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Does EV and battery tech really sound the death knell for Oil and Gas?

Future of Oil and Gas

In an era of rising demand and hype for electric vehicles (EV) and battery technology, commodities and ETFs linked to oil and gas have managed to hold their prices. EV stocks like Tesla and Nio have increased by 71% and 100% respectively in the past year. The price of WTI Crude Oil has also increased by 76%, while prices of micro-cap oil stocks like #ECHO Echo Energy and #MSMN Mosman Oil and Gas have increased by 58% and 13% respectively.

This clearly signifies that even after the rise in demand of EVs, commodities like oil and gas are here to stay in the short and long term.

Consumers are under the impression that they could be in an oil-free world by 2030 and most consumers perceive batteries and electricity as the primary source of energy. However, this is highly unlikely and nothing but a series of myths planted in our brains due to effective marketing.

The International Energy Agency (IEA) that analyses trends in energy industry, released its annual World Energy Outlook in November 2019. It looks at potential energy demand and supply under different scenarios to explore different possible futures. The IEA scenario stated a global increase in energy demand by 24% by 2040 of which, oil and natural gas will supply 64% of the world’s energy needs. In accordance with the Paris Climate Agreement, if based on the Sustainable Development Scenario, the oil and natural gas will still supply 47% of the world’s energy by 2040.

More than 15% of oil demand goes into non-combusted use including petrochemicals which is expected to grow to 20% by 2040. Even if the demand for gasoline and other fuels may hypothetically be on the decline, the petrochemical sector, in contrast, still has room to grow. Some major companies have even pledged some $100bn into the petrochemical industry over the next decade.

Developing countries like India have one of the most aggressive renewable power capacity roll-out programmes worldwide. However, its access to affordable fossil fuels remains a priority for its government because its needs for cheap oil, gas and coal continue to rise to meet energy demand that is forecast to more than double by 2040. India’s petroleum minister Dharmendra Pradhan believes the world’s third-largest oil consumer could be the “golden goose” for crude suppliers as it buys more than 80% of its oil needs from foreign crude purchases.

The graph below demonstrates that the forecasted oil demand for 2040 is higher than present day with non-combusted being the driver to increase the demand. While in the primary energy consumption chart, oil is forecasted to maintain its consumption as a primary source by 2040. Whereas the primary consumption of gas is forecasted to rise.

 

(Financial Review, 2020)

 

Texas Oil Wells

In 2018, companies in the Permian Basin – “an ancient, oil-rich seabed that spans West Texas and South Eastern New Mexico — were producing twice as much oil as they had four years earlier” whilst forecasters expected the production to double again by 2023.

The International Energy Agency (IEA) had also predicted that American oil mostly from the Permian will account for 80% of growth in global supply over the next seven years.

Some small companies already had presence in the Permian Basin before these predictions and report in 2018. In 2017, Mosman Oil & Gas (MSMN) acquired several oil and gas leases comprising the Welch Permian Basin Project for a consideration of $310,000. Although the Welch project contributed to a gross profit of $167,000 in the year ended 30 June 2020, recently Mosman sold this Welch Project for $420,000 receiving a premium of 40% from the sale of the project alone.

Mosman is steadily growing its working interests across a number of projects in Texas, including Stanley, Falcon-1, Winters and Galaxie. These have produced a gross profit of over $500,000 in the 2020 year. Stanley also has a 100% success rate with oil production from four wells drilled to date.

Texas wells are providing high returns to oil companies, and with a growing number of projects and acreage, Mosman is well placed for future growth.

South Argentina Oil Wells

Many companies own wells in Argentina and Latin America as it is considered a region rich in resources with 4% of natural gas reserves and 20% of world oil reserves. They are also often undergoing positive development in macro conditions. A strong demand outlook for energy consumption and economic growth coupled with underdeveloped – but lower cost – onshore plays, makes Latin America a favourable region for companies like Echo Energy (ECHO) to deploy its expertise in support of an exploration-led growth strategy.

For the financial year ended 31 December 2020, Santa Cruz Sur at the south-eastern tip of Argentina helped Echo Energy to increase its revenue fourfold to US $11.1mn. This was also due to Echo securing new gas sales contracts at premium rates to the prevailing spot markets in early Q1 2021.

The increase in revenue drove an significant increase in the Echo Energy (ECHO) stock price by 51% from 55p to 83p between December 2020 and January 2021.

Major and Small Suppliers of Oil and Gas

The difference between the barrels of oil supplied can be huge when major suppliers are compared to the small suppliers. But all that glitters is not gold. High supply and production would require a higher demand to be profitable, if the demand of oil stagnates in the future it will affect the major suppliers before the small suppliers.

The big 10 companies accounted for 28% of global oil production in 2020 as shown below.

