Longreach Oil & Gas (CVE:LOI) said it has made solid progress across its Moroccan assets during the March quarter and is well funded for its work programmes with C$9 million in the bank.

At the Sidi Mokhtar licences, the company is currently working on completing seismic reinterpretation studies to better delineate leads and prospects.

The results should help the company determine strategy for further reprocessing and seismic acquisition.

Longreach is also processing and interpreting the new 2D seismic data from the Tarfaya licence, which is now nearing completion, while the interpretation of the 2D seismic shot over the onshore Zag basin is expected to be completed this year.

Elsewhere, the farm-out of the Foum Draa and Sidi Moussa exploration licences offshore Morocco remains underway. The company hopes to secure a partner for the drill phase on both licences.

On the financial front, Longreach had a cash balance of C$9 million at the end of March.

“Longreach continues to make solid progress on the extensive work programmes it has in place across all its licences in Morocco, for which it remains well funded,” said chairman and CEO of Longreach Bryan Benitz.

“Looking ahead, we expect to see an acceleration in activity with further seismic work, data interpretation and the identification of drill targets.

“We look forward to the future with confidence.”

The company has also made board changes earlier this month, hiring Ronald Lansdell as vice president exploration and as a board director. In addition, Mehdi Ali was appointed as an advisor to the board.

Silvermere Energy (LON:SLME) said this morning it expects production from the Mustang Island gas condensate field off the coast of Texas to begin this summer.

It follows the documented delays to the construction of a platform for the I-1 well, which have recently been resolved.

Chief executive Andy Morrison said the business, which listed on AIM in August, has come a long way in a short space of time.

“The company will soon be a gas and condensate producer and we look forward to expanding through the identification of at or near production, secondary and tertiary oil and natural gas opportunities onshore or shallow offshore the US,” he add.

Silvermere owns 33.3 per cent of Mustang Island, which is operated by Dominion Production. 

Its development was the key focus of the last financial year, which saw the company post a £1.3 million operating loss for the 12 months to December 31.

Cash and equivalents at the period end were £202,352.

The WC 35 State No. 1 well is operated by CML and Caza has a 20 per cent working interest for a 17.125 per cent production interest in the well.

The well has been perforated and CML reports that it has good fluid entry. There remains 25 per cent of load left and a frac crew is awaited, said Caza, as it updated inverstors on its Mexican operations.

Elsewhere, at the Bradley "29" horizontal well in Eddy county, drilling has reached the primary target and and operator Mewbourne has begun horizontal drilling and reported good mud log shows.

The Quail "16" horizontal well in Lea county, operated by Fasken Oil is at a depth of 10,787 feet aiming for the main horizontal target of Third Bone Spring sand at approximately 10,965 feet.

Caza also highlighted that in its Bone Spring play, energy firm Cimerex has two producing horizontal wells within half a mile of Caza's Lynch property. 

One well has produced 105,141 barrels of oil and 72.4 million cubic feet of natural gas in its first 131 days of production, while another has generated 101,111 barrels and 139.7 million cubic feet of gas in its first 221 days, it said.

In the Bone Spring play, where Caza has acquired 4,000 net acres to date, the firm has prospects Lynch, Forehand Ranch, Lennox, Copperline, Mad River, Bradley 29, Two Mesas and Quail Ridge.  

It said it was well positioned in the play, adding it continued to monitor opportunities to build on Caza's current acreage position.

Caza chief executive W. Michael Ford said: "We are very pleased that the San Andres appears to be productive for oil in the Sombrero well. The Permian basin is known for stacked pay zones, and we look forward to completing the frac job and getting the well completed and on line in the near future.  

"We are also very pleased with progress made by Mewbourne and Fasken to date on the Bradley and Quail State wells.  

"We hope to reach total measured depth on both wells within the next few weeks. Good news continues to be disseminated from activities in the horizontal Bone Spring play, and management is very pleased with recent activities near the Company's Lynch Property. 

"Successful horizontal Bone Spring wells have been drilled on all sides of this property."

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Leni Gas & Oil (LON:LGO) has now mobilised a workover rig to start re-developing the onshore Goudron oilfield in south-eastern Trinidad.

