ADX Energy (ASX: ADX) is poised to prove that it is all about the oil as it takes steps in its expected transition into an oil producer.

Production testing of the Sidi Dhaher-1 in the onshore Chorbane Block, Tunisia, is set to begin soon with the test rig now on site, potentially confirming both flow rates and reserves as well as providing a source of cash flow.

Further activities towards the transition to a producer are drilling an appraisal of the Dougga gas condensate field and testing of the Lambouka well offshore Tunisia.

The Company has also secured a farm in partner which will provide significant funding for the highly prospective onshore Parta Concession in Romania, and is planning to shoot seismic and drill a well there in 2013. 

Share Price: A$0.08 
Issued Shares: 438.3 million
Market Cap: A$35.0 million

ANALYSIS

ADX Energy’s Sidi Dhaher oil discovery is poised for producing with the rig contract in place, key personnel in place and support camp and drilling rig mobilised.

A successful production test would be transformational and underpin the future of the Company providing near term cash flow potential.

Success at Sidi Dhaher will also serve to de risk several other prospects and leads in the Chorbane permit.

Further valuation upside could come from a successful appraisal of the Dougga gas condensate find and/or testing of the Lambouka discovery, both of which could be undertaken under the same campaign.

The new moderate pro-development government in Tunisia, coupled with a well established oil and gas infrastructure that connects with local and export markets in Europe are likely to result in quick commercialisation with excellent pricing.

ADX also has a track record for securing farm-in partners, which had helped to spread and de-risk its Tunisian exploration programs.

This was proven again when it signed up Austria’s Rohoelaufsuchungsgesellschaft as its farm in partner to help defray the costs of exploring the Parta Block in Romania. 

The completion of testing at the Sidi Dhaher-1 in the first half of 2012 should be an inflexion point for the Company.  

A successful commercial production test at Sidi Dhaher-1 would assist to underwrite the future of the Company.   A positive result could take ADX Energy to early cash flows and possibly become an oil producer in a six month time frame.

BACKGROUND

ADX Energy is an ASX listed oil and gas explorer with five oil and gas permits in North Africa, the Mediterranean and Central Europe, and retains an interest in gold and base metals through a 31.28% stake in Riedel Resources(ASX: RIE). 

ADX Energy acts as operator and has established a $60M exploration program with $12M of shareholder funds, and farm-outs to venture partners who pay the balance of exploration and development expenditures. 

These farm-outs have been very successful with the first two wells resulting in both an onshore oil discovery, and an offshore gas discovery that should establish the Company as an emerging oil and gas producer. 

The Company has also acquired the first Geostreamer 3D seismic survey for offshore Tunisia that resulted in the discovery at Lambouka and a significant resources upgrade and de-risking of the Dougga condensate field. Geostreamer technology eliminates interference that is picked up by conventional hydrophone technology and presents sharper and clearer images of subsurface formations for further evaluation.  

A data exchange has also been executed with Shell who completed an offshore 2D seismic survey in the Sicily Channel that abuts and covers part of the Kerkouane Block. This includes a highly prospective Cretaceous Formation that extends out from the historic Kerkouane-1 well within the ADX Energy controlled block, and has potential to contain significant volumes of hydrocarbons.   

The political situation appears to have stabilised in Tunisia, where the revolution was followed by democratic elections that elected a moderate Islamist government. Tunisia maintains an open banking and legal system, along with a civil society that is managed by a competent and well educated public service.

ADX Energy is utilising a well developed oil and gas infrastructure that connects with local and export markets into nearby Europe that provides a strong demand for energy products, and excellent pricing for oil and gas.  

MANAGEMENT

Wolfgang Zimmer is the Managing Director, and has 32 years’ experience in the oil and gas industry. He previously worked with Mobil Oil in Europe and the USA in oil & gas exploration and production, and with OMV where he served in a variety of senior management roles that included the establishment of an exploration and energy production business in Australia, New Zealand, and Tunisia. Most recently he was the CEO of Grove Energy of Canada that merged with other interests in 2007.

Ian Tchacos serves as Chairman, and has over 25 years of international experience in corporate development and strategy, mergers and acquisitions, petroleum exploration, development and production operations, commercial negotiation, oil and gas marketing and energy financing. He was previously the Managing Director of Nexus Energyand was responsible for developing the Company from a micro-cap explorer to an ASX top 200 offshore producer of oil and gas. 

Paul Fink serves as Technical Director, and has 18 years experience in diversified oil and gas exploration and production in both technical and managerial positions. He also worked for OMV in exploration and production assignments on a global basis, headed his own petroleum consulting business, and operated a highly successful exploration campaign for Focus Energy.  

Andrew Childs serves as Non Executive Director and is also a Non Executive Director of Riedel Resources Limited, Managing Director of Petroleum Ventures Pty Ltd, Chairman of Australian Oil Company Ltd and Non Executive Director of Timor Oil Ltd, Orion Energy Pty Ltd and Bombora Energy Pty Ltd. Andrew is also Principal of Resource Recruitment and Managing Director of International Recruitment Services Pty Ltd.

FUNDING AND SHAREHOLDERS

J.P. Morgan Nominees hold 105.48 million shares, with the top 20 shareholders controlling 398.95 million shares prior to the recent placement and issue.

ADX held A$1.03 million in cash of the end of March 2012 and also owns 25 million shares, or 31.28%, of Riedel Resources (ASX: RIE), worth a current A$2.62 million. Additional funding of A$4.2 million for the farm out of the Romanian Part permit to RAG will also be received shortly.

The Company has issued 28.8 million unlisted options exercisable between 31 December 2012 and 28 February 2014 at various prices from $0.25 - $0.45, that are currently out of the money. 

CHORBANE BLOCK, ONSHORE TUNISIA

The Chorbane Block covers 2,428 square kilometres in central Tunisia, near the port city of Sfax, and has all the hallmarks of a highly prospective oil and gas asset.

It contains large undrilled structures high quality seismic available over prospects and leads, and is surrounded by several producing oil fields that contain extensive oil and gas infrastructure for collection and distribution of hydrocarbons.

Sidi Dhaher-1 was discovered in October 2011 after the ADX led joint venture intersected a 30 metre column of live crude oil with minor amounts of water and a good seal in the Cretaceous Bireno formation.

The Bireno hosts a number of producing fields in the area and the structure intersected here has been estimated to hold mean in-place oil of 51 million barrels. The confirmation of recoverable volumes and resulting potential reserves are contingent upon a successful well test with the objective of proving commercial flow rates and likely recovery factors.

High quality seismic was also obtained over additional prospects and leads within the block and has defined a number of new drilling opportunities within the block.

Following the discovery of a 30m oil column at Sidi Dhaher-1, ADX secured a contract with Dietswell SA for the provision of the Sedlar – 160 drilling rig to flow test the Sidi Dhaher-1 oil discovery. 

Key personnel required for the program were recruited and mobilised during the quarter. The rig and auxiliary equipment are currently on site with flow testing expected to start soon.

ADX also continued to engage with the local population preparing and negotiating environmental compensation agreements and work contracts. 

Approval of the testing programme was granted by Enterprise Tunisienne d’Activités Petrolieres (“ETAP”) and the operational work program agreed and finalised by the joint venture. 

The results of the Sidi Dhaher-1 well test will be a major factor in ADX’s plans for the medium term. A success could inspire the Company to carry out further studies to better understand the structure and drilling to boost production.

ADX has a 40% interest in Chorbane while other partners include Gulfsands Petroleum Plc 40%, XState Resources Ltd 10% (ASX: XST), and Verus Investments Limited 10% (ASX: VIL).

