Baron Oil Regulatory News (BOIL)

Market Abuse Regulation (MAR) Disclosure

Certain information contained in this announcement would have been deemed inside information for the purposes of Article 7 of Regulation (EU) No 596/2014 until the release of this announcement.

 29 April 2020

 Baron Oil Plc

("Baron Oil" or "the Company")

 Final Results for the Year Ended 31 December 2019

Baron Oil Plc (AIM:BOIL), the AIM-quoted oil and gas exploration and production company focused on opportunities in SE Asia, Latin America and the UK, is pleased to announce its audited financial results for the year ended 31 December 2019.

Operations

Chuditch PSC: The award in November of the TL-SO-19-16 Production Sharing Contract ("Chuditch PSC"), offshore Democratic Republic of Timor-Leste, marks a major step forward for the Company. Shell's internal analyses following the drilling of the Chuditch-1 discovery in 1999, indicate a Mean Gas Initially in Place (GIIP) for the surrounding group of prospects in the Chuditch PSC of 2,320 BCF, considered by Baron to be low-risk GIIP Pmean Prospective Resources (but not SPE PRMS compliant). Baron has an indirect interest of 25% in the Chuditch PSC, held through its shareholding in SundaGas (Timor-Leste Sahul) Pte. Ltd.

Block XXI: The Company continues to pursue efforts to drill the El Barco-3X well in Peru, including introducing a partner. However, plans for drilling are currently halted by COVID-19 issues, with strict movement restrictions including the inability to visit the site. Baron has a 100% interest.

Inner Moray Firth (UK): Initial subsurface work on Licence P2478, which contains the large Dunrobin and smaller Golspie prospects, is under review and further seismic reprocessing is planned. Licences P2470 and P2235 have been relinquished. Baron has a 15% interest in the Inner Moray Firth.

Dorset (UK): The latest analysis of the Colter South Prospect (on Licence P1918), in which oil was found during 2019, indicates that a further appraisal well is required to define the resources before development can be planned. The current oil price collapse and short remaining duration of the Licence mean efforts to bring in a new drilling partner are now unlikely to succeed. Hence, under IFRS6, the entire carrying amount for Colter has been impaired. The status of PEDL330 and PEDL345 onshore Licences, lying to the south of Wytch Farm oilfield, continue to be reviewed in light of the current business environment. Baron has an 8% interest in the Dorset Licences.

Financials

· Net result for the year was a loss before taxation of £1,674,000 (2018: loss of £3,280,000)

· Loss after taxation attributable to shareholders was £1,674,000 (2018: loss of £2,495,000)

· Exploration and evaluation expenditure of £1,207,000 (2018: £1,592,000)

· IFRS6 intangible asset impairment charge of £1,047,000, mainly relating to P1918 Colter (2018: IFRS6 charge of £1,360,000 relating to Block XXI, Peru)

· Administration expenditure for the year was £442,000 (2018: £549,000), a 20% reduction

· The end of year free cash balance was £347,000 (2018: £1,709,000). Excluding the proceeds of a share placing in June 2019 amounting to £440,000 gross (£408,000 net), the overall cash outflow during the year amounted to £1,770,000.

· In Q1 2020, the Company undertook a further capital raise of £2.5m gross (£2.3m net) at 0.1p per share.

The Company intends to hold its AGM in June 2020 and the Notice of Annual General Meeting to that effect will be sent to Shareholders in due course.

Competent Person's Statement

Pursuant to the requirements of the AIM Rules for Companies, the technical information and resource reporting contained in this announcement has been reviewed by Dr Malcolm Butler BSc, PhD, FGS, Executive Chairman of the Company. Dr Butler has more than 45 years' experience as a petroleum geologist. He has compiled, read and approved the technical disclosure in this regulatory announcement. The technical disclosures in this announcement comply with the Society of Petroleum Engineers' standard, except as stated.

Commenting on the results, Malcolm Butler, Executive Chairman, said:

 "The final award of the Chuditch PSC was a great result for your Company and marks a step-change in Baron's asset base. However, our industry is currently faced with the dual global impact of significantly lower oil prices and the rapid spread of the COVID-19 virus. While Baron is not insulated from the oil price shock, it should be noted that the Company's assets are all in the pre-cashflow exploration phase and, following the award of the Chuditch PSC, are now heavily weighted towards gas where regional markets play a much greater role in pricing.