When this is compared to small oil producers like Echo Energy and Mosman Oil and Gas,  Echo Energy produced a cumulative of 94,000 barrels of oil in Santa Cruz Sur in South Argentina. While Mosman Oil and Gas produced a gross of 90,000 barrels of oil in the year ended June 2020. Based on available data, the production of Echo and Mosman combined is 0.2% of the global oil demand.

This is effective during times of recession or when the global demand is low as during unprecedented times a major oil supplier to generate profits and work at full capacity would need to sell between 5-12% of oil demand while small suppliers of oil would need to fulfil a negligible percentage of global demand of oil to turn profitable. This is due to high storing and inventory costs for major oil suppliers as well as higher fixed costs due to bigger operations.

Conclusion

Therefore, even though the oil demand is perceived to be lower in the future due to alternative resources, the demand doesn’t seem to be in decline due to oil having uses other than fuel and gas for cars and transportation like non-combusted petrochemicals. Even if the demand for oil is on the decline it would not affect small oil suppliers; as working at full capacity they fulfil just a small percentage of global oil demand and still manage to make hefty profits.

These among many, are the reasons keeping the oil prices buoyant and in the mix, not only for the present day but also for the future.

Mosman Oil and Gas Limited #MSMN – Covid Update

MSMN

Mosman Oil and Gas Limited (AIM: MSMN) the oil exploration, development, and production company, announces operations and exploration activities continue with some minor delays due to the Covid-19 pandemic in both Australia and the USA.

In Australia, the geophysical Survey over permit EP-145 has been successfully acquired and processed following minor time delays resulting from Covid related travel restrictions. This data is currently being interpreted and integrated into the regional basin model with the now expected early in October. Once the report is received, the information will be considered and integrated with the geological model. We note that Central Petroleum has been active drilling wells in the nearby permits with positive results on the Stairway sandstone which is one of the target zones in EP-145, as well as the sub-salt helium potential. Covid related restrictions may impact the timing of the Work Area Clearance Survey by the Central Land Council, a requirement for the planned seismic survey.

In the USA, the site for the Winters 2 well is ready and waiting for the drilling rig. The rig operator has advised that the delay is due to restricted crew availability as a result of Covid issues, and the rig is now scheduled to arrive on site on 27 September 2021.

The combinations of pandemic related staffing issues and higher oil prices have also meant a shortage of workover rigs, however a workover is now re-completing a well on the Duff lease and will then move to the Stanley lease.

The delay to workovers, particularly at Stanley, has meant some reduction of short term production rates which, as noted above, should be resolved with a rig now on contract. Production at Falcon has continued to perform strongly with some natural decline from the rates notified on 29 July 2021.

The effect on revenue is currently being mitigated by the strong oil and gas prices, with the WTI oil price over USD 70/barrel and gas currently over USD 5/mmbtu, higher than prices from last quarter when the acquisition of additional interests was being negotiated.

Covid19 restrictions in NSW also mean the Company’s Sydney based accountants and Company Secretary office is currently closed and staff restricted to working from home.

Market Abuse Regulation (MAR) Disclosure

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the Market Abuse Regulations (EU) No. 596/2014 (‘MAR’) which has been incorporated into UK law by the European Union (Withdrawal) Act 2018. Upon the publication of this announcement via Regulatory Information Service (‘RIS’), this inside is now considered to be in the public domain.

Enquiries:

Mosman Oil & Gas Limited John W Barr, Executive Chairman Andy Carroll, Technical Director

jwbarr@mosmanoilandgas.com acarroll@mosmanoilandgas.com

NOMAD and Broker

SP Angel Corporate Finance LLP

Stuart Gledhill / Richard Hail / Adam Cowl

+44 (0) 20 3470 0470

Alma PR

Justine James / Joe Pederzolli

+44 (0) 20 3405 0205

+44 (0) 7525 324431

mosman@almapr.co.uk

Joint Broker

Monecor (London) Ltd trading as ETX Capital Thomas Smith

020 7392 1432

Mosman Oil & Gas #MSMN – Winters Lease and Winters-2 well update

Winters Lease and Winters-2 well update

Mosman Oil and Gas Limited (AIM: MSMN) the oil exploration, development, and production company, announces an update on the Winters lease in Polk County, East Texas including increasing its Working Interest in the lease and the timing of drilling the Winters-2 well.

 

Winters Lease

Mosman acquired a 23% interest in the Winters lease as part of its recent purchase of Nadsoilco LLC, (“Nadsoilco”) in June 2021. Nadsoilco is now a subsidiary of Mosman and is the Operator of the Winters lease.  The Winters lease is held by production with circa 969 bbls of oil sold in the last 12 months from the Winters 1 well.