SICILY CHANNEL BLOCKS, OFFSHORE TUNISIA AND ITALY

The Sicily Channel Blocks consist of three existing gas and condensate discoveries which are 60% owned, and include the Dougga gas condensate field that was independently assessed by Tracs AGR at 239 billion cubic feet (Bcf) of gas and 41 million barrels (MMbbl) of liquids, along with the 60% owned Lambouka and Kerkouane that have been estimated by ADX Energy at about 254 million barrels of oil equivalent (MMboe). 

Additional prospective exploration prospects defined on 3D seismic total 410MMboe, and on 2D seismic total a prospective resource of 570MMboe.  

A new 100% owned Italian licence has been added that is contiguous with the Kerkouane discovery, and on a combined basis forms a contingent and prospective resource of 1.5 billion barrels of oil equivalents for the entire project area. 

ADX believes that resources at Dougga may be higher as recent 3D seismic depth work has confirmed that the Dougga structure has a much lower/ deeper gas water contact than the one utilised for the Tracs estimate.  

The Company has a mean in house estimate of 110MMboe for Dougga. 

The seismic has also allowed ADX to identify a 30.6 square kilometres satellite structural closure of Dougga. Dougga West has estimated mean recoverable resources of 226MMboe. 

Lambouka was discovered by the Lambouka-1 well was drilled in mid 2010 in around 625m of water to a total measured depth of 2,786m, before being suspended for future re-entry.

Located just 12 kilometres from Dougga, it hosts contingent mean recoverable gas resources of 309Bbf of gas, and has both an appraisal opportunity and potential upside from a deeper reservoir formation that has not been drilled. 

The close proximity of Lambouka, Dougga, Dougga West and other leads offers ADX the opportunity to develop them together as a single project.

This proposed “Dougga Hub” is close to the Tunisian shore, existing infrastructure and high price markets both locally and in Europe.

The Kerkouane Block contains the historic Kerkouane-1 discovery that was drilled at a shallow water depth of 108 metres by Shell in 1981, and produced massive gas kicks and solvent shows from the Ain Grab, and Nilde Limestones, that were intersected above 1,352 metres. A nearby oil field in Italian waters, the “Nilde field”, has produced around 30 mmbbls of oil from this reservoir.

However, Kerkouane-1 failed to reach the primary target Abiod Limestone and was never tested. The deeper Cretaceous Abiod reservoir may carry significant volumes of hydrocarbons. 

ADX is currently conducting a data exchange agreement with Shell who operate adjoining permits for 104 kilometres of 2D seismic, which is aimed at defining significant targets around Kerkouane. 

ROMANIAN PARTA BLOCK

While Tunisia is the focus of ADX's attention, the Company has also recently reached a farm-in agreement with Rohoelaufsuchungsgesellschaft, who will take a 50% stake in the Parta Block, which is located in a proven and producing hydrocarbon province in Romania.

The Austrian company will make an upfront payment to ADX and will earn the stake by paying past costs and a promoted share of future costs prior to the start of the seismic program.

The 1,221 square kilometre area contains 40 identified oil and gas leads that can be evaluated with low cost seismic and drilling programs.

While several oil and gas fields with total discovered proved and probable reserves of 12MMbble of oil and 50Bcf of gas have been made in the block since the late 1960s, it is still considered to be underexplored and lacks modern 2D and 3D seismic data.

ADX plans to remedy this in part through its committed work program.

This consists of the reprocessing of 300 kilometres of seismic, acquiring 100 square kilometres of new 3D seismic and 100 kilometres of new 2D seismic as well as drilling 2 wells.

It has already completed geotechnical studies that have identified two independent fairways within the migration pathway of the MAKO source kitchen.

The MAKO trough contains the Algyo Field in Hungary which has historical production of 2.6 trillion cubic feet of gas and 225MMbbl of oil. 

Romania has a favourable tax and royalty regime and has easy access to local infrastructure and European markets.

Riedel Resources – MINERAL INTERESTS

Besides its oil and gas assets, ADX also holds 31.28% of Riedel Resources (ASX: RIE), which it spun-off in 2010.

Riedel holds the Mt. Webb, Marymia, Millrose and Cheritons gold and base metal projects in Western Australia.

These have existing inferred gold resources with potential for expansion, along with mature drill ready targets for gold, copper and gold, and nickel. 

Riedel has also acquired gold tenements in Burkina Faso where early stage surface sampling and auger drilling are underway.  

CATALYSTS – WITHIN A YEAR

• Testing at Sidi Dhaher-1 to confirm commercial flow rates and reservoir size.
• Completion of 2D and 3D seismic at Parta opens up potential.
• Farmout of Sicily Channel acreage.
• Drilling and testing of a successful Dougga appraisal well may increase resource size and confirm commercial flow rates.
• Testing of Lambouka-1 to confirm resource estimates and another addition to “Dougga-Hub”.
• Exploratory well adds speculative interest and potential materiality.

ANALYSIS

Sidi Dhaher-1 is surrounded by several producing oil fields and extensive oil and gas infrastructure which are significant in terms of attractiveness to investors for funding any future development. Oil could be trucked to a nearby field where it would enter a transportation pipeline, taking it south to a port for export. 

The completion of testing at the Sidi Dhaher-1 in the first half of 2012 should be an inflexion point for the Company.  Success at Sidi Dhaher will also serve to de-risk several other prospects and leads in the Chorbane permit.

The offshore program in the Sicily Channel should attract attention with the appraisal drilling of the Dougga gas field, and back to back testing of Lambouka-1. The drilling of an exploratory well on a prospect defined by 3D seismic and proximal to Dougga within the Sicily Channel also has potential to provide very significant upside to the current market capitalisation of the Company.  This is expected to be de risked by securing a farm-in partner, a process that is expected to gain from ADX’s successful track record in doing so. 

A successful commercial production test at Sidi Dhaher-1 would assist to underwrite the future of the Company.   A positive result could take ADX Energy to early cash flows and becoming an oil producer in a three to six month time frame.  

The confirmation of recoverable volumes and resulting potential reserves are contingent upon a successful well test with the objective of proving commercial flow rates and likely recovery factors.

Actual flow rates and recovery will only be known once testing begins but assuming industry standard oil recovery of 35% and a US$100 (A$97.4) price per barrel of oil, Sidi Dhaher could be worth US$714 million over its life to ADX. 

Taken further, Sidi Dhaher could have recoverable reserves of (conservatively) 10 to 17 mmbbls which would provide ADX Energy with an entitlement of 4 to 6.8 mmbbls, or a gross worth of around $90 million or $0.20 per share.  This is against a current share price of $0.08 – indicating significant upside potential for investors.

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Wasabi’s Turkish subsidiary Imparator Enerji signed an option to take a 50 per cent stake in the Tuzla Geothermal Power Project (TGPP) in April subject to partner and regulatory approval.

TGPP owner and operator Enda Enerji has now given its go-ahead, though the exercise of the option remains subject to the project lender's consent as well as regulatory approvals, Wasabi said.

The total consideration for the option is US$11.75 million (including a US$5 million loan note).

The project includes an operating 7.5 MWe geothermal power plant in Canakkale Turkey, with opportunities to expand further.

Historical studies indicate geothermal power generation potential of up to 80 MWe said Wasabi, which has started work on a pre-feasibility study for the development of a first stage 14 - 17.5 MWe build-out.

Wasabi will develop the project with Enda, which is an experienced power plant developer and operator in Turkey. 

The TGPP covers an area of approximately 11sq km of a very shallow and relatively high temperature geothermal zone in North Western Turkey and hosts a recently installed and currently operating 7.5 MWe power plant. 

The Tuzlageothermal field has also been extensively studied and drilling has confirmed the TGPP as a major regional geothermal resource. 

