Wood-1 Well Test

- Egdon Looks Ahead to Markwells Wood-1 Well Test

Wednesday, August 03, 2011
Egdon Resources plc

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

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

Keddington

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

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

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

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

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

Kirkleatham

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

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

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

Ceres

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

Waddock Cross

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

Markwells Wood

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

Avington

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

Dukes Wood/Kirklington

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

PEDL201 Seismic Program

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

PEDL180/182 3D Seismic Program

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

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

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

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American Eagle Energy Charges Ahead

- American Eagle Energy Charges Ahead

Friday, July 29, 2011
American Eagle Energy Inc.

American Eagle Energy provided a general operations update on the Company's projects. The Company's proposed merger with Eternal Energy Corp. continues to progress, subject to the completion of remaining, standard regulatory and administrative processes. American Eagle's individual project updates include:

Hardy Field, Saskatchewan, Canada

The first development well in the field, Hardy S HZ 1A4-16-4B4-9-4-21W2, was drilled and cased in May, 2011. Completion plans included a 29-stage fracture stimulation of the Bakken horizontal well that placed a total of 429,000 pounds of sand and 6,400 barrels of water in the 1370 meter lateral section. The well is currently being evaluated and is projected to be placed on pump in the first week of August. Additional locations are being considered for the 2011 drilling program pending the outcome of the well testing. The existing producing well, Hardy S Re 2D7-9-3D2-16-4-21W2, continues to average approximately 40 BOPD.

Spyglass Project, Divide County, ND

The Spyglass Project is a Bakken and Three Forks play in northern Divide County, North Dakota. The first closing of the sale of half of the respective working interests in the Spyglass Project by American Eagle, and its proposed merger partner Eternal Energy Corp., to a third party occurred on May 26, 2011. The first transaction netted approximately $7.165 million divided equally between American Eagle and Eternal Energy. The previously announced second closing is now scheduled for August 2, 2011, and relates to the potential sale of an undivided 50% interest in approximately 800 additional net acres for roughly $700,000. In addition, the Company will complete the closing on the sale of an undivided 50% interest in 227 net acres for approximately $200,000 from the original closing. The proceeds from both of these subsequent closings will be divided equally between American Eagle and Eternal Energy

American Eagle and Eternal Energy requested regulatory approval for six 1,280-acre spacing units in an area of the Spyglass Project in which they expect to operate. Well permitting for two company-operated horizontal wells in these spacing units has started with the intention of drilling them in late 2011.

Approximately 5,000 acres of additional leasehold has been acquired in the western portion of the Spyglass project through purchase of two land packages and ongoing leasing efforts.

American Eagle and Eternal Energy have participated in drilling of three outside-operated wells in the second quarter of 2011 that are pending completion. One of these wells, fracture stimulated in mid-July, is the second offsetting Three Forks well to yield average flowing rates above 500 BOPD. The other two are expected to be fracture stimulated in August. American Eagle and Eternal Energy have elected to participate in 4 additional wells, with working interests ranging from 4.19% to 7.03%, operated by Crescent Point Energy Corp., SM Energy Company, and Samson Resources Company that are expected to be drilled in the current quarter.

Glacier Project, Glacier & Toole Counties, MT

The American Eagle Glacier Project is located in Montana portion of the Alberta Bakken play. The Company and its two partners control Bakken/Three Forks rights in slightly over 75,000 net acres.

Two vertical evaluation wells were drilled during the second quarter of 2011.

The FX 81-3 well was drilled to evaluate the Banff, Bakken, Three Forks, Nisku and Devonian Formations by deepening an existing well in the Southwest Cut Bank Sand Unit where American Eagle and its partners, FX Energy and Big Sky Operating, own a controlling interest in approximately 10,000 net acres about 6 to 10 miles southeast of multiple vertical and horizontal wells being completed by both Rosetta Resources, Inc and Newfield Exploration Company. The 81-3 well encountered oil shows in the Banff, Bakken and Three Forks and is scheduled to be fracture stimulated in August.

The FX American Eagle Big Sky 14-29 well was drilled in May as the first earning well associated with a large farm-in block east of the Cut Bank well structurally higher on the Kevin Sunburst Dome. A core of the Bakken and Three Forks encountered excellent oil saturation within a thick section including the Middle Bakken and Three Forks. The 14-29 well is scheduled to be fracture stimulated in August.

A third vertical assessment well is currently expected to be drilled in September, 2011 to evaluate the eastern portion of the Company's leasehold. Depending upon the results of the testing of the vertical wells, one or more horizontal wells are projected to be drilled during the fourth quarter of 2011.

Benrude Project, Roosevelt County, MT

The Benrude Project is high-impact Nisku Formation development project in Montana. A contract with Dawson Geophysical was signed for a focused 3-D seismic survey designed to optimize the structural location for the proposed development well. After acquiring and analyzing the seismic data, the new well is currently expected to be drilled in early 2012.

Richard Findley, the Company's Chief Executive Officer stated, "American Eagle has made significant progress on several of our projects despite the operational constraints associated with the exceptionally wet spring and high activity levels in these areas. The drilling of our Hardy and Glacier wells represents major steps forward for both of these projects and the consummation of several acreage acquisitions bodes well for future growth potential of the Company. The non-operated production results in Spyglass provide significant confirmation of the high potential of the Spyglass Project and furthers our efforts to build solid cash-flow and reserves as we move our focus towards company-operated drilling of our higher interest wells"

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Range Drills Ahead at Georgia Well

- Range Drills Ahead at Georgia Well

Thursday, July 28, 2011
Range Resources Ltd.

Range Resources, along with its joint venture partners, Strait and Red Emperor announced that following the successful spudding of the Mukhiani 1 well earlier this month, the well is currently at 510m.

