Solo Oil Ups Stake in Tanzania Ruvuma Basin

- Solo Oil Ups Stake in Tanzania Ruvuma Basin

Thursday, September 08, 2011
Solo Oil plc

Solo Oil announced an update on its plans for the drilling of an exploration well, Ntorya-1, in the Mtwara Block of the Ruvuma Basin PSA in Tanzania with its partners Tullow Oil and Aminex.

Further to the announcement on June 7, 2011, plans for the Ntorya-1 well have now been finalized with the all major services tendered and the Caroil-6 rig mobilization agreed to follow the current Aminex well Nyuni-2. The well will most likely be spudded in early November and is programmed to take 25 days to drill to a planned TD of 2026 meters.

Solo also announce that it has increased its stake in the Ruvuma Basin PSA from 12.5% to 18.75% in an agreement with Tullow in which Solo will assume the future obligations on the additional interest. Both Solo and Aminex have acquired additional interests in the PSA and Aminex will take over as operator from Tullow with immediate effect. Tullow will retain a 25% interest and will continue to support the joint venture with regional expertise and logistics.

The assignment is subject to final Tanzanian Government approval, which is expected to be granted shortly.

Solo Executive Director Neil Ritson commented, "The Ntorya-1 well, which is a follow up to the Likonde-1 well drilled in 2010, is an important further test of the largely unexplored onshore Ruvuma Basin. Both Solo and Aminex have a strong focus on Tanzania and by gaining a greater participation in the PSA will jointly be able to advance the work program more quickly. The long term potential is significant and we are very keen to continue the work started at Likonde as soon as possible."

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TAG Enters Farmout Agreement with Apache in NZ East Coast Basin

- TAG Enters Farmout Agreement with Apache in NZ East Coast Basin

Friday, September 02, 2011
TAG Oil Ltd.

TAG Oil reported that it has entered into a farmout agreement with Apache to explore and potentially develop oil and natural gas resources in the East Coast Basin of New Zealand.

Apache has agreed to conduct a multi-phased exploration, appraisal and potential development program within TAG's East Coast Basin exploration permits PEP 38348, PEP 38349 and PEP 50940. The Permits comprise in excess of one million prospective acres of onshore oil and gas opportunities located on the southeast portion of the North Island. TAG currently holds a 100% working interest in the properties.

Apache has agreed to pay for a portion of TAG's direct costs incurred to date, as well as providing TAG a full carry on three phases of operations to a maximum agreed cost in each phase. If the agreed cost is exceeded in any phase, or if additional operations are conducted, Apache will pay a majority share of any drilling or seismic costs in the specified percentages set out in the Agreement.

Each phase of operations will include an aggressive program of both 2D / 3D seismic and drilling with Apache earning an increasing interest in the Permits as follows:

• Phase 1: Apache will earn a 50% interest in 5,120 acres of the Permits after operations are conducted and by committing to Phase 2.
• Phase 2: Apache will earn a 25% interest in the Permits after operations are conducted and by committing to Phase 3.
• Phase 3: Apache will earn a 50% interest in the Permits after operations are conducted and by committing to Phase 4 operations.

Subject to certain conditions, the planned exploration work program will be conducted over the next four years. Seismic operations will start in 2011 with drilling to commence in 2012.

Apache will be the Operator for all activities undertaken pursuant to the Agreement, excluding the initial four vertical wells of the work program that TAG will operate with Apache's assistance. Apache will spend up to $100 million upon completion of Phase 3 to earn a 50% interest in the Permits. At the end of Phase 3 operations TAG will remain as operator of the Permits. If Apache commits to Phase 4 operations, all costs will then be shared equally between Apache and TAG going forward.

TAG Oil CEO, Garth Johnson, commented, "TAG Oil is excited and honored to partner with Apache in the East Coast Basin to achieve a common goal of converting the potential of the East Coast Basin to proven reserves with integrity, respect and excellence in a safe and environmentally responsible manner. We are planning an aggressive exploration program with Apache with a starting date of September 2011 to initiate seismic acquisition with drilling to begin in early 2012"

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Beach Secures Rigs for Shale Gas Plays in Cooper Basin

- Beach Secures Rigs for Shale Gas Plays in Cooper Basin

Monday, August 29, 2011
Beach Energy Ltd.

