Andalas Energy and Power Plc* 25 October 2018

Barney Gray (Research Analyst) +44 (0) 20 3137 1906 Graeme Dickson (Dealing Desk) +44 (0) 20 3411 1880 Hal Norwood (Dealing Desk) +44 (0) 20 3411 1882 Vishal Balasingham (Institutional Sales) +44 (0) 20 3411 1881 16 Christian Dennis (CEO/Corporate Broking) +44 (0) 20 3137 1903

Andalas Energy and Power plc* 25 October 2018

BUY A renewed strategy to deliver value Andalas is an AIM-quoted oil and gas E&P company with a growing portfolio of assets in the Stock Data UK and Indonesia. Its core assets include an 8.0% interest in the imminent Colter appraisal Share Price: 0.82p well on UK offshore licence P1918 in Q4 2018 and a 25.0% investment in Eagle Gas Limited Market cap.: £3.2m* Shares in issue: 385.0m* which holds a 66.67% interest in UK Licence P2112 in the Southern North Sea, containing Fully diluted equity: 489.3m* the large Badger gas prospect. Andalas also recently entered into a deal to acquire 25% of *Pro forma until Bunga Mas PSC deal is completed the Bunga Mas PSC in Indonesia with the right to increase this interest to 100% upon the undertaking of new development activity on the Bunga Mawar field. Company Profile Since the appointment of new CEO, Simon Gorringe in October 2017, Andalas has re- Sector: Oil & Gas orientated its focus from integrating upstream assets with wellhead located independent Exchange: AIM power producers (IPPs) in Indonesia to conventional E&P opportunities with a broader Ticker: ADL geographical focus. Activities On 21 September 2018, Andalas acquired an 8.0% interest in UKCS Licence P1918 through a Andalas is an AIM-quoted oil and gas E&P farm-in deal with the operator Corallian Energy whereby Andalas will pay 10.67% of the cost company with a portfolio of exploration and of an upcoming appraisal well on the exciting Colter prospect. This well, currently scheduled appraisal assets located in the UKCS in addition to be drilled in Q4 2018, will target over 19 mmbbls of mean contingent and prospective to significant exploration, appraisal and resources in a location updip from the original discovery well. In the event of a successful development interests in Sumatra in Indonesia. outcome, the operator believes that Colter could be developed through the existing onshore

Wytch Farm oil field facilities located in close proximity. Performance data In July 2018, Andalas completed a deal increase its interest to 25.0% in Eagle Gas Limited, a private UK oil and gas company. Eagle’s primary asset is a 66.67% interest in UK Licence P2112 which contains the large Badger gas prospect, one of the largest undrilled targets in the Southern North Sea. Badger is estimated to contain mean prospective resources of almost 400 BCF over four intervals. As a function of the company’s investment in Eagle rather than the licence itself, Andalas may see its exposure to Badger diluted in the event that Eagle farms down its position prior to

exploratory drilling. However, we would view such as scenario as positive given that such an Directors outcome has the potential to secure full or part funding for an initial exploration well and de- Robert Arnott: Chairman Simon Gorringe: CEO risk Andalas’ investment significantly. Dan Jorgensen: Finance. Director Leveraging its accumulated experience in Indonesia, Andalas entered into a conditional Ross Warner: Legal & Commercial agreement to acquire an initial 25% participating interest in the Bunga Mas Production Sharing Contract (PSC) on the island of Sumatra in Indonesia in late August 2018. This deal Important Notice gives Andalas the right to increase its interest in Bunga Mas to 49% and ultimately to 100% OSL’s investment research products are paid for upon the undertaking of new exploration and development activity on the PSC. by corporate clients as part of their retainer fee. As such, this document falls under Article 12 3 Bunga Mas contains the Bunga Mawar oil field on which the company will focus its initial (b) of the European Commission’s Delegated appraisal programme. If successful, this work is expected to form the basis of a longer term Directive of 7 April 2016 and it qualifies as an development plan. The potential economics of Bunga Mawar and the wider licence, which ‘acceptable minor non-monetary benefit’ and contains substantial exploration and appraisal upside, are greatly enhanced by the existence does not qualify as ‘chargeable research’. OSL of an historical cost pool of US$111.7m, the recovery of even a proportion could greatly are therefore able to send this document to enhance the economics of a development programme. investors without the requirement for any compensation to be paid to OSL from the We believe that Andalas could be worth 5.6p per share on a fully diluted basis with upside recipients – it is ‘freely available’. potential of up to 10.9p per share. We envisage that the company will require additional funding in mid-2019 in order to expedite an appraisal programme at Bunga Mawar. *Optiva Securities acts as joint broker to However, near term activity in the UK, particularly in regards to Andalas’ participation in Andalas Energy and Power plc. the Colter well is fully funded and we expect news flow to accelerate significantly over Q4 2018 as drilling operations commence.

Contents

Introduction to Andalas Energy & Power 3

A change of strategy 3

Andalas assets in summary 3

Recent corporate activity 4

Company valuation summary 5

Potential funding requirement 5

UKCS Licence P1918 – Colter appraisal well 6

The Colter prospect 7

Estimated valuation 9

UK exploration: Interest in Eagle Gas Limited 10

Work programme on Badger 10

Indicative valuation 13

Indonesian oil and gas sector overview 14

Historical lack of investment now provides opportunities 15

Indonesian fiscal terms for oil and gas 19

Key components 19

Gross Split PSC – an alternative fiscal model 20

The Bunga Mas PSC 21

Bunga Mas PSC resources 22

Valuation focused on Bunga Mawar 23

Resource upside on Bunga Mas 25

Appendix 1 - Directors’ Biographies 26

Appendix 2 – Badger natural gas liquids 27

Appendix 3 – Details of the Bunga Mas acquisition 28

Disclaimer 29

Introduction to Andalas Energy and Power

Andalas Energy and Power is an AIM-quoted oil and gas E&P junior with assets located in the UK and Indonesia. Over the last twelve months, Andalas has drastically realigned the long term strategy of the business by enacting several fundamental changes across all aspects of the company.

A change of strategy

Management changes

In October 2017, Andalas instigated a number of key changes to its Board of Directors including the appointment of new CEO, Simon Gorringe, appointed to steer the company’s new strategy focused on conventional E&P opportunities that offer investors exposure to a range of exploration, development and production opportunities and a more balanced risk reward portfolio. This move was consolidated with the appointment of former non-executive director, Dr Robert Arnott to the role of chairman in April 2018. Dr Arnott has significant experience in the UK North Sea and was appointed to guide Andalas’ refocused operational strategy over the longer term. More details regarding the current Andalas management can be found in Appendix 1 at the end of this report.

Operational changes

As the current company name implies, Andalas historically focused on developing upstream assets with a view to applying innovative technical solutions to monetise undeveloped reserves. This original strategy was focused on the island of Sumatra in Indonesia where the company was attempting to integrate upstream oil and gas production assets with wellhead located independent power producers (IPPs) or export pipelines.

However, at the time of the company’s recent final results announcement, Andalas outlined the results of a detailed review of the business and announced that it will concentrate on conventional E&P opportunities and broaden its geographical focus to include regions outside its existing operations in Indonesia.