As was expected in the early stages of drilling, progress was relatively slow, however the Company reported that the last few days has seen drilling progress as planned with the lithology encountered being in line with expectations (derived from seismic interpretations and analysis). It is anticipated that drilling will continue to circa 700m after which casing will be set and logging performed.

The Mukhiani Well is targeting the Vani 3 prospect which has the following estimated undiscovered stock tank oil-in-place ("STOIIP"):

• Vani 3 Prospect - STOIIP (MMbbls)
• P90 P50 P10 Mean
• Gross (100%) 41.7 92.7 178.2 115.2
• Net Attributable to Range (40%) 16.7 37.1 71.3 46.1

The recently completed geochemical helium survey undertaken by Range confirmed the suitability of the first drill location with oil exploration and development prospectivity complementing the earlier seismic work completed on the target.

The Company will continue to provide updates on a 7-10 day basis as to the progress of the drilling of the Mukhiani well.

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Entek Drills Ahead at Niobrara Shale Proj.

- Entek Drills Ahead at Niobrara Shale Proj.

Thursday, July 21, 2011
Entek Energy Ltd.

Entek provided an update on the Niobrara Shale Oil Project Appraisal Program in the Green River Basin.

Battle Mountain 14-10L- current operation, drilling ahead at 805 ft after setting surface casing and testing rig equipment. The proposed total depth of the well is 7,600 ft.

Entek holds a 55% interest in the Green River Basin Joint Venture (GRBJV) with Emerald Oil & Gas holding 45%. Entek is the Operator. The GRBJV now controls close to 80,000 gross acres, approximately 60,000 net acres, covering the Niobrara Shale Oil Play.

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Europa Charges Ahead in Romania

- Europa Charges Ahead in Romania

Wednesday, July 20, 2011
Europa O&G Holdings plc

Europa provided an update on planned operations in Romania for the coming 6 months.

Europa has received both drilling approval and an extension to the license from the Romanian authorities in order to undertake the deepening of the Barchiz-1 exploration well, situated in the EPI-3 Brates Concession (Europa 100%). The deepening of the well is planned to test the exploration target thought to lie beneath the current 1,450m depth of the well.

Aurelian Oil & Gas, the Operator of the Brodina Concession (Europa 28.75%) in northern Romania, has advised partners that the Voitinel gas discovery appraisal well is due to spud on or around October 1, 2011. Subject to the results of this well, a further well is anticipated to be drilled to test the upside to the play in early 2012.

The 2011 seismic program in Romania is underway, with the EIII-3 Cuejdiu area (Europa 17.5%) acquisition over 70% complete. The EIII-1 Brodina program will follow on from this survey. Both of these seismic programs are concentrating on the underexplored thrustbelt oil play.

Managing Director Paul Barrett said, "these Romanian projects are coming together to create a significant amount of activity for the remainder of 2011 and we hope to exit the year with greater reserves and contingent resources."

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McMoran Looks Ahead at Reserve, Production Profile

- McMoran Looks Ahead at Reserve, Production Profile

Tuesday, July 19, 2011
McMoRan Exploration Co.

McMoRan reported a net loss applicable to common stock of $50.2 million, $0.32 per share, for the second quarter of 2011 compared with a net loss of $21.7 million, $0.23 per share, for the second quarter of 2010.

HIGHLIGHTS

• Shallow Water, Ultra-Deep Exploration & Development Activities:
  • Davy Jones No. 2
    • In June 2011, results from wireline logs of the Cretaceous section indicated that the Davy Jones No. 2 well encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. Flow testing will be required to confirm the potential hydrocarbons and flow rates from these sandstones and limestones.
    • Completion for flow testing expected to commence in the second quarter of 2012.
    • Previous wireline logs confirmed hydrocarbon bearing Wilcox sands seen in the Davy Jones No. 1 discovery well.
  • Blackbeard East
    • Exploration results to date indicate updip potential in the Miocene (178 net feet of hydrocarbons) above 25,000 feet and downdip potential in the Oligocene (Frio) below 30,000 feet.
    • In July 2011, commenced operations to drill a by-pass well at approximately 30,700 feet to evaluate targets in the Eocene.
  • Lafitte
    • Commenced drilling on October 3, 2010, currently below 24,200 feet with a proposed total depth of 29,950 feet. Targeting Miocene and Oligocene objectives.
• Shallow Water, Deep Gas Exploration & Development Activities:
  • Laphroaig No. 2
    • Production commenced in April 2011 and averaged a gross rate of approximately 50 million cubic feet of natural gas equivalents per day (MMcfe/d) (15 MMcfe/d net to McMoRan) in May and June of 2011.
• Boudin
  • Exploratory well commenced drilling on February 27, 2011 and is drilling below 19,350 feet towards a proposed total depth of 23,100 feet.
• Second-quarter 2011 production averaged 197 MMcfe/d net to McMoRan, compared with 165 MMcfe/d in the second quarter of 2010.
• Average daily production for 2011 is expected to approximate 185 MMcfe/d net to McMoRan, including 180 MMcfe/d in third quarter 2011.
• Operating cash flows totaled $102.6 million for the second quarter of 2011, including working capital sources of $28.4 million and $20.0 million in abandonment expenditures.
• Capital expenditures totaled $162.4 million in the second quarter of 2011 and $258.9 million for the six months ended June 30, 2011.
• Cash at June 30, 2011 totaled $765.3 million.