Mosman has now agreed to farm-in to acquire an additional 6% working interest in the Winters lease. The key terms are payment of US$12,000 for past costs, and Mosman to pay 8% of the next well costs. This will increase Mosman’s interest in the lease (including the Winters-1 well) from c23% to c29% (before royalties).

Winters-2 well

Nadsoilco is now preparing to drill the Winters-2 well on the Winters Lease. Due to the well location, the Winters lease holders have agreed to share the participation in the Winters-2 well (not the lease) with the adjacent lease holder (“Arcadia”). The Winters lease holders will have 78% and Arcadia will have 22% of the well. Therefore, Nadsoilco will have a c29% x c78% = c23% working interest in this well.

Winters-2 is a development well targeting the Wilcox formation, the same zone that is producing in adjacent wells (on other leases not held by Mosman). The well will be drilled as soon as site preparation has been completed, and the drilling rig is available, which Mosman anticipates will be in a few weeks’ time.  The Budget to drill and case the Winters-2 well has been set at cUSD600,000.

Funding of the farm-in and the drilling costs of c USD 150,000 will be from existing cash resources. A positive drill result, in line with an existing adjacent well which is producing at c190bopd,should result in the well costs being recovered from production this calendar year.

Qualified Person’s Statement

The information contained in this announcement has been reviewed and approved by Andy Carroll, Technical Director for Mosman, who has over 35 years of relevant experience in the oil industry. Mr. Carroll is a member of the Society of Petroleum Engineers.

Market Abuse Regulation (MAR) Disclosure

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the Market Abuse Regulations (EU) No. 596/2014 (‘MAR’) which has been incorporated into UK law by the European Union (Withdrawal) Act 2018. Upon the publication of this announcement via Regulatory Information Service (‘RIS’), this inside is now considered to be in the public domain.

 

Enquiries:

Mosman Oil & Gas Limited John W Barr, Executive Chairman Andy Carroll, Technical Director

jwbarr@mosmanoilandgas.com acarroll@mosmanoilandgas.com

NOMAD and Broker

SP Angel Corporate Finance LLP

Stuart Gledhill / Richard Hail / Adam Cowl

+44 (0) 20 3470 0470

Alma PR

Justine James / Joe Pederzolli

+44 (0) 20 3405 0205

+44 (0) 7525 324431

mosman@almapr.co.uk

Joint Broker

Monecor (London) Ltd trading as ETX Capital Thomas Smith

020 7392 1432

Mosman Oil & Gas #MSMN – Alan Green talks to Executive Chairman John Barr

Alan Green talks to John Barr, Executive Chairman at Mosman Oil & Gas #MSMN about the oil assets in production and development in Texas, plus the strategic helium assets in the Amadeus Basin, Northern Territories, Australia. John discusses the Falcon-1 well before moving onto the assets now owned by Mosman following the Nadsoilco acquisition. We then look at the most recent developments and work scheduled at the EP155 and EP145 helium assets in the Amadeus Basin in Australia. John then discusses the company cash position, before providing investors with key inflection points to watch out for during the 2nd half of 2021.

Atlantic View – Streamlining and Resilience Have Laid The Foundations For Recovery at Shell #RDSB

Streamlining and Resilience Have Laid The Foundations For Recovery at Shell #RDSB
by John Woolfitt, Atlantic Capital Markets
Fundamentals and Statement Summary
Anglo Dutch oil giant Royal Dutch Shell (RDSB) today announced results for Q2 2020, which include impairments of $16.8 billion post-tax (6.1% of average capital employed), reflecting revised price and margin assumptions. Shell reported ‘very strong crude and oil products trading and optimisation results’ and a resilient marketing performance, and said it was on track to deliver cost reduction targets, with a $1.1 billion reduction in underlying opex compared with Q1 2020, delivering a reduction target of $3 – $4 billion. 

Adjusted earnings came in at $638 million, with $6.5 billion in cash flow from operations and $243 million of free cash-flow. Return on Average Capital Employed (ROACE) came in at 5.3%, while gearing is now at 32.7%. Total dividends distributed to Royal Dutch Shell plc shareholders in the quarter were $1.2 billion. An interim Q2 dividend of US$ 0.16 per A ordinary share and B ordinary share was declared.

Royal Dutch Shell Chief Executive Officer, Ben van Beurden said that Shell “has delivered resilient cash flow in a remarkably challenging environment.”

“We continue to focus on safe and reliable operations and our decisive cash preservation measures will underpin the strengthening of our balance sheet.”

He added that a number of new working practices had “accelerated digitalisation across the company”..while the oil giant’s high-quality integrated portfolio, disciplined execution and forward-looking strategy “enable sustained competitive free cash flow generation.” 