As previously announced, the company plans to re-develop the Goudron oilfield in partnership with Trinidad and Tobago state-owned Petrotrin under the terms of an existing contract.

Field operations are starting imminently. LGO will first be working over up to 50 existing wells and will then drill additional wells.

The Goudron field lies between the East Moruga and Beach Marcelle fields in south-eastern Trinidad and has direct access to the Petrotrin oil export pipeline to the Pointe-a-Pierre refinery in western Trinidad. 

The oil reservoirs generally lie between 300 and 3,500 feet below surface and the oil is low sulphur and has API gravities ranging between 25 and 55 degrees.

Proven reserves, recoverable using existing wells and a small number of infill wells, have been estimated at 1.9 million barrels (mmbbls), whilst proven plus probable reserves were estimated at 8 mmbbls. 

LGO has recently engaged Challenge Energy to prepare a Competent Persons Report (CPR) on the Goudron field and the report is expected in the third quarter 2012.

Broker Old Park Lane Capital views the announcement as important as it values Goudron as the company’s core asset.

“Upon the conclusion of the partnership agreement to co-develop the field with Range Resources, we believe that LGO’s ultimate 50% interest in Goudron will be worth approximately 2.4p per share (fully diluted),” said the broker, which is a 'buyer'.

This suggests significant upside to the current price of 0.82 pence, which has dipped 0.02 pence, or 2.4 per cent, today.

“We believe that the commencement of workover operations and the publication of a CPR will act as catalysts for further value recognition for the Goudron Field,” the broker concluded.

New World Oil & Gas (LON:NEW) has exceeded its goals since listing on the AIM market last year - and now operates three highly prospective oil and gas licences, it said.

The comments came as the company unveiled final results for the year to December 31 - in which it made "outstanding" progress, it told investors.

Within months of listing on AIM in May last year, it progressed two projects - the Blue Creek in Belize with a P50 resource of 294 million barrels of oil - and the Danica Jutland Licences in Denmark, where one licence has an estimated P50 gross resources unrisked recoverable volume of 1.4 trillion cubic feet of gas and 97 million barrels.

And in late 2011, the firm identified a third project in Denmark - the Als prospect, which was described as "close to drillable" by RPS Energy.

Als has an estimated P50 gross resources unrisked recoverable volume of 1.4 trillion cubic feet of recoverable gas and 97 million barrels of recoverable oil with a gross potential value of US$2.4 billion.

A farm-out agreement has been signed with Danica Resources, which names New World as operator.

When a mutually agreed seismic and drilling programme is completed, the company will have the opportunity of earning into an 80 per cent participating interest.

The firm posted a loss before tax of $2.6 million in the period, compared to a pre-tax loss of $517,000 from April 15, 2010 to December 31, 2010.

As at December 31 last year, it had $3.67 million in cash.

Chairman William Kelleher told investors that the company was delighted with the progress it had made at its flagship project - Blue Creek.

"We have fast-tracked its development, following the highly positive results of the seismic acquired to date.  We are currently in the process of acquiring additional seismic.  

"We feel that the potential of Blue Creek may be significant, in that it lies in close proximity to and displays structural similarity to the recently discovered and producing Spanish Lookout and Never Delay Fields, each with reported reserves of approximately 25MMbbls."

He added that the firm had completed the first phase of seismic acquisition on its second project, the Danica Jutland Licences in Denmark, to better define hydrocarbon resources and upside value potential.  

"We expect to announce an updated competent person's report from RPS Energy in H2 2012.  The Danica Jutland licences cover 1.015 million acres, and contain two identified Triassic leads and eight Zechstein leads," he said.

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Drilling of Shabeel-1 has been suspended pending testing, with Range saying it had been a significant success to date with the discovery of a 12 to 20 metres net hydrocarbon pay zone in the Jesomma sands.

Managing director Peter Landau added that based on Range's internal technical team's review of the net pay zone and results to date, a successful flow test could result in 70 to 130mm barrels of recoverable oil from the well.

Of that, 14 to 26mm bbls would be attributable to Range.

“The zone needs to be commercially flow tested and this will be undertaken after the completion of the second well, Shabeel North, which will spud early June,” he said.