Beach has secured two Ensign rigs, Ensign#65 and Ensign#16, to drill both horizontal and vertical wells targeting its unconventional gas play in the Nappamerri Trough of the Cooper Basin. From recent drilling results, it is clear that the target zone in PEL 218 (Beach 90%) goes beyond shale and incorporates other lithologies that are also gas saturated. Beach believes, that in addition to the substantial shale gas potential, it is now dealing with an unconventional basin centered gas play.

The 2012 program for these rigs will focus on pilot horizontal production wells in both ATP 855P (Beach 40%) and PEL 218, as well as a series of vertical delineation wells in PEL 218. The program is designed to test the significant potential of the basin centered play in what is now considered a thick, continuous, multi lithology gas accumulation across the PEL 218 permit and potentially ATP 855P.
Details of the rigs and the two separate programs are as follows:

Ensign#65 (ADR1500):

• New build 1,500 horsepower rig out of Canada and the US which is expected to arrive around April 2012;
• Encompasses the latest proven technology being used for drilling horizontal wells in the Haynesville shale province in the US;
• Will be built to meet Australian standards and conditions and has the capability to drill 1,500 meter laterals from a depth of 4,000 meters; and
• Will drill the first horizontal well in ATP 855P to target shale and other lithology target zones. Upon completion of this well, the rig will commence the horizontal pilot well program in PEL218, with two pilot horizontal wells planned adjacent to Holdfast-1 and Encounter-1.

Ensign#16:

• 1,200 horsepower rig used to drill Holdfast-1 and Encounter-1, which is currently in the Officer Basin and expected to be available around January 2012;
• Will drill a series of vertical wells in PEL 218 to continue the evaluation of the continuous basin centred gas play in the permit; and
• Has the capability of drilling to 4,270 meters, with the vertical program set to increase the size of the resource in PEL 218 beyond the initial booking of 2 trillion cubic feet. This booking relates to a restricted area of 100km2 around each of Holdfast-1 and Encounter-1.

Beach Managing Director Reg Nelson said, “Beach has started to unlock a significant basin centred unconventional gas play in the Cooper Basin. These two rigs will take us a step closer to understanding the extent of the gas resource that resides within our permits. The horizontal pilot wells to be drilled by Ensign#65 will be production style wells designed to flow gas at commercial rates. Should these wells be successful we will seek to commence a pilot development program as soon as possible.”

• PEL 218 (Permian JV): Beach (90% and Operator), Adelaide Energy Ltd (10%)
• ATP 855P: Beach (40% and Operator), Icon Energy Ltd (40%) and Adelaide Energy Ltd (20%)

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OGX Concludes Drill-Stem Test in Santos Basin

- OGX Concludes Drill-Stem Test in Santos Basin

Monday, August 29, 2011
OGX S.A.

OGX has concluded the drill-stem test performed in the Santonian section of well 1-OGX-47-RJS, in the BM-S-59 block, in the shallow waters of the Santos Basin. OGX has a 100% interest in this block.

"With a successful exploration campaign underway in the Santos Basin, we initiated the drill-stem test phase. This is the first of a series of tests which has obtained significant productivity data from our sandstone reservoirs and represents an important step in broadening our understanding of this basin and in beginning the development of this area," commented Paulo Mendonça, OGX's General Executive Officer and Exploration Officer.

Following the discovery announced on July 1, 2011, a drill-stem test was performed in a vertical well in the Maceió accumulation. Besides the presence of gas, the test confirmed the existence of condensate of about 50° API that should account for around 20% of the hydrocarbon volume of this structure. The results of this test, with three production intervals, indicate a production potential of 1 million cubic meters per day in a vertical well, which could reach 2.5 million cubic meters per day in a horizontal well, both at Absolute Open Flow.

The test information is extremely important to the Company, because when combined with the accumulations of Natal (OGX-11), which will be the next well to be tested, and Aracaju (OGX-19), which will be tested in a Discovery Appraisal Plan, indicate the existence of one more important gas and condensate region in Brazil.

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

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AWE Updates Activities in Perth Basin

- AWE Updates Activities in Perth Basin

Friday, August 26, 2011
AWE Ltd.

AWE advised that preparations have continued for the planned hydraulic stimulation activities in the onshore Perth Basin. Preparation works on the Woodada Deep-1 and Arrowsmith-2 wells have been completed, and the final preparatory workover activities on the Senecio-1 well are now under way.