This was driven in part by the company’s frustrations over its ability to both advance and influence its portfolio of wellhead IPPs over the longer term but more by the availability of new exciting opportunities which imply considerably greater growth prospects for the group. Consequently, the legacy Indonesian projects have been mothballed in order to both preserve the group’s financial resources and save substantial amounts of management time which will now be focused on the current portfolio.

Andalas assets in summary

In the space of less than six months, Andalas has completely re-orientated the business with several acquisitions that we expect to drive the future growth of the company.

In the UK, the company has leveraged the current management’s considerable North Sea experience and acquired exciting exposure to a range of exploration and appraisal opportunities. These are:

• An 8.00% interest in UKCS Licence P1918 providing the company with exposure to upcoming near- offshore appraisal drilling focused on the Colter prospect. • A 16.67% indirect interest in UKCS Licence P2112 through Andalas’ 25.00% interest in Eagle Gas Limited (which holds 66.67% of P2112). Licence P2112 contains the large Badger prospect which is estimated to contain nearly 400 BCF of gas over multiple horizons.

In Indonesia, where the company has gained years of valuable experience, Andalas has acquired an initial 25% interest in the Bunga Mas PSC (Production Sharing Contract) on South Sumatra. This deal provides Andalas with economic control of the project and the right to increase its interest in the licence to 49% and then to 100% upon the completion of certain operational milestones.

Location maps of Andalas’ core portfolio assets

Source: Company

Recent corporate activity

Over the course of 2018, Andalas has conducted several modest placings in connection with the rejuvenated strategy for the company.

On 30 April 2018, in tandem with the deal to acquire an initial tranche of Eagle Gas Limited, Andalas raised £0.6m through the issue of 3,529.4 million shares at a price of 0.017p (*adjusted to 0.85p for recent share consolidation). This was followed by a two-part placing of 5,000 million shares consisting of unconditional and conditional (subject to AGM) elements to raise a further £1.0m at a higher price of 0.02p per share (*adjusted to 1.0p). The conditional element of the placing was completed in early August 2018 following the passing of a share consolidation resolution at an AGM on 3 August 2018.

*With over 14.6 billion shares in issue at the time of the AGM, Andalas shareholders also passed a resolution to enact a share consolidation with every 50 existing shares consolidated into 1 share. This subsequently reduced the company’s share capital to 293.2 million shares in issue as of 10 August 2018, when the new shares were admitted to trading on AIM.

Colter appraisal well is fully funded

Finally, in tandem with the company’s acquisition of an 8.00% interest in the UK Licence P1918, Andalas also completed a placing of 69.6 million shares at 1.15p per share to raise £0.8m with which to fund its share of the upcoming appraisal well on the exciting Colter prospect, currently scheduled for Q4 2018.

Company valuation summary

Outlined in the table below is our sum of the parts valuation for Andalas. Our valuation assumptions are based on the company’s basic equity of almost 385.0 million shares. We have calculated this on a pro forma basis to include the 19.2 million shares that Andalas intends to issue to complete the acquisition of the Bunga Mas PSC in Indonesia. Our fully diluted equity number includes a further 104.3 million options and warrants, over 90% of which are exercisable in the realistic price range of 0.85p -3.0p. Our indicative valuations have been generated in US dollars and converted into a Sterling equivalent at the current exchange rate of approximately US$1.30: £1.00.

We have established a base case valuation of 5.9p per share on a fully diluted basis which consists of our indicative risked NPV (net present valuation) assessments of Andalas’ core assets in Indonesia and the UK in tandem with several corporate adjustments. In this case, we have assumed a base case equity interest of 25% for the company’s interest in the Bunga Mas PSC. However, given that this particular deal is expected to result in an interest that entitles Andalas to 100% of the cash flows available to participating interest owners under the terms of the PSC, this is in effect an aggressively commercially risked valuation and we have illustrated the full upside case in the right hand column which culminates in a fully diluted indicative valuation of 11.6p per share for the company.

Andalas’ asset portfolio summary

Valuation Valuation Undiluted Diluted Upside case Diluted Item Country Status $m £m p P £m P Bunga Mas PSC Indonesia Appraisal/Development 5.0 3.9 1.0 0.8 15.4 3.1 Bunga Mas PSC upside Indonesia Exploration/Appraisal 6.3 4.8 1.2 1.0 19.2 3.9 Eagle Gas (25% interest) UK Exploration 9.5 7.3 1.9 1.5 7.3 1.5 Licence P1918 (Colter) UK Exploration/Appraisal 12.3 9.5 2.5 1.9 9.4 1.9 Overheads Corporate -1.0 -0.8 -0.2 -0.2 -0.8 -0.2 Warrants and options Corporate 3.8 2.9 0.7 0.6 2.9 0.6 Cash (debt) Corporate 0.0 0.0 0.0 0.0 0.0 0.0 Total 35.9 27.5 7.2 5.6 53.5 10.9

Source: Optiva estimates

Potential funding requirements

There are a number of important observations to make regarding the scope of Andalas’ current portfolio. Key assets within this summary have scheduled upcoming activity and in the case of the Colter well in particular, can be funded from existing resources. In addition, the company’s interest in Eagle Gas is structured as an investment and therefore Andalas is not exposed to any future funding commitments. As is the case in such investments, Andalas’ holding is subject to potential dilution in the event that the company does not participate in any future Eagle fund raisings. However, we believe that any potential dilution will be offset by the positive impact of commercially de-risking of the investment in the event that Eagle can secure farm-inees on Licence P2112 in the UK Southern North Sea.

We have excluded Andalas’ current cash position from our assessment given that we do not classify any funds currently held as ‘free cash’, not yet attributed to any specific asset within the portfolio. Nevertheless, we note that a longer term work programme on Andalas’ Indonesian assets, specifically the Bunga Mawar field, is largely unfunded at present and Andalas would need to raise additional capital or find suitable farm-in partners to commence an appraisal programme that could expedite a full development of the field in the near term that would also enable the securing of operatorship and control of the entire PSC.

We estimate that this funding requirement could be US$2.5m over the next 18 months although the timing of this requirement remains conditional on the terms of the licence extension. However, with the instigation of early cash flow from Bunga Mawar, the project has the potential to be self-funding after the onset of production from initial wells in 2020 and cash flow from Bunga Mawar also has the potential to fund a significant proportion of future drilling activity on the field and also on other prospective structures on the wider PSC in later years.

UKCS licence P1918: The Colter prospect

On 21 September 2018, Andalas through its 100% owned subsidiary Resolute Oil & Gas (UK) Limited, agreed a farm-in deal to acquire an 8.0% interest in UK Continental Shelf Licence P1918 from Corallian Energy Limited; a private UK oil and gas company with a portfolio of licences in the UK onshore and offshore sectors. Licence P1918 contains the Colter prospect and also PEDL 330 and PEDL 334, together termed ‘the licences’, which are located offshore Dorset in the southern UK (see map below). The other participants in the licences are:

• Corallian Energy (operator) 49.00% • Corfe Energy 25.00% • United Oil & Gas 10.00% • Baron Oil 8.00% • Andalas Energy 8.00%

Of primary interest is the Colter appraisal project which is located adjacent to the large Wytch Farm oilfield in the south of England. Wytch Farm has been a prolific producer since discovery by British Gas Corporation in 1973 and has produced over 450 mmbbls of oil with peak production reaching 110,000 bopd in 1997 under the operatorship of BP.

