SRSP – Transaction Update

Sirius Petroleum (AIM: SRSP), the Nigeria focused oil and gas development and production company, is pleased to announce that it has completed its due diligence in relation to OML 109 and is now finalising the financing with a dedicated fund, and awaiting final Block Partner consents to complete the transaction and have mutually agreed with Sirius to extend the transaction period a further 45 days to 31 March. The Company will update the market once this has been concluded.


The Board of Red Emperor Resources NL (ASX/AIM: RMP) (“RMP”, “Red Emperor” or the “Company”), is pleased to provide an operational update with respect to the drilling of the Winx-1 exploration well (“Winx-1”), located on the Western Blocks, North Slope of Alaska.


·      Spud of Winx-1 commenced on 15 February 2019 at 15:15 (AK time) – on schedule 

Red Emperor is pleased to announce that 88 Energy Limited (ASX/AIM: 88E), in its capacity as consortium operator, has advised that the Nordic Rig#3 commenced drilling of Winx-1 on schedule at 15:15 (AK time) on 15 February 2019. The well was drilled to 600ft prior to pulling out of the hole to pick up the smart bottom hole assembly, with logging while drilling tools were attached. At 11:45 on 17 February 2019 (AK time), the Nordic Rig#3 was drilling ahead at 880ft. The forward plan is to deepen the hole to approximately 2,500ft before setting surface casing. Regular updates will be made throughout the drilling operations.

SOU – TE-10: Net Pay Upgrade and Volume Estimates

Sound Energy, the Moroccan focused upstream gas company, is pleased to provide a further update on operations in Eastern Morocco, following the Company’s announcements of 27 December 2018, 7 January 2019 and 28 January 2019.  The Company previously announced a discovery, and a planned stimulated well test, at TE-10, the second well in Sound Energy’s current three well exploration programme in the Greater Tendrara area, onshore Morocco.

TE-10 Net Pay Upgrade

The Company announced on 7 January 2019 that the FMI (high definition formation micro-imager log), which provides a micro resistivity image of the well bore at a much finer resolution than the initial logging suite, had potentially identified the presence of additional thin bedded net pay within the previously identified potential gross reservoir interval between a measured depth (“MD”) of 1,899m and 2,009m MD.

The Company recently commissioned the independent consultancy ERCE* to undertake a petrophysical analysis** of the gross reservoir interval encountered in TE-10.  The analysis integrates a preliminary sample subset of the 57 side wall core samples with the wireline log data, including the FMI data and the high-resolution density logs.

Based on the results of this analysis the Company has made an upward revision of the previously announced net pay estimates, from up to 10.5m to up to 15.4m (a 47% increase), with a mid-case of 13.1m and a low case of 9.5m.  This net pay is distributed throughout the 110m gross reservoir interval identified.  The objective of the previously announced mechanical stimulation testing programme will be to access this distributed pay.

The Company has recognised the presence of a fracture network in both the FMI data and side wall cores.  The potential for a positive impact of this fracture network on the net pay calculation was not included in the scope of the petrophysical analysis undertaken by ERCE but will be considered once the well has been tested.

TE-10 Volume Estimates confirming Multi Tcf Potential

The Company previously confirmed gas shows observed during drilling and calculated that net pay extended below the newly mapped structural closure at approximately 1,943m MD (updated from 1,958m MD communicated on 28 January 2019). These observations suggest that the gas accumulation most likely extends up-dip into the North East Lakbir structural-stratigraphic trap.

Following the latest seismic mapping, modelling and net pay analysis, the Company has now estimated the gas resources discovered by TE-10 across both the structural and stratigraphic trapping geometries.

The North East Lakbir structural-stratigraphic closure has been assessed with a mid-case potential on a gross (100%) basis of 1,430 bcf gas originally in place (“GOIP”) with a 3,408 bcf GOIP upside case and a 584 bcf GOIP low case.  As is always the case with new discoveries, a further reduction in this range of volume uncertainty will require appraisal drilling. The volume range in the structural closure alone has been assessed with a mid-case potential on a gross (100%) basis of 81 bcf GOIP, 170 bcf GOIP upside case and a 30 bcf GOIP low case.  Whilst these structural closure volumes have already been demonstrated by the TE-10 well, a successful well test is always required to confirm reservoir deliverability and commerciality.

James Parsons, Chief Executive Officer, commented:

“We set out last year to deliver an ambitious three well exploration programme to further unlock the Tendrara Basin and our second well (TE-10) is a discovery.

Following our initial post drill technical analysis, we are delighted to materially upgrade our net pay and provide confirmation of the multi Tcf potential of this well.  We now look forward to addressing reservoir deliverability and hence commerciality with the well test. “

TE-10 Well Test Timing

As announced on 28 January 2019, the testing and stimulation equipment has been mobilised from Libya and Tunisia.  The Company has decided to utilise heavy duty perforating guns to maximise the gas flow rate and extra equipment has now been mobilised from the USA.  The Company is expecting the equipment to arrive on location, and be rigged up and be ready to commence the test programme within four weeks.  From mid-March, a series of unstimulated flow tests will be conducted on multiple intervals between 1,899m MD and 2,070m MD to establish the presence of deepest moveable gas.  Stimulated production flow tests will then follow in late March, over the most prospective reservoir zones, and are expected to take at least 30 days.  The Company expects the initial post stimulation flow rate around end March.