Wasabi added the proposed 14 - 17.5 MWe first-stage build-out at the TGPP may utilise its Kalina Cycle technology, which has the potential to increase power generation at the project by 20 per cent.

Wasabi said the option and development work would be funded through asset sales and other capital raising initiatives.

John Byrne, Wasabi’s executive chairman, said: 

"The opportunity we have in Turkey, through our option over the Tuzla project (TGPP) looks compelling.  As well as the potential geothermal resource we would be looking to utilize our proprietary technology.

"The Turkish power generation sector is receiving unprecedented interest from domestic and international investors and continues to be driven by the strong underlying demand for power in Turkey as a result of sustained economic growth.

"Should we decide to exercise the option, we would look to redeploy capital within the group and/or raise additional funds as appropriate to ensure the acquisition is value-accretive."

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.

ADX Energy (ASX: ADX) has secured a farm-in partner for the Parta Block concession in Romania who will alleviate much of the costs of the forward work program there.

Rohoelaufsuchungsgesellschaft (RAG), an Austrian private company that has been exploring for and producing oil and natural gas in Central Europe since its foundation in 1935, will make an upfront payment to ADX and will have the right to earn a 50% interest in Parta.

This can be achieved by a payment in lieu of past costs and a payment of a promoted share of future costs prior to the start of seismic operations.

ADX is required to shoot 100 square kilometres of new 3D seismic and 100 kilometres of new 2D seismic as well as drilling 3 exploration wells.

The company has already secured €3.1 million for the seismic work with a view to drilling exploration wells as soon as possible.

ADX added the deal positioned it as the operator of a strong joint venture with a capable partner in Parta. It also retains a 100% interest over 8 prospecting permits.

RAG has extensive industry experience, technological expertise and highly specialised knowledge. It is also one of the leading underground natural gas storage operators in Europe supplying both national and international customers.

The 1,221 square kilometre Parta concession contains 40 identified oil and gas leads that can be evaluated with low cost seismic and drilling programs.

While several oil and gas fields with total discovered proved and probable reserves of 12MMbble of oil and 50Bcf of gas have been made in the block since the late 1960s, it is still considered to be underexplored and lacks any modern 2D and 3D seismic data.

Geotechnical studies carried out by ADX have identified two independent fairways within the migration pathway of the MAKO source kitchen.

The MAKO trough contains the Algyo Field in Hungary which has historical production of 2.6 trillion cubic feet of gas and 225MMbbl of oil. 

Romania has a favourable tax and royalty regime and has easy access to local infrastructure and European markets.

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ADX Energy (ASX: ADX) is making its final preparations to test its key Sidi Dhaher-1 oil discovery at the Chorbane licence, onshore Tunisia, with the test rig now on site.

Well testing will aim to confirm the recoverable volumes and resulting potential reserves, and identify commercial flow rates and recovery factors.

Detailed interpretation and analysis of reservoir fluid samples recovered during drilling had indicated a good quality Bireno carbonate reservoir with an estimated 30 metre oil column.

This formation has proven very productive in several nearby fields.

Log analysis has also indicated potential pay in the Cherahil formation, which will be tested if the Bireno formation test results are unfavourable.

A successful test will lead to an extended well test program to provide additional production and reservoir performance information that will be used for field development and planning purposes.

Sidi Dhaher has estimated mean contingent oil in place resource volumes of 51 million barrels.

The 2428 square kilometre Chorbane permit has all the hallmarks of a highly prospective oil and gas asset. 

It contains large undrilled structures in a producing oil and gas province with high quality seismic available over prospects and leads that gives ADX plenty of follow up potential.

To top it off, the permit is close to existing onshore pipelines, a strong gas market and oil equivalent pricing conditions, making it commercialisation of any discoveries both quick and economically attractive.

ADX holds a 40% stake (operator) in Chorbane while Gulfsands Petroleum (LON: GPX) also holds 40%. The remaining 20% is split equally between XState Resources (ASX: XST) and Verus Investments (ASX: VIL).

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The three-part, C$33 million package, includes a loan, a convertible bond, and a share purchase agreement, which will allow the Company to bring up to seven wells into production, three in Ukraine and up to four in Canada.

In addition the facilities provide spare capital for acquisitions and new ventures. 

“We can call down on the remaining tranches of the loan agreement and on the equity as a contingency item to manage overruns and to do additional work, but we won’t disadvantage existing shareholders by paying for it now, upfront,” said Worrall.

“We will use it as and when we want and hopefully that will be when the share price is significantly higher.

“But securing access to the funds means we can plan future campaigns with confidence and make commitments to our government partners in Ukraine.”

 Worrall moved to allay fears over the share purchase agreement, a form of funding which is commonly mis-understood by market, and is wilfully misrepresented in other quarters.

“Yorkville has agreements in place with other companies it supports, which have led to increases in stock prices,” he said. 

“They work closely with companies to ensure the additional shares are placed carefully and gradually without disrupting normal market activity. And they have committed not to short the stock at any time.” 

“We think what we have done is particularly suitable to funding for junior oil and gas companies,” said Worrall.

The first and major landmark of what promises to be an exciting year is the multi-stage fracture stimulation of the Karl 101 well on the Karlavskoye field, which gets under way in the next couple of weeks.

The company has hired Schlumberger to carry out the work, which reflects a more open attitude from the local authorities towards the use of foreign contractors on Ukrainian soil.

The well has been drilled and has flowed natural gas and condensates at stable flow rates from all five reservoir intervals. But fracturing is required to increase the flow rates and to make the well commercial.  

Frack operations get underway in the next few week, and should be completed and test results announced within a month”. 

Karlavskoye, which is in the Crimean Peninsula, is one of many fields discovered and appraised in the Ukraine during the 1960s and 70s that were deemed uneconomic because the technology didn’t exist to achieve commercial production.

It is estimated to contain 472 billion cubic feet of gas in place, so this initial target is reasonably significant.

However, the bigger prize is the opportunity it opens. 

There are scores of discovered, but unproduced fields in the Ukraine with broadly similar characteristics to Karlavskoye, which offer the potential for fracking.

These aren’t exploration targets as numerous wells have already been drilled on the fields, and a huge amount of data compiled, although the quantity and quality of this data is sparse by modern standards.  

“In Crimea alone there are another 10 licences we are interested in,” said Worrall. 

“In all cases they have been discovered. Now we need to drill a modern well so we can compare the results to the old wells and then apply the appropriate stimulation technology.” 

Over the summer the company’s attention will turn to Beaver River, in Canada, where the focus will be on its conventional gas assets rather than the shale play.

“The reason for this is the production rate should be far higher on the conventional targets,” Worrall explained. 

“They high rates may not last very long and the ultimate recovery may not be enormous, but with low prices expected to continue for a while what you need is flow rate to retain profitability.

“You can’t be building shale gas wells producing at one or two million [cubic feet] a day because they don’t pay while the gas sales price is so low. 

“If we can bring on a conventional well in Canada at 10 million a day you can survive in the low price environment. 

“I think everyone expects prices to strengthen in the course of this year as demand picks up across North America and lot of conventional and shale gas developments are put on hold because they are just not economic.”

Separately, senior management and directors have subscribed to the convertible, including operations manager Bob Petryk, who will be overseeing the frack of Karl 101, which is a huge vote of confidence.

Petryk has 30 years of experience fracking over 1,000 wells and his involvement in the financing cleared demonstrates his belief in the Ukraine well, Worrall said.  

“Within the next year this financing should allow Transeuro to develop into a vastly different company with sustained production in the Ukraine and Canada and resources moving into the reserves category,” he added.

Unveiling 2011 results today, the company highlighted the fact it shut its UK businesses in February this year to concentrate on the Ukraine-based biomass operation, blaming weak trading and a lack of orders.