Location of the undeveloped Colter prospect on Licence P1918

Source: Corallian Energy Limited

The transaction terms

Andalas has acquired an 8.00% interest in the licence group in return for paying 10.67% of the costs of an initial appraisal well on Colter up to a maximum gross cost of £8.0m. A contract has already been signed with Ensco UK for the provision of the jack-up rig Ensco-72 and a rig survey has been completed which will enable operations to commence as a planned. The rig is scheduled to drill the Wick exploration well in the Moray Firth prior to Colter and upon completion of Wick, the drilling of the Colter well can commence. Colter is currently scheduled to spud later in Q4 2018 subject to the usual regulatory approvals.

The company has noted that an Authorisation for Expenditure (AFE) for the upcoming Colter well has been signed by all the Colter equity partners for a total cost of £7.5m. On this basis, Andalas estimates that the dry hole cost for the company would be approximately £0.8m for which the company is fully funded after a recent placing to raise the same amount.

The Colter prospect

The undeveloped Colter discovery is located offshore immediately southeast of the Wytch Farm oil field. BP drilled the 98/11-3 discovery well on the Colter prospect in 1986 and recovered a modest amount of 41.9° API oil from a 10.5 metre oil column within the Sherwood Sandstone horizon, the same formation as that which is productive in the Wytch Farm field.

Although Colter was not developed at the time, more recent seismic technology has been employed to merge and reprocess two 3D seismic data sets that enabled the identification of over 100 metres of mapped vertical relief up-dip of the original discovery well.

The Colter well is planned to be drilled in a location updip of the original discovery well in order to assess the full potential of the prospect. The well is planned to be drilled from an offshore jack-up rig given the shallow water depths. However, we expect that full development upon a successful result is most likely to be through the existing Wytch Farm facilities located onshore, subject to agreement with the field’s operator.

Resource estimates

A competent person’s report (CPR) has been carried out on the targeted Colter structure by independent consultant, ERC Equipoise (ERCE). ERCE have ascribed unrisked mid-case gross contingent resources of 4.1 mmbbls assigned to the original 98/11-3 discovery well and a further unrisked mean prospective resource of approximately 15 mmbbls to the rest of the structure extending to the west, implying an unrisked mean base case of approximately 19 mmbbls at this pre-drill stage.

Colter prospect resource estimates (mmbbls)

Prospect Resources (mmbbls) Low Mid High Mean Colter East Gross contingent resources 1.7 4.1 10.1 4.1 Colter West Gross Unrisked prospective resources 4.0 11.0 29.0 15.0 Total gross resources 5.7 15.1 39.1 19.1 Colter East Net Contingent Resources 0.1 0.3 0.8 0.3 Colter West Net unrisked prospective resources 0.3 0.9 2.3 1.2 Total net resources (Andalas: 8.00%) 0.5 1.2 3.1 1.5

Source: ERCE

Potential upside

As the map previously suggests, there could be additional exploration upside on the licences in the form of the Ballard Point undeveloped gas discovery immediately to the south of Colter. Additionally, the licences also contain the Purbeck prospect to the southwest which could contain at least 36 BCF of gas.

Technical aspects and risks

At the time of discovery, the 98/11-3 discovery well flowed at low rates during test, recovering 8.5 barrels of oil and 100 barrels of water. Subsequent analysis of the test by independent consultants suggested that the low hydrocarbon recovery rates were a consequence of a combination of reservoir damage, poorer quality reservoir at the top of the Sherwood formation and water being in the mobile phase within the transition zone when the zone was encountered.

Subsequent 3D seismic data over the crest of the Colter structure has now been reprocessed but the relatively complex structure combined with faulting still provides challenges. However, we note that there are clear indications from the data of a significant area updip from the 98/11-3 well which has not been tested to date.

In our view, an appraisal well in this location does carry an appreciable degree of risk that it is a separate compartment across a fault boundary. At the pre-drill stage, the CPR has ascribed a 58.5% chance of success (CoS) to the combined Colter East and West prospects which we have applied to our internal assumptions. The map below depicts the proposed location of the Colter appraisal well and its location up-dip of the original 98/11-3 discovery well.

Colter prospect reservoir map

Source: Corallian Energy Limited

Estimated valuation

For the purposes of establishing an indicative valuation for Andalas’ interest in Colter, we have valued the prospect on the gross base case resources scenario of approximately 19 mmbbls. To this we have applied a range of variables to a notional development of a field of this size in order to assess the potential value of a successful appraisal project to Andalas. Within our calculations, we have assumed the following production profile from a full two well development.

Colter production profile (bopd)

Source: Optiva estimates

Development cost assumptions

Within our estimates, we have assumed the successful completion and testing of an appraisal well costing US$9.75m (£7.5m) gross. As outlined previously, Andalas will pay 10.67% for an 8.00% equity interest under its farm-in terms implying a net cost exposure of £0.8m to the company. Our assumptions also factor in a two well development consisting of two extended reach development wells of the type producing oil at Wytch Farm, a water injector and a processing tie-in again at Wytch Farm. This portion of the development is expected to cost approximately US$120m in total with the bulk of the expenditure incurred between 2019 and 2021. This would be subject to agreement with the field operator.

We have applied a long term oil price of US$70 per barrel from 2021, when production commences, flat over the life of the field and for operating cost assumptions, we have factored in fixed opex of approximately US$2.6m per annum coupled with variable opex of US$10.00 per barrel of oil produced.

After applying the appropriate levels of UK oil and gas taxation to profits from production, we arrive at an indicative NPV for Colter of US$21.1m for Andalas’ 8.00% interest. If we apply the CoS risk factor of 58.5% to this unrisked NPV, we arrive at a technically risked NPV of US$12.3m net to the company’s interest.

UK exploration: Interest in Eagle Gas Limited

On 30 April 2018, Andalas acquired an indirect interest in Licence P2112 in the UK Southern North Sea (SNS) through the acquisition of a 14.75% equity interest in Eagle Gas Limited (Eagle), a private UK oil and gas company. Through its wholly owned subsidiary, Holywell Resources, Eagle holds a 66.67% interest in Licence P2112 which contains the Badger gas prospect (the balance of 33.33% is held by Atlantic Petroleum). Andalas consolidated this deal in July 2018 by increasing its interest in Eagle to 25.00% providing the company with an indirect interest of 16.67% in Licence P2112.

Location of P2112 in the UK SNS (shaded in darker blue)

Source: Atlantic Petroleum

Terms of the acquisition

Over the two investments, Andalas paid Eagle a consideration of £250,000 in cash as well as two tranches of 2.94 million Andalas shares equating to a total of c.£50,000 for the full 25.00% interest in Eagle. Andalas has agreed to issue a further £100,000 of Andalas shares (at 90% of the 3-day VWAP) on the earlier of the licence being extended beyond December 2018 and Eagle acquiring additional assets agreed by Andalas. As part of the agreement, Andalas CEO, Simon Gorringe has also been appointed to the board of Eagle.