“It is also important to remember that this is the first hydrocarbon well drilled in the Dharoor Valley for over 50 years and it is a massive credit to all involved, namely Horn Petroleum, the Puntland Government and the local Puntland communities that the well has been successfully drilled to date,” he said in an interview with Open Briefing.

“Globally, the average discovery rate is between one in five and one in 10 for a ‘wildcat’ well, which essentially is what Shabeel-1 is, hence we consider the well successful to date with both the net pay and the confirmation of an active petroleum system.

“Whilst the market and short term traders may have been anticipating further success in the deeper sections of the well, what we have discovered is extremely significant and the chances of a commercial hydrocarbon operation in Puntland are far greater now than when the well was spudded.

“And it must be remembered that we did encounter additional potential net pay sands in a Jurassic aged formation over a 184 metre section at a depth of 3,246 metres to 3,430 metres. The fact that hydrocarbons were encountered at a number of levels is particularly significant moving ahead.”

Landau added the company decided to test the Shabeel-1 well after drilling Shabeel North for timing and logistic reasons.

“Obviously the preference would be to flow test immediately but timing and logistics would mean that the rig and crew would be idle for four to six weeks at what are expensive day rates in the region.

“Previous test equipment flown in was designed for open hole, smaller diameter testing as opposed to the now cased well requiring high performance perforation.

“This is quite standard practice across the world, particularly in remote areas.”

Laundau added that the Shabeel North well is scheduled to spud early June with a revised target depth of 2,400 metres.

“The well has an identified Jessoma formation significantly thicker and of better quality than the Shabeel-1 well providing the joint venture with great comfort in moving the rig immediately to drill the second well.

“Internal technical estimates suggest recoverable oil of between 100 to 150mm barrels from a successful discovery in the Jessoma formation, of which 20 to 30mm barrels would be attributable to Range.

“It is also important to note that given the Jessoma discovery in the first well, the second well will be drilled with smaller casing to ensure that open hole testing can be undertaken with the equipment already on site.“

Landau said that the Shabeel North well is not contingent on the Shabeel-1 outcome, but the success there certainly gives Range greater confidence moving forward.

He added that he was still confident of a commercial discovery even with a revised target of just the Jessoma formation.

“If the Shabeel-1 well successfully flows and the Shabeel North well delivers to current expectations, we would have discovered between 170 to 280mm barrels of recoverable oil in our first two wells (with 34 to 56mm barrels attributable to Range) with the remainder of the basin still to be tested.

“Investors must also remember the well's proximity to the coast (approx 60 km) and the relative ease of constructing a pipeline to an offshore loading facility based on a commercial discovery.

“Nothing changes for Range in the immediate future. We are fully funded and look forward to updating the market on a number of fronts including Colombia and our flagship operations in Trinidad and of course hopefully on further drilling success in Puntland,” he concluded.

Range has a 20 per cent stake in the Dharoor Block in Puntland, Horn Petroleum has 60 per cent and Red Emperor Resources 20 per cent.

Solo Oil (LON:SOLO) has raised £150,000 from its equity drawdown facility as it prepares to test its recent discovery in East Africa.

Solo issued 32.3 million shares at a “small premium” to the market price and will use the money to fund its 25 per cent share of the testing of the Ntorya-1 well gas discovery in the Ruvuma Basin in Tanzania

In February, Solo and partner Aminex (LON:AEX) reported the  discovery in a 25 metre (80 foot) gross sandstone interval at Ntorya.

The drawdown has been taken from at three year £10 million equity line facility with Dutchess Opportunity Cayman Fund.

Last month, Solo said it will invite offers from potential partners to participate in the next round of exploration at Ruvuma, commencing with the acquisition of additional seismic data later in 2012.

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Zeta will hit the ASX boards at 12.30am AEST on Wednesday 23rd May 2012.

The company will use proceeds from its initial public offering used to start drilling at the onshore Bobocu gas field with the aim of producing gas by the middle of 2013.

This corresponds with the expected deregulation of Romanian gas market that would more than double current gas prices of about US$4.25 (A$4.27) per thousand cubic feet.

It plans to achieve this by drilling new development wells using modern drilling techniques and possibly carrying out workovers of existing wells.

Bobocu has contingent resources of 44.36 billion cubic feet (Bcf) and  prospective resources of 14.09Bcf.