Chart and Technicals
Source Factset & Hargreaves Lansdown

RDSB shares suffered a precipitous COVID driven fall in February / March 2020, briefly touching below £9 per share – a 30+ year low. The stock recovered the 50-day moving average at the start of April, and intermittently held that level until late June. Given the stock is trading at these historic lows, if Shell recovers and holds the 50-day moving average, currently at 1264p, our next target will be the gently falling benchmark 200-day moving average, currently at 1,725p.

Summary and Atlantic View

A darling of the FTSE100, and up to recently, a cornerstone investment among leading fund managers, the COVID crisis has seen Shell battling a seemingly existential crisis on a par with the challenges face by the venerable oil giant during WWII. However, the company has delivered a remarkably resilient performance during the depths of the crisis, and as CEO Ben van Beurden said in his Q2 results statement video clip, cash preservation (£1.1bn reduction in opex), streamlining and digitalisation have all been prioritised during the quarter, and these will in turn enable sustained competitive free cash flow generation going forward. As travel and movement starts to pick up on the back of expectations of vaccines and effective testing measures for COVID, it is reasonable to expect that energy and resource companies will start to return to some semblance of normality. Historically Q3 has been a strong earnings quarter for Shell, and with the measures management have already taken to streamline the company, Atlantic Capital Markets are backing Shell as a recovery play, firstly to regain the moving 50-day level at 1264p, and shooting for the 200-day benchmark by the end of the year. There is the added dividend bonus to boot, and although the payout was cut from 47 cents to 16 cents in Q1, (same for Q2), investors can still pick up the stock and collect the Q2 payout before the August 13 ex-dividend deadline. Atlantic Rating: Buy.
To take advantage of this trading idea, speak to a member of our dealing team on 01872 229000 or visit the Atlantic Capital Markets website here

Andalas Energy and Power Plc (ADL) Bunga Mas update

Andalas Energy and Power Plc recognises recent press speculation regarding the Bunga Mas PSC (“PSC”) acquisition (announced 29 August 2018) and would like to clarfy the current position.

Andalas has been advised that the government of Indonesia (“GOI”) has provided the PSC contractors, with an agreement to convert the PSC into a gross split production sharing contract.  The contractors, including the vendor, Tilegarre Corporation, have elected not to sign it because certain issues regarding the terms of the renewal have not yet been resolved to their satisfaction. 

Andalas has been advised that the GOI has requested that the contractors deposit funds into an escrow account as security against a future work programme.   This requirement would result in Andalas having to raise significant amounts of additional capital which has a material negative impact on the  economics of the project.

The sale and purchase agreement is conditional on the PSC being extended on terms satisfactory to Andalas and includes a representation from the vendor that no performance bonds or other financial guarantees or obligations are required or in place under the PSC.  At this stage, this condition precedent has not been fulfilled and the representation is incorrect. 

Andalas will continue to monitor the situation over the coming days as further information becomes available following the decision by the vendor not to sign the gross split PSC. 

Andalas expects to be in a position to provide an update on or before 7.00am 18 February 2019.

To date Andalas has incurred direct costs of an estimated £200,000 of legal, professional and other direct costs in connection with Bunga Mas.  No consideration has yet been paid to the vendor and will not be paid unless and until Andalas secures an interest in the licence.

Andalas Energy & Power PLC CEO, Simon Gorringe, said: “We are disappointed by the recent developments at Bunga Mas.  As its stands the financial commitment required for Andalas to fund its participation in the Bunga Mas PSC would require significantly more capital than the original SPA envisaged.  We are currently of the opinion that, without significant changes to the GOI’s expectations around funding the commitments it makes it very difficult for Andalas to proceed with the acquisition. 

“We remain hopeful that an amicable position can be reached with GOI and look forward to updating the market next week.”

“To end on a positive note, Colter is currently drilling, and we expect further news on the Company’s interest in Badger in the coming weeks.  Each of these projects has the potential to transform the near term outlook for the Company, whilst the Company looks to secure other opportunities and provide further guidance on Bunga Mas.” 

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the Market Abuse Regulations (EU) No. 596/2014 (‘MAR).  Upon the publication of this announcement via a Regulatory Information Service (‘RIS’), this inside information is now considered to be in the public domain.

For further information, please contact:

Simon Gorringe

Andalas Energy and Power Plc

Tel: +62 21 2965 5800

Roland Cornish/ James Biddle

Beaumont Cornish Limited
(Nominated Adviser)

Tel: +44 20 7628 3396

Colin Rowbury

Novum Securities Limited
(Joint Broker)

Tel: +44 207 399 9427

Christian Dennis

Optiva Securities Limited
(Joint Broker)

Tel: +44 20 3411 1881

Stefania Barbaglio

Cassiopeia Services Limited                                       (Public Relations)

Stefania@cassiopeia-ltd.com

Andalas Energy & Power #ADL – Conditional Acquisition of Indonesian oil project

Andalas Energy and Power Plc, the AIM listed oil and gas company (AIM: ADL), is pleased to announce it has entered into a conditional agreement to acquire an interest in the Bunga Mas Production Sharing Contract (the “Bunga Mas PSC” or the “PSC”), located in South Sumatra, Indonesia.