AAOG – SNPC Costs Reimbursements

Anglo African Oil & Gas plc (AIM: AAOG), an independent oil and gas developer, is pleased to provide an update on the repayment of funds owed to the Company by Société Nationale des Pétroles du Congo (‘SNPC’), the Congolese national oil company, in regards to SNPC’s 44% holding in the Tilapia Licence (‘the Licence’) in the Republic of the Congo.

As a result of the work conducted to date on the Licence, including the successful drilling of the TLP-103C well (‘TLP-103C’ or ‘the Well’), SNPC owes approximately US$10m to the Company in respect of SNPC’s share of the total costs.  The Company had proposed to SNPC that it would accept the transfer of a substantial portion of SNPC’s 44% interest in the Licence in satisfaction of the debt.

The Company has, however, now received an initial cash payment of US$663,000 from SNPC.  SNPC has also informed the Company that it will propose a short-term payment plan to meet the remaining debt of approximately US$9.5m.

David Sefton, Executive Chairman of AAOG, said: “We are pleased to receive this payment from SNPC although our preference remains to increase the size of our holding in the Licence, as we had recently proposed to SNPC. However, SNPC is entitled to repay the overdue debt in cash, and we have emphasised to SNPC that this needs to be done in a timely manner.  We also recognise that SNPC takes a similar view to us as to the value of the field and therefore why it would prefer to meet the debt in cash.”

“As previously stated, we are working towards bringing TLP-103C into production in April.  The extra cash that we have now received plus the substantial further funds to come from SNPC, reinforces the cash position of the Company and therefore its ability to meet the costs associated with this work.” 

PVR – Licence Update – Avalon Prospect – Porcupine Basin

Dublin and London – February 18, 2019 – Providence Resources P.l.c. (PVR LN, PRP ID), the Irish based Oil and Gas Exploration Company, today provides an update on Frontier Exploration Licence (“FEL”) 2/19, operated by TOTAL E&P Ireland B.V. (50.0%) on behalf of its partners, Providence Resources P.l.c. (40.0%) and Sosina Exploration Limited (10.0%), collectively referred to as the “JV  Partners”.   FEL 2/19 is located in the Porcupine Basin, offshore Ireland and contains the undrilled Paleocene “Avalon” exploration prospect.

The JV Partners have licensed c. 1,500 km2 of multi-client 3D (MC3D) seismic data over FEL 2/19 which forms part of the larger Crean 3D seismic survey which was acquired by TGS in 2017.  These new MC3D data should significantly improve the delineation of the Avalon prospect, together with facilitating any drill-decision on the prospect.

Commenting on the announcement, Dr John O’Sullivan, Technical Director at Providence, said:

These new 3D seismic data should greatly enhance our understanding of Avalon’s origins, resource potential as well as possible exploration well locations.  The commitment of the JV Partners to licence these data attest to the significant resource potential at Avalon.  As these data are ‘off the shelf’, they should greatly reduce the cycle time to the drill-decision for the Avalon prospect.  We look forward to providing further updates to shareholders in relation to the assessment of these new 3D data.

IGAS EDR – Operational Update – Tinker Lane and Springs Road

We note the press article today in relation to our Tinker Lane exploration site in North Nottinghamshire.

The preliminary tests on shale samples from within the Millstone Grit Group at Tinker Lane are encouraging for the potential gas resources in the Gainsborough Trough basin. The analysis of these samples is still subject to further testing and validation.  As previously stated, the well, which is part of a wider exploration programme in the basin, has been plugged and abandoned and preparations are being made to fully restore the site.

Drilling operations at Springs Road-1 are progressing well. We have encountered shales on prognosis, at c.2,200 m, including the Bowland Shale horizon and coring will commence imminently. The rate of drilling at Springs Road has been quicker than anticipated, building on our learnings and operating efficiencies from Tinker Lane and augurs well for the future.

88E RMP – Operations Update – Spud on Schedule

88 Energy Limited (“88 Energy” or the “Company”, ASX:88E, AIM 88E) is pleased to advise the following in relation to its oil and gas operations on the North Slope of Alaska.

Highlights: Winx-1 

Spud on schedule for 15th February (AK time) – final preparations underway

Western Leases – Winx-1 Exploration Well

The Nordic Rig#3 arrived on location, as planned, on the 7thFebruary (AK time). Rig up activities have proceeded smoothly and final preparations for spud are now underway. The call to “crew-up” was made at 0530 14th February (AK time), which usually indicates spud will occur within 24 hours. Regular updates will be made during the drilling operations.

CAB -Update on Italian assets (of relevance to all companies with interests in Italy exploration licences)

As indicated in the announcement of 12 February, Cabot Energy (AIM: CAB), the AIM quoted oil and gas company focussed on creating predictable production growth in Canada, confirms that late on 12 February 2019, the Italian government signed a decree which enacts the suspension of work on oil and gas exploration permits or applications for new exploration permits in Italy whilst a review is undertaken. The period given for the review is up to 18 months. The suspension will be lifted as soon as consensus is reached on the terms under which the different areas will proceed with oil and gas exploration. In the event that no consensus is reached within 24 months, the suspension will be lifted. 

