TXP – Spudding of COHO-1 and Notice of Interim Results

Calgary, Alberta – August 8, 2019 – Touchstone Exploration Inc. (Touchstone or the Company) (TSX / LSE: TXP) announces that drilling operations have commenced with the spudding of the first exploration well on the Ortoire block. The Company also provides an operational update and a date for the release of interim results.


·      Spudded Coho-1, the Company’s first exploratory well on its Ortoire property, on August 7, 2019.

·      Achieved crude oil sales of 1,768 barrels per day (bbls/d“) and 1,944 bbls/d for the three and six months ended June 30, 2019, respectively, representing increases of 3% and 19% relative to the prior year comparative periods.

·      Delivered an average of approximately 1,829 bbls/d of field estimated crude oil production through the first six days of August 2019.

·      Received regulatory approval to reinject produced water from four of our producing properties.

Drilling Operations

Touchstone spudded the Coho-1 exploration well on the Ortoire exploration block on August 7, 2019 using Well Services rig #80. The Coho-1 well is targeting gas prospects in the Herrera formation at depths between 5,200 and 8,500 feet. The well offsets the Corosan-1 well drilled by Vintage Petroleum Inc. in 2001. Touchstone’s Coho-1 well is targeting the same zones tested in the Corosan-1 well in an up-dip location and the well is also expected to penetrate a second and previously untested thrust sheet that the Company deems prospective based on 3D seismic and offset production records. The Coho-1 well is expected to be drilled to a total measured depth of 8,545 feet at an estimated cost of approximately US$3 million. Drilling is anticipated to take approximately 28 days and the Company will make a further announcement once the well is drilled and logged. Following rig release, we will utilize a smaller service rig to test the well. Testing is anticipated to take up to 30 days as a full flow and build-up is planned to be completed on each zone.

The Coho-1 well is the first of four earning exploration wells under Touchstone’s Ortoire Exploration and Production Licence. The Company has an 80% working interest in the well but is responsible for 100% of the drilling, completion and testing costs associated with the well. Heritage Petroleum Company Limited holds the remaining 20% working interest.

Touchstone has no Reserves associated with this well location included in the Company’s December 31, 2018 Reserves Report. An independent prospect evaluation review prepared by GLJ Petroleum Consultants Ltd. dated January 16, 2019 and effective December 31, 2018 estimated 2,058 thousand barrels of oil equivalent (best estimate) of unrisked Contingent Resources (Development Pending) and 1,190 thousand barrels of oil equivalent (best estimate) of unrisked Prospective Resources (Prospect) for the Company’s 80% working interest in the well. Please refer to Touchstone’s January 17, 2019 announcement titled Touchstone Announces Ortoire Independent Prospect Evaluation for further information, definitions and advisories regarding the resources other than reserves associated with prospects evaluated on the Ortoire exploration block.


After a strong 2019 first quarter of production buoyed by flush volumes from the 2018 drilling programme, the Company embarked upon a well optimization programme which spanned the majority of the second quarter of 2019. The programme focused on converting flowing wells to pumping wells as volumes declined, equipping certain wells with capillary strings to combat wax production and to extend run-times and the recompletion of low rate producers. As a result of these initiatives, various wells and associated production were off-line during the second quarter. Additionally, mechanical issues with a bottom hole assembly in the Company’s CO-372 well resulted in nil production in the second quarter.

As a result, the Company averaged 1,768 bbls/d of crude oil sales in the second quarter of 2019 and 1,944 bbls/d of crude oil sales during the six months ending June 30, 2019. Field estimated production through the first six days of August 2019 has averaged approximately 1,829 bbls/d, which the Company anticipates maintaining in the third quarter of 2019 through further well optimization and recompletions.

Water Disposal

The Company has commenced transportation of all produced water from its Barrackpore, San Francique and Palo Seco properties to the recently commissioned water disposal facility on our Fyzabad block. We have also completed an initial injectivity test on our WD-8 block and will now begin a test period where substantially all produced water originating from the property will be disposed. These are key environmental milestones as we have undertaken to eliminate all surface water release by the end of 2019.