James R. Moffett and Richard Adkerson, McMoRan's Co-Chairmen, said, "The data gained to date from our ultra-deep drilling program in the shallow waters of the Gulf of Mexico add to our enthusiasm for the resource potential of this important new geologic trend. Through our drilling activities, we have confirmed the potential for large hydrocarbon bearing structures below salt in the Miocene, Wilcox, Frio, Tuscaloosa and Cretaceous Carbonate formations. Our ongoing exploration drilling and flow testing of the Davy Jones wells in the coming months have the potential to enhance our reserve and production profile meaningfully."

PRODUCTION AND DEVELOPMENT ACTIVITIES

Second-quarter 2011 production averaged 197 MMcfe/d net to McMoRan, compared with 165 MMcfe/d in the second quarter of 2010. Production in the second quarter of 2011 was higher than McMoRan's previously reported estimates of 190 MMcfe/d in April 2011 because of favorable production performance. Production is expected to average approximately 180 MMcfe/d in the third quarter of 2011 and 185 MMcfe/d for the year, higher than the previous 2011 annual estimate of 175 MMcfe/d. McMoRan's estimated production rates are dependent on the timing of planned recompletions, production performance, weather and other factors.

Production from the Flatrock field averaged a gross rate of approximately 172 MMcfe/d (70 MMcfe/d net to McMoRan) in the second quarter of 2011. McMoRan owns a 55.0 percent working interest and a 41.3 percent net revenue interest in the Flatrock field.

As previously reported, McMoRan successfully commenced production from the Laphroaig No. 2 well in St. Mary Parish, Louisiana in late April 2011. Production from the Laphroaig No. 2 well averaged a gross rate of approximately 50 MMcfe/d (15 MMcfe/d net to McMoRan) in May and June of 2011. McMoRan owns a 38.4 percent working interest and a 29.5 percent net revenue interest in the Laphroaig No. 2 well. Energy XXI (NASDAQ:EXXI - News) holds an 18.8 percent working interest.

As previously reported, the Brazos A-23 development well commenced drilling on February 13, 2011, and was drilled to a total depth of 15,946 feet. This traditional Shelf well targeted proved undeveloped reserves updip from logged pay zones. Log evaluation indicated that the well encountered 30 net feet of hydrocarbon bearing sands and a protective liner has been set. The well has been temporarily abandoned while future plans are developed. McMoRan owns a 100.0 percent working interest and an 81.25 percent net revenue interest in the well. McMoRan recorded a $23.8 million impairment charge in the second quarter to reduce the carrying value of the Brazos A-23 well to $17.4 million.

EXPLORATION ACTIVITIES

McMoRan's exploration strategy is focused in the shallow waters of the Gulf of Mexico (GOM) and Gulf Coast area on the "ultra-deep gas play" and on the "deep gas play."

Shallow Water, Ultra-Deep Exploration Update

Since 2008, McMoRan has actively pursued large ultra-deep targets located in the shallow waters of the GOM below the salt weld (i.e. listric fault) at depths generally below 25,000 feet. The data gained to date from four wells confirm McMoRan's geologic model and the highly prospective nature of this emerging geologic trend. Prior to McMoRan's involvement in the ultra-deep, there had been only two wells drilled on the Shelf targeting these objectives; one did not reach its targeted depth and the other was outside McMoRan's focus area. McMoRan's results to date have indicated the potential for large accumulations of hydrocarbons at these deeper depths in the shallow waters of the GOM.

McMoRan's activities to date have confirmed that drilling below the salt weld on the Shelf of the GOM can be achieved safely. In addition, the data indicate the presence below the salt weld of geologic formations including Middle/Lower Miocene, Wilcox, Frio, Tuscaloosa and Cretaceous carbonate. These formations have been prolific onshore, in the deepwater GOM and in international locations. McMoRan is encouraged by the results which indicate the potential for prospects with high quality reservoirs on large structures with multi-Tcfe of gross unrisked potential. McMoRan intends to conduct further drilling and flow testing to determine the ultimate potential of this emerging geologic trend.

The Davy Jones offset appraisal well (Davy Jones No. 2), located on South Marsh Island Block 234 two and a half miles southwest of the Davy Jones No. 1 discovery well, was drilled to a total depth of 30,546 feet. Log results above 27,300 feet confirmed 120 net feet of hydrocarbon bearing Wilcox sands, indicating continuity across the major structural features of the Davy Jones prospect.

In June 2011, results from wireline logs of the Cretaceous section below 27,300 feet indicated that the Davy Jones No. 2 well encountered 192 net feet of potential hydrocarbons in the Tuscaloosa and Lower Cretaceous carbonate sections. Flow testing will be required to confirm the potential hydrocarbons and flow rates. A 6 5/8 inch production liner has been set to 30,511 feet and the well has been temporarily abandoned. McMoRan is evaluating development options and expects to commence completion of the No. 2 well for flow testing in the second quarter of 2012. McMoRan is also considering updip locations in a subsequent well to the north to evaluate the Tuscaloosa sands and Lower Cretaceous carbonates higher on the Davy Jones structure.

The Tuscaloosa sands are correlative with the prolific Tuscaloosa trend onshore South Louisiana and the carbonate section may be analogous to productive fields located offshore and onshore Mexico in the southern GOM. These potential hydrocarbon bearing zones are the first Cretaceous sandstones and limestones encountered offshore Central Louisiana on the GOM Shelf. McMoRan believes the combination of productive Wilcox and Cretaceous intervals on the same structure could enhance the value of Davy Jones and the prospectivity of McMoRan's other ultra-deep prospects on its acreage position within the Davy Jones trend.

As previously reported, in January 2010 McMoRan logged 200 net feet of pay in multiple Wilcox sands in the Davy Jones No. 1 well on South Marsh Island Block 230. In March 2010, a production liner was set and the well was temporarily abandoned to prepare for completion. McMoRan is preparing to complete and flow test the No. 1 well in late 2011.