Work programme on Badger

Licence P2112 contains the Badger prospect, considered to be one of the largest undrilled gas prospects in the UK Southern North Sea (SNS). Eagle conducted a work programme in the earlier part of 2018 that included the reprocessing of 3D seismic which met the current licence commitment. Oil services company, Petroleum Geo- Services (PGS) was contracted to conduct the reprocessing programme for Eagle.

In mid-August 2018, Eagle announced that the work programme had been completed and following interpretation of the reprocessed 3D seismic date, it had fully assessed the resource potential of the Badger gas prospect.

Technical conclusions

Eagle has mapped four seismic horizons which represent prospective sandstone reservoir objectives. These are:

• Westphalian A (consisting of three compartments) • Westphalian B • Namurian • Base Ketch

These four primary horizons are estimated to contain gross mean prospective resources of 399 BCF of recoverable gas (net of inert gases and liquids) in addition to 3.9 mmbbls of natural gas liquids. The table below outlines the recoverable resource estimates for each objective within the Badger prospect in addition to the indirect upside exposure net to Andalas. Natural gas liquids volumes are very modest in the context of the potential gas resources and Andalas’ indirect exposure amounts to approximately 0.7 mmbbls of liquids. The equivalent table for natural gas liquids can be examined in Appendix 2 of this report.

Badger prospective gas resource estimates (BCF)

GIIP Recoverable gas Gross unrisked prospective resources 100% P90 P50 P10 Mean P90 P50 P10 Mean GCOS Westphalian A Compartment A 22 48 102 57 17 36 77 43 34% Compartment B 22 48 104 59 17 36 81 44 34% Compartment C 19 49 124 64 15 37 94 48 26% Westphalian B Murdoch sandstone 24 62 138 74 18 46 104 55 28% Namurian Trent sandstone 54 121 268 146 40 90 202 110 30% Lower Ketch Ketch 64 140 297 166 38 84 180 99 22% Total 566 399 GIIP Recoverable gas Net to Eagle (Holywell Resources) 66.67% P90 P50 P10 Mean P90 P50 P10 Mean GCOS Westphalian A Compartment A 14.7 32.0 68.0 38.0 11.3 24.0 51.3 28.7 34% Compartment B 14.7 32.0 69.3 39.3 11.3 24.0 54.0 29.3 34% Compartment C 12.7 32.7 82.7 42.7 10.0 24.7 62.7 32.0 26% Westphalian B Murdoch sandstone 16.0 41.3 92.0 49.3 12.0 30.7 69.3 36.7 28% Namurian Trent sandstone 36.0 80.7 178.7 97.3 26.7 60.0 134.7 73.3 30% Lower Ketch Ketch 42.7 93.3 198.0 110.7 25.3 56.0 120.0 66.0 22% Total 377.4 266.0 Net to Andalas (indirect) GIIP Recoverable gas Net unrisked prospective resources 25.00% P90 P50 P10 Mean P90 P50 P10 Mean GCOS Westphalian A Compartment A 3.7 8.0 17.0 9.5 2.8 6.0 12.8 7.2 34% Compartment B 3.7 8.0 17.3 9.8 2.8 6.0 13.5 7.3 34% Compartment C 3.2 8.2 20.7 10.7 2.5 6.2 15.7 8.0 26% Westphalian B Murdoch sandstone 4.0 10.3 23.0 12.3 3.0 7.7 17.3 9.2 28% Namurian Trent sandstone 9.0 20.2 44.7 24.3 6.7 15.0 33.7 18.3 30% Lower Ketch Ketch 10.7 23.3 49.5 27.7 6.3 14.0 30.0 16.5 22% Total 94.3 66.5

Source: Eagle Gas Limited

Exploration drilling potential

In the event that an exploration well is drilled, Eagle has concluded that a well could comfortably target two of the four objectives. This would imply a well drilled in water depths of approximately 45 metres to a total depth (TD) of 4,200 metres. We understand that the terms of the licence extension beyond December 2018 contain a drill or drop well commitment. As yet, we understand that a well has not been scheduled.

Nevertheless, the proposed location for an exploratory well is approximately 35 km from local infrastructure, including the Perenco operated Eagles Transport System (ETS) pipeline which, subject to negotiation, could provide a transport route for produced gas from Badger to the Bacton gas terminal in north Norfolk.

The map below illustrates the location of Badger relative to the producing Trent field and the analogous Schooner field located to the east. The Badger prospect has remained undrilled given that it is located at the junction of four licence blocks which were historically under different ownership prior to Eagle’s operatorship.

Location map of Badger prospect and associated infrastructure

Source: Company

Work programme complete

Andalas has outlined that work to reprocess the 3D seismic to Pre-Stack Depth Migration is now complete and has reduced the risk associated with the Badger prospect given that the target formations lie beneath a Zechstein salt dome, the influence of which can increase uncertainty with estimating the scale of prospective resources. With the 2018 work programme now complete, the operator has commenced the farm-out process which has the potential to provide additional news flow over the next three months.

Farm-in potential for Badger

As a function of its interest in Eagle providing exposure to Badger, we understand that Andalas has the right to maintain its 25% shareholding but it cannot be directly cash called for further work on the licence. However, the company may be diluted in the event of a farm-out agreement, whereby Eagle may reduce its working interest in licence P2112 in return for a free or partial carry from a larger operator with regards to funding exploration drilling. This would have the effect of reducing Andalas’ indirect interest in Badger. However, it would also reduce significantly the commercial risk factor that we currently ascribe to an unfunded exploration project, offsetting much of the impact of a reduced interest in Eagle.

Indicative valuation

The table below outlines our indicative valuation for Andalas’ indirect interest in Badger based on the current licence terms. We have applied the prospective resource estimates and the associated GCoS (Geological Chance of Success) for each of the reservoir objectives as outlined in the previous table. To this, we have applied a unit NPV derived from a notional 130 BCF gas field and subsequent multi-well development in order to generate a technically risked gross NPV.

After the application of Eagle’s and Andalas’ working and equity interests respectively and a conservative 50% commercial risk factor given that an exploration well on the prospect is not currently unfunded nor subject to farm-out at this stage.

Consequently, we have arrived at a fully risked NPV based valuation of US$9.5m for Andalas’ indirect interest in Badger. As outlined previously, a farm-in reducing Eagle’s interest is likely to be broadly neutral to Andalas in value terms as this would mitigate much of the commercial risk associated with funding a future exploration well.