Paul R. Baay, President and Chief Executive Officer, commented:

“It is very exciting to commence drilling in Ortoire at our Coho-1 prospect. This is a significant milestone for Touchstone as we begin drilling the prospective exploration wells. We look forward to sharing the results of the wells with our shareholders throughout this potentially transformational period. The exploration programme has been a priority for 2019, but it is important that we continue to see annual production growth from our current producing assets. We are currently prioritizing our development drilling locations and will continue to focus on maintaining base production. While fostering a safe work environment we intend to further enhance our operations through various initiatives including our water disposal programme.” 

Notice of Results

The Company expects to release its unaudited interim results for the three and six months ended June 30, 2019 on August 14, 2019.

IOG – Spudding of Harvey Appraisal Well

Independent Oil and Gas plc (“IOG” or the “Company”), the development and production company focused on becoming a substantial UK gas producer, is pleased to confirm that the Maersk Resilient rig spudded the Harvey appraisal well at 2230hrs BST on Tuesday 6 August 2019. As previously indicated, completion of the well is expected to take approximately two months in the success case.

Harvey is centrally located within IOG’s asset portfolio in UK Southern North Sea Blocks 48/23c, 48/24a, and 48/24b, close to the Thames Pipeline export route. The primary objective of the well is to confirm gas volumes which management estimate at 85/129/199 BCF Prospective Resources in the Low/Best/High case, with a 63% Geological Chance of Success¹, and secondly to demonstrate reservoir deliverability. If successfully appraised, the additional scale and synergies of a Harvey development could substantially enhance the portfolio’s overall value and returns.

On completion of the farm-out transaction announced on 26 July 2019 the Company’s designated partner, CalEnergy Resources Limited (“CER”), will have the option to acquire 50 per cent of the Harvey licences within three months of completion of the appraisal well. If this option is exercised, CER will pay an additional £20 million to IOG and a £0.95/MCF royalty on all of CER’s life-of-field net gas production from Harvey (equivalent to £61.3 million if Harvey produces IOG’s 129 BCF Best Estimate Prospective Resources). This would maintain full alignment between IOG and CER across IOG’s entire SNS Assets.

The Maersk Resilient is a modern, high-spec rig with a strong operating history and an excellent safety record. The designated well operator is Fraser Well Management, who have extensive experience in drilling successful wells in the UK Southern North Sea (“SNS”). In addition, Halliburton Manufacturing and Services Ltd have been contracted to provide offshore drilling services for the well.  

Andrew Hockey, CEO of IOG, commented:

Spudding the Harvey appraisal well is an exciting development for IOG and potentially a major catalyst for the business. Our objective is to prove up a substantial, high-quality reservoir in the heart of our core asset base which would create significant shareholder value over and above our recently announced farm-out. Success at Harvey could trigger a further significant near-term cash payment plus valuable life-of-field royalties should our designated partner exercise its right to farm in. We are pleased with our choice of rig and contractors and look forward to drilling the well safely and successfully.”

MATD – Spud of Red Deer and Operational Update

Petro Matad Limited (“Petro Matad” or “the Company”), the AIM quoted Mongolian oil explorer, announces that the Red Deer-1 exploration well in the Asgat Sag Basin of Block XX in eastern Mongolia spudded on 4 August. The well is being drilled with the Daton Petroleum Engineering and Oilfield Service LLC rig, DXZ1.

The Red Deer-1 well is targeting a prospect with 48MMbo of Mean Prospective Recoverable Resource and is planned to be drilled to a total depth (TD) of 2,100 metres. The well is expected to take up to 35 days to complete. In the event of a discovery, the Company will bring in a separate rig for testing. A call-off testing contract has been signed which ensures testing operations, if warranted, can commence soon after discovery. 