In Timor-Leste, there is no obligation to drill before 2022 and any commercial production is unlikely to be achieved before 2025. There are no plans to fund drilling in the UK for the foreseeable future. In both cases, work on these projects over the next 12 months is desk and computer-based and should not be affected by current movement restrictions, although gaining access to the necessary data is being delayed.

As regards the El Barco-3X well in Peru, it is unclear how much local oil companies' appetite for drilling will be affected by oil price movements and although it is unlikely that local gas prices in this part of Peru will be affected by the drop in oil prices, it is impossible to predict the effects on short term gas demand of a COVID-19 related recession.

Critically for shareholders, following our £2.5m (gross) fund raise in Q1 2020, our proposed work programme for 2020 and into 2021 is funded."

For further information, please contact:

CHAIRMAN'S STATEMENT & OPERATIONS REPORT

Financial and Financial Results

The net result for the year was a loss before taxation of £1,674,000, which compares to a loss of £3,280,000 for the preceding financial year; the loss after taxation attributable to Baron Oil shareholders was £1,674,000, compared to a loss of £2,495,000 in the preceding year.

Turnover for the year was £nil (2018: £nil), there being no sales activity during the period.

Exploration and evaluation expenditure written off included in the Income Statement amounts to £160,000. This arises from expenditure of £133,000 in Peru on Block XXI, £42,000 in costs regarding the South East Asia Joint Study Agreement with SundaGas prior to the award of the TL-SO-19-16 Production Sharing Contract in November 2019, minor pre-licence expenditures of £9,000 relating to the UK Offshore 31st Licensing Round and technical consultancy, less £24,000 recovered in respect of 2018 exploration activities in Licence P2235 (Wick).

On the Colter prospect (licence P1918), wells 98/11a-6 and its sidetrack 98/11a-6z were drilled in February and March 2019 at a total cost to Baron of £996,000. £376,000 had been invoiced during 2018 in respect of preparations for the drilling of the well and had previously been treated as a prepayment. Including other licence costs, total expenditure in the year was £1,042,000, which was capitalised to give a total intangible asset value of £1,108,000. The initial evaluation of the well results indicated that the Colter South Prospect had the potential to contain commercial quantities of oil and the licence was therefore continued into its second term in February 2020. However, re-evaluation of the geophysical information, the failure of attempts to bring in an additional partner, and, most recently, the precipitous drop in oil prices in March 2020 has led to a further reassessment of the economic case, increasing the likelihood that the licence will be relinquished before expiry of the Second Term of the licence on 31 January 2021. IFRS6 (the relevant accounting standard) states that an asset should be impaired if there is a prospect of a licence coming to an end in the near future, which for the purposes of this Annual Report would be the next 12 months. On this basis, the decision has now been taken to impair the entire carrying amount for Colter of £1,108,000.There was a small reduction in the provision relating to Peru Block XXI of £61,000 due to exchange rate fluctuations, leading to a total net cost of impairment amounting to £1,047,000.

In Colombia, the liquidation of Inversiones Petroleras de Colombia SAS ("Invepetrol"), in which the Company held a 50% interest, was completed on 2 October 2019, with no further liability to the Company.

Administration expenditure for the year was £442,000, compared to £549,000 in the preceding year, excluding the effects of exchange rate movements. Directors and employee costs amounted to £258,000, listing compliance and other professional fees £133,000 and other overheads £51,000. During the year, the directors agreed to a temporary reduction in their contracted salaries which resulted in cost savings of £89,000.

We saw a modest strengthening of the Pound Sterling against the US Dollar and, with the majority of the group's assets being denominated in US dollars, this has given rise to a loss of £41,000. This compares with a gain of £130,000 in the preceding year, when the Pound Sterling showed relative weakness against the US Dollar.

At the end of the financial year, free cash reserves of the Group had decreased to £347,000 from a level at the preceding year end of £1,709,000. Excluding the proceeds of a share placing in June 2019 amounting to £440,000 gross (£408,000 net of costs), the overall cash outflow amounted to £1,770,000, consisting of £1,207,000 in respect of exploration and evaluation activity and £563,000 operating cash outflow. In Q1 2020, the Company undertook a further capital raise with a new ordinary share Placing of £2,500,000 gross (£2,306,000 net).

The Group continues to pursue a conservative view of its asset impairment policy, giving it a Balance Sheet that consists largely of net current assets and what it considers to be a realistic value for its exploration assets. Given limited cash resources, the Board will take a prudent approach in entering into new capital expenditures beyond those expected to be committed to existing ventures.