Zeta may also re-enter an existing well at Jimbolia if it is unable to find a farm in partner to drill an appraisal well at the oil field.

While the company had originally planned to raised A$8 million, the strong level of interest led to the issue of 41.7 million shares priced at A$0.20 each, for a total of A$8.35 million.

Each share includes a free attaching option exercisable at A$0.20 each.

Zeta is also offering a 1 for 4 loyalty option to all shareholders on the register after 3 months. These options will be exercisable for 3 years at A$0.30 each.

Bobocu

The Bobocu gas field is located 20 kilometres northeast of Buzau and 110km northeast of Bucharest.

It was discovered in 1966 with the discovery well testing gas at a flow rate of 2.5 million cubic feet per day (MMcfd) and the field put into production in 1977.

Peak production of 12.8MMcfd was reached in April 1981 from 9 wells though sand production, poor completion practices and a general poor understanding of the field, led to it being shut in 1995.

Zeta acquired the field in 2007 and has shot 75 square kilometres of new 3D seismic that led to a revised geological model that improved understanding of the geology and distribution of hydrocarbons across the field.

The seismic also identified additional prospectivity on the field in intervals both above and below the Delta Wedge sequence where previous wells had produced from.

Jimbolia

Jimbolia is located in the proven producing eastern part of the Pannonian Basin, about 40 kilometres east of Timisoara on the Romania’s border with Serbia.

The 23.9 square kilometre licence contains two discoveries, Jimbolia Veche and Jimbolia Vest that were made in 1983 by Petrom.

Zeta acquired the Jimbolia licence in 2007 and since then has collated all existing well data and 2D seismic data on the field to complete a geological model, identify drill targets and establish a contingent oil resource of 1.72MMbbl.

Jimbolia Veche contains the Jimbolia oil field that was intersected by two wells including Jimbolia-1, which flowed at rates of up to 120 barrels per day, as well as the Jimbolia gas field that was brought on stream from 1985 to 1998 and produced 2.89Bcf of gas from the Pliocene III gas reservoir.

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Although preliminary results from Davenport-1, they build upon the positive results from Beach Energy (ASX:BPT) and Strike’s Marsden 1 well in PEL 95.

Elevated gas shows were also recorded across the target formations.

Preliminary log data indicated Davenport-1 had intersected thick shales and coals in the Toolachee Formation as well as the Roseneath, Epsilon and Murteree formations.

More importantly, the well encountered 45 metres of net coal in the Patchawarra Formation along with 2 other seams with net coal thickness of more than 20 metres each.

Strike said a sidetrack well is currently being drilled to cut cores in the Patchawarra Formation.

Davenport-1 is the first well drilled in the centre of the Milpera Trough in PEL 94. It is aimed at demonstrating that the  thick, hydrocarbon-rich Permian-aged coal and shale formations in the centre of Cooper Basin extend into the southern Cooper Basin.

Analysis

Today's results are significant for Strike and may pave a faster road to monetisation than shales.  In fact, with the project near to pipelines, today's results and thickness of coal seams could prove a catalyst for development within a 12-24 month timeframe. At this rate, current valuation of Strike of around $100 million looks decidedly meagre given the value of its U.S. Eagle Ford Shale assets and valuations for acreage. We would expect the valuation of Strike to reflect this over the next 12 months.

Cooper Basin

Other shale and unconventional gas exploration wells drilled in the Cooper Basin have also being successful thus far.

PEL 94 operator Beach had last year booked contingent gas resources of 2 trillion cubic feet following the successful drilling of the Holdfast-1 and Encounter-1 wells in PEL 218, Cooper Basin.

A third well – Moonta-1 – that was drilled last month also appeared to be gas saturated throughout the Permian target zone.

Meanwhile, Senex Energy (ASX: SXY) has has drilled the successful Vintage Crop-1 and Sasonof-1 exploration wells and has started fracture stimulation work on latter well to prove the ability of the Roseneath and Murteree shales as well as the tight sands of the Patchawarra Formation to produce gas.

Outlook from Eastern Australia gas markets is also positive with gas prices expected to reach between A$6 and A$9 per gigajoule in the next couple of years as oil-linked pricing becomes increasingly common.

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