As previously advised to ASX, these stimulation activities are planned to proceed in the September quarter, subject to the receipt of all regulatory approvals.

Currently, the Woodada Deep and Arrowsmith activities have been referred to the Western Australian Environmental Protection Agency and a decision is expected in September.

The forward program for operational activities will be dependent on the receipt of these final regulatory approvals and the availability of the stimulation equipment, which is currently located at Dongara, in the Perth Basin. Given the current delays in the receipt of these approvals, there is a risk the stimulation equipment may not be available to commence this work in the September quarter.

AWE will advise further on this timing and the progress towards the stimulations when further information is made available from the regulators.

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Beach to Construct New Flowline from Cooper Basin Western Flank

- Beach to Construct New Flowline from Cooper Basin Western Flank

Thursday, August 25, 2011
Beach Energy Ltd.

Beach has signed an agreement with Senex to tie-in the Growler Field (Beach 40%) to the Lycium oil field. It has also agreed with Senex to construct a trunkline from Lycium to the Moomba facility, however, the tie-in of this section remains subject to approval from the South Australian Cooper Basin (SACB) Joint Venture (~Santos Ltd 67%, Beach 20%, Origin Ltd 13%).

It is anticipated that the flowline from the Growler Field will be constructed in two main sections. The first section, directly from the Growler Field to the Lycium oil field, will consist of a six inch flowline with an initial capacity of approximately 8,000 barrels of oil per day. The equity interests for this section of flowline will be Beach 40% and Senex 60%.

Pending approval from the SACB Joint Venture, the main trunkline will service the whole of Beach's operated and non-operated Western Flank acreage and is planned to run between Lycium and the Moomba facility. The capacity of this eight inch trunkline is expected to be in the order of 15,000 barrels of oil per day. The equity interests for this section will be Beach 60% and Senex 40%.

Beach will undertake both the construction and operatorship of the flowlines, with the total cost of approximately $40 million to be effectively shared between Beach and Senex.

These flowlines will provide Beach with access to the Growler Field during times of flooding in much the same way it has for Beach's PEL 92 acreage during the recent flooding events. The second trunkline will also provide for increased production flows from Beach's operated PEL 91 and PEL 92 acreage as a result of recent development, appraisal and exploration success in the area.

The six well approved exploration program set down for PEL 104 and PEL 111 is expected to commence in October 2011, when flood waters are forecast to recede to levels where access can be restored. A number of Birkhead targets have been identified by the Operator which has had an exploration drilling success rate of 80% in the acreage to date.

The tenure of the Beach Operated Western Flank PEL's 91 and 92 have been granted a twelve month extension by PIRSA in acknowledgment that flooding has delayed exploration in the area. It is expected that the flowlines will be commissioned around June 2012.

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Petrolympic Tests Well in Tx. Maverick Basin

- Petrolympic Tests Well in Tx. Maverick Basin

Tuesday, August 23, 2011
Petrolympic Ltd.

Petrolympic announced the completion of the Acid Stimulation on the 80-2V well located on the Chittam Ranch property in the Texas Maverick Basin. The operator, "Big Shell Oil & Gas, Inc.", stimulated the lowest level reservoir and will appraise the reservoir characteristics of multiple stacked oil bearing horizons starting with the bottom and working its way up. The target reservoir is now on test and Petrolympic expects to announce production rates in the near term.

"Well 80-2V responded extremely well to our stimulation techniques which included the use of new acids that were specifically designed to maximize production," commented Robert Kinsey, Petrolympic's Chief Engineer. "We are currently testing and expect to have production numbers out in the near future. I am very pleased with our progress to date and we hope to discover additional untapped potential as we work our way up through the multiple hydrocarbon bearing horizons."

"This was a low cost vertical well which we were able to complete in a relatively short period," said CEO Mendel Ekstein. "The geology which underlies well 80-2V is prevalent throughout the property and if the oil production rate warrants expansion our goal is to drill multiple wells at 40 acre spacing on the 8,000 acre Chittam Ranch Property which would provide for significant production."

During drilling of the well, Petrolympic penetrated 7 oil and gas bearing horizons. The Chittam Ranch well is being drilled by Petrolympic as part of an earn in agreement with Texas HBP and Shell Western E&P, pursuant to which Petrolympic has the right to earn a 50% working interest (yielding a 37.5% net revenue interest) in the Chittam Ranch property.