Risked assessment of resources estimates for Badger

Item Prospect Westphalian A Westphalian B Namurian Base Ketch Total Comp A Comp B Comp C Recoverable prospective resources BCF 43 44 48 55 110 99 399 GCoS % 34% 34% 26% 28% 30% 22% 28% Risked resources BCF 15 15 12 15 33 22 112 NPV per mcf USD 1.02 1.02 1.02 1.02 1.02 1.02 1.02 NPV US$m 14.9 15.3 12.7 15.7 33.7 22.2 114.5 Risked NPV US$m 14.9 15.3 12.7 15.7 33.7 22.2 114.5 Eagle Gas interest 66.67% 9.9 10.2 8.5 10.5 22.4 14.8 76.3 Andalas interest in Eagle Gas 25.00% 2.5 2.5 2.1 2.6 5.6 3.7 19.1 Commercial risk factor % 50% 50% 50% 50% 50% 50% 50% Risked Andalas interest US$m 1.2 1.3 1.1 1.3 2.8 1.9 9.5 USD/GBP 1.30 Risked Andalas interest £m 1.0 1.0 0.8 1.0 2.2 1.4 7.3

Source: Company, Optiva estimates

Indonesian oil and gas sector overview

Current status

Indonesia is a huge country with a population of over 267.5 million (Worldometers 2018). It is also a significant oil and gas producer with estimated oil and gas production of 949,000 bopd and 6.6 BCF per day in 2017 according to BP (Statistical Review 2018), at least half of which is located on the island of Sumatra. Although 47% of primary energy demand is met by oil and gas production, large areas of the country face critical energy shortages and domestic gas demand in particular is growing rapidly in line with strong population increases and steady economic growth. This is currently not being balanced by the same growth in energy supplies, creating a significant opportunity for oil and gas producers in particular.

We believe that Indonesia’s oil and gas sector could provide significant opportunities for Andalas. In broad terms, the industry has been characterised by declining oil production since the mid-1990s with the country becoming a net importer of crude since 2003 as the chart below depicts. While production has recovered slightly since 2015, this has been matched by increases in consumption and Indonesia meets its increasing demand for oil with significant levels of imported crude. With oil imports required to be paid for in US dollars, this is putting an increasing strain on the Indonesian economy.

Indonesian oil production vs consumption (mbopd), 1965-2017

Source: BP Statistical Review (2018)

Opportunities in the oil sector

We believe that activity in the oil sector in Indonesia has the potential for accelerated growth over the next decade given that the country’s reserve replacement ratio is estimated by Indonesia’s Energy and Mineral Resource Minister, Arcanda Tahar, to have fallen below 50% (proportion of production replaced by discovered reserves) and as such, the volume of imports has the potential to continue to increase significantly.

BP estimates that Indonesia’s proved reserve base is approximately 3.2 billion barrels of oil which implies that the country’s reserve base could be depleted in less than 10 years. However, we understand that the country’s resources base is considerably higher with an additional 3.9 barrels* of oil reserves classified as 2P and 3P ‘potential’ reserves (probable and possible). These estimates do not include prospective resources which would have potential to increase reserve estimates further given the appropriate levels of investment in exploration.

*Source: Directorate General of Oil and Gas – Ministry of Energy and Minerals

Historical lack of investment now provides opportunities

We believe that Indonesia’s oil supply/demand deficit has been driven by insufficient levels of investment in the sector over the last ten years in particular. In broad terms, this is highlighted by Chevron which has estimated that there are up to 60 distinctive hydrocarbon basins throughout the country of which only 22 have been fully explored and exploited to date. In more specific terms, however, the oil price weakness of recent years has resulted in a 60% decline in oil companies’ spending since 2014 according to Reuters, a trend that is eroding the prospects for long term growth in the sector significantly.

Wood Mackenzie also states that exploration in Indonesia has underperformed over the last decade and the lack of major discoveries has led in turn to a lack of significant development projects with which to reverse the long term trend of production decline.

This has been compounded by uncertainty in the fiscal and regulatory background. In particular, BPMIGAS, a state owned entity which was originally intended to be an agency for optimising the upstream oil and gas sector in Indonesia for all stakeholders, was dissolved in 2012 leading to an environment of weak investor confidence and lower investment in the sector.

Falling expenditure since 2013

This is encapsulated clearly in the chart below which depicts very starkly the decline in upstream oil and gas expenditure in Indonesia from an estimated peak of more than US$19.3bn in 2013 to only US$10.3bn in 2017, a decline of almost 47%. PWC indicates that the recent trough in investment was considerably below even the modest target of US$12.3bn indicated by SKK Migas at the start of 2017. Nevertheless, the outlook is more positive with the Directorate of Oil and Gas (DGOG) currently expecting a strong recovery in investment to US$14.5m in 2018 as a function of considerably higher global oil prices.

Upstream investment in Indonesia (US$m)

Source: PWC (Based on BP Migas/SKK Migas data)

Exploration expenditure cuts choke off new developments

Although a relatively modest proportion of the annual spend within the upstream Indonesian oil sector compared to production costs, aggressive declines in exploration expenditure, on which discoveries and future development projects are based has declined at an alarming rate of almost 70% since 2013 choking off subsequent development expenditure and therefore the potential for longer tern production growth by a substantial degree. This is depicted in the charts below. Although the DGOG has indicated that upstream expenditure has recovered significantly in 2018, we believe that it will take several years of success with the drill bit to return development expenditure in particular to the levels seen in the years up to 2014 prior to the last oil price collapse.

Exploration (left hand chart) and Development (right hand chart) expenditure in Indonesia (US$m)

Source: PWC (Based on BP Migas/SKK Migas data)

The Indonesian government’s reforms of some of the tax laws governing the oil and gas sector in 2016 were viewed as positive. However, Reuters’ summary of the investment community surmised that more is needed from the government to return investment back to historical levels and reverse long terms production declines.

Opportunity for Andalas

We believe that the opportunity for Andalas is very encouraging. Indonesia’s increasing demand for energy is unlikely to diminish for the foreseeable future and Wood Mackenzie also notes crucially, that Indonesia is increasingly reliant of the development of smaller fields and often more challenging projects to meet demand for oil. With numerous such projects in evidence in Sumatra alone as seen on the map below, we believe that the environment for smaller operators such as Andalas to prosper is firmly in evidence.

Undeveloped oil and gas targets in southern Sumatra

Source: Andalas

Gas production sector is robust

The Indonesian gas sector by contrast has been in better shape than the oil sector and the country produces considerably more gas than it consumes. However, as the chart below depicts, gas production has declined by more than 21% since peak output in 2010 against a background of relatively stable consumption.

Gas production has benefited from increased investment, partly as a consequence of more favourable fiscal terms attributed to gas production coupled with the Indonesian’s government’s increasing priority to investment in the gas sector. However, private sector companies have been increasingly reluctant to invest in the sector for many of the same reasons that have held back investment in the oil sector in recent years.

Although gas is not the immediate focus for Andalas in terms of its acquisition of the Bunga Mas PSC, the licence does possess gas resource upside and we do not rule out the prospect of the company examining gas acquisitions as part of a longer term strategy.

Indonesian gas production vs consumption (BCF per day), 1970-2017

Source: BP Statistical Review (2018)

Gas reserves are huge

BP estimates that proven gas reserves in Indonesia were almost 103 TCF at the end of 2017, significantly more than oil on a comparable basis. This is augmented by a further 42 TCF of potential reserve upside as outlined in the map below which depicts the estimated distribution of gas reserves throughout Indonesia (2016).