It said the key to future success lies with working with its Ukrainian partners and is confident it is positioned to achieve growth.

The company's financial performance in 2011 was impacted by the strategic change, the company said.

For the 12 months to December 31, the firm posted revenues of £0.9 million, compared to £3 million in 2010.

The loss for the year widened to £2.5 million compared to a loss, in 2010, of £2 million. The loss per share came in at 1.47 pence compared to 1.95 pence in the comparative period.

As at year-end, the company had  £1 million in cash (2010: £0.7mln).

Chairman Gavin Little told investors: "Whilst 2011 was a tough year, as evidenced in our results, the board believes that shifting the focus to solely Biomass and managing the business to a very tight cost base as we build our position in the Ukraine establishes the right platform for Active Energy to return to growth.

"The board believes that there are exciting opportunities for Active Energy to position itself in the Biomass market in the Ukraine, building a position with access to guaranteed feedstock supply with the highest quality standards and thus enabling the Group to expand its client base in Europe."

He added that the increasing demand for biomass fuels was encouraging and the firm already has expertise in this field.

"The board is cautious but remains confident that it is positioned to realize its new growth plans."

As revealed earlier this year, Active Energy Ukraine (AEU), which the company bought last November, has an 80,000 tonne per year contract with Polish group Medium to supply wood chips.

Active Energy said it expected to generate £3 million in revenues this year from this contract to suppy the chips to industrial power stations in Poland.

ADX Energy (ASX: ADX) is moving forward at the Sidi Dhaher-1 oil discovery at the Chorbane licence, onshore Tunisia, with the support camp now mobilised.

The company added that consistent with the process followed for the drilling of the Sidi Dhaher-1 well, camp mobilisation has been undertaken cautiously.

The local authorities in the Sfax area are supporting ADX’s efforts to complete the mobilisation of the drilling rig, with the company to provide updates on operational milestones as they occur.

The mean contingent oil in place resource volume for the Sidi Dhaher oil discovery has been estimated at 51 million barrels, with the 2428 square kilometre Chorbane permit having all the hallmarks of a highly prospective oil and gas asset.

It contains large undrilled structures in a producing oil and gas province with high quality seismic available over prospects and leads.

ADX holds a 40% stake (operator) in Chorbane while Gulfsands Petroleum (LON: GPX) also holds 40%. The remaining 20% is split equally between XState Resources (ASX: XST) and Verus Investments (ASX: VIL).

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The Isle of Man-headquartered group, which was formed in 2007, has six exploration and prospection concessions covering approximately 4,387 square kilometres (1,084,000 acres) in the onshore Baltic Basin of northern Poland.

As well as the Baltic concessions, 3Legs also holds exploration licences near Krakow, southern Poland, two licences in Baden-Württemburg, south-west Germany, while two further licence applications have been submitted in southern France.

The company raised over £58 million in 2011 through an initial public offering (IPO) on AIM last June, and had cash of £50.9 million at year end, compared to £1.6 million in 2010.

After shale gas burst onto the US market in recent years, the focus has now shifted to finding available resources in Europe, and 3Legs has drilled the only 2 horizontal shale gas wells (Lebien LE-2H and Warblino LE-1H) on the continent, according to the company.

However, there have been concerns about the economic feasibility of shale gas in Europe, given the complicated drilling techniques required to access the gas.

Shale gas is natural gas trapped within shale formations, which can be rich in petroleum and natural gas.

Hydraulic fracturing (or “fracking”) is applied, where water, chemicals and sand are pumped into the well to unlock trapped hydrocarbons by opening the fractures in the rock and allowing natural gas to flow from the shale into the well. This technique, in conjunction with horizontal drilling, makes shale plays commercially feasible.

And with initial flow rates from 3Legs’ Lebien LE-2H and Warblino LE-1H wells below forecasts at 450-520 mscf/d and 18 mscf/d respectively, concerns have also been raised as to whether or not it really will prove to be a commercially viable option.

3Legs’ chief financial officer Alex Fraser clAIMs the results from the first well in particular in fact showed a good flow rate but that investors were expecting better.

“Mechanically, the frac job was successful. The flow rate wasn’t as good as investors were looking for. We consider it was actually quite a reasonable flow rate,” he said.

US energy firm ConocoPhillips (NYSE:COP) must think so, as it recently exercised its option to acquire 70 per cent of 3Legs’ Baltic concessions.

Broker Jefferies believes that the ConocoPhillips deal is a “positive signal of the potential of the blocks”, and has a target price of 230 pence per share for 3Legs.

The broker added a note of caution however: “Key risks remain proving commercial production rates for Polish shale.”

Fraser told Proactive Investors that this will take time.

After all, the company had originally promised to show its wells were commercially viable in 18 to 24 months after floating last June.

“It’s difficult to really form a view about it – the long-term commercial potential – until you see more horizontal wells drilled and that’s what we need to see happen now,” he said.

“It can take half a dozen or a dozen horizontal wells to really understand the commercial viability of a new shale basin,” he added.

Fraser maintains that Poland is the best market to be in for gas.

“Poland is a very attractive market for shale gas exploration. They import 70 per cent of their gas from Russia. They are very keen to reduce that dependency for a lot of reasons, so the incentive in Poland to develop domestic gas reserves is absolutely huge.”

He added there had been huge government backing, as well as “a clean bill of health” from the Polish Ministry of Environment relating to environmental concerns about the fracking operation.

Looking forward, the company is considering retesting both of its two existing horizontal wells to gain a better understanding of the potential of its Polish concessions, after which Fraser believes the company will have a far clearer idea of the commercial upside.

“There is no guarantee of long-term success until you know what the likely commercial returns from the acreage are. And no-one has any idea of that yet.”

Fraser believes that the hype about shale gas from last year has contributed to the current weakness in the share price.

“The pendulum’s gone the other way against Polish shale right now. But there was a little bit too much hype last year and that’s really what we’re paying for now,” he said.

“There were few places for investors to look for investing in shale gas in Europe, so they piled into a small number of companies and those share prices did very well.

“We floated in June last year somewhat on the back of that excitement. At the same time there was no hard data.”

He believes however that data sharing will help entice investors back.

Drilling activity on San Leon’s (LON:SLE) adjoining acreage, for example, “will certainly help the investor community further advance their understanding of the potential of shales,” he stated.

With a total of 22 new shale wells expected in Poland in 2012, most of which are vertical and one of which will be drilled by 3Legs, Fraser expects the newsflow to provide further clarity. 

3Legs is now also targeting further unconventional oil and gas resource opportunities.

“We view the company as an independent, nimble, fast-mover, able to get into new unconventional assets and opportunities at an early stage,” said Fraser.

“That’s what we did in the Baltic Basin – we were first in there. We secured the only shale concessions in the Baltic Basin in 2007.

“And we want to replicate that sort of achievement elsewhere if we can. It might not necessarily be through licensing, it might be through other types of participation – farm-ins for example, or joint ventures.”

As 3Legs certainly has the firepower with its hefty cash balance, the question is where.

“We’d prefer to be in Europe but we will also look at other areas in the world which we consider a company of our size can operate in safely and effectively,” Fraser concludes.

Coal bed methane (CBM) is a less well-known form of natural gas.

It is already used extensively in Australia and Asia and advocates say it can do the same for the energy supply in the UK as shale has for the US.

So what exactly is coal bed methane?

It is methane that has been trapped within coal seams that is extracted prior to mining the coal.

This methane is in near-liquid state and lines the pores within the coal.

It can be extracted by drilling wells into and across the coal seam and pumping off the water in the fracture spaces.