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Magnum Hunter: Proposed Acquisition in Williston Basin Did Not Close

- Magnum Hunter: Proposed Acquisition in Williston Basin Did Not Close

Friday, August 19, 2011
Magnum Hunter Resources Corp.

Magnum Hunter announced that the previously announced proposed acquisition by its wholly owned subsidiary, Williston Hunter ND, LLC, of oil and gas properties in the Williston Basin in North Dakota from Eagle Operating, Inc. ("Eagle") did not close yesterday due to unresolved issues between the parties resulting from what Magnum Hunter considers to be Eagle's intentional and bad faith breach of its obligations under the Purchase and Sale Agreement ("PSA"). In the proposed acquisition, Magnum Hunter would have acquired from Eagle for total consideration of $57 million ($55 million in cash and $2 million in Magnum Hunter restricted common stock), the remaining approximate 48% working ownership interest in the Williston Basin properties owned by Eagle, subject to Eagle's retention of a variable overriding royalty interest not exceeding 2% on certain properties.

The acquisition would also have resulted in the settlement of two pending lawsuits between the Company and Eagle currently filed in the United States District Court for the District of North Dakota (Northwestern Division), which litigation is now expected to continue. Management of Magnum Hunter does not consider this pending litigation to be of any material nature to the Company.

Magnum Hunter has today filed a new lawsuit against Eagle in the United States District Court for the District of North Dakota (Northwestern Division) asking the court to order Eagle to comply with its obligations under the PSA and complete the sale of the properties to the Company on the specific terms outlined in the PSA. Magnum Hunter is also seeking monetary damages, including compensatory, consequential and general damages, for Eagle's material default under the PSA. The Company intends to vigorously pursue all available remedies against Eagle.

As of August 18, 2011, Magnum Hunter had total liquidity including cash and availability under its various credit facilities of approximately $75 million, of which approximately $55 million is currently available to continue to fund its upstream capital program focused on the Company's high growth unconventional resource plays. In addition, Magnum Hunter has a commitment from its bank group to provide an additional $42.5 million in borrowing capacity for the purchase of the Eagle properties referenced above. Moreover, Magnum Hunter continues to pursue various non-dilutive alternatives to provide access to capital in order to fund capital budget needs later in fiscal year 2012.

Additional information regarding the Company's lawsuit against Eagle, including a copy of the complaint filed by the Company Friday in the United States District Court for the District of North Dakota (Northwestern Division), is contained in a Report on Form 8-K also filed today by the Company with the Securities and Exchange Commission.

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Senex to Divest Stakes in AU Cooper Basin

- Senex to Divest Stakes in AU Cooper Basin

Thursday, August 18, 2011
Senex Energy Ltd.

Senex announced the farm-out of southern Cooper Basin conventional oil exploration licenses to Ambassador Exploration Pty Limited (Ambassador).

Senex is farming out a 60% interest in PEL 516 Mudlalee Block, a 60 %interest in PEL 516 Rowley Block and a 50% interest in PEL 113 Zulu Block to Ambassador. Notwithstanding the farm-outs, Senex retains 100% of the rights to "unconventional hydrocarbon production" within the Zulu Block and to any petroleum recovered from the Mudlalee and Rowley Blocks from beneath the Poolowanna horizon. Senex will retain Operatorship of each of these licenses.

The Farm-out Agreements have been executed and are subject to specific Conditions Precedent which are in the process of being completed. Details of the farm-out terms follow:

South Australian Cooper Basin License PEL 113 Zulu Block

Ambassador to pay 100% of the drilling cost of one well within the license area and 100% of the cost of acquiring, processing and interpreting 100 square kilometers of 3D seismic over the license area subject to agreed cost limits. On completion of the program, Senex will retain a 50% interest and Ambassador will have earned a 50% interest in Zulu Block production other than unconventional hydrocarbon production from the shale and coal deposits in the Permian sequence. Senex retains the rights to 100% of any unconventional hydrocarbon production from the Permian sequence.

South Australian Cooper Basin License PEL 516 Mudlalee Block

Ambassador to pay 100% of the drilling cost of one well within the license area subject to an agreed cost limit. On completion of the program, Senex will retain a 40% interest and Ambassador will have earned a 60% interest in the Mudlalee Block other than production from deposits that extend beneath the Poolowanna horizon. Senex retains the rights to 100% of any petroleum recovered from deposits beneath the Poolowanna horizon, being the unconventional hydrocarbon zones.