Meanwhile, at Heron-1, the first casing point at 551 metres was reached on schedule and casing has been run and cemented. The DQE rig 40105 is now ready to drill out cement and then drill 8 ½ inch hole to the prognosed TD of 3,050 metres. However, the provincial government has challenged Petro Matad’s legal right to use the land at Heron-1 on the basis that a tripartite agreement between two central government agencies and the province has not been executed. In all of Petro Matad’s operations the Company has followed the land permitting regulations as required under the PSC and in accordance with instructions from the Ministry of Mining and the industry regulator MRPAM. The absence of a tripartite land use agreement between government agencies has never previously been an issue. We are working with the Ministry, MRPAM and the provincial government to remedy this situation as soon as possible.

The rig at Heron-1 has been put on standby whilst the situation is resolved. All efforts are currently directed at fixing this interruption as quickly as possible in order to minimise rig standby costs. Daily standby costs are low by industry standards and are of the order of $12,000. The Red Deer-1 well is located in a different province to that in which Heron-1 is located and has not been affected.

Further updates will be provided in due course.

UKOG ALBA – Horse Hill Update

UK Oil & Gas PLC (London AIM: UKOG) is pleased to announce that in preparation for the late summer start of the Horse Hill-2/2z (“HH-2/2z”) Portland drilling programme, test production was switched successfully from the Portland to the deeper Kimmeridge oil pool. From 6th July to date, the Phase 2 Kimmeridge test has produced a further 5,524 barrels (“bbl”) of dry Brent quality oil. Total aggregate Portland and Kimmeridge test oil production from the Horse Hill oil field, in which the Company has a 50.635% majority interest, now totals a significant landmark of 60,186 barrels (“bbl”).

Kimmeridge oil flow was re-established at initial half-hourly metered rates of up to 332 bbl of oil per day (“bopd”), with continued stable production of dry oil at daily rates of 200-266 bopd. Total Kimmeridge production to date, now exceeds 30,618 bbl with no apparent produced formation water. Following a 5-month shut-in, flow rates and flowing bottom hole pressures appear more stable than during Phase 1 Kimmeridge testing.

Prior to the Kimmeridge production switch, which was necessary for the safe drilling and coring of HH-2/2z through the Portland reservoir, total aggregate Portland production reached 29,568 bbl, with HH-1 continuing to produce dry Portland oil at a stable rate of over 220 bopd. Preliminary Company analysis of the final Portland pressure build-up test, indicates that the Portland connected oil volume accessed by HH-1 has significantly increased from 7-11 million bbl to 11-14 million bbl, a robustly commercial volume.

Kimmeridge test production is planned to continue throughout the drilling of HH-2/2z except for two short shut-ins to enable the moving of oil storage tanks and installation of the drilling rig.  The drilling rig is now scheduled to arrive on site following routine servicing after the completion of its current job.

The Horse Hill oil field and surrounding highly prospective PEDL137 and PEDL246 licences are operated by UKOG’s subsidiary company Horse Hill Developments Ltd, in which UKOG holds a 77.9% direct interest.

Horse Hill 2018-19 EWT Oil Production Milestones:

·    60,186 bbl aggregate Kimmeridge and Portland oil production

·    29,568 bbl total Portland production

·    30,618 bbl total Kimmeridge oil production

·    No discernible formation water produced from either reservoir

·    Stable Portland test production has continued to prove more oil in the ground

·    Kimmeridge flow resumed at more stable rates and flowing pressures after 5 month shut-in

Stephen Sanderson, UKOG’s Chief Executive, commented:

The resumption of Kimmeridge oil flow at more stable rates than previously seen is welcome news for the Kimmeridge’s commercial future and further justifies the decision to conduct simultaneous Portland drilling and HH-1 Kimmeridge test production at the site. The successful production switch from Portland to Kimmeridge now paves the way for the expected late summer arrival of the rig and the HH-2/2z Portland horizontal drilling and testing campaign.