The numbers for unconventional reserve potential, not depicted on this map, are enormous, with Bow Energy Ltd highlighting the potential for 574 TCF of shale resource in country and some 453 TCF of coal bed methane resources across the Indonesian archipelago.

Distribution of Indonesian conventional gas reserves (BCF)

Source: Bow Energy Ltd

Indonesian fiscal terms for oil and gas

Indonesia was an early pioneer of PSCs which represent the type of contract signed between the government of Indonesia and resource extraction companies (the contractor). As with many agreements signed between governments and foreign oil and gas companies, there is often significant variance in the detailed terms and conditions and rarely a ‘one size fits all’ type of contract. However, we have endeavoured to establish the broad variables within most PSCs in Indonesia, including the type to which Andalas will be subject. This is outlined in the illustration below.

Illustrative Production Sharing Contract terms

Source: CCOP EPF

Key components

First Tranche Petroleum (FTP ) – this represents the Indonesian government’s first claim from the sale of petroleum. This is generally a negotiable variable is similar to a royalty and is currently 10%-20% of gross field revenue in most areas of Indonesia.

Cost Recovery – After the payment of FTP, the contractor is allowed to recover its operating costs and capital expenditure (for which the contractor is wholly responsible) from the remaining revenue. There is no cost recovery ceiling in Indonesia and in many cases, the contractor can claim historical costs invested in the field prior to their ownership that remain unclaimed. Again, such levels of historical cost recovery may be subject to negotiation.

Profit sharing – The share of contractor profit after FTP and cost recovery again can vary depending on the location and type of development. However, generally the contractor’s share of profit oil is 15%-35% and can be considerably higher for gas in the region of 62.5%-71.4%.

Income tax - the current rate of income tax on profits is 44%. This is comprised of 30% corporation tax on taxable income and 20% Branch Profits Tax (BPT) in income after the application of corporation tax.

Domestic market obligation (DMO) – After the fifth year of production from, contractors must sell a proportion of their profit oil at a discounted price. The DMO price is usually 25% of the international crude price.

Gross Split PSC – an alternative fiscal model

In early 2017, Indonesia established an alternative new form of Production Sharing Contract called the Gross Split PSC which will apply to new PSCs. This was in response to reducing revenue from the oil and gas sector as a consequence of declining domestic production coupled with increasing cost recovery budgets, the benefits of which were largely accruing to the contractors in the sector. In addition to this, the government argued that the cost recovery mechanism was becoming bloated as a consequence of the inefficiencies of oil and gas companies which in some cases, operated without a pressing need to reduce operating expenditure.

The Gross Split PSC is a direct response to the pressures that have put existing PSC regime under pressure. Primarily, the new PSC system dispenses with the cost recovery mechanism and instead splits gross field revenue between the government and the contractor. The contractor must then fund its capital and operating costs from its share of revenue subject to such costs being tax deductible if commercial reserves are discovered and production generates taxable income.

In this model, the contractor still takes on the initial expenditure risk for new exploration and development as in the old PSC system but the government is not burdened with exposure to future cost recovery liabilities. By contrast with the old PSC regime, the Gross Split PSC also dispenses with First Tranche Petroleum and the Domestic Market Obligation to simplify the regime and to also balance out returns to contractors which benefit from the removal of these deductions.

Gross field revenue split under the Gross Split PSC

Contractor Government Oil 43% 57% Gas 48% 52%

Source: The Journal of World Energy, Law and Business

The numbers in practice

In the case of oil production, the Gross Split PSC regulation provides 43% of gross field revenue to the contractor from which it must fund its own capex and operating costs. The contract does allow for flexibility and the proportion accruing to the contractor can be adjusted for several variable elements including the location of the field, depth of reservoir, reservoir type (e.g. unconventional) and CO 2 and H 2S content. Other progressive components are also considered including Indonesian oil and gas prices and cumulative field production which also alters the gross field revenue split.

In practise, we expect that only a decade or more of full implementation, the smoothing out of the legislative detail and rising Indonesian production will provide concrete evidence that the new system is superior to the old. However, in broad terms, we would expect to see a reduction in short term cost recovery cash flow spikes which typically provides a boost to contractor income in the early years of new field production replaced by slightly higher cash flow generation in the mid to late years of production providing both the government and contractors with smoother and more visible income.

No impact on older PSCs

Industry reaction to the Gross Split PSC has been reportedly lukewarm although there is no suggestion that it will be applied retrospectively given the huge potential administrative cost and disruption to the government and particularly to the oil and gas sector that would ensue. This view is supported by the state oil company Pertamina which has already successfully refused to accept the new regime for various expiring PSCs until the government has demonstrated that the Gross Split fiscal terms are economic.

Indonesia – The Bunga Mas PSC

On 29 August 2018, Andalas entered into a conditional agreement to acquire an initial 25% participating interest in the onshore Bunga Mas PSC (Production Sharing Contract) in South Sumatra, Indonesia which contains the Bunga Mawar oil field in addition to a portfolio of additional structures with resource upside. The deal also gives Andalas the right to increase its interest in Bunga Mas to 49% and ultimately to 100%.

Completion of the deal is subject to several factors including an extension of the PSC’s exploration period. However, we believe that this asset is particularly attractive given the potentially large historical expenditure pool associated with the licence; the recovery of even a proportion will enhance significantly the economics of an initial development project. Prior contractors on the PSC have incurred US$111.7m of costs exploring the PSC and Andalas is confident that an appreciable proportion of this expenditure will be recoverable by the company in the event that production from Bunga Mawar commences.

Location of the Bunga Mas PSC in South Sumatra

Source: Company

Outline PSC terms

2 The Bunga Mas PSC was entered into on 7 October 2005 and currently comprises 447 km after earlier relinquishments in accordance with the terms of the PSC. The term for the PSC is 30 years and includes an initial term for exploration after which the contractor may progress to further periods for development and production. The first exploration term of 12 years expired in 2017 and the previous operator was awarded a 12 month extension to October 2018. A further extension of this term is a condition precedent on the completion of the sale and purchase agreement outlined below.

Terms of the transaction

Andalas will issue 9.6 million new shares upon completion of the acquisition of the initial participating interest of 25%. The company will issue a further 9.6 million new shares upon regulatory approval of the increase in the company’s interest to 49%.

As outlined above, completion is subject to various regulatory conditions including the extension of the exploration period of the PSC. However, Andalas has agreed to undertake new exploration and development activity within the PSC as an exclusive operator entitling the company to 100% of the cash flow under the PSC terms. Additional detail regarding the terms and conditions are outlined in Appendix 3 for reference.

Bunga Mas PSC resources

The primary asset on the Bunga Mas PSC is the Bunga Mawar field which is estimates to contain 2C gross contingent resources of 0.22 mmbbls and a further 2.09 mmbbls of best case prospective resources in the Air Benakat formation which will form the basis of a development plan for the wider field. Initial work on Bunga Mawar will focus on appraising the field in order to convert prospective resources into contingent resources.

The table below also highlights the additional resource upside on the PSC including five further oil objectives comprising over 54 mmbbls of best estimate prospective resources in addition to the Melati gas discovery which is estimated to contain over 26 BCF.