South Australian Cooper Basin License PEL 516 Rowley Block

Ambassador to pay 100% of the drilling cost of one well within the license area subject to an agreed cost limit. On completion of the program, Senex will retain a 40% interest and Ambassador will have earned a 60% interest in the Rowley Block other than production from deposits that extend beneath the Poolowanna horizon. Senex retains the rights to 100% of any petroleum recovered from beneath the Poolowanna horizon, being the unconventional hydrocarbon zones.

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Bill Barret Finalizes DJ Basin Acquisition

- Bill Barret Finalizes DJ Basin Acquisition

Wednesday, August 17, 2011
Bill Barrett Corp.

Bill Barrett has closed its previously announced acquisition of properties in the Denver-Julesburg (DJ) Basin from an affiliate of Texas American Resources Company.

The DJ Basin acquisition includes a preliminary estimate of 7 million barrels of oil equivalent (MMBoe) net proved reserves, approximately 650 Boe per day net production and approximately 28,000 net acres of mineral leasehold, primarily on fee lands. The acquired properties currently have producing wells in the Wattenberg Field with production from the Codell, Niobrara and J Sands formations. Acquired exploration acreage is located predominantly in the Chalk Bluffs area just north of the Wyoming-Colorado border, neighboring the Hereford area just south of the border, where the Company intends to target oil in the Niobrara formation.

The DJ Basin acquisition was completed for approximately $150 million, subject to post-closing adjustments. The Company plans to initiate exploration and development of the Chalk Bluffs and Wattenberg areas, respectively, with a one-rig program beginning in October 2011.

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Shell NZ to Join Great South Basin JV, Seismic Program to Begin in 4Q11

- Shell NZ to Join Great South Basin JV, Seismic Program to Begin in 4Q11

Tuesday, August 16, 2011
OMV

OMV New Zealand and Shell New Zealand announced major milestones for the Great South Basin joint venture, with the addition of Shell into the venture and confirmation that a comprehensive 3D seismic program will begin later this year on Permits 50119 and 50120. Permit 50121 will be returned to the Crown.

Subject to ministerial approval, under the new joint venture agreement Shell, a world leader in deep water exploration and production with a 100 year history in New Zealand, will take a 50% share while the existing joint venture partners OMV and PTTEP retain 18% each and Mitsui Australia retains 14%.

OMV New Zealand will remain operator of the Great South Basin permits until the end of the seismic acquisition program which is expected to be completed in early 2012. The 3D program itself will be undertaken by the state of-the-art vessel Polarcus Alima and is expected to cover about 3,000 km2.

Shell will become the joint venture's operator once the seismic acquisition program is completed.

"We are very pleased to announce these developments which we believe clearly demonstrate the joint venture's commitment to the Great South Basin. It is important to be geared up for the next steps in the exploration of a frontier basin," said OMV New Zealand Managing Director Peter Zeilinger.

"We have allocated significant manpower to studying the Great South Basin over the past four years and invested over NZ$50 million to date. The joint venture is now committing to an additional significant investment for the next phase of the project," he said.

In late 2010 OMV and its joint venture partners began an in-depth review of their planning for the Great South Basin. As part of that assessment, the joint venture identified the need for an additional partner with considerable deep water experience and best practice exploration and operating processes.

OMV New Zealand

"We undertook a detailed evaluation of several companies who could meet these tests. Shell's proven track record as an internationally experienced deep water operator with high safety and environmental standards made them the logical partner of choice," Mr. Zeilinger said.

Shell brings valuable technical expertise to the joint venture from safely delivering more than 20 groundbreaking deepwater projects around the globe. Shell's membership in the Great South Basin joint venture builds on its continuing investment in Taranaki, where it is a joint venture partner in the Maui, Kapuni and Pohokura fields.

Chairman Shell Companies in New Zealand Rob Jager said the new Great South Basin venture reflected Shell's continuing commitment to exploration and production in New Zealand.

"Shell has been investing in New Zealand for more than 100 years and safely operating offshore for more than 30 years in the challenging conditions off the coast of Taranaki. We have been impressed by the work of the joint venture to date, and see this as an exciting opportunity to bring our local and global experience to another promising region," he said.

Exploring a new frontier area is very much a long term process, Mr. Zeilinger explained.