The test results to date also signify that after a year of production testing, the simple non-optimised vertical HH-1 well remains capable of continuous production from both Portland and Kimmeridge zones at an aggregate rate of 450 bopd. Consequently, as a result of the test’s ongoing success, in the opinion of the Directors, the future potential for significantly higher rates from the Portland HH-2z horizontal together with production from the underlying Kimmeridge therefore remains an even more tangible, imminent and exciting prospect.”

IOG – Farm-out of Southern North Sea Assets

Independent Oil and Gas plc (“IOG” or the “Company”), the development and production company focused on becoming a substantial UK gas producer, is pleased to announce that it has entered into a comprehensive farm-out transaction with CalEnergy Resources Limited (“CER”).


·      IOG has signed binding definitive agreements with CER to farm out 50 per cent of its Southern North Sea assets, comprising all of the Company’s upstream assets (except for the Harvey licences), as well as the Thames Pipeline and associated Thames Reception Facilities (the “Farm-out”).

·      The consideration payable by CER comprises:

£40 million initial cash payment

up to £125 million by way of a development carry representing 80 per cent of the costs associated with IOG’s retained 50 per cent interest, comprising:

§ up to £60 million of development costs for Phase 1

§ up to £65 million of development costs for Phase 2

£0.50/MCF royalty on CER’s interest in Goddard production above 70 BCF gross up to a cap of £9.75 million.

·      CER will receive a royalty of 20.2 percent of IOG’s Phase 1 revenues up to a cap of £91 million.  

·      CER will have the option, within three months of the Harvey appraisal well completion, to farm in to 50 per cent of the Harvey licences in consideration for:

£20 million additional cash payment

an uncapped royalty of £0.95/MCF on CER’s net Harvey gas production (equivalent to £61.3 million if Harvey produces IOG’s 129 BCF Best Estimate Prospective Resources).

·      IOG and CER have also signed an Area of Mutual Interest (“AMI”) agreement to pursue further business development opportunities in the scope of the Thames Pipeline on a 50:50 basis.

·      IOG is planning to issue a Euro-denominated Senior Secured Bond (“Bond”) of approximately £70 million to fund its share of Phase 1 costs. There is no additional external funding requirement expected for Phase 2.

·      Upon Farm-out and Bond completion, IOG and CER will submit notice of Core Project Phase 1 Final Investment Decision (“FID”) to the Oil and Gas Authority (“OGA”).

·      IOG has also entered into agreements to repay and restructure its existing financing arrangements with London Oil and Gas (“LOG”)

·      IOG will retain Operatorship of the Core Project.

Farm-out Transaction

IOG is pleased to announce that it has entered into binding agreements to farm out 50 per cent of its SNS Assets (excluding Harvey) to CER. IOG will be paid initial cash consideration of £40 million on completion of the Farm-out. CER will also pay for up to £125 million of IOG’s development costs, representing 80 per cent of IOG’s 50 per cent share of Core Project costs, up to caps of £60 million for Phase 1 and £65 million for Phase 2 respectively.

The Core Project comprises 410 BCF¹,² of 2P+2C reserves and resources across six discovered Southern North Sea (SNS) gas fields. IOG will pay CER a royalty of 20.2% of its net revenues from the Phase 1 fields only (i.e. 10.1 per cent of gross Phase 1 revenues, net of National Transmission System entry charges and applicable marketing fees), up to a cap of £91 million over field life. 

In addition, IOG will receive an effective royalty interest equating to £0.50/MCF on CER’s 50 per cent share of production from certain sections of the Goddard Field after 70 BCF gross has been produced from the field up to a maximum royalty of £9.75 million.

Given its experienced SNS development team, IOG will retain Operatorship of the Core Project. 

Completion of the Farm-out is conditional on certain conditions being satisfied, including the receipt of OGA approval, the receipt of binding commitments from investors in respect of the Bond and various conditions relating to real estate leases at the Bacton terminal. Upon completion of the Farm-out of the SNS Assets (excluding Harvey) and the Bond, IOG and CER intend to proceed to immediate approval of Phase 1 FID.