Davy Jones involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres). McMoRan holds a 60.4 percent working interest and a 47.9 percent net revenue interest in Davy Jones. Other working interest owners in Davy Jones include: Energy XXI (15.8%), JX Nippon Oil Exploration (U.S.A.) Limited (12%), Moncrief Offshore LLC (8.8%) and a private investor (3%). McMoRan's total investment in Davy Jones, a substantial majority of which is associated with allocated costs associated with the PXP property acquisition, totaled $619.4 million at June 30, 2011.

In July 2011, McMoRan commenced operations to drill a by-pass of the Blackbeard East ultra-deep exploration well at approximately 30,700 feet to evaluate targets in the Eocene. The well is permitted to 34,000 feet. Based on interpretations of drilling data obtained in the first quarter of 2011 prior to the mechanical issue, McMoRan believes the well encountered Sparta sands in the Eocene, which are younger than the Wilcox. Sparta sands are productive onshore in South Louisiana. Wireline logs will be required to evaluate this interval.

As reported in January 2011, wireline logs indicated that Blackbeard East encountered hydrocarbon bearing sands in the Oligocene (Frio) with good porosity below 30,000 feet. McMoRan is considering down dip drilling opportunities on the flanks of the structure to evaluate this section further. This is the first hydrocarbon bearing Frio sand encountered either on the GOM Shelf or in the deepwater offshore Louisiana. The Frio sand section below 30,000 feet is in addition to the 178 net feet of hydrocarbons in the Miocene sands above 25,000 feet announced in December 2010 at Blackbeard East. Pressure and temperature data below the salt weld between 19,500 feet and 24,600 feet at Blackbeard East indicate that a completion at these depths could utilize conventional equipment and technologies.

Blackbeard East is located in 80 feet of water on South Timbalier Block 144. McMoRan holds a 70.0 percent working interest and a 56.2 percent net revenue interest in the well. Other working interest owners in Blackbeard East include: EXXI (18.0%), Moncrief Offshore LLC (10.0%) and a private investor (2.0%). McMoRan's total investment in Blackbeard East, which includes allocated costs associated with the PXP property acquisition, totaled $216.1 million at June 30, 2011.

The Lafitte ultra-deep exploration well commenced drilling on October 3, 2010 and is currently drilling below 24,200 feet towards a proposed total depth of 29,950 feet. Lafitte is located on Eugene Island Block 223 in 140 feet of water. The well is targeting Miocene objectives and possibly Oligocene (Frio) sections below the salt weld. McMoRan holds a 72.0 percent working interest and 58.3 percent net revenue interest in Lafitte. Other working interest owners in Lafitte include: EXXI (18.0%), and Moncrief Offshore LLC (10.0%). McMoRan's total investment in Lafitte, which includes allocated costs associated with the PXP property acquisition, totaled $100.2 million at June 30, 2011.

Information gained from the Blackbeard East and Lafitte wells is expected to assist McMoRan in developing plans for future operations at Blackbeard West. As previously reported, the Blackbeard West ultra-deep exploratory well on South Timbalier Block 168 was drilled to 32,997 feet in 2008. Logs indicated four potential hydrocarbon bearing zones that require further evaluation and the well was temporarily abandoned. McMoRan is evaluating whether to drill deeper at Blackbeard West, drill an offset location or complete the well to test the existing zones.

McMoRan has also identified a new location within the Blackbeard West unit on Ship Shoal Block 188 to evaluate the Miocene age sands seen in Blackbeard East above 25,000 feet. McMoRan is developing plans to commence drilling this ultra-deep well, which has a proposed total depth of 26,000 feet, in the second half of 2011. The Ship Shoal Block 188 location is approximately 4 miles west of the Blackbeard West #1 well on South Timbalier Block 168. McMoRan holds a 67.3 percent working interest and 51.5 percent net revenue interest in the Blackbeard West well on Ship Shoal Block 188. McMoRan's total investment in Blackbeard West, which includes allocated costs associated with the PXP property acquisition, totaled $58.9 million at June 30, 2011.

Shallow Water, Deep Gas Exploration Update

In addition to the ultra-deep play on the Shelf of the GOM, McMoRan's exploration strategy is also focused on the "deep gas play." Deep gas prospects target large Miocene age deposits above the salt weld (i.e. listric fault) at depths typically between 15,000 to 25,000 feet.

The Boudin deep gas exploration well commenced drilling on February 27, 2011 and is drilling below 19,350 feet. Boudin, which is located in 20 feet of water on Eugene Island Block 26, has a proposed total depth of 23,100 feet and will test Miocene objectives. McMoRan holds a 53.5 percent working interest and a 42.4 percent net revenue interest in Boudin. EXXI holds a 20.6 percent working interest. McMoRan's total investment in Boudin, which includes allocated costs associated with the PXP property acquisition, totaled $49.1 million at June 30, 2011.

The Hurricane Deep well, which is located in 12 feet of water on South Marsh Island Block 217, was drilled to a true vertical depth of 21,378 feet in July 2011. Log results indicated the presence of Operc and Gyro sands that McMoRan determined could be pursued in an updip location. The well is being temporarily abandoned to preserve the wellbore and McMoRan is evaluating opportunities to sidetrack or deepen. McMoRan's total investment in Hurricane Deep, which includes allocated costs associated with the PXP property acquisition, totaled $54.5 million at June 30, 2011. McMoRan's investment is expected to be reduced by approximately $11 million for reimbursable costs associated with its insurance programs.

Second-quarter 2011 exploration expense includes $36.8 million in costs for the previously reported noncommercial well at Blueberry Hill.