"There are no guarantees that drilling will take place, but we are hopeful that the seismic survey will yield positive results. Our focus right now is on carrying out a robust survey," he said.

Mr. Jager said that as the new joint venture partner and future operator Shell is looking forward to working with OMV on the next stage of the project.

"Safety comes first for Shell. We have a Goal Zero operating philosophy which demands no harm to people and protect the environment. Another top priority is to get to know the local stakeholders better so that we have a strong understanding of their views and a positive foundation for continuing engagement over the coming years," he said.

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Doyon Plans New Interior Gas Exploration Effort in Nenana Basin

- Doyon Plans New Interior Gas Exploration Effort in Nenana Basin

Monday, August 15, 2011
Alaska Journal of Commerce
by Tim Bradner

Doyon Ltd., the Interior Alaska Native regional corporation, is planning new seismic work this winter in the northern part of the Nenana Basin, an Interior Alaska basin about 60 miles west of Fairbanks that is considered gas prone but also has oil potential.

About 120 miles of two-dimensional seismic is planned for this winter, according to Jim Mery, Doyon's vice president for lands. The seismic will set the stage for a possible exploration well drilled in the area, he said. It would be the second test well drilled in the Nenana Basin in recent years.

Doyon is an Alaska Native development corporation with about 11 million acres of surface and subsurface land holdings in Interior Alaska. The Nenana Basin project is on state-owned lands held under an exploration license, a form of state lease. The license area includes 483,000 acres of general state lands and an additional 9,500 acres of lands owned by the Alaska Mental Health Trust Authority, a state agency that leases its lands to support mental health programs.

Mery said Doyon plans to press ahead with exploration in spite of an announcement by Golden Valley Electric Association, the regional electric utility, and Flint Hills Resources, operator of a refinery near Fairbanks, that they will pursue a project to truck liquefied natural gas from the North Slope.

The Fairbanks area is a near-term market for any gas discovered in the Nenana Basin, although a 60-mile pipeline would be needed to bring the gas to the Interior city.

On the other hand, a plan by the state of Alaska to pursue a 24-inch pipeline built from the North Slope to Southcentral Alaska would have its line pass through the Nenana Basin near where Doyon plans exploration. If gas is discovered, and if the pipeline is built, Doyon could ship its gas to Southcentral Alaska through the pipeline.

"There are a lot of moving parts to the pipeline and natural gas picture, and our decision is to move ahead with our plans," Mery said.

Doyon and three partners drilled a well two years ago in the southern part of the basin with mixed results. No gas was found but there were indications that hydrocarbons were present in the region. Doyon's partners in the Nenana Basin exploration have been Arctic Slope Regional Corp., another Native development corporation with holdings on the North Slope, and Usibelli Energy LLC, an affiliate of Usibelli Mines, which operates a coalmine near Healy, also in Interior Alaska.

Mery said this winter's program will involve the first seismic done in the northern part of the Nenana Basin, which is believed to hold the deepest part of the basin, with sedimentary rocks possibly as deep as 16,000 feet.

State geologists have said the basin exhibits somewhat similar geology to the prolific Cook Inlet basin in southern Alaska and is generally considered prospective for natural gas. A geologic assessment of the basin indicated the possibility of 3 trillion cubic feet of technically recoverable thermogenic gas in the basin, with the possibility of additional biogenic gas. There were two earlier exploration wells drilled, by Unocal in 1962 and ARCO in 1984, but the wells were drilled at the far southern, and shallowest, part of the basin and were unsuccessful.

A key advantage of Nenana Basin gas for the state's 24-inch pipeline is that a 500 million cubic feet per day limit that applies to the state project because of its contract with TransCanada Corp. does not apply to gas found in Interior Alaska and shipped through the pipeline, said Dan Fauske, president of the Alaska Gasline Development Corp., the state corporation planning the 24-inch pipeline.

The state's 24-inch pipeline could move 500 million cubic feet per day from the North Slope to comply with the TransCanada contract and any gas from the Nenana Basin could be above that amount, Fauske told legislators in recent briefing.

TransCanada and ExxonMobil Corp. are planning a 48-inch pipeline built from the North Slope to Canada and are working with incentives offered by the state. As a part of the agreement the state is limited in helping a competing pipeline that would ship more than 500 million cubic feet per day from the slope.