Harvey Option

As part of the Farm-out, CER has also been granted an option to acquire 50 per cent of the Harvey licences within three months of completion of the Harvey appraisal well. Exercise of this option would maintain full alignment between IOG and CER across IOG’s entire SNS Assets in the event of a successful Harvey appraisal. On completion of the farm-in to Harvey CER will pay a further £20 million cash payment to IOG and a £0.95/MCF royalty on all of CER’s life-of-field net gas production from Harvey (equivalent to £61.3 million if Harvey produces IOG’s 129 BCF Best Estimate Prospective Resources). IOG’s pre-well estimates of the gross Prospective Resources at Harvey are low/mid/high 85/129/199 BCF³.

Area of Mutual Interest Agreement (AMI)

In addition to the Farm-out, IOG and CER have signed an AMI to allow for future co-operation in further SNS business development activities on a 50:50 basis. The specific focus is a defined area of the UK SNS which contains the wider tie-back radius of the Thames Pipeline. IOG has already identified and is working up several opportunities in this region for potentially value accretive incremental licensing applications and asset acquisitions, with a view to leveraging the competitive advantage provided by the Core Project’s infrastructure. With the Farm-out and AMI in place, the two partners are well placed to develop future projects.

CalEnergy Resources Limited (CER)

CER is focused on upstream oil and gas projects and has interests in the UK, Australia and Poland, and is an active operator in the latter two jurisdictions. CER or its predecessors has been active in the oil and gas industry since the 1970s as a full-cycle exploration and production (E&P) company.

IOG believes that CER is a very strong and naturally well-aligned partner for IOG both in co-developing the SNS assets and in jointly acquiring and developing further upside opportunities in the Thames Pipeline Catchment Area. CER’s high calibre management team, previous experience in this area and strong technical capabilities further cement the alignment.

Berkshire Hathaway Energy Company owns CER through its UK subsidiary Northern Powergrid Holdings Company whose primary business are its electricity distribution companies in the NorthEast of England.

Senior Secured Bond and Path to FID

IOG is planning to raise approximately £70 million through the issue of a Euro-denominated senior secured bond to institutional investors based on standard Nordic documentation. The proceeds from the bond issue will provide for the full balance of IOG’s Phase 1 funding requirements, with an excess capital buffer. The Company has mandated the Nordic investment bank ABG Sundal Collier as bookrunner and advisor in relation to this transaction and a detailed term sheet has been agreed in principle setting out the terms of the Bond issue. It is anticipated that the Bonds will be listed on the Oslo Stock Exchange.

The planned Bond is anticipated to have a 5-year tenor, be redeemable after 2.5 years (with a market standard call premium) and have a bullet repayment structure, which will allow for Phase 2 capex with a strong cash buffer at maturity. The Bond will be secured against IOG’s post-Farm-out asset portfolio. Final terms will be known following completion of marketing and book-building. The Company and its advisors are confident of completing the Bond on favourable terms.

IOG and CER have agreed that completion of the Farm-out and Bond will trigger Phase 1 FID and submission of confirmation of full funding to the OGA. Following FID the award of key contracts will commence. Phase 1 Field Development Plan (FDP) approval by the OGA is anticipated within weeks of FID.

Core Project Capital Expenditure

Following extensive due diligence discussions with CER, a detailed third-party cost contingency review and the initial results of re-tendering certain Phase 1 contracts, IOG has further refined its Core Project cost estimates. Total Phase 1 gross capex is estimated at £293 million, plus £24 million of contingency and, subsequent to First Gas, a further £65 million investment in onshore compression. IOG’s net Phase 1 funding requirements further to the Farm-out will be fully covered by the proceeds of the proposed Bond.