This ‘dewatering’ process is the important bit as it allows a decrease in pressure which means the methane can ‘desorb’ from the coal and flow up the well as a gas, which is then compressed and piped to market.

Although this all sounds very complicated, it’s not.

In fact, compared to hydraulic fracturing, or ‘fracking’, which is used to extract shale gas, the process is relatively simple.

On top of this, fracking is very controversial due to its potentially harmful environmental effects, including the contamination of ground water and other pollution-related consequences.

There are no such concerns surrounding CBM, however, as the dewatering process is far more environmentally sound.

This opinion has been backed up by the Department of Energy and Climate Change (DECC), which explains that extracting the gas prior to mining reduces the “potentially dangerous methane gas encountered when carrying out traditional mining methods”.

Furthermore, methane has the potential to be fed directly into the gas distribution network, such are its qualities.

CBM is also different and more attractive than coal mine methane (CMM) and abandoned mine methane (AMM), which is methane released as a result of mining activities.

These methods usually have higher carbon dioxide content, which is not suitable for direct introduction.

Australian company Dart Energy (ASX:DTE) is pioneering CBM’s use in the UK.

Eytan Uliel, the company’s chief commercial officer, told Proactive Investors that despite Dart’s extensive worldwide portfolio, its most advanced asset is the Airth project, which is in fact in Scotland.

“There we have drilled our first test wells, we have encouraging results, we have entered into a long-term gas sales agreement with Scottish Southern Energy, we have at the same time certified our first reserves and on the back of all that, we are looking to move that project into commercial development in the near-term,” Uliel said.

A pilot-to-power project will utilise pilot well gas from Airth to generate electricity and provide first revenues from the field. The generator has now been installed on-site and first electricity sales are expected in the coming months.

UK-based IGas Energy (LON:IGAS) is also a firm believer in the potential of CBM in this country.

Earlier this year, the company told Proactive Investors that CBM remains its priority despite a shale gas discovery in Cheshire.

So while shale gas is making all the headlines in the industry, CBM’s potential should not be underestimated.

And with all this potential, it may only be a matter of time before we see CBM projects popping up all over the country.

--Adds broker comment & share price details--

Wentworth Resources (LON:WRL) today said that the Ziwani-1 exploration well has been plugged and abandoned after testing showed the new gas discovery to be non-commercial.

The well was spudded in February and initial results showed that the pre-drill targets were not present in the well. It later revealed that gas shows encountered while drilling were confirmed to be a new discovery.

However, the three metre gas interval tested at an unstable rate of 7.2 million cubic feet per day, and separate analysis indicates that potential resource volumes are sub-commercial.

Focus will now turn to the upcoming work-over programme on the group’s existing gas production assets.

"Although the results of Ziwani-1 did not meet our expectations, we remain committed to our exploration programme on the block and to the second well, which is expected to be drilled later this year,” said chairman Bob McBean.

“We look forward to the forthcoming workover programme as the next step in development of the Mnazi Bay and Msimbati gas fields."

Wentworth said the rig is now being moved from the Ziwani-1 location to the Mnazi Bay gas field, which is found within the same concession area.

There it will undertake a three well work-over programme. This will include extended well tests on each well, which AIMs to establish an insight into the long term producibility of the Mnazi Bay and Msimbati gas fields.

Wentworth will return to exploration drilling once this workover programme is complete.

“The Wentworth investment case is supported by 0.7 Tcf gross contingent resources in the Mnazi Bay concession, the exploration activities on the prospective onshore Rovuma Basin, Mozambique, and a well capitalised balance sheet,” Panmure Gordon analyst Leila Reddy said in a note to clients.

She adds: “We see the current price weakness as an attractive entry point in the gas rich East African region.”

Panmure Gordon has a ‘buy’ recommendation for Wentworth, targeting 113p  a share.

On AIM today Wentworth fell 8.5p, or 16 per cent, to trade at 42.5p each.

The original hit an ‘unmarked and unreported’ obstruction while in transit.

"The replacement lift-boat is expected to come off its existing contract in about 30 days and then to complete the piling and installation of the platform at Mustang Island for the re-entry of the I-1 well,” Silvermere said in a stock exchange statement this morning.

The AIM quoted oil firm has a 33.33 per cent working interest in the venture, which is operated by Dominion Production. Poor weather has delayed operations in recent weeks. 

Last month Silvermere told investors that the new Mustang Island platform, tripod and other associated equipment had been loaded and “tied down” onto the barges on location at Laredo's yard in Galveston.

Silvermere says the installation of the new platform will be a “major milestone” in the development of the Mustang Island 818 reserves. The facility will allow for the production from three future wells.

The well was spudded in February and initial results showed that the pre-drill targets were not present in the well. It later revealed that gas shows encountered while drilling were confirmed to be a new discovery.

However, the three metre gas interval tested at an unstable rate of 7.2 million cubic feet per day, and separate analysis indicates that potential resource volumes are sub-commercial.

Focus will now turn to the upcoming work-over programme on the group’s existing gas production assets.

"Although the results of Ziwani-1 did not meet our expectations, we remain committed to our exploration programme on the block and to the second well, which is expected to be drilled later this year,” said chairman Bob McBean.

“We look forward to the forthcoming workover programme as the next step in development of the Mnazi Bay and Msimbati gas fields."

Wentworth said the rig is now being moved from the Ziwani-1 location to the Mnazi Bay gas field, which is found within the same concession area.

There it will undertake a three well work-over programme. This will include extended well tests on each well, which aims to establish an insight into the long term producibility of the Mnazi Bay and Msimbati gas fields.

Wentworth will return to exploration drilling once this workover programme is complete.

Transeuro Energy Corp (CVE:TSU) updated investors on three financing arrangements, which are aimed at developing its existing wells and potential new ones through to production and revenue.

The final terms of the secured convertible bond, announced last month, is for NOK 60 million (around C$ 10.4 million) with an annual interest rate at 12 per cent and a conversion price at NOK0.85 (around C$0.146), it said today.

The company also said it was finalising a further facility with a US-based alternative investment manager, including a loan agreement for up to C$5million and a share purchase agreement for up to NOK100million (around C$17.2 million).

Under the proposed loan, Transeuro will receive up to C$5 million over two years, advanced in tranches. The loan will be unsecured and pay annual interest at 10 per cent. 

Transeuro will also issue 1 million share purchase warrants with each $1million drawn from the loan agreement. The exercise price will be the greater of either C$0.146 or a 50 per cent premium to the closing price on the date the loan is executed.

The firm can then withdraw funds of up to NOK 100 million over a three year period, and the investment manager will purchase shares at a discount of 5 per cent to the forward volume weighted average share price during a 40 day forward pricing period. 

Transeuro Energy chairman Aage Thoen said the three financing agreements provided a combination of debt at very competitive rates and equity through progressive share issuances.

This would provide the capital required to develop the firm's existing wells and possible new wells through to production and revenue, he said. 

"The funding structure covers our short and long term needs and widens our strategic options," he added.

WHL Energy’s (ASX: WHN) newly awarded La Bella gas field in Otway Basin could add further value in the near future with strong industry interest and the expected growth in eastern Australia gas demand coming together to attract farm-in partners.
    
While WHL has said that its priority is on finalising a partnership in its Seychelles and capturing further African portfolio growth, a partner in VIC/P67 could drive exploration and a quick development through existing infrastructure in the area.

Gas prices

The company said the La Bella gas field within the permit could have a conservative net present value of A$75 million at current gas prices of A$6 per gigajoule. 

This value could more than double to over A$140 million if gas prices increase to A$8 per gigajoule.
 