Report On Operations

Introduction

The directors are pleased to report the success of SundaGas Pte.Ltd. in gaining the award of the TL-SO-19-16 Production Sharing Contract in Timor-Leste. As shareholders will be aware, this follows an application made in early 2016, during the period of the Joint Study Agreement between Baron and SundaGas. Baron now holds a 33.33% interest in SundaGas (Timor-Leste Sahul) Pte.Ltd, whichgives it an indirect interest of 25% in a substantial gas discovery. The Company continues to pursue efforts to drill the El Barco-3X well on Block XXI in Peru in 2020. As announced during the year, Baron participated in the drilling of two vertical wells and a sidetrack in offshore UK waters. Although oil was encountered in Triassic Sherwood Sandstones on the Colter South Prospect by well 98/11a-06, the results of subsequent analysis indicate that a further appraisal well must be drilled before Colter South can be moved towards development. Efforts to bring in a new partner to participate in the necessary additional work have been unsuccessful so far and the recent precipitous drop in oil prices makes it unlikely that such work can be carried out before the expiry of the current licence term in January 2021.

It is difficult to predict what effect the COVID-19 pandemic will have on operations planned for 2020 but it is already clear that drilling activities will suffer significant delays, which will impact plans for Peru Block XXI. In addition, it is impossible to predict the effects on short term gas demand in Peru and longer term gas demand in Southeast Asia of a potential global recession.

Southeast Asia: Timor-Leste Tl-S0-19-16 Psc (Baron 25%, Effective)

The award in November 2019 to a subsidiary of SundaGas Pte.Ltd. of the TL-SO-19-16 Production Sharing Contract (the "Chuditch PSC"), offshore Democratic Republic of Timor-Leste, marks a major step forward for the Company. Baron supported the original application for a PSC in this area made by the SundaGas group in October 2016, which gave it the right to an interest in the subsequent award. A Shareholders' Agreement ("SHA") has been executed with SundaGas Resources Pte. Ltd ("SundaGas") governing the operation of SundaGas (Timor-Leste Sahul) Pte.Ltd ("SundaGas TLS"), in which Baron now has a 33.33% shareholding and SundaGas retains 66.67%. The sole asset of SundaGas TLS is its 100% shareholding in SundaGas Banda Unipessoal Lda., Operator of the Chuditch PSC, in which it holds a 75% interest.

The SHA contains provisions typical of an agreement of this nature including, but not limited to, mutual undertakings, the right to appoint one of the three directors of SundaGas TLS and certain shareholder rights protections.

Under the terms of the Carry Agreement, executed between SundaGas and Baron on 27th January 2020, and the SHA, US$521,149 was paid to SundaGas on 21st April 2020 to reimburse Baron's 33.33% share of costs incurred since the Chuditch PSC was signed on 8 November 2019. This amount includes Baron's 33.33% share of the $1,000,000 Bank Guarantee and the subscription for 3,333 shares in SundaGas TLS, representing 33.33% of the issued share capital of that company. Baron now plans to maintain its interest by continuing to pay 33.33% of the costs incurred on the Chuditch PSC through additional investment into SundaGas TLS. The Company's 33.33% interest in SundaGas TLS equates to an indirect 25% interest in the Chuditch PSC after accounting for the 25% carried interest of the Timor-Leste state company. Information has been derived from publicly released reports on the area, prepared by Shell Development (Australia) Pty. Ltd. ("Shell") in 1998 and 2001 after the drilling of the discovery well Chuditch-1. These indicate that the well, drilled in 64 metres water depth in a total of 25 days for US$8 million, encountered a 25m gas column in Jurassic Plover Formation reservoir sandstones on the flank of a large faulted structure. The reports include estimated ranges of gas in place and recovery factors derived from Shell's internal analyses and, whilst not compliant with the 2018 SPE PRMS Prospective Resources standard, are considered to be a valid indication of the potential for the Chuditch gas accumulation.

The key Shell estimates for the combined Chuditch, Chuditch North and Chuditch South closures ("Greater Chuditch") tested by Chuditch-1 within the area of the PSC are:

1. Estimated Mean Gas in Place (GIIP) of 2,320 BCF, considered by Baron to be Pmean Prospective Resources;

2. Gas recovery factors in the range of 55% to 75%, leading Baron to estimate Mean Recoverable Gas of 1,276 to 1,740 BCF, considered by Baron to be recoverable Pmean Prospective Resources;

3. Risks associated with trap, reservoir and charge for the Greater Chuditch closure considered to be zero (that is, the Geological Chance of Success is 100%), with remaining uncertainty around in place and recoverable volumes.