Andalas notes that the contactor is entitled to 35.7% of the profit oil on Bunga Mawar after cost recovery under the terms of the Bunga Mas PSC and 71.4% of the profit on gas production after permitted costs are recovered (including brought forward cost pool expenditures).

Bunga Mas PSC resource estimates

Oil/Gas Asset Resources (mmboe) 1C 2C 3C GCoS Oil Bunga Mawar Contingent resources 0.08 0.22 0.46 Prospective resources 0.52 2.09 6.54 44% Gas Melati Contingent resources (BCF) 22.0 26.0 32.0 30% Contingent resources (boe) 3.7 4.3 5.3 Low Best High Oil Bakung Prospective resources 0.8 10.2 33.0 23% Oil Sakura Prospective resources 1.5 8.8 30.5 20% Oil Anggrek Prospective resources 0.8 6.8 13.4 15% Oil Melati East Prospective resources 1.2 3.1 8.7 20% Oil Melati West Prospective resources 8.5 25.6 51.6 23% Total 17.0 61.2 149.4

Source: Company, Current operator

Notes on the resource estimates

The project’s economics are enhanced considerably by previous expenditures on the PSC totalling US$111.7m of which a proportion is expected to represent a recoverable cost pool attributable to the Bunga Mawar field. Like the terms of the extension to the exploration period, we understand that the level of recoverable costs will also be subject to regulatory approval.

There is appreciable resource upside in terms of several additional structures containing significant oil and gas upside on the PSC and Andalas notes that these structures possess GCoSs ranging from 15% to 30%.

These are relatively low given that the early stage nature of these accumulations reflects the likelihood of future commercial development. In the case of the Melati gas field, a comparatively low GCoS has been ascribed to a contingent resource given that analysis of the gas has determined the CO 2 content to be 67%. Although test rates from the Talang Akar Formation at Melati tested 11.8 mmcfpd, two thirds of this was CO 2 and a development plan would be dependent of future appraisal work and the ability to address the CO 2 content. Note that high CO 2 levels in gas production is a common characteristic of Indonesian gas production although we acknowledge that the content of CO2 at Melati is considerably higher than average.

Valuation focused on Bunga Mawar

Assuming that Andalas concludes successfully the acquisition of Bunga Mas, we expect that the company will focus its efforts on bringing the Bunga Mawar field into production through a multi-well drilling programme. Even in the event that less than a fifth of the previous expenditure on the field is available as a recoverable cost pool, we believe that the economics and early years’ cash flow from a development project indicate rapid payback of early stage drilling costs and solid long term cash flow to the company.

Valuation metrics

For our valuation of Bunga Mawar, we have assumed that the extension of the exploration period is successful and Andalas can embark on the workover of existing discovery well (BMW-1) and the drilling of a new appraisal well (BMW-2) to a depth of approximately 2,300 feet in order to initiate the planned and approved development of the field in 2019. We expect that this programme will cost approximately US$1.4m on a 100% basis and first oil production could be expected as early as Q4 2019.

Assuming a successful early programme, we have factored in a 17 well development drilling programme of which 14 wells are completed as successful producers. We have assumed that the average cost per well is approximately US$1.05m. On the assumption that each well commences production at an average rate of 150 bopd and declines quite aggressively at 30% per annum, we have derived a production profile for the field which converts nearly all the prospective resources into production over a ten year period.

Bunga Mawar indicative gross production profile (bopd)

Source: Optiva estimates Key variables applied

We have applied a conservative oil price of US$60.00 per barrel flat over the productive life of the field and several key fiscal terms consistent with PSC terms in South Sumatra. In particular:

• First Tranche Petroleum of 10% to gross field revenues • 100% cost recovery after the application of FTP • Contractor/government share of profit oil – 35.7%/64.3% • Domestic market obligation (DMO) of 25% on contractor share of profit oil • Corporation tax of 44%

Of particular note is that the Bunga Mas PSC has a cost recovery pool of US$111.7m ascribed to work conducted by previous operators. While we do not expect that this entire cost pool will accrue to production from Bunga Mawar, our valuation assumes US$20m of cost recovery to Bunga Mawar from the existing total assuming that the full development is expedited. Naturally, any variance in this amount will change our estimated valuation.

Indicative valuation

On our raft of assumptions, we have ascribed a valuation of US$5.0m to a 25% interest in Bunga Mawar. This increases to US$9.8m upon the assumption of a 49% interest and reaches US$20.0m in accordance with a 100% interest which Andalas would earn following the undertaking of the field development as described.

Cash flow implies rapid payback

Indonesia carries a reputation for relatively tough fiscal terms, particularly for oil production. However, there is a positive impact on NPV from the cost recovery given that it results in the acceleration of project generating free cash flow as the chart for estimated field cash flow depicts below. Characteristic with all PSC, the contractor carries the early stage risk by funding early development costs. However, upon the commencement of first production, cost recovery is rapid and initial cash flow is high with the bulk of field revenue accruing to the contractor through cost recovery. Within our estimates, we have assumed that Andalas’ total net cash exposure will be up to US$2.5m for initial development work before moving into a cash positive position when early production commences in 2020.

Cash flow estimates for Bunga Mawar (100% basis)

Source: Optiva estimates

Resource upside on Bunga Mas

We have elected to value the resource upside on Bunga Mas with a similar methodology to our treatment of Andalas’ indirect interest in Eagle Gas. To the recoverable resource estimates for the additional oil and gas accumulations on the wider Bunga Mas PSC, we have applied the ascribed GCoSs which we believe to be conservative given the scale of appraisal work required to upgrade these prospective resources to contingent classification.

To the risked resource numbers, we have again applied a commercial risk factor of 50% to account for non- technical factors including the government approval process and likely funding requirements which are not yet in place. We acknowledge that the Melati gas discovery is effectively double discounted as the operator has already applied a discount related to the commercial chance of success. However, we believe that this is acceptable given that Melati is unlikely to be a prime candidate for development for the foreseeable future.

Our unit NPV is also very conservative as we have derived this metric from the Bunga Mas field without the application of any benefit from the historic pool associated with the PSC. Consequently, any further cost recovery from the historical balance of US$111.7m will have a marked impact on our indicative NPVs.

Additionally, we only have applied only the company’s initial 25% interest in Bunga Mas. In the event that the company expedites the development of the Bunga Mar field, we understand that the 100% interest will apply to the whole PSC and our risked NPV increases to US$25.2m.