The 500 million cubic feet per day limit is a source of frustration to many state legislators because it limits the development of industrial customers who would need more than the gas that could be delivered under the limit. Industrial customers are needed for the 24-inch pipeline build to Southcentral Alaska to be economically viable.

Copyright (c) 2011, Alaska Journal of Commerce, Anchorage

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TAG Confirms O&G Discoveries in Taranaki Basin

- TAG Confirms O&G Discoveries in Taranaki Basin

Thursday, August 11, 2011
TAG Oil Ltd.

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

Lower Mt. Messenger Oil Discovery in Sidewinder-2 Well

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

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

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

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

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

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

Cheal-C1 Testing Confirms Oil Discovery

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

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

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

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

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

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Magnum Hunters Acquires Acreage in Williston Basin

- Magnum Hunters Acquires Acreage in Williston Basin

Friday, August 05, 2011
Magnum Hunter Resources Corp.

Magnum Hunter's wholly owned subsidiary, Williston Hunter ND, LLC, has entered into a Purchase and Sale Agreement ("PSA") with a privately-held company ("Seller") for all of the Seller's operated working interest ownership in oil and gas mineral leases and 191 wells on approximately 15,500 gross acres located within four counties of the Williston Basin of North Dakota. Gross production from the properties is approximately 833 BOE per day. Total proved reserves attributable to the acquired properties are estimated at 2.6 million barrels of oil equivalent. Magnum Hunter presently owns an approximate 47% working interest in these oil and gas properties. Upon closing of this transaction, Magnum Hunter will own an approximate 95% working interest in these properties. The effective date of the transaction is April 1, 2011. Magnum Hunter intends to close the purchase transaction on or before August 18, 2011.

Magnum Hunter will pay to the Seller a total purchase price of $57 million, to be paid at closing in the form of $55.0 million in cash and $2.0 million in Magnum Hunter restricted common stock. The number of shares of Magnum Hunter common stock will be determined based on the volume weighted average price of the Company's common stock during the five trading days prior to closing. Magnum Hunter intends to fund the cash portion of this purchase through existing liquidity and borrowings under the Company's senior credit facility. Additionally, the Seller will retain an overriding royalty interest in certain of the properties in various amounts not to exceed 2%. No existing debt of Seller will be assumed by Williston Hunter in connection with the closing of the acquisition.

The PSA between Williston Hunter and the North Dakota based privately-held Seller was negotiated pursuant to a Settlement Agreement between Magnum Hunter and the Seller as a result of certain lawsuits pending in the United States District Court for the District of North Dakota (Northwestern Division). The agreed upon settlement between the parties will resolve all outstanding claims. The parties will file stipulations with the District Court for dismissal, with prejudice, of the two pending civil actions upon the PSA's final closing.

Management Comments

Mr. Glenn Dawson, President of Williston Hunter, commented, "We are pleased to announce this final agreement to acquire these Williston Basin properties where we have been a minority owner for years. With this 'bolt on' transaction, we will be establishing an operating base in North Dakota which has been a primary objective as we continue to grow our presence in the Williston Basin. Our game plan in 2011 is to continue our geological and engineering evaluation of these properties so that we will be in a position to prudently develop these assets beginning early next year."

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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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Whiting Posts Production Rates for Williston Basin Wells

- Whiting Posts Production Rates for Williston Basin Wells

Thursday, August 04, 201
Whiting Petroleum Corp.

Whiting released information on six western Williston Basin areas within its Lewis & Clark prospect and three nearby prospects. The initial production rates from wells drilled in these nine areas averaged 1,471 barrels of oil equivalent (BOE) per day. Whiting believes that its drilling results at Lewis & Clark and Hidden Bench as well as non-operated drilling results at Missouri Breaks and Starbuck indicate that a large portion of its 1,102,302 gross acres and 680,137 net acres in the Williston Basin has been shown to be productive and have excellent initial production rates.

Eleven Whiting-operated Sanish Sand wells in our Pronghorn area had initial production rates averaging 1,298 BOE per day. This average excludes four delineation wells drilled to determine the southwest boundary of the Sanish Sand reservoir at Pronghorn.