Further information is available on the Company's website (www.baronoilplc.com) and a glossary of terms is included at the end of the report.

SundaGas has put in place the $1 million Performance Guarantee Bond and is moving forward with the initial agreed work programme commitment to reprocess existing 2D and 3D seismic data over the PSC area. Subject to satisfactory results from the reprocessing, the subsequent commitment is for a well to be drilled in the third year of the Initial Term of the Chuditch PSC.

Peru Onshore Block XXI (Baron Oil 100%)

The Company continues to strive to drill on Block XXI, in the Sechura Basin of northern Peru. An experienced local operator with onshore drilling capacity is available and together we are looking at funding options which, subject to local community approval, should see the El Barco-3X well drilled in 2020. However, plans for drilling are currently halted by COVID-19 issues, with strict movement restrictions and the inability to visit the site. It is unclear how much our proposed partner's appetite for drilling will be affected by this and by oil price movements. Gas production in this part of Peru is sold at a price determined by local industries. Although it is unlikely that local gas prices will be greatly affected by the drop in oil prices, it is impossible to predict the effects on short term gas demand in Peru of a potential global recession.

Gold Oil Peru SAC ("GOP"), Baron's Peruvian subsidiary, currently operates Block XXI with 100% interest but it is likely that the interest will reduce to between 50% and 70% on farming out to bring in a new partner.

The well is planned to be drilled to a total depth of 1,850 metres to test a prospect for which Baron estimates unrisked recoverable SPE-PRMS-compliant Prospective Resources (2U-P50) of 14 BCF of gas from the shallower Mancora Sand target, with a 55% Chance of Geological Success, and 8.5 MMBBLS, with associated gas and a 27% Chance of Geological Success, from the higher-risk fractured Amotape Basement. This Basement structure may be larger than presently mapped because it extends beyond the edge of existing 2D seismic data.

The current estimated cost of site preparation and drilling of El Barco-3X is US$1.2 million. The proposed location is approximately 19 kilometres east of the Pan-American Highway and only 1.5 kilometres from the Oleoducto Nor Peruano, the oil pipeline that crosses the Andes from the Amazon Basin and runs to the coast at Bayovar.

The Block is in the fifth and last exploration phase with approximately 6 months left in which to drill once Force Majeure is lifted, which will occur when access details are agreed with the local community. Once the well is drilled, the Company has an agreement in principle with PeruPetro that Baron will have the option of a three-year extension. Under the terms of the current period, GOP is entitled to the return of its US$160,000 government performance bond if the well is drilled.

United Kingdom Offshore Licences P2470 And P2478 (Baron 15%)

Baron Oil and its partners were formally awarded these two new licences in the Inner Moray Firth area of the North Sea by the UK Oil & Gas Authority in September 2019, following the UK 31st Offshore Licensing Round. These Innovate Licences are held by Corallian Energy Limited ("Corallian") (Operator, with 45%), Upland Resources (UK Onshore) Limited (40%) and Baron (15%).

Licence P2478, over blocks 12/27c, 17/5, 18/1 and 18/2, contains the Dunrobin prospect which consists of three large shallow Jurassic rotated fault blocks that are mapped mostly on 3D seismic data within a single culmination with Direct Hydrocarbon Indicators. The lowest closing contour covers 40 square kilometres and Corallian estimates the prospect to have Pmean Prospective Resources of 172 mmboe, with upside potential of c. 400 mmboe (P10). These resource estimates are non-SPE-PRMS compliant recoverable Prospective Resources for the Jurassic sands primary target. . Additional Pmean Prospective Resources of 23.5 mmboe are estimated by Corallian for the smaller Golspie Prospect also contained within the licence. Both prospects are already defined by existing 3D seismic and reprocessing of these data, together with supporting 2D seismic, is underway.

Licence P2470 includes blocks 11/23, 11/24c and 11/25b, surrounding the Wick Prospect, on which Baron Oil participated in the dry Wick Well (11/24b-4) at the beginning of 2019. These blocks were applied for before the results of 11/24b-4 were known and, although they contain the small Knockinnon oil discovery and several small prospects, they have been downgraded by the Wick well result. The modest work commitment on this licence consists of a small volume of 3D seismic reprocessing, which has now been completed. The results of such work were not encouraging and the Licence was relinquished with effect from 31st March 2020.

Former Licence P2235, on which the unsuccessful Wick Well was drilled, was relinquished at the end of Q3 2019.