Highlights:

  • Acquisition of initial 25% participating interest in Bunga Mas PSC via a corporate acquisition with right to increase interest to 49% and then 100%.
  • Consideration of 19,200,000 Andalas ordinary shares to be issued as follows:
    • 9,600,000 shares on completion of the acquisition of the initial participating interest (“Completion”).
    • 9,600,000 shares on regulatory approval of increase of interest to 49%.
    • The consideration shares, representing 6.5% of Andalas’ current issued share capital, to be issued at the prior 5-day volume weighted average at the date of issue.
  • Completion is subject to various matters including extension of the exploration period of the PSC.
  • Andalas to undertake new exploration and development of the PSC as an exclusive operation entitling it to 100% of the cash flows available to participating interest owners under the PSC.
  • The Bunga Mas PSC is located onshore, near existing upstream facilities, in the prolific producing South Sumatra basin, Indonesia:
    • Within the PSC, the Bunga Mawar field has been assessed by the operator to contain 2C contingent resources of 0.22 million barrels of oil (“MMBO”) and best prospective resources of 2.09 MMBO (gross) in the Air Benakat formation.
    • Initial work programme plans to test the Bunga Mawar field and to convert prospective resources to additional contingent resources which will form the basis for a plan of development.
    • Further details of work programme to be announced on completion.
  • The acquisition includes a pro-rata share of unaudited brought forward past costs that are recoverable by participating interest owners from future revenues in priority to various other distributions (“Cost Pool”).
  • Previous expenditures on the PSC total US$111,695,000 (gross) of which a proportion is expected to be Cost Pool attributable to the Bunga Mawar project and will, assuming recovery is permitted by the regulator significantly enhance the projects economics.
  • A further detailed description of the transaction and the asset, including a royalty created by the vendor, is set out below.
  • The operator has assessed the PSC to include the resources set out in Table 1 below:

Table 1 Gross resources (Notes 1, 2, 3, 4, 5 and 6):

Bunga Mawar Field:

Resource Description Oil/Cond. Recoverable (mmbbls) GCOS
1C 2C 3C
Contingent Resources (Note 1) 0.08 0.22 0.46
Low Best High %
Prospective Resources (Note 3 and 4) 0.52 2.09 6.54 44%

Other Structures on Licence:

Contingent Resources (Note 1) Gas Recoverable (net of CO2) (Bcf) COS
Structure 1C 2C 3C %
Melati (Note 2) 22.00 26.00 32.00 30%

 

Prospective Resources (Note 3) Oil/Cond. Recoverable (mmbbls) GCOS
Structure Low Best High %
Bakung 0.77 10.19 32.96 23%
Sakura 1.50 8.82 30.49 20%
Anggrek 0.80 6.80 13.37 15%
Melati East 1.18 3.13 8.7 20%
Melati West 8.52 25.58 51.56 23%

Simon Gorringe, CEO of Andalas Energy and Power PLC said “We are very pleased to have reached agreement with the vendor for the acquisition of interests in the Bunga Mas PSC.  It is an all share deal structured to align the interests of the vendor and our shareholders and ensure that consideration does not pass and additional costs are not incurred until the deal completes.

“The PSC contains the Bunga Mawar field, which was discovered in 2012 by the drilling of the Bunga Mawar-1 well into the Air Benakat formation, which produced sweet light crude of 45o API from a depth of 704 m.  Our initial work programme will target the Bunga Mawar Field, following which we expect to submit, for approval, our Plan of Development to bring the field into production and will then look to appraise and develop the other oil and gas accumulations on the licence.”

Note 1:  Contingent Resources are defined as those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingent Resources are a class of discovered recoverable resources.

Note 2:  Based on well test data and analysis supplied by the Operator and reviewed by Andalas, the Bunga Melati 1 well tested natural gas from the Talang Akar Formation (TAF) at rates up to 11.8 mmscfd.  However, the gas analysis determined the CO2 content to be 67%.  Bunga Melati is a discovered accumulation.  Future commercial development will be dependent on further appraisal and the ability to address the CO2 content. The low chance of success (“COS”) reflects the likelihood of a future commercial development.

Note 3:  Prospective Resources are defined as those quantities of petroleum that are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.  The GCOS in respect of the Bungar Mawar prospective oil resource was assessed by Andalas using information provided by the Operator.

Note 4: The work programme in contemplation has the potential to move these Bunga Mawar Prospective Resource volumes to the Contingent Resource category, and ultimately, with the preparation and approval of a Plan of Development for the field to the Reserves classification.