During the suspension period, the Ministries of Economic Development and Environment will review all areas in the Italian onshore and offshore territories as part of the Plan for Sustainable Energy Transition of Suitable Areas (“PTESAI”) Bill, to determine which are suitable for sustainable hydrocarbon prospecting, exploration and development activities. 

Following the assessment of areas, a decision will be taken whether to allow further exploration activity or to reduce or withdraw licences in that area. Should agreement not be reached between The Government and The Regions on all on-shore licences within 24 months, the suspension will be lifted and rulings will only be issued for offshore areas.

Cabot Energy confirms that its exploration licences went through a rigorous environmental review and is hopeful for a positive outcome. However, the moratorium provides the opportunity for the Company to evaluate its future strategy in both its onshore Po Valley Cascina Alberto exploration permit with its partner, Shell Italia, and in its 100 per cent owned and operated offshore permits in the Southern Adriatic and Sicily Channel. Cabot Energy has five permits and seven applications in process in total in Italy.

The legislation makes allowance for compensation for companies that are impacted. Should it become necessary, Cabot Energy could seek compensation for all exploration costs up to the withdrawal date.   

Scott Aitken, Chief Executive Officer, commented: “This new legislation is not a ban on exploration. It allows the Italian government to reappraise the exploration licences it has granted. Cabot Energy will ensure the Company is prepared to rapidly progress our licences as soon as the review is completed, whenever that occurs within the next 18 months. 

“Cabot Energy’s focus remains the funding of a scalable and repeatable development drilling programme in Canada. As announced in November 2018, our Canadian assets have shown great promise with an annual increase of 26% in gross Net Proven plus Probable reserves to 3.6 mmboe as well as a 339% increase in gross reserves and resources of the Canadian asset to 42.2 mmboe. We will continue to work with the authorities in Italy and remain hopeful of either securing a positive outcome for our exploration licences or receiving appropriate compensation at the end of the two-year assessment period.”

AAOG – Production Plan for TLP-103C

Anglo African Oil & Gas plc (AIM: AAOG), an independent oil and gas developer, is pleased to provide details of its plan to bring the TLP-103C well (‘the Well’ or ‘TLP-103C’) at its Tilapia licence in the Republic of the Congo into production. 


·     TLP-103C to produce from the upper reservoirs by comingling production from R2 and the Mengo, following a double completion including a one-off frack of the Mengo

·     Initial anticipated aggregate flowrate in excess of 1,500 bopd for the first 14-18 months

·     Projected financial metrics at 1,500bopd:

c.US$1 million/month net free cashflow generated

breakeven oil price falls to below US$20 per barrel

·     First production targeted for April 2019

·     Completion of the Well to production will be funded from existing cash resources

David Sefton, Executive Chairman of AAOG, said: “We are excited by this funded plan for TLP-103C and are working hard to bring the Well into production as soon as possible.  The development schedule is predicated on the availability of Schlumberger’s fracking equipment which we have been informed will be available in the beginning of April. 

“Bringing TLP-103C into production is the key to realising the value that we believe has been unlocked by the very successful results from the Well.  With production rates of up to 1,500 bopd expected, TLP-103C will provide considerable cashflow for the Company of approximately US$1 million net per month. The board is focused on building shareholder value and bringing TLP-103C into production is the next step in what has been a very successful programme so far.”

As previously announced, TLP-103C encountered hydrocarbons in each of its target reservoirs. Based on the Company’s analysis of the results from the Well and the board’s long-stated desire to become cashflow positive as quickly as possible, management has concluded that TLP-103C is to be brought into production through comingling of the R2 and Mengo reservoirs via a double completion.  This can be achieved from the Company’s existing cash resources whereas production from the Djeno would require improvements to the topside infrastructure at Tilapia.

Analysis of TLP-103C in conjunction with the TLP-101 well and older well TLPM-1 gives the Company confidence of an initial flowrate in excess of 1,500 bopd with a steady decline after 14-18 months in the Mengo and a sharper decline in the R2.  The Company then expects to see a long-term production profile of approximately 400 bopd.

The production plan developed provides for a dual completion from both R2 and the Mengo, with a one-off frack being used to bring the latter horizon into production. Schlumberger fracking equipment is due to arrive in the Congo at the beginning of April and the Well will be brought into production immediately following fracking, around the end of April 2019.  The Company is currently funded for this work stream.

At 1,500bopd the Company has a breakeven oil price, including covering all operating and G&A costs in both the Congo and London, of less than US$20 per barrel and produces monthly net free cashflow of approximately US$1 million.   To the extent that the Company is still owed monies by SNPC, it will be able to recover such amounts from gross oil receipts otherwise due to SNPC from the Well.

The board is encouraged by the progress made to date on its negotiations to renew the Tilapia licence and having now received a letter of intent to re-award from the government anticipates further news in the coming weeks regarding an extension of the licence to 2040.