United Kingdom Offshore Licence P1918 (Colter) (Baron 8%)

The Colter area lies in UKCS Licence P1918 in Poole Bay, immediately southeast of the Wytch Farm oilfield, which has been developed from onshore facilities. The Colter well (98/11a-06) and its sidetrack (98/11a-06z) were drilled in February and March 2019 and indicated the presence of an oil accumulation with commercial potential in the Colter South Prospect within P1918. Efforts since then have been concentrated on Colter South, where a review of the seismic data and mapping was undertaken in an attempt to improve the subsurface imaging of this complex area. Although the Operator, Corallian Energy Limited, estimated nonSPE-PRMS compliant Pmean recoverable Prospective Resources of 16 mmboe in the Colter South Prospect (1.2 mmboe net to Baron), it has become clear that an additional vertical appraisal well is necessary before any plans can be made for development.

The P1918 group has elected to proceed into the Second Term of the Licence, expiring on 31 January 2021, and has simultaneously reduced the Licence area to incorporate only that acreage surrounding the Colter and Colter South Prospects. The Joint Venture participants have been seeking an additional partner to help fund the drilling of the required vertical well and thereafter to move it forward into development. However, given the short time frame to expiry of the licence and the current oil price situation it is considered unlikely that this can take place before the Second Term expires. On this basis, the directors have elected to impair costs previously capitalised in respect of 98/11a-06 and 98/11a-06z.

United Kingdom Onshore Licences PEDL330 & PEDL345 (Baron 8%)

PEDL330 and PEDL345 are onshore Licences, lying to the south of Wytch Farm oilfield. PEDL345 includes a major part of the Purbeck Prospect, which is being evaluated. However, the combination of the current low oil price and the environmental issues associated with drilling in this coastal area of Dorset has led the directors to conclude that it will be difficult for drilling to take place before these licences expire in July 2021.

Conclusions

Baron is currently faced with the dual global impact of significantly lower oil prices and the rapid spread of the COVID-19 virus. While we are not insulated from the oil price shock, it should be noted that the Company's assets are all in the pre-cashflow exploration phase and, following the award of the Chuditch PSC, are now heavily weighted towards gas where regional markets play a much greater role in pricing.

There is no obligation to drill before 2022 in Timor-Leste and there are no plans to fund drilling in the UK in the foreseeable future. In both cases, planned work for at least the next 12 months is desk and computer-based and should not be affected by current movement restrictions, although gaining access to the necessary data is being delayed. As regards the El Barco-3X well in Peru, plans for drilling are currently halted by strict movement restrictions and the inability to visit the site. It is unclear how much our proposed partner's appetite for drilling will be affected by oil price movements. Although it is unlikely that local gas prices in this part of Peru will be affected by the drop in oil prices, it is impossible to predict the effects on short term gas demand in Peru. Moreover, the impact on longer term gas demand and the currently depressed regional gas prices in Southeast Asia from a steep economic recession brought on by the COVID-19 pandemic remains to be seen.

Following our £2.5m (gross) fund raise in February 2020, our proposed work programme for 2020 and into 2021 is funded. The majority of the funds are planned to be used to pay Baron's share of the ongoing TL-SO-19-16 PSC ("Chuditch PSC") work programme and the drilling of the onshore El Barco-3X well in Peru.

Once the global economic outlook becomes clearer, we look forward to progressing the drilling of El Barco-3X and moving forward with the Timor-Leste project, which has the potential to make a step-change in the value of your Company.

This has been a stressful period that has required intense effort by our small team and I would like to record my particular thanks to Andy Yeo for the long hours he has put in to maintain and strengthen the Company's financial capability.

NOTES TO THE FINANCIAL STATEMENTS

General Information

Baron Oil Plc is a company incorporated in England and Wales and quoted on the AIM market of the London Stock Exchange. The address of the registered office is disclosed in the financial statements. The principal activity of the Group is described in the Strategic Report.

(1) Significant accounting policies

The principal accounting policies applied in the preparation of these consolidated financial statements are set out below. These policies have been consistently applied to all the periods presented, unless otherwise stated.

Going concern basis

The directors have prepared a cash flow forecast covering a period extending beyond 12 months from the date of these financial statements which contains certain assumptions about the development and strategy of the business. The directors are aware of the risks and uncertainties facing the business but the assumptions used are the directors' best estimate of its future development.

After considering the forecasts and the risks, the directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. For these reasons, they continue to adopt the going concern basis of accounting in preparing the annual financial statements.

The financial statements do not include any adjustments that would result if the Group was unable to continue as a going concern.