Phase 2 gross capex, encompassing three platforms and eight wells, is currently estimated at £367 million plus £41 million of contingency. IOG’s net portion is projected to be fully funded from Phase 1 cashflows plus the £65 million development carry. Based on the current UK NBP gas forward curve, IOG’s Project IRR on the Core Project before any carry or financing benefits is 30%.

Repayment and Restructuring of LOG debt facilities  

IOG has also entered definitive documentation with LOG which supersedes the debt restructuring agreed in April 2019. As a result, on completion of the Farm-out, IOG will repay in full LOG’s non-convertible debt, currently £16.6 million including accrued interest. In addition, LOG’s convertible loans, currently £22.0 million including accrued interest, will, at LOG’s election to be made by Friday 9 August 2019, be either repaid, converted into IOG Ordinary Shares at the relevant exercise prices, up to a maximum holding of 29.9% of IOG’s issued share capital, or exchanged for long-term unsecured debt convertible at the equivalent price. Consequently, the Company’s post-Farm-out assets will be left unencumbered to be pledged as security for the Bond. The Substantial Shareholder Relationship Agreement with LOG remains in place and will expire upon completion of the Farm-out, at which time sales of shares held by LOG following Farm-out completion will be subject to orderly market restrictions for a period of 12 months. LOG’s warrants will remain in place.

Andrew Hockey, CEO of IOG commented:

“The successful Farm-out to a partner of the stature of CalEnergy Resources, part of Berkshire Hathaway Energy Company, is a landmark transaction for IOG which should deliver very significant value for our shareholders both now and in the future.

This transaction with CER is a strong validation of our exciting portfolio of upstream and infrastructure assets, as well as our focused Southern North Sea gas strategy which can generate exceptional shareholder returns. Importantly, with the balance of funding to come from the bond market, we expect to deliver FID without equity issuance. These transactions will provide the funding to develop our portfolio to cash flow and therefore a clear path to delivering material shareholder value.

It is a testament to my team’s expertise, resourcefulness and tenacity to have reached this milestone after navigating some considerable challenges over recent years. We now look forward with real optimism to realising the significant value in our portfolio and embracing opportunities to generate further upside through our partnership with CER.

Additionally, we are pleased to continue as Operator, which reflects the quality of the operational team we have assembled under our COO Mark Hughes, who has extensive experience of successful project execution in the Southern North Sea.

We look forward to updating our shareholders on this very busy and exciting time for IOG, including progress with the bond, Farm-out completion, reaching FID and, last but not least, progress with the Harvey appraisal well which will be spudding imminently.”

AEX – Ruvuma Farm-Out Update

Aminex announces that all parties to the previously announced Ruvuma farm-out agreement (“Farm-Out”) intend to extend the longstop date to 31 October 2019 should it be required.  Whilst acknowledging that completion of the Farm-Out is taking longer than anticipated, due to an ongoing review of active Production Sharing Agreements by Tanzania’s Attorney General’s Office, the Company and ARA Petroleum Tanzania Limited (“APT”) remain actively engaged with the Government of Tanzania to close out the remaining conditions.  The Company will make a further announcement if or when the longstop date has been formally extended.

The principal conditions of the Farm-Out still to be met are the extension of the Mtwara Licence and approval by the Tanzanian Government of the transfer of the interest and operatorship.  

Tom Mackay, Chief Executive of Aminex PLC, said:

“Aminex and APT have received, and continue to receive, positive feedback regarding the Ruvuma Farm-Out and the licence extension and look forward to a close-out of the remaining conditions which will facilitate the progression of the Ntorya Development and, specifically, the drilling of the Chikumbi-1 well.”

Sultan Al-Ghaithi, Chief Executive of Ara Petroleum LLC, said:

“We are similarly disappointed in the time it is taking to obtain approvals but continue to be encouraged by the positive response by the Tanzanian authorities to our future involvement in the Ntorya project and content to further extend the longstop date to the Ruvuma farm-out agreement, should it be required”