Note 5: The tables present the gross contingent and prospective resources within the Bunga Mas PSC.  Following completion Andalas has the right to seek to extract 100% of the oil and gas potential.  However, whilst the volumes above are the estimated potentially recoverable volumes, the economic entitlement to Andalas will be dictated by the terms of the PSC and Andalas’ percentage working interest held in each operation.

Note 6: The work carried out in calculating the Contingent and Prospective Resources above was done using international resources and reserves reporting and classification standard adopted by the AIM market of the London Stock Exchange plc – the March 2007 SPE/WPC/AAPG/SPEE Petroleum Resources Management System (“PRMS”).

About the Bunga Mas PSC

The Bunga Mas PSC was initially entered into on 7 October 2005 in respect of an initial contract area in South Sumatra comprising 2,233 km2 and which now comprises an area of 447 km2 after relinquishments in accordance with the PSC.  The term of the PSC is 30 years and includes an initial term for exploration after which the contractor may progress to further periods for development and then exploitation.  The exploration term is the subject of an application for extension and the granting of that extension is a condition precedent to completion of the sale and purchase agreement.

The PSC provides that the contractor (i.e. the participating interest owners) is entitled to 35.7% of the oil and 71.4% of the natural gas available for distribution after recovery by the contractor of its permitted costs (including the brought forward cost pool).  The PSC also contains customary provisions regarding first tranche petroleum and domestic market obligation.

Prior contractors have incurred expenditures of US$111,695,000 in exploring the PSC.  Andalas expects a proportion of this expenditure will be recoverable by Andalas in priority to distributions of profits to the state.  The bulk of the original exploration was focussed on the discovery of gas.

Description of the transaction

Andalas has entered into a sale and purchase agreement pursuant to which it has agreed to acquire 100% of Aura Violet International Ltd (“AVI”) from Tilegarre Corporation.

AVI is the parent company of PT Bunga Mas Energi (“BME”).  BME has a 25% participating interest in the PSC.  The other participating interests in the PSC are held by Bunga Mas International Company (“BMIC”) as to 51% and Dorato Fiore Pacifico Ltd (“DFP”) as to 24%.  BMIC is the operator of the PSC.  Each of AVI, BMIC and DFP are subsidiaries of Arctic Bay Ventures Inc (“ABV”).

In consideration, Andalas has agreed to issue 19,200,000 fully paid ordinary shares in two equal tranches.  The first tranche shall be allotted on Completion and the second tranche shall be allotted on receipt of the approval of SKK Migas and the Government of the Indonesia to the transfer by DFP of its participating interest to BME.

The sale and purchase agreement is conditional on:

  1. DFP agreeing to assign its 24% participation interest in the PSC to BME for $1 and submission to SKK Migas of an application to approve the transfer;
  2. The Indonesian Minister of Energy and Mineral Resources approving an extension to the exploration period of the PSC on terms acceptable to Andalas and various other related matters;
  3. Various parties including the ABV group entering into a further agreement (“Framework Agreement”) to regulate the activities of BMIC, DFP and BME under the joint operating agreement (“JOA”) and various other matters; and
  4. Various procedural matters necessary to perfect the transaction.

The agreement has a longstop date of 31 December 2018.

The Framework Agreement, which the parties must execute at Completion, provides that further exploration and development on the PSC will be undertaken as an exclusive operation by BME in accordance with the JOA.  Accordingly, all future PSC revenues available to participating interests and all expenses shall be for the account of BME.

Initially, BMIC shall continue to be the operator.  However, Andalas has the right to require BMIC to withdraw from the PSC and transfer its participating interest to BME for $1.  At this stage, BME would seek to be the new operator.

If BME has not commenced its exclusive operations within 7 months after Completion, Artic may sell BMIC to a third party and permit it to undertake exclusive operations.

Prior to Andalas executing the sale and purchase agreement, each of BMIC, DFP and BME granted a royalty in favour of Arctic (“Royalty”) pursuant to which they agreed to pay:

  1. 20% of the proceeds, net of tax, from the sale of that portion of production allocated to the participating interest owners for the recovery of costs (“Cost Hydrocarbons”) incurred in relation to the development of the Mawar formation until such time as the aggregate proceeds distributed to participating interest owners is $19.7m or such other sum as SKK Migas permits for the recovery of the costs incurred to date in relation to that project; and
  2. 5% of the proceeds, net of tax, from the sale of all hydrocarbons allocated to the participating interest owners other than Cost Hydrocarbons (“Profit Hydrocarbons”).

Andalas has granted Arctic an option to purchase a 20% participating interest in the PSC.  The consideration payable on exercise of the option is the termination of the Royalty and a cash sum equal to all amounts paid to Arctic pursuant to the Royalty.  The option may only be exercised after completion of the sale and purchase agreement and DFP transferring its participating interest to BME provided that notice is given before 30 June 2020.