In our Big Stick area, we have completed three wells with initial production rates averaging 1,043 BOE per day. At Demores, where two wells had initial production rates averaging 479 BOE per day, Whiting is changing the direction of its well bores to a north-south orientation to encounter more natural fractures. In its Beaver Creek area, Whiting has completed six wells that averaged 1,119 BOE per day. A recent well in the Beaver Creek area, the Dry Creek 44-20TFH, flowed 2,337 BOE per day from the Three Forks formation on August 2, 2011. The Company has completed one well in its O'Neil Creek area. The Mosser 11-27TFH well was completed in the Three Forks formation with an initial production rate of 193 BOE per day. Severe weather conditions which caused a shut-down of flow back operations post frac is believed to have resulted in the low initial production rate on this well.

At Missouri Breaks and Starbuck, another operator has drilled within the outline of our acreage position. One non-operated well at Missouri Breaks was completed flowing 2,962 BOE per day. Three non-operated wells at Starbuck had initial production rates averaging 1,264 BOE per day. Whiting currently has two operated wells waiting on completion at the Starbuck prospect with results expected within 30 days.

James J. Volker, Whiting's Chairman and CEO, commented, "We are very encouraged with our results at Lewis & Clark and Hidden Bench. We are also encouraged by the initial production rates of area non-operated wells and the shows encountered during drilling operations on our two operated wells at Starbuck. We plan to complete these wells in early September.

"We own 387,351 gross (254,818 net) acres in Lewis & Clark, which is more than three and a half times larger than our Sanish field. At Lewis & Clark, Whiting has a controlling interest in 164 1,280-acre spacing units with an average working interest of 64%. Based on production to date at Lewis & Clark, it appears that these wells have a relatively shallow decline rate. Therefore, we continue to believe that our wells at Lewis & Clark will have Estimated Ultimate Recoveries (EURs) in the 300,000 to 500,000 BOE range."

Mr. Volker added, "Based on IHS data, with its average of 100,000 BOE, we continue to be on top of the list in terms of cumulative production during the first six months from all Bakken wells drilled in North Dakota since January 2009. For companies with a sample of at least 10 wells, Whiting leads the pack by 15,000 to 70,000 BOE in the first six months. We hold more than 680,000 net acres in the Bakken/Three Forks Hydrocarbon System that we believe will generate increased production and reserve additions."

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Bering IDs New Prospect in Permian Basin

- Bering IDs New Prospect in Permian Basin

Wednesday, August 03, 2011
Bering Exploration Inc.

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

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

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

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

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PetroFrontier Spuds Southern Georgina Basin Well

- PetroFrontier Spuds Southern Georgina Basin Well

Wednesday, August 03, 2011
PetroFrontier Corp.

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

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

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

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

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

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

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TGS Kicks Off Seismic Survey in Faroe-Shetland Basin

- TGS Kicks Off Seismic Survey in Faroe-Shetland Basin

Tuesday, August 02, 2011
TGS-NOPEC Geophysical Co. ASA

TGS has commenced a new multi-client 3D survey in the Faroe-Shetland Basin. The survey covers 2,500 km(2) west of the British Isles over quads 6004, 204 and 205 and is acquired in partnership with PGS.

The new seismic data is being acquired by the PGS Ramform Viking towing 12 X 6,000 m with 75 m separation and utilizes PGS' GeoStreamer Technology. Data acquisition will continue through Q3 2011 and the vessel will return in 2012 to complete the survey. Data processing will be performed by both TGS and PGS. "This is TGS' first investment in a 3D multi-client seismic program west of the British Isles, located in an area with a number of discoveries and further undiscovered hydrocarbon potential," stated Kjell Trommestad, SVP Europe & Russia for TGS.

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Vanguard, Encore Finalize Permian Basin Acquisition

- Vanguard, Encore Finalize Permian Basin Acquisition

Monday, August 01, 2011
Vanguard Natural Resources, LLC

Vanguard and Encore Energy announced that on July 29, 2011 they consummated the previously announced joint acquisition of oil and natural gas producing properties from an undisclosed seller for an adjusted purchase price of $81.4 million, subject to customary post-closing adjustments. The effective date of the acquisition was May 1, 2011.

The acquired properties are all located in the Permian Basin of West Texas and include:

• Estimated total net proved reserves of 5.48 MMboe
• 70% oil and natural gas liquids
• Reserve to production ratio of approximately 15 years
• Approximately 1,000 Boe/d of net daily production

In conjunction with this acquisition, both VNR and ENP have entered into new oil and natural gas hedges covering a substantial portion of the estimated production through 2014.

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