Indicative valuation of Bunga Mas PSC resources

Item Prospect Oil Oil Oil Oil Oil Gas Bakung Sakura Anggrek Melati E Melati W Melati Total Recoverable prospective resources mmboe 10.2 8.8 6.8 3.1 25.6 4.3 58.9 GCoS* % 23% 20% 15% 20% 23% 30% 22% Risked resources mmboe 2.3 1.8 1.0 0.6 5.9 1.3 12.9 NPV per boe USD 3.88 3.88 3.88 3.88 3.88 3.88 3.88 NPV US$m 9.1 6.8 4.0 2.4 22.8 5.0 50.2 Commercial risk factor % 50% 50% 50% 50% 50% 50% 50% Risked NPV US$m 4.5 3.4 2.0 1.2 11.4 2.5 25.1 Andalas interest 25% 25% 25% 25% 25% 25% 25% Risked Andalas interest US$m 1.1 0.9 0.5 0.3 2.9 0.6 6.3 USD/GBP 1.30 Risked Andalas interest £m 0.9 0.7 0.4 0.2 2.2 0.5 4.8

Source: Optiva estimates, Company *Commercial chance of success in the case of Melati gas

Appendix 1: Directors’ biographies

Robert Arnott – Non-Executive Chairman

Rob has over 30 years’ experience in the oil and gas industry, during which he has successfully executed a number of high profile transactions and sourced funding for several major development projects. Starting his career with Shell International, Rob subsequently moved into investment banking, working at both Morgan Stanley Dean Witter and Goldman Sachs, where he established an extensive network of investment contacts. Moving back into the upstream industry he has distinguished himself as an active board member with high level involvement in the growth and success of numerous public and private energy related ventures.

As a Board member of Spring Energy AS, Rob rapidly grew the Norwegian Continental Shelf focused upstream oil and gas company ahead of its eventual sale to Tullow Oil in January 2013. He was subsequently a director of Core Energy AS, an oil and gas company focused on the producing fields of the Norwegian Continental Shelf. During his career he has also held the role of Chairman at each of Petroceltic International plc, Global Petroleum Limited and Oyster Petroleum Limited and a non-executive directorship at Rocksource ASA.

Simon Gorringe – Chief Executive

Simon began his 35-year career in the petrochemical industry, moving into cryogenics and finally into the oil and gas industry in the late-1980s. He has worked for Kerr-McGee on the Gryphon field and for ConocoPhillips Ltd on its UK continental shelf developments, before moving to BHP Billiton plc. Whilst there, he developed a reputation for unlocking marginal fields by developing the Keith Field, an asset that was previously deemed to be uneconomic. In Indonesia Simon was the development manager for Serica’s Kambuna Gas Field Development and Chief Operating Officer for NuEnergy Gas Ltd. which was developing coal bed methane projects in South Sumatra. He has also held a number of senior roles including at SOCO International and Kerr- McGee. He is a graduate of Chemical Engineering from UMIST in Manchester.

Dan Jorgensen – Finance Director

Dan has 15 years of experience in the public markets and with international groups, qualifying with BDO as a chartered accountant. He has worked on many corporate transactions, including assisting on the readmission of Andalas to AIM. Since 2011, Dan has held senior finance roles with a number of AIM-listed international resource companies. He holds a BSc in Economics from Reading University.

Ross Warner – Legal and Commercial Director

Ross is a lawyer and experienced company director of both private and public resource companies listed on AIM and the ASX. He has also held senior corporate roles with Mallesons Stephen Jaques in Australia and Clifford Chance in the UK. He holds a Bachelor of Laws from University of Western Australia, and Master of Laws, University of Melbourne.

Other key management

Greg Mawhinney – Non-Board VP of Operations

Greg has over 40 years’ of international petroleum industry experience in senior operations positions: roles In Indonesia and internationally including President and General Manager, Yemen where he managed production of over 200,000bopd. He holds a BSc (Hons) from the University of Newfoundland and an MSc (Chemical Engineering) from the University of New Brunswick.

Appendix 2: Badger natural gas liquids

Badger prospective natural gas liquids resource estimates (mmbbls)

Recoverable liquids Gross unrisked prospective resources 100% P90 P50 P10 Mean GCOS Westphalian A Compartment A 0.1 0.3 0.4 0.4 34% Compartment B 0.1 0.3 0.4 0.4 34% Compartment C 0.1 0.3 0.5 0.5 26% Westphalian B Murdoch sandstone 0.1 0.3 0.7 0.4 28% Namurian Trent sandstone 0.3 0.8 1.9 1.0 30% Lower Ketch Ketch 0.4 1.0 2.2 1.2 22% Total 3.9 Recoverable liquids Net to Eagle (Holywell Resources) 66.67% P90 P50 P10 Mean GCOS Westphalian A Compartment A 0.1 0.2 0.3 0.3 34% Compartment B 0.1 0.2 0.3 0.3 34% Compartment C 0.1 0.2 0.3 0.3 26% Westphalian B Murdoch sandstone 0.1 0.2 0.5 0.3 28% Namurian Trent sandstone 0.2 0.5 1.3 0.7 30% Lower Ketch Ketch 0.3 0.7 1.5 0.8 22% Total 2.6 Net to Andalas (indirect) Recoverable liquids Net unrisked prospective resources 25.00% P90 P50 P10 Mean GCOS Westphalian A Compartment A 0.0 0.1 0.1 0.1 34% Compartment B 0.0 0.1 0.1 0.1 34% Compartment C 0.0 0.1 0.1 0.1 26% Westphalian B Murdoch sandstone 0.0 0.1 0.1 0.1 28% Namurian Trent sandstone 0.1 0.1 0.3 0.2 30% Lower Ketch Ketch 0.1 0.2 0.4 0.2 22% Total 0.7

Source: Eagle Gas Limited

Appendix 3 – Details of the Bunga Mas transaction

Under the terms of the deal, Andalas has agreed to acquire 100% of Aura Violet International (AVI) from Tilegarre Corporation. AVI is the parent company of PT Bunga Mas Energi (BME) which has a 25% interest in the PSC. The other interests in the PSC are held by Bunga Mas International Company (BMIC: 51%) and Dorato Fiore Pacifico (DFP: 24%). BMIC is currently the operator of the PSC and each of AVI, BMIC and DFP are subsidiaries of Arctic Bay Ventures Inc. (ABV).

Andalas has agreed to issue 19.2 million new shares in two equal tranches to secure a 49% interest in the Bunga Mas PSC. The first tranche of 9.6 million shares will be allotted on receipt of the approval of SKK Migas and the Government of Indonesia with regards to the transfer by Dorato Fiore Pacifico (DFP) for its participating 24% interest to PT Bunga Mas Energi (BME).

The sale and purchase agreement which has a longstop date of 31 December 2018 is conditional upon:

1. DFP agreeing to assign its 24% interest to BME for US$1.00 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 acceptable to Andalas. 3. Various parties including the Arctic Bay Group entering into a further Framework Agreement to regulate the activities of BMIC, DFP and BME under the joint operating agreement (JOA). 4. Other procedural matters necessary to complete the transaction

The company notes that BMIC will initially continue to be the operator of the PSC although Andalas has the right to require BMIC to withdraw from the PSC and transfer its participating interest to BME (already acquired by Andalas) for US$1.00. At this stage, BME would seek to be the new operator.

If BME has not commenced its exclusive operations within seven months after Completion of the agreement, Arctic Bay may sell BMIC to a third party and permit it to undertake exclusive operations on the PSC.

Prior to Andalas executing the sale and purchase agreement, each of BMIC, DFP and BME granted a royalty in favour of Arctic where each company agrees 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 Bay 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 Bay 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 US$1.00 each and an option to put AVI back to Arctic for US$1.00

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