In addition, Arctic has granted Andalas an option to purchase each of BMIC and DFP for $1 each and an option to put AVI back to Arctic for $1.

The unaudited management accounts of the acquired group of companies for the period from 1 January 2018 to 30 June 2018 showed a pre-tax loss of $30,811 and net liabilities as at 30 June 2018 were $13,888.  The effective date of the agreement, once all conditions have been achieved, is 1 May 2018.

Reserves and Resources Cautionary Statement

Oil and gas reserves and resource estimates are expressions of judgment based on knowledge, experience and industry practice.  Estimates that were valid when originally calculated may alter significantly when new information or techniques become available.  Additionally, by their very nature, reserve and resource estimates are imprecise and depend to some extent on interpretations, which may prove to be inaccurate.  As further information becomes available through additional drilling and analysis, the estimates are likely to change.  This may result in alterations to development and production plans which may, in turn, adversely impact the Company’s operations.  Reserves estimates and estimates of future net revenues are, by nature, forward looking statements and subject to the same risks as other forward looking statements.

Qualified Person’s Statement

The technical information contained in this announcement has been reviewed and approved by Mr. Gregor Mawhinney. Mr. Mawhinney is consulting for Andalas, acting in the role of Vice President Operations. He has nearly 40 years’ experience in the oil and gas industry, is a member of the Society of Petroleum Engineers (SPE) and a member of the Professional Engineers and Geoscientists of Newfoundland and Labrador (PEGNL).

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the Market Abuse Regulations (EU) No. 596/2014 (‘MAR).  Upon the publication of this announcement via a Regulatory Information Service (‘RIS’), this inside information is now considered to be in the public domain.

For further information, please contact:

Simon Gorringe Andalas Energy and Power Plc Tel: +62 21 2965 5800
Roland Cornish/ James Biddle Beaumont Cornish Limited
(Nominated Adviser)
Tel: +44 20 7628 3396
Colin Rowbury Novum Securities Limited
(Joint Broker)
Tel: +44 207 399 9427
Christian Dennis Optiva Securities Limited
(Joint Broker)
Tel: +44 20 3411 1881
Stefania Barbaglio Cassiopeia Services Limited                                       (Public Relations) Stefania@cassiopeia-ltd.com

Glossary:

Unless otherwise stated, words and expressions used in this announcement have the same meaning as is given to them in the SPE Petroleum Resources Management System.

1C Low estimate of Contingent Resources
2C Best estimate of Contingent Resources
3C High estimate of Contingent Resources
bbl Barrel
Bcf Billions of cubic feet
Best (or mid) estimate or P50, a 50% probability that a stated volume will be equalled or exceeded
COS Commercial chance of success
GCOS Geological chance of success
GIIP Gas initially in place
High estimate or P10, a 10% probability that a stated volume will be equalled or exceeded
Low estimate or P90, a 90% probability that a stated volume will be equalled or exceeded
MMbbl million barrels
Recoverable Gas Those quantities of hydrocarbon gas which are estimated to be producible from accumulations, either discovered or undiscovered.
Recoverable Liquids Those quantities of hydrocarbon liquids which are estimated to be producible from accumulations, either discovered or undiscovered.

Salt Lake Potash #SO4 Appendix 5B Quarterly Report

Mining exploration entity and oil and gas exploration entity quarterly report

Introduced 01/07/96  Origin Appendix 8  Amended 01/07/97, 01/07/98, 30/09/01, 01/06/10, 17/12/10, 01/05/13, 01/09/16

 

Name of entity

Salt Lake Potash Limited

ABN

Quarter ended (“current quarter”)

98 117 085 748

30 June 2018

Consolidated statement of cash flows

Current quarter $A’000

Year to date              (12 months)
$A’000

1.

Cash flows from operating activities

1.1

Receipts from customers

1.2

Payments for

(1,143)

(5,930)

(a)   exploration & evaluation

(b)   development

(c)   production

(d)   staff costs

(628)

(2,553)

(e)   administration and corporate costs

(264)

(790)

1.3

Dividends received (see note 3)

1.4

Interest received

48

242

1.5

Interest and other costs of finance paid

1.6

Income taxes paid

1.7

Research and development refunds

457

1.8

Other (provide details if material)
– Business Development

– GST refunds (paid)

– Exploration Incentive Scheme

(385)

(50)

(989)

11

30

1.9

Net cash from / (used in) operating activities

(2,422)

(9,522)

2.