REVENUES

McMoRan's second-quarter 2011 oil and gas revenues totaled $155.5 million, compared to $104.1 million during the second quarter of 2010. During the second quarter of 2011, McMoRan's sales volumes totaled 11.6 Bcf of gas, 778,400 barrels of oil and condensate and 1.6 Bcfe of plant products, compared to 9.8 Bcf of gas, 626,400 barrels of oil and condensate and 1.4 Bcfe of plant products in the second quarter of 2010. McMoRan's second-quarter comparable average realizations for gas were $4.71 per thousand cubic feet (Mcf) in 2011 and $4.66 per Mcf in 2010; for oil and condensate McMoRan received an average of $109.08 per barrel in second-quarter 2011 compared to $76.20 per barrel in second-quarter 2010.

CASH, LIQUIDITY AND CAPITAL EXPENDITURES

At June 30, 2011, McMoRan had $765.3 million in cash. Total debt was $561.0 million at June 30, 2011, including $74.7 million in Convertible Senior Notes due in October 2011 with a conversion price of $16.575 per share and $186.3 million in Convertible Senior Notes due in December 2017 with a conversion price of $16.00 per share. On June 30, 2011, McMoRan entered into a new five-year, $150 million senior secured revolving credit facility, which replaced the revolving credit facility that was scheduled to mature in August 2012. McMoRan had no borrowings and $100 million of letters of credit issued under its revolving credit facility resulting in total availability of $50 million at June 30, 2011.

Capital expenditures totaled $162.4 million for the second quarter of 2011 and $258.9 million for the six-months ended June 30, 2011. McMoRan expects 2011 capital expenditures to approximate $500 million, including $300 million for exploration and $200 million for development. Capital spending will continue to be driven by opportunities, drilling results and follow-on development activities.

Net abandonment expenditures, which include scheduled conventional and hurricane-related work, totaled $20.0 million for the second quarter of 2011 and $42.2 million for the six-months ended June 30, 2011. Abandonment expenditures are expected to approximate $160 million in 2011.

In the second quarter of 2011, McMoRan recorded $12.9 million in gains for reimbursable costs associated with its insurance programs. Since 2009, McMoRan has recorded $92.9 million in gains associated with the 2008 hurricane events in the GOM and continues to pursue reimbursement of certain hurricane-related abandonment costs under its insurance programs.

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Phoenix Drills Ahead at Marathon Well

- Phoenix Drills Ahead at Marathon Well

Wednesday, July 13, 2011
Petsec Energy Ltd.

Petsec advised that as at July 12, 2011, the Marathon #2 well had reached a measured depth of 18,845 feet (5,744 meters), 7 inch liner had been set and preparations were being made to drill ahead. The well is projected to reach its total depth of 21,000 feet (6,500 meters) within approximately 2 weeks.

The Marathon #2 well is a follow up to the successful #1 well and is situated in approximately 8 feet (2.4 meters) water depth and is located approximately 900 meters from the #1 well location. The #2 well is designed to serve as a development well for the field as well as to test deeper exploratory reserve potential on the Marathon structure.

Participating working interests in the well are:

• Petsec Energy Ltd 8%
• Phoenix Exploration Company LP (operator) 65%
• Private Companies 27%

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Premier Looks Ahead to Next Stage of Growth

- Premier Looks Ahead to Next Stage of Growth

Tuesday, July 12, 2011
Premier Oil plc

Premier provided a trading and operations update ahead of its 2011 Interim Results.

Simon Lockett, Chief Executive, commented, "With continuing good progress on our Asian development projects we expect to see a significant increase in production to around 60 kboepd by year end. Our development teams in the North Sea and Asia are already focused on delivering the next stage of Premier's growth. Our exploration program of around 20 wells over the next 12 months targets around 300 mmboe of unrisked prospective potential."

Production outlook

2011 to date has seen continuing good production performance from the Anoa field in Indonesia, while Pakistan's production has remained steady. This was offset by increased maintenance activity in the UK and a recent unplanned shutdown at Balmoral. As a result, estimated average group production for the first half of 2011 was 36.6 thousand barrels of oil equivalent (kboepd) (2010: 42.8 kboepd) and forecast full year production is now estimated at between 40 kboepd and 45 kboepd.

Near term developments in Asia (Chim Sao and Gajah Baru) are progressing well and 2011 year end run rate is expected to be around 60 kboepd as these projects ramp up. With the UK Huntington and Rochelle projects due on-stream next year, Premier is on target to reach a run rate of 75 kboepd in 2012. Our medium term target of 100 kboepd remains unchanged.

Singapore gas demand continues to grow for our gas exports from the Natuna Sea, with average gas sales under the West Natuna gas contract of 373 bbtud in the first half of 2011 compared to 357 bbtud in the second half of 2010. Block A's share of the contract amounted to 41 percent in the period (against a contractual share of 37 percent), though with a recovery in output from the other two PSC's participating in the contract, actual levels of production reduced from the prior period. Premier's production levels will rise in the second half of the year as the Gajah Baru development contributes from October.

In the UK, production was below expectations due to maintenance related downtime earlier in the year at the Balmoral and Wytch Farm facilities and a recent unplanned shutdown at Balmoral due to a subsea hydraulic leak. Production resumed at Balmoral on 4 July after a three week outage. Scott and Telford production has remained steady since April following earlier disruptions for gas compression maintenance.

As announced in June, Premier increased its stake in the Wytch Farm Assets by 17.715 percent. This is expected to add around 2.5 kboepd to Premier's UK production from year end 2011 when the transaction is targeted for completion. Following the shutdown in the first quarter, production at the Wytch Farm facilities has been rising in recent weeks to around 14 kboepd (gross).