Basis of preparation

The financial statements have been prepared in accordance with International Financial Reporting Standards (IFRSs) and IFRIC interpretations issued by the International Accounting Standards Board (IASB) as adopted by the European Union and with those parts of the Companies Act 2006 applicable to companies reporting under IFRS. The financial statements have been prepared under the historical cost convention. The principal accounting policies adopted are set out below.

Changes in accounting policies and disclosures

New and amended standards adopted by the Group

IFRS 16 'Leases' became effective for the Group from 1 January 2019. The core principle of IFRS 16 is to provide a single lessee accounting model, requiring lessees to recognise a right-of-use asset and lease liability for all leases unless the term is less than 12 months, or the underlying asset has a low value.

As a result of applying IFRS 16, the Group is not impacted by IFRS 16, as no operating leases exists within the Group.

New and amended standards not yet adopted

A number of new and amended accounting standards and interpretations have been published that are not mandatory for the Group's accounts ended 31 December 2019, nor have they been early adopted. These standards and interpretations are not expected to have a material impact on the Group's consolidated Financial Statements:

• Amendments to References to Conceptual Framework in IFRS Standards (effective from 1 January 2020);

• Amendments to IFRS 3 'Definition of a Business' (effective from 1 January 2020);

• Amendments to IFRS 10 and IAS 28 - Sale or Contribution of Assets between an Investor and its Associate or Joint Venture (effective date not yet confirmed); and

• IFRS 17 'Insurance Contracts' (effective from 1 January 2022).

Basis of consolidation

The consolidated financial statements include the financial statements of the Company and its subsidiaries and associated undertakings.

Subsidiaries

Subsidiaries are all entities over which Baron Oil Plc has the power to govern the financial and operating policies generally accompanying a shareholding of more than one half of the voting rights, or where Baron Oil Plc exercises effective operational control. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether the Group controls another entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Company. They are de-consolidated from the date that control ceases.

The purchase method of accounting is used to account for the acquisition of subsidiaries by the Group. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange, plus costs directly attributable to the acquisition. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date, irrespective of the extent of any minority interest. The excess of the cost of acquisition over the fair value of the Group's share of the identifiable net assets acquired is recorded as goodwill. If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognised directly in the income statement.

Inter-company transactions, balances and unrealised gains on transactions between Group companies are eliminated. Unrealised losses are also eliminated but considered an impairment indicator of the asset transferred. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the Group.

Joint ventures

Where the Group is engaged in oil and gas exploration and appraisal through unincorporated joint ventures, the Group accounts for its share of the results and net assets of these joint ventures as jointly controlled assets. The Group's interests in jointly controlled entities are accounted for by proportionate consolidation. The Group combines its share of the joint ventures' individual income and expenses, assets and liabilities and cash flows on a line-by-line basis with similar items in the Group's financial statements. The Group recognises the portion of gains or losses on the sale of assets by the group to the joint venture that is attributable to the other venturers. The Group does not recognise its share of profits or losses from the joint venture that result from the Group's purchase of assets from the joint venture until it re-sells the assets to an independent party. However, a loss on the transaction is recognised immediately if the loss provides evidence of a reduction in the net realisable value of current assets, or an impairment loss. In addition, where the Group acts as operator of the joint venture, the gross liabilities and receivables (including amounts due to or from non-operating partners) of the joint venture are included in the Consolidated Statement of Financial Position.

Goodwill

Goodwill represents the excess of the cost of an acquisition over the fair value of the Group's share of the net identifiable assets of the acquired subsidiary or associate at the date of acquisition. Goodwill on acquisitions of subsidiaries is included in 'intangible assets'. Separately recognised goodwill is tested annually for impairment and carried at cost less accumulated impairment losses. Impairment losses on goodwill are not reversed. Gains and losses on the disposal of an entity include the carrying amount of goodwill relating to the entity sold.

Goodwill is allocated to cash-generating units for the purpose of impairment testing. The allocation is made to those cash-generating units or groups of cash-generating units that are expected to benefit from the business combination in which the goodwill arose. The Group allocates goodwill to each business segment in each country in which it operates.

Impairment of non-financial assets

Assets that have an indefinite useful life, for example goodwill, are not subject to amortisation and are tested annually for impairment.

At each statement of financial position date, the Group reviews the carrying amounts of its tangible and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where the asset does not generate cash flows that are independent from other assets, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs. An intangible asset with an indefinite useful life is tested for impairment annually and whenever there is an indication that the asset may be impaired.

Recoverable amount is the higher of fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted.