WHL said recent public briefings by companies such as Santos (ASX: STO), Origin Energy (ASX:ORG) and Beach Energy (ASX: BPT) had flagged an expected increase in east coast gas demand that could see prices increase to between A$6 to A$9 per gigajoule as gas contracts become increasingly linked to oil prices.

“Importantly, the deal by Origin to supply gas to Santos was agreed at oil linked prices confirming the Company’s view that gas pricing for firm-supply delivered around 2016 will be significantly higher than current levels,” WHL managing director Steve Noske said.

“Oil-linked gas prices would cost the buyer around $7 a gigajoule when international oil prices were at US$100 a barrel.

“The industry and WHL Energy is in agreement that gas pricing will increase. With East coast gas deals now being completed at oil linked pricing we have confidence that we can realise the significant value in our VIC/P67 acreage that includes La Bella, a ready to develop gas field.”

Exploration upside

While La Bella allows WHL to book an immediate best estimate contingent resource of 158 petajoules (149 billion cubic feet) of gas and 1.2 million barrels (MMbbl) of condensate, other prospects in the permit hold prospective resources of 668 petajoules of gas and 4.9 million barrels of condensate.

These include the relatively low risk prospects present at Highlander and West La Bella which provide additional tie-back opportunities to a potential La Bella development.

VIC/P67 is located close to existing infrastructure including the Santos operated Casino gas development, Origin's Otway gas project, the BHP Billiton (ASX: BHP) operated Minerva development and TRU Energy’s Iona gas plant.

WHL had committed to a A$62.1 million primary work program to secure the permit.

This includes the reprocessing of 1000 kilometres of 2D seismic, acquiring and processing of 811 square kilometres of 3D seismic as well as 650 kilometres of 2D seismic, 2 exploration wells and geotechnical studies.

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WHL Energy (ASX: WHN) has been officially awarded the VIC/P67 permit in the Otway Basin offshore Victoria that holds the La Bella gas field.

The company had committed to a primary work program totalling A$62.1 million in the first 3 years to beat out 6 other bids for VIC/P67, which was released as V11-2, under the Federal Government’s 2011 Offshore Petroleum Exploration Acreage Release round.

This includes the reprocessing of 1000 kilometres of 2D seismic, acquiring and processing of 811 square kilometres of 3D seismic as well as 650 kilometres of 2D seismic, 2 exploration wells and geotechnical studies.

WHL also has the option for a A$27 million secondary work program that consist of geotechnical studies and 1 exploration well.

VIC/P67 is located close to existing infrastructure including the Santos (ASX: STO) operated Casino gas development, Origin Energy’s (ASX:ORG) Otway gas project, the BHP Billiton (ASX: BHP) operated Minerva development and TRU Energy’s Iona gas plant.

WHL had previously said the La Bella gas field will allow it book an immediate best estimate (2C) contingent resource of 158 petajoules (149 billion cubic feet) of gas and 1.2 million barrels (MMbbl) of condensate.

Further upside potential exists in the block including the relatively low risk prospects present at Highlander and West La Bella which provide additional tie-back opportunities to a potential La Bella development.

Also winning an offshore Victoria permit was Bass Strait Oil Company (ASX: BAS), which was awarded VIC/P68 (released as V11-5) in the Gippsland Basin after committing to a A$3.5 million work program of geotechnical studies and 225km2 3D seismic survey.

The Department for Resources and Energy awarded 12 permits from the acreage round, securing A$303 million in new investment over 3 years.

The Northern Carnarvon Basin was the centre of the most attention with Woodside Petroleum (ASX: WPL) and BHP Billiton (ASX: BHP) awarded 2 permits each while Hess, Murphy Oil and Finder Exploration were each awarded 1 permit.

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A benign political backdrop and a generous fiscal regime have made it a magnet for globally recognised names such as Shell (LON:RDSB) and Total right the way through to Tangiers Energy and Longreach at the other end of the spectrum.

The success of the Jubilee field off the coast of Ghana has also had an impact, with explorers such Tullow (LON:TLW), Kosmos and Anadarko heading north to Morocco in a bid to locate Africa’s next elephantine oil discovery. 

A minnow among these big fish is ASX-listed explorer Pura Vida (ASX:PVD), which is sitting on a 75 per cent share of the Mazagan Offshore Area.

The other 25 per cent of the permit is owned by ONHYM, the state national oil company, which has a free carried interest through the exploration phase.

Mazagan covers almost 12,000 square kilometres and is due north of the Tarfaya offshore block owned by Tangiers Petroleum (LON:TPET), another Aussie company.

However, Pura Vida is several steps ahead of Tangiers in owning 3,500 square kilometres of 3D seismic and around 5,000 kilometres of 2D.

This story includes a Jubilee lookalike in the form of the Toubkal prospect with a potential mean 790 barrels of oil recoverable, according to an independent report compiled by RISC.

The recent resource upgrade to 2.4 billion barrels of recoverable oil from 825 million underlines the huge the potential of block, which consists of 11 leads and prospects.

“Once in a while in your career something like this comes up,” said managing director Damon Neaves. 

“We believe in it. We have put our own money in it. If we can just get the market to give a value equating to something near our peers then it is 10 or 15 times our current market cap.”

RISC’s revised estimates focused on Lower Cretaceous prospects following technical work that assessed deeper water 2D seismic data.

Most of the potential resources to that point comprised the Miocene prospects whereas many of the company’s peers in the region have focused their efforts on the Lower Cretaceous.

That said, the Toubkal structure, identified early on in the game, remains the most likely target of the company’s first well.

Before this happens Pura Vida must first complete the reprocessing of the 3D seismic data, which is expected to be completed in September.

The plan then is to farm down its stake to a partner in return for a free carried interest on a one to three well programme.

At US$50 million per well, exploration isn’t cheap in this part of the world, which means Pura Vida will inevitably have to team up with a big brother that has very deep pockets. 

So Neaves has a very definite idea of Pura Vida’s ideal partner: “It is likely to be a renowned African deepwater operator. We have been very selective about who we have shown the data to so far.”

A deal, which Neaves expects to be signed by the year-end, would also give an objective valuation of the company well in excess of its current market capitalisation.

A recent note from the UK broker N+1 Brewin Dolphin suggests the stock is worth 95 cents, a significant premium to the current price of 36 cents.

It points out that its closest comparator company, Tangiers, is trading at around US$1.50 a barrel of oil compared with Pura Vida’s 9 cents a barrel based on their respective risked prospective reources.

This glaring inconsistency stems from the fact that Pura Vida is new to the market (it listed in February) and therefore its story has not been as widely known and understood as that of Tangiers.

Of course this will change as the newsflow increases. “In aggregate, we believe there is potential for near-term, high impact events, including the recognition of additional resources following completion of the seismic reprocessing (currently underway), farm-out negotiations leading to securing funding for the drilling program and  acquisitions,” said Brewin analyst Tracy Mackenzie.

Deals are on the company’s radar screen, with Pura Vida’s management sizing up potential targets in Africa, Neaves confirmed.

This may prompt the company to come back to the market to fund a purchase, and there have even been whispers of a London listing.

The Pura Vida managing director is tight lipped on this prospect of a UK IPO, though we know the company is fully funded for its current work commitments with A$5 million in the bank.

The group bought the Mazagan permit for A$3.5 million last October, and in doing so acquired some of the last remaining open acreage. This was quite a coup.

“Morocco needs to develop its oil industry, particularly its deepwater potential,” said Neaves. 

“To do this they need to attract the big companies into the country. They saw us as having the technology and expertise to do this: the modern seismic reprocessing techniques in particular.”

“They saw us as a conduit to bringing in the big, deepwater operators to make the big investments required to pursue deepwater drilling."

Silvermere Energy (LON:SLME) today revealed a further delay to the start of production at the Mustang Island gas field in the Gulf of Mexico.