Pakistan production is stable, with the natural decline in the fields offset by infill drilling and the completion of ongoing front-end compression projects. The successful K-18 sidetrack well on Kadanwari, which came on-stream in February 2011, continues to perform favorably. Delays in the front-end compression project at Zamzama are being resolved and increased production is anticipated imminently.

Current and future developments

Asia

In Vietnam, the Chim Sao project remains on schedule with first oil expected in August. On July 1, the FPSO moved from the Keppel yard to its offshore anchorage where deep water commissioning and trials were completed. The FPSO is now on tow to the Chim Sao field for the installation of the umbilicals that will connect it to the production wells.

The Gajah Baru project in Indonesia is progressing ahead of schedule. The Central Processing Platform topsides were installed on the jacket on July 6 and the bridge linking this to the wellhead platform was installed on July 7. Elsewhere on Block A, EPCI technical bids have been received and are under evaluation for the Anoa Phase 4 Development which will add additional compression capacity on the Anoa platform. In addition, the Front End Engineering and Design has been completed for the facilities and pipelines for the Pelikan and Naga fields. These projects are on target for sanction in the fourth quarter of 2011.

In North Sumatra, discussions with the shortlisted facilities EPCI bidders are under way. Technical bids are due in by September and final contract award is expected by year end. First gas on Block A Aceh remains on target for late 2013.

North Sea

The Huntington development in the UK is progressing, with work continuing on the Sevan Voyager FPSO upgrade project and sub-contracted modules. Timing for sail away (and therefore first oil) is likely to be impacted by the current financial situation of the FPSO supplier. Any material delay in the Huntington project will impact the average production for 2012 and the date at which a run-rate of 75 kboepd is achieved. In the meantime, key subsea equipment is on order and an installation contract has been signed. Development drilling commenced in April and is proceeding well.

An agreement for the Rochelle area has been executed with Premier acquiring a 15 percent equity in the unitised East and West Rochelle projects. First gas is anticipated for the fourth quarter of 2012. As previously announced, a Sale and Purchase Agreement for the Solan field was signed in May and Premier will become the development operator of the field at sanction with a 60 percent equity interest. Pre-sanction activities are progressing with final project approval targeted for later this year.

Development concept selection for Fyne is expected by year end, after the East Fyne appraisal well has been drilled. Discussions are ongoing with partners regarding potential development solutions for the Catcher Area. In Norway, development plans for the Froy field received Premier support for moving to the next phase. However, the operator has indicated that, due to limited resources and commitments elsewhere, they will not be proceeding with the project at this time. As a result, discussions with third party new entrants to the Froy project are underway. Dialogue also continues with the preferred contractor for the Bream field development regarding the timing of the FPSO availability.

Exploration and appraisal

Around 20 exploration and appraisal wells are planned during the next 12 months, with unrisked net prospective resource potential, on a P50 basis, of around 300 mmboe. Several of the planned wells for the first half of 2012 remain subject to partner approvals and government consents.

North Sea

As previously announced, the Grosbeak well in Norway was spudded in April 2011 and has now been sidetracked. The results of the sidetrack, which reached target depth on July 7, are anticipated later in July. Premier plans to drill its first operated well in Norway, the Gardrofa exploration well, in the third quarter of 2011.

Premier has signed a Heads of Agreement (HOA) with Antrim Energy to gain additional acreage in the Greater Fyne Area. Under the HOA, Premier will earn a 50 percent working interest in the acreage in return for funding a promoted share of the costs to drill a well on the Erne Prospect, which is planned for the third quarter. The Erne well will target an Eocene Tay Formation oil prospect located between the Fyne and Guillemot NW fields in the UK Central North Sea. A successful Erne exploration well will be taken into account for the Fyne development concept selection targeted for year end.

Separately the East Fyne appraisal well is now planned for the fourth quarter, using the Sedco 704 semi-submersible rig, the results of which - along with the results of the Erne exploration well - will feed into the Fyne development concept process. The Sedco 704 will then move to spud the Bluebell well, a prospect near to the Premier-operated Caledonia field and the Balmoral facility.

The Stingray well (Premier interest, 50 percent), which is scheduled for the first half of 2012, is targeting a Jurassic sandstone reservoir in UK Block 15/13b. In UK Block 28/9, the Joint Venture partners have decided to acquire 3D seismic data over the block in the second half of 2011. As a result, the Carnaby well will now be drilled in the first half of 2012.

Asia

In Indonesia, on the Tuna Block, Gajah Laut Utara was plugged and abandoned in June with oil and gas shows. The Ocean General Rig has now moved to Belut Laut, which spudded on 4 July. The Belut Laut prospect is in a separate sub-basin to that of Gajah Laut Utara and is an independent test of the petroleum system on the Tuna acreage. The results of Belut Laut are expected in August.

Elsewhere in Indonesia the Benteng-1 well on the Buton licence is expected to be drilled in the first quarter of 2012. The Matang-1 well on Block A Aceh is also scheduled to be drilled in the first quarter of 2012. The Antareja Resources land rig, Antareja-8, has been contracted for Matang-1.

Pakistan

As previously announced, the K-27 exploration well was successful and will be tied back to the production facility by the end of the third quarter, delivering around 30 MMscfd (gross). The K-29 and K-30 exploration wells, together with Badhra-6 Parh, are planned for late 2011.

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Rodinia Drills Ahead at Mulyawara Well

- Rodinia Drills Ahead at Mulyawara Well

Tuesday, July 05, 2011
Rodinia Oil Corp.

Rodinia reported that Mulyawara-1 exploration well in the Officer Basin of South Australia has set surface casing and is drilling ahead to target formations.

rogress and Plan

Mulyawara-1 has reached a depth of 795 meters with surface casing set at 465 meters in the Dey Dey Mudstone. The well will commence intersecting prospective target formations below the Dey Dey Mudstone, which acts as the upper regional seal in the Officer Basin.