If the recoverable amount of an asset (or cash-generating unit) is estimated to be less than its carrying amount, the carrying amount of the asset (cash-generating unit) is reduced to its recoverable amount. An impairment loss is recognised as an expense immediately, unless the relevant asset is carried at a re-valued amount, in which case the impairment loss is treated as a revaluation decrease.

Where an impairment loss subsequently reverses, the carrying amount of the asset (cash-generating unit) is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset (cash-generating unit) in prior periods. A reversal of an impairment loss is recognised as income immediately, unless the relevant asset is carried at a revalued amount, in which case the reversal of the impairment loss is treated as a revaluation increase.

Intangible Assets

Oil and gas assets: exploration and evaluation

The Group has continued to apply the 'successful efforts' method of accounting for Exploration and Evaluation ("E&E") costs, having regard to the requirements of IFRS 6 'Exploration for the Evaluation of Mineral Resources'.

The successful efforts method means that only the costs which relate directly to the discovery and development of specific oil and gas reserves are capitalised. Such costs may include costs of licence acquisition, technical services and studies, seismic acquisition; exploration drilling and testing but do not include costs incurred prior to having obtained the legal rights to explore the area. Under successful efforts accounting, exploration expenditure which is general in nature is charged directly to the income statement and that which relates to unsuccessful drilling operations, though initially capitalised pending determination, is subsequently written off. Only costs which relate directly to the discovery and development of specific commercial oil and gas reserves will remain capitalised and to be depreciated over the lives of these reserves. The success or failure of each exploration effort will be judged on a well-by-well basis as each potentially hydrocarbon-bearing structure is identified and tested. Exploration and evaluation costs are capitalised within intangible assets. Capital expenditure on producing assets is accounted for in accordance with SORP 'Accounting for Oil and Gas Exploration'. Costs incurred prior to obtaining legal rights to explore are expensed immediately to the income statement.

All lease and licence acquisition costs, geological and geophysical costs and other direct costs of exploration, evaluation and development are capitalised as intangible or property, plant and equipment according to their nature. Intangible assets comprise costs relating to the exploration and evaluation of properties which the directors consider to be unevaluated until reserves are appraised as commercial, at which time they are transferred to tangible assets as 'Developed oil and gas assets' following an impairment review and depreciated accordingly. Where properties are appraised to have no commercial value, the associated costs are treated as an impairment loss in the period in which the determination is made.

Costs are amortised on a field by field unit of production method based on commercial proven and probable reserves, or to the expiry of the licence, whichever is earlier.

The calculation of the 'unit of production' amortisation takes account of the estimated future development costs and is based on the current period and un-escalated price levels. Changes in reserves and cost estimates are recognised prospectively.

E&E costs are not amortised prior to the conclusion of appraisal activities.

Property, plant and equipment

Oil and gas assets: development and production

Development and production ("D&P") assets are accumulated on a well by well basis and represent the cost of developing the commercial reserves discovered and bringing them into production, together with the E&E expenditures incurred in finding commercial reserves transferred from intangible E&E assets as outlined above. The carrying values of producing assets are depreciated on a well by well basis using the unit of production method based on entitlement to provide by reference to the ratio of production in the period to the related commercial reserves of the well, taking into account any estimated future development expenditures necessary to bring additional non producing reserves into production.

An impairment test is performed for D&P assets whenever events and circumstances arise that indicate that the carrying value of development or production phase assets may exceed its recoverable amount. The aggregate carrying value is compared against the expected recoverable amount of each well, generally by reference to the present value of the future net cash flows expected to be derived from production of commercial reserves.

The cost of the workovers and extended production testing is capitalised within property, plant and equipment as a D&P asset.

Decommissioning

Site restoration provisions are made in respect of the estimated future costs of closure and restoration, and for environmental rehabilitation costs (which include the dismantling and demolition of infrastructure, removal of residual materials and remediation of disturbed areas) in the accounting period when the related environmental disturbance occurs. The provision is discounted where material and the unwinding of the discount is included in finance costs. Over time, the discounted provision is increased for the change in present value based on the discount rates that reflect current market assessments and the risks specific to the liability. At the time of establishing the provision, a corresponding asset is capitalised where it gives rise to a future benefit and depreciated over future production from the field to which it relates. The provision is reviewed on an annual basis for changes in cost estimates, discount rates or life of operations. Any change in restoration costs or assumptions will be recognised as additions or charges to the corresponding asset and provision when they occur. For permanently closed sites, changes to estimated costs are recognised immediately in the income statement.