This latest delay is the result of an incident involving a lift-boat that was contracted for the upcoming work programme.

The vessel struck an ‘unmarked and unreported’ obstruction while on its way to Corpus Cristi, where it would have picked up supplies prior to the Mustang Island programme, Silvermere explained. 

This created a three foot hole in the vessels hull. And the boat took on large amounts of water. It has now been towed to the port town of Cameron, Louisiana. Silvermere says the incident is now the subject of a coastguard investigation and it is expected that the vessel will be out of action for at least two months.

The contractor, Laredo, is now attempting to source an alternative lift-boat.

"This delay to the preparation for production is unfortunate and frustrating, but it does not present additional liabilities to the company. The lift-boat was not at the time of the incident on contract,” said chief executive Andy Morrison.

The AIM quoted oil firm has a 33.33 per cent working interest in the venture, which is operated by Dominion Production. Poor weather has already delayed operations in recent weeks. 

Last month Silvermere told investors that the Mustang Island new platform, tripod and associated equipment had been loaded and “tied down” onto the barges, on location at Laredo's yard in Galveston.

Silvermere calls the installation of the new platform a “major milestone” in the development of the Mustang Island 818 reserves. The facility will allow for the production from three future wells.

The installation process consists of three phases. The installation of the tripod base structure is followed by raising the main deck by crane and lowering it on the tripod and phase three is the pipeline hook-up.

That is the view of UK broker N1 Brewin which today repeated a 'buy' recomendation and upgraded its price target to A$0.95 from A$0.80. 

Analyst Tracy Mackenzie says these events will come in the form of farm-out negotiations, acquisitions and additional resources.

A farm-out would be significant and it would open the door to a pivotal drill programme, the analyst says. 

The probable plan would be to drill the large Toubkal structure first. This is just one part of the Mazagan offshore liecence block that was the subject of a significant increase in resource potential this week

On Monday it was revealed that a recently completed review had identified an additional 1.6 Billion barrels of resources potential – in new prospects and leads.

It is now estimated that the Mazagan offshore area may contain 3.2 billion barrels of oil, up from the previous estimate of 2.6 billion barrels.

Most of the potential resources reported previously comprised the Miocene prospects whereas many of the company’s peers in the region have focused their efforts on the Lower Cretaceous.

Mackenzie explains that with the review Pura Vida has now included additional estimates for the Lower Cretaceous (LC) age horizons within Mazagan. 

“In essence the existing LC prospects have been upgraded and new leads have been identified, with the LC now being acknowledged as a major prospective play fairway in the deep water of Morocco (due to work combining historical well data with recently added deeper water 2D seismic),” Mackenzie said in a note to clients. 

The analyst adds: “With Kosmos having completed 2,500 square kilometres of 3D on its adjacent block recently, and a decision to drill in 2013 expected to be taken at the year end, we expect attention to turn increasingly to Morocco. 

“We would expect Pura Vida to be able to have a better chance of farmout (on better promote terms) given the newly enhanced database and additional play type.”

Perth-based Pura Vida owns 75 per cent of Mazagan, with the remainder held by the Morocco state oil company.

Morocco has become a magnet to the likes of Total, Repsol, Anadarko and Kosmos because of its favourable fiscal regime, which is one of the most accommodating in the world.

The government take is minimal when compared with hydrocarbon-rich neighbours Algeria and Libya.

The state receives 25 per cent of any project and a 5 per cent royalty if gas is produced, which rises to 10 per cent for oil.  An unprecedented ten-year corporate tax holiday is offered upon discovery.

This means the government take is never more than 35 per cent. Contrast this with Algeria, where the authorities take 92 per cent and you can see why foreign investment is flooding into Morocco.

Not that Pura Vida’s interest could be placed in this category. By far the largest feature of the Mazagan permit area is the Toubkal stratigraphic trap, with mean unrisked prospective resources of 790 million barrels and an estimated chance of success of one-in-five.

Under the licence deal, partner BG (LON:BG) transferred its 50 per cent ownership of the licences in exchange for Dart completing the drilling programme. The transfer boosts Dart’s UK portfolio by 1.2 Tcf of 2c contingent gas.

Talks are still ongoing with BG over a sales agreement that will see gas from the licences sold to the FTSE 100 company. 

The ownership of Dart’s PEDL 133 prospect in Scotland remains unchanged. It holds 100 per cent of the coal bed methane (CBM) and shale resource in the Black Metal Shale layer, and 49 per cent of the shale resource in the Lothian (Broxburn) shale layer.

Dart added it has also decided to take up an option over two licences in Germany, Saxon 1 and 2, offered by BG as part of the restructuring.

Both licences are believed to be prospective for both CBM (carboniferous) and shale (lower carboniferous) with a multi-TCF gas in place potential in aggregate. The licences were acquired for no cost.

The Australia-listed firm added today that it has also completed the A$42 million acquisition of Greenpark Energy’s unconventional gas assets and paid the first tranche of US$6 million cash and US$10m worth of shares.

Greenpark has a portfolio of UK licence assets that Dart said complements its existing acreage in the UK with a similar footprint, similar CBM and shale potential, a sizeable certified 2C resource base in excess of 1.7 Tcf, initial 3P reserves, an early stage development option at PEDL 159 (the Canonbie project), and 100 per cent working interest and operatorship of most licences.

As part of the transaction, Dart also secured an exclusive option over Greenpark’s interests in licences prospective for CBM and shale gas in Poland and Spain. This option is exercisable within 3 months of completion.

Elsewhere, Dart said that the its flagship UK project, PEDL 133 at Airth in Scotland, has had a pilot well on stream since January with stable gas production since mid-April.

A pilot-to-power project will utilise pilot well gas from PEDL 133 to generate electricity and provide first revenues from the field. The generator has now been installed on-site and first electricity sales are expected in the coming months.

A field development plan and front end engineering design study for the full development of the PEDL 133 project has been completed. Initial work on the Environmental Impact Study has commenced, Dart added.

Dart also said it had recently appointed Mark Lappin as its European General Manager. Lappin has almost 30 years experience in the upstream oil and gas business with ConocoPhillips and ExxonMobil. 

The company has gas interests in Indonesia, China, India, continental Europe and Australia as well as the UK.

Shares in Tanzania-focused Wentworth Resources (LON:WRL) rose by 10 per cent today after gas shows encountered in the Ziwani-1 exploration well were confirmed as a new discovery.

"We believe that this new horizon provides added confidence that the Mnazi Bay Concession is gas rich,” said broker Panmure Gordon.

A 3 metre gas bearing zone was identified, at a depth of 1,106 to 1,109 metres and testing is underway to evaluate the find. 

Wentworth said that this is a new reservoir interval that has not previously been encountered in the Mnazi Bay block.

It is a clean Pliocene age reservoir that exhibited strong gas shows during drilling. Analysis of wireline logs indicates a pay zone with 17 per cent porosity and 78 per cent hydrocarbon saturation, it added.

Ziwani-1 will now undergo a drill stem test so that potential gas flow rates can be assessed.

“There can be no assurance that any flow rate achieved will prove to be commercial but the information acquired is expected to be valuable in respect of knowledge of the basin for further exploration,” Wentworth told investors.

Panmure Gordon also said that it is too early to attribute any commercial value, but believes it could build the knowledge of the Mnazi Bay Concession overall for further exploration.

“In addition, given that monetisation of shallower horizons may yield a higher return than deeper wells, this newly identified zone may unlock additional upsides,” the broker added.

The Ziwani-1 well is operated by Wentworth’s partner Maurel et Prom.

And it is being drilled on the Mnazi Bay licence block that also hosts gas production assets and a gas-fired power station nearby.