"To date, I am pleased with the rates of penetration into this very hard surface section," stated Paul Bennett, President and Chief Executive Officer of Rodinia. "Our plan is to continue drilling ahead using the air hammer drilling technique as far as possible and if necessary, switch to rotary drilling should penetration become too difficult."

Mulyawara-1 is located in the northwest corner of PEL 253 in the Officer Basin on a structure of approximately 36.3 square kilometers (per horizon) in size as identified on seven separate 2-D seismic lines. It will be drilled vertically to an estimated total drilling depth of 2,700 meters to test five prospective reservoir horizons: Murnaroo, Tarlina, Mundallio, Emeroo and Pindyin, the deepest of which is the aeolian Pindyin sandstone (also called the sub-salt unit).

As Mulyawara-1 is entering the prospective target formations, management of Rodinia has imposed an operational trading blackout on all officers, employees, directors and consultants until the results of the exploration well are made public at the conclusion of drilling and preliminary evaluation.

Rodinia expects to issue the next drilling update report once Mulyawara-1 has reached total depth early August 2011, unless a material event occurs in the interim.

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Breitling Charges Ahead in Haynesville Play

- Breitling Charges Ahead in Haynesville Play

Tuesday, July 05, 2011
Breitling O&G Corp.

Breitling O&G issued an operational update on the company's recent activity related to the development of various oil and gas properties in its portfolio. Oil and Gas is working very hard to retain all of its viable Haynesville leases in this difficult pricing environment.

Through June 15, 2011 the company participated in 171 new wells, 21 operated and 150 non-operated. The company is running 4 rigs currently. Breitling Oil and Gas expects to drill an additional 112 wells in the second half of 2011. The company has two frac fleets on retainer and had an inventory of ten wells awaiting completion as of June 2011. Breitling Oil and Gas has leaseholds in Texas that are prospective for the Eagleford Shale; leaseholds in Colorado that are prospective for the Niobrara Shale; leaseholds in Oklahoma that are prospective for the Woodford Shale; and leaseholds in Louisiana that are prospective for the Haynesville and Bossier Shales. The company recently hydraulic fractured its fifth Eagleford well in Guadalupe County, Texas and will commence production operations on this well sometime in August 2011. The company is working in partnership with Sandridge Energy on three wells in Gaines County, Texas and is preparing to spud a well with Devon Energy in Hemphill County, Texas.

Breitling Oil and Gas is developing the Haynesville Shale on acreage in Louisiana, and has three gross wells waiting on completion. The company expects hydraulic fracturing capacity to be available in August 2011 and will start completion operations on this backlog at that time.

Breitling Oil and Gas is working in the Woodford Shale in Oklahoma. The company has six prospects it plans to drill during the second half of 2011. It expects production to commence from the field in early 2012.

Breitling Oil and Gas chief executive officer Chris Faulkner stated, "Breitling has done a great job shifting its focus to liquids during a very difficult gas commodity trading price this year." Faulkner added, "Breitling Oil and Gas is carrying very little debt, is involved in no litigation and lawsuits, has a perfect safety record and has positioned itself for triple-digit revenue growth for the foreseeable future."

The company continues driving innovation within its EnviroFrac™ program which the company started in January 2010. Breitling Oil and Gas' EnviroFrac™ calls for the elimination of any additive not critical to the successful completion of the well and determines if greener alternatives are available for all essential additives.

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San Leon Looks Ahead to Polish Drilling Programs

- San Leon Looks Ahead to Polish Drilling Programs

Thursday, June 23, 2011
San Leon Energy plc

San Leon provided the following Operational Update.

Poland - Exploration program continues as planned

• Interpretation and prospect evaluation is ongoing in Szczecinek Block 106 (San leon 50%). San Leon and its partner, Gas Plus, are looking at further studies including a regional core study to evaluate the paleogeography and continued evaluation of the newly acquired 3D survey. Gas Plus, the operator of the license, are likely to delay drilling until 2012 (from 3Q 2011) due to internal planning considerations.
• The Baltic Basic 2D seismic program, over the Gdansk W, Braniewo and Szczawno Concessions, was completed in June 2011. The Company successfully acquired 480 km of 2D data. The program was completed with a perfect HSE (Health, Safety and Environment) performance. A drilling rig has been booked for August 1, 2011, which will be used to drill three back-to-back wells.
• Geofizyka Krakow completed 120 km of high quality 2D seismic over the Company's 100% owned Nida Concession in May 2011. The data has been interpreted and confirmed three high potential structures on trend with the prolific Grobla and Plowice oil fields. A San Leon subsidiary, Vabush Energy, plans to drill two of these prospects commencing in July/August 2011.
• Acoustic Geophysical has started the acquisition of 165 km2 of 3D seismic on the Company's 100% owned Nowa Sol Concession. The survey is currently c.20% complete and is seeking to delineate numerous prospects and leads along the southern Fore Sudetic Monocline of the Permian Basin. This survey is designed to support an upcoming drilling campaign in the Nowa Sol Concession which is currently planned to start in 4Q 2011.
• Work is ongoing in the Carboniferous shale play across the Wschowa, Gora, Winsko and Rawicz Concessions (San Leon 100%). The Company continues to evaluate the existing core and well data in preparation for the first exploration well in the area which is planned for 4Q 2011. Core analysis is being performed by TerraTek (Schlumberger) and the Polish Oil & Gas Institute in Krakow. Petrophysics on the existing well logs has been performed by NuTech.