Cash flows from investing activities

(168)

(290)

2.1

Payments to acquire:

(a)   property, plant and equipment

(b)   tenements (see item 10)

(c)   investments

(d)   other non-current assets

2.2

Proceeds from the disposal of:

(a)   property, plant and equipment

(b)   tenements (see item 10)

(c)   investments

(d)   other non-current assets

2.3

Cash flows from loans to other entities

2.4

Dividends received (see note 3)

2.5

Other (provide details if material)

2.6

Net cash from / (used in) investing activities

(168)

(290)

3.

Cash flows from financing activities

3.1

Proceeds from issues of shares

3.2

Proceeds from issue of convertible notes

3.3

Proceeds from exercise of share options

3.4

Transaction costs related to issues of shares, convertible notes or options

(75)

3.5

Proceeds from borrowings

3.6

Repayment of borrowings

3.7

Transaction costs related to loans and borrowings

3.8

Dividends paid

3.9

Other (provide details if material)

3.10

Net cash from / (used in) financing activities

(75)

4.

Net increase / (decrease) in cash and cash equivalents for the period

8,300

15,597

4.1

Cash and cash equivalents at beginning of period

4.2

Net cash from / (used in) operating activities (item 1.9 above)

(2,422)

(9,522)

4.3

Net cash from / (used in) investing activities (item 2.6 above)

(168)

(290)

4.4

Net cash from / (used in) financing activities (item 3.10 above)

(75)

4.5

Effect of movement in exchange rates on cash held

4.6

Cash and cash equivalents at end of period

5,711

5,711

5.

Reconciliation of cash and cash equivalents
at the end of the quarter (as shown in the consolidated statement of cash flows) to the related items in the accounts

Current quarter
$A’000

Previous quarter
$A’000

5.1

Bank balances

1,711

2,300

5.2

Call deposits

4,000

6,000

5.3

Bank overdrafts

5.4

Other (provide details)

5.5

Cash and cash equivalents at end of quarter (should equal item 4.6 above)

5,711

8,300

6.

Payments to directors of the entity and their associates

Current quarter
$A’000

6.1

Aggregate amount of payments to these parties included in item 1.2

(207)

6.2

Aggregate amount of cash flow from loans to these parties included in item 2.3

6.3

Include below any explanation necessary to understand the transactions included in items 6.1 and 6.2

Payments include director and consulting fees, superannuation and provision of corporate, administration services, and a fully serviced office.

7.

Payments to related entities of the entity and their associates

Current quarter
$A’000

7.1

Aggregate amount of payments to these parties included in item 1.2

7.2

Aggregate amount of cash flow from loans to these parties included in item 2.3

7.3

Include below any explanation necessary to understand the transactions included in items 7.1 and 7.2

Not applicable.

8.

Financing facilities available
Add notes as necessary for an understanding of the position

Total facility amount at quarter end
$A’000

Amount drawn at quarter end
$A’000

8.1

Loan facilities

8.2

Credit standby arrangements

8.3

Other (please specify)

8.4

Include below a description of each facility above, including the lender, interest rate and whether it is secured or unsecured. If any additional facilities have been entered into or are proposed to be entered into after quarter end, include details of those facilities as well.

Not applicable

9.

Estimated cash outflows for next quarter

$A’000

9.1

Exploration and evaluation

1,200

9.2

Development

9.3

Production

9.4

Staff costs

650

9.5

Administration and corporate costs

200

9.6

Other (provide details if material)
– Business Development


150

9.7

Total estimated cash outflows

2,200

10.

Changes in tenements
(items 2.1(b) and 2.2(b) above)

Tenement reference and location

Nature of interest

Interest at beginning of quarter

Interest at end of quarter

10.1

Interests in mining tenements and petroleum tenements lapsed, relinquished or reduced

Refer to Table 3

10.2

Interests in mining tenements and petroleum tenements acquired or increased

Compliance statement

1        This statement has been prepared in accordance with accounting standards and policies which comply with Listing Rule 19.11A.

2        This statement gives a true and fair view of the matters disclosed.

Sign here:         ……………………………………………………                        Date: 30 July 2018

(Director/Company secretary)

Print name:       Sam Cordin

Notes

1.       The quarterly report provides a basis for informing the market how the entity’s activities have been financed for the past quarter and the effect on its cash position. An entity that wishes to disclose additional information is encouraged to do so, in a note or notes included in or attached to this report.

2.       If this quarterly report has been prepared in accordance with Australian Accounting Standards, the definitions in, and provisions of, AASB 6: Exploration for and Evaluation of Mineral Resources and AASB 107: Statement of Cash Flows apply to this report. If this quarterly report has been prepared in accordance with other accounting standards agreed by ASX pursuant to Listing Rule 19.11A, the corresponding equivalent standards apply to this report.

3.       Dividends received may be classified either as cash flows from operating activities or cash flows from investing activities, depending on the accounting policy of the entity.

This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.

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