It is also proposed that a pipeline will be built to connect up to Tanzania’s capital Dar es Salaam.

Wentworth is mostly carried for the costs of Ziwani-1. It has to pay 11.98 per cent of the drilling costs for its 39.93 per cent stake in the project. The cost to Wentworth is currently expected to be US$1.95 million.

Panmure maintained its buy recommendation and 113 pence target price after today’s news. 

“Our recommendation is underpinned by Wentworth’s fully funded development and exploration programme in the Mnazi Bay Concession, Tanzania, and the onshore Rovuma Basin, Mozambique."

Shares rose by 10 per cent to 54.5 pence.

A 3 metre gas bearing zone has been identified, at a depth of 1,106 to 1,109 metres, and testing is underway to evaluate this find. Wentworth adds that this is a new reservoir interval that has not previously been encountered in the Mnazi Bay block.

It is a clean Pliocene age reservoir that exhibited strong gas shows during drilling, Wentworth said. Analysis of wireline logs indicates a pay zone with 17 per cent porosity and 78 per cent hydrocarbon saturation, it added.

Ziwani-1 will now undergo a drill stem test so that potential gas flow rates can be assessed.

“There can be no assurance that any flow rate achieved will prove to be commercial but the information acquired is expected to be valuable in respect of knowledge of the basin for further exploration,” Wentworth told investors.

The Ziwani-1 well is operated by Wentworth’s partner Maurel et Prom. And it is being drilled on the Mnazi Bay license block which also hosts gas production assets and a gas-fired power station is nearby. It is also proposed that a pipeline will be built to connect up to Tanzania’s capital Dar es Salaam.

Wentworth is mostly carried for the costs of Ziwani-1. It has to pay 11.98 per cent of the drilling costs for its 39.925 per cent stake in the project. The cost to Wentworth is currently expected to be US$1.95 million. 

Pura Vida Energy (ASX:PVD) this morning weighed in with a significant resource upgrade to its Mazagan permit off the coast of Morocco.

It rises to 3.2 billion barrels of oil following an independent review carried out by Resource Investment Strategy Consultants from 2.6 billion barrels previously.

RISC’s revised estimates for the Lower Cretaceous prospects following technical work that focused on the recently added deeper water 2D seismic data.

Most of the potential resources reported to date comprised the Miocene prospects whereas many of the company’s peers in the region have focused their efforts on the Lower Cretaceous.

“[Our] resource estimates for Lower Cretaceous prospects have been upgraded and new leads have been recognised as a major prospective play fairway in the deep water of Morocco due to the presence of reservoirs encountered by wells and this is very positive for the future development of the Mazagan asset,” said Pura Vida managing director Damon Neaves.

The large Toubkal structure remains the most likely target of the company’s first well, Neaves he added.

The Perth-based explorer owns 75 per cent of Mazagan, with the remainder held by the Morocco state oil company.

Morocco has become a magnet to the likes of Total, Repsol, Anadarko and Kosmos because of its favourable fiscal regime, which is one of the most accommodating in the world.

The government take is minimal when compared with hydrocarbon-rich neighbours Algeria and Libya.

The state receives 25 per cent of any project and a 5 per cent royalty if gas is produced, which rises to 10 per cent for oil.  An unprecedented ten-year corporate tax holiday is offered upon discovery.

This means the government take is never more than 35 per cent. Contrast this with Algeria, where the authorities take 92 per cent and you can see why foreign investment is flooding into Morocco.

Not that Pura Vida’s interest could be placed in this category. By far the largest feature of the Mazagan permit area is the Toubkal stratigraphic trap, with mean unrisked prospective resources of 790 million barrels and an estimated chance of success of one-in-five.

City broker N+1 Brewin (formerly Brewin Dolphin) said its closest comparator company is ASX and AIM listed Tangiers.

However Pura Vida is valued at a significant discount to Tangiers and many of its rivals in Morocco when assessing their respective resource bases.

On top of that there is also a plan for another C$20 million funding facility.

The company says the proceeds will be used for general corporate purposes. And it ensures Transeuro can develop seven of its existing well up to production in the next twelve months.

“The planned activities include rig work-overs, hydraulic fracturing, acidizing and installation of the necessary production facilities and flow lines,” the company said.

“The target is to increase production rates and sales revenues and to reduce the break even production cost in Canada.”

The convertible bond will carry a 12 per cent annual interest rate and they can be converted for the equivalent of C$0.146 (NOK0.85). This issue has been arranged by Oslo based broker Fondsfinans.

The convertible debt funding has a minimum bond size of NOK60, and this has already been subscribed for. The subscription period will now remain open until 5pm (Norwegian time) on Wednesday 2 May.

Meanwhile the C$20 million facility is expected to be formally approved within a week.

Tangiers Petroleum (LON:TPET, ASX:TPT), which joined the AIM market in February, today reported on the significant progress it made at its assets in Morocco and Australia during the first quarter of the year. 

In today’s report, Tangiers highlighted the completion of a 670 square kilometre 3D seismic survey over the primary prospects at its Tarfaya block offshore Morocco.

Tender requests for processing of the data were issued with contract award expected imminently, Tangiers said in the report.

In the meantime, seismic interpretation including analysis of 2D data over multiple leads within the shallower Lower Cretaceous intervals is ongoing. The results will be used for an independent resource estimate.

The Tertiary and Triassic age sections will be evaluated following completion of the Lower Cretaceous programme.

Tarfaya has an un-risked prospective resource of 867 million barrels, with a high-end estimate of almost 5 billion.

In Australia, Tangiers unveiled an assessment of its Milligans Fan oil play in the Bonaparte basin permit areas WA-442-P and NT/P81, which placed its prospective resources at 218 million barrels of oil.

A competent person’s report (CPR) by ISIS Petroleum Consultants confirmed there was "significant" oil potential in 14 identified leads with combined unrisked oil-in-place of 683 million barrels of oil with a high case of nearly 1.5 billion barrels.

On the financial side, Tangiers had A$3.1 million in the bank at the end of March following a A$6.4 million placing in January. The company spent A$3.54 million on exploration and evaluation during the quarter.

The company AIMs to complete farm-out arrangements for the Moroccan and Australian permits during 2012 to finance its multi-well exploration campaign. The plan then is to have two wells on each by the end of this year.

Unconventional gas group Dart Energy (ASX:DTE) expects first production and electricity from its PEDL 133 well in Scotland this quarter.

The Australia–listed firm said the PEDL 133 production well was put on pump in the quarter to March and after early dewatering had already shown good production potential that will be further tested following the commissioning of the power plant.

A two core well program is also in its final planning phase to support further exploration drilling outside the current PEDL 133 2P reserve area. It is expected to commence in June 2012.

Dart, which has gas interests in Indonesia, China, India, continental Europe and Australia as well as Scotland increased its international net 3P reserves by 39 per cent in the quarter to March, with commercial reserves confirmed in three countries.

Scotland, China and Indonesia have completed pilot wells, while progress is being made in establishing arrangements to enable rapid commercialisation of gas once produced, the company said.

In China, production testing from four vertical wells and five inseam wells is underway as part of the pilot testing campaign on the Liulin coal bed methane (CBM) project.  

In India, drilling of pilot wells is expected to commence at Electrosteel (Jharkhand, India) this quarter upon incorporation of a joint venture company.  Dart is in discussions to connect these wells to facilities of a local CNG producer and commence initial gas sales during 2013.

Dart Energy’s cash position at the end of March was approximately A$98.8 million (£62.5 million), inclusive of A$12.4 million cash-backed guarantees. In addition, Dart Energy has liquid assets worth approximately A$6.9 million. 

Dart added it intends to complete the IPO of its international arm by the end of June.