Morocco

• The Tarfaya Oil Shale pilot project is well advanced.
• The base camp has been constructed and all operational personnel are on site with all communications systems in place.
• The pilot plant site construction and the assembly of the process equipment has been completed.
• Two wells have been drilled at a distance of 10 meters apart confirming the presence of 30 meters of prospective oil shale at a depth of 195 meters. This is slightly thicker than the original prognosis. The initial model provided by ONHYM (Morocco National Office of Hydrocarbons and Mines) has also been confirmed by the well logs.
• A pre frac injection test with water was applied to collect data concerning the natural connectivity between the two wells and was followed by a mini hydro frac. This was unable to establish connectivity between the wells.
• Initial analysis of these tests has suggested the presence of natural fractures in the shale. San Leon is encouraged by the possibility of these natural fractures which could enhance the propagation of heated gas throughout the prospective intervals.
• The Company is re-evaluating the technical program to incorporate the new data gained from these tests into its model for commercial extraction of oil from the Tarfaya Shale.
• The Company plans to drill a third test well using the same rig in August 2011. Core data will be collected, from this well, in order to evaluate the local geologic parameters of the prospective shale interval as well as the presence and orientation of any natural fractures at the pilot location. Following the drilling of the third well, San Leon will again perform a small frac on the shale to establish connectivity between the wells. Based upon these results injection tests will be designed to take advantage of the fractures.
• Upon successful flow testing with water, followed by nitrogen, propane will subsequently be brought to the pilot plant to test the process of heating the shale with natural gas.
• San Leon's new seismic acquisition subsidiary, NovaSeis, is up and running in Morocco. NovaSeis plans to start the acquisition of 1,200 km of 2D seismic in its Tarfaya and Zag Licenses by July 1, 2011.
• Full re-interpretation of the seismic data on the offshore Foum Draa and Sidi Moussa Licenses is near completion. Once this is successful, the Company is likely to seek farm-in partners for drilling.

Ireland

• Following the Company's acquisition of Island Oil & Gas plc, San Leon continues to appraise its high impact Atlantic Margin assets and is seeking farm-in partners.
• San Leon completed a 250 km2 3D seismic survey on the North Porcupine License (FEL 1/04) in May 2011. The offshore survey was designed to evaluate the highly prospective C1 Lead. PGS Exploration UK Limited was contracted to carry out the survey using the M/V Ramform Vanguard. San Leon has a seismic services agreement with PGS Ventures AS, who is providing a US $50m facility for seismic services, part of which was used for this survey. We expect to finalize the data processing contractor(s) in the coming weeks. Seismic processing is expected to be complete in early 4Q 2011.
• The Company continues to interpret the 300 km2 Slyne License (FEL 4/06) 3D survey. Delays in processing and interpretations are the result of very complex structural issues and significant surface volcanics which have made imaging some areas of the survey very difficult. The initial interpretation is encouraging and the Company plans to open a data room in August/September 2011.
• Following the completion of the assignment of OMV's 50% interest in Rockall License (FEL 3/05) to San Leon in March 2011, the Company had insufficient time to secure a seismic survey vessel for the license in Summer 2011. San Leon expects to apply to the Irish Government for a license extension.
• The company is also considering several options for data acquisition/analysis of the South Porcupine License (FEL 3/08) including 2D/3D seismic and controlled source electro magnetic data acquisition with a view to seeking a farm-in partner to the license.
• 3D seismic acquisition operations have commenced on Barryroe Licensing Option (08/01) in the north Celtic Sea, offshore Ireland. Polarcus has been contracted to carry out a 220 km2 survey, which is expected to be completed by the end of June.

Albania

• The 840 km2 Durresi Block 3D seismic acquisition survey was completed in April 2011. The data is currently being processed by Western Geophysical in London, who are expected to deliver the final processed data in early 4Q 2011. Parallel interpretation and prospect generation will continue in the interim.
• The 3D seismic program will evaluate a number of highly prospective structures in the Block, including the A4-1X discovery, in preparation for a planned 2012 exploration and appraisal drilling program.

Netherlands

• GDF Suez E&P Nederland B.V, the new 50% owner in the Amstel Field, offshore Netherlands, has successfully completed the drilling of an appraisal well on March 29, 2011. The partners are currently evaluating a development plan for the oil field, in which San Leon Energy holds a 2.5% royalty.

Italy

• San Leon has notified the Italian authorities that it is relinquishing two offshore Sicily permits. The Company has made the decision following the publication of a new Italian Environmental Law in June 2010 which placed tighter restrictions on oil and gas exploration within five nautical miles of the coast and twelve nautical miles of any protected environmental area. In effect, San Leon would not have gained an environmental authorization to drill exploration or appraisal wells in two permit areas, D.352 CR-SL (Narciso) and D.354 CR-SL (Sciacca). The relinquishment will become effective upon publication of a notice in the official Italian Ministerial Gazette, B.U.I.G.. San Leon will continue to retain D.353 CR-SL (Narciso South) and its two onshore Po Valley assets Sorbolo and Sospiro.

Oisin Fanning, Chairman of San Leon Energy commented, "We continue to make steady progress and meet our objectives as we move from seismic acquisition to drilling on many of our licenses. The completion of three seismic acquisition programs in Poland, particularly the 2D seismic acquisition in the Baltic Basin, and the start of another program on our Nowa Sol Concession mean our shareholders can now look forward to drilling these prospects over the coming months.

Furthermore, our new seismic acquisition company, Novaseis, is about to begin the first of two seismic acquisition programs in Morocco and this follows the successful completion of our offshore Albania and Atlantic Margin Ireland surveys.

The Company's operational and technical capacity continues to grow in line with our increasing activity, particularly in Poland, where our knowledge base and expertise is geared towards delivering near term value for our shareholders."

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