Non oil and gas assets

Non oil and gas assets are stated at cost of acquisition less accumulated depreciation and impairment losses. Depreciation is provided on a straight-line basis at rates calculated to write off the cost less the estimated residual value of each asset over its expected useful economic life. The residual value is the estimated amount that would currently be obtained from disposal of the asset if the asset were already of the age and in the condition expected at the end of its useful life.

Buildings, plant and equipment unrelated to production are depreciated using the straight-line method based on estimated useful lives.

The annual rate of depreciation for each class of depreciable asset is:

Equipment and machinery 4-10 years

The carrying value of tangible fixed assets is assessed annually and any impairment is charged to the income statement.

Investments

Investments are stated at cost less provision for any impairment in value.

Trade and other receivables

Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment. A provision for impairment is established when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of the receivables. Significant financial difficulties of the debtor, probability that the debtor will enter bankruptcy or financial reorganisation, and default or delinquency in payments are considered indicators that the trade receivable is impaired.

Cash and cash equivalents

Cash and cash equivalents include cash in hand, deposits held on call with banks, other short-term highly liquid investments with original maturities of three months or less, and bank overdrafts. Bank overdrafts are shown within borrowings in current liabilities on the statement of financial position.

Inventories

Inventories, including materials, equipment and inventories of gas and oil held for sale in the ordinary course of business, are stated at weighted average historical cost, less provision for deterioration and obsolescence or, if lower, net realisable value.

Revenue

Oil and gas sales revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for the Group's share of oil and gas supplied in the period. Revenue is shown net of value-added tax, returns, rebates and discounts and after eliminating sales within the Group. Revenue is recognised when the oil and gas produced is despatched and received by the customers.

Taxation

Income tax

Income tax expense represents the sum of the tax currently payable and deferred tax.

The tax currently payable is based on taxable profit or loss for the year. Taxable profit or loss differs from profit or loss as reported in the same income statement because it excludes items of income or expense that are taxable or deductible in other periods and it further excludes items that are never taxable or deductible. The Company's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the statement of financial position date.

Deferred tax

Deferred tax is recognised on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the statement of financial position liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit.

The carrying amount of deferred tax is reviewed at each statement of financial position date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset realised. Deferred tax is charged or credited to income statement, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity.

Deferred tax assets and liabilities are offset when there is a legally enforceable right to set off current tax assets against current tax liabilities and when they relate to income taxes levied by the same taxation authority and the Company intends to settle its current tax assets and liabilities on a net basis.

Trade payables are not interest bearing and are stated at their nominal value. Trade and other payables are initially recognised at fair value. They are subsequently measured at amortised cost using the effective interest method unless the effect of discounting would be immaterial, in which case they are stated at cost.

Fair values

The carrying amounts of the financial assets and liabilities such as cash and cash equivalents, receivables and payables of the Group at the statement of financial position date approximated their fair values, due to relatively short term nature of these financial instruments.

Share-based compensation

Share based payments (Note 19)

The fair value of share-based payments recognised in the income statement is measured by use of the Black Scholes model, which takes into account conditions attached to the vesting and exercise of the equity instruments. The expected life used in the model is adjusted based on management's best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations. The share price volatility percentage factor used in the calculation is based on management's best estimate of future share price behaviour and is selected based on past experience, future expectations and benchmarked against peer companies in the industry.

Ordinary shares are classified as equity.

Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction, net of tax, from proceeds.

Financial assets

On initial recognition, financial assets are classified as either financial assets at fair value through the statement of profit or loss, held-to-maturity investments, loans and receivables financial assets, or available-for-sale financial assets, as appropriate.

Loans and receivables

The Group classifies all its financial assets as trade and other receivables. The classification depends on the purpose for which the financial assets were acquired.

Trade receivables and other receivables that have fixed or determinable payments that are not quoted in an active market are classified as loans and receivables financial assets. Loans and receivables financial assets are measured at amortised cost using the effective interest method, less any impairment loss.

The Group's loans and receivables financial assets comprise other receivables (excluding prepayments) and cash and cash equivalents included in the Statement of Financial Position.

Financial liabilities

Financial liabilities are recognised when, and only when, the Group becomes a party to the contracts which give rise to them and are classified as financial liabilities at fair value through the profit and loss or loans and payables as appropriate. The Group's loans and payable comprise trade and other.

When financial liabilities are recognised initially, they are measured at fair value plus directly attributable transaction costs and subsequently measured at amortised cost using the effective interest method other than those categorised as fair value through income statement.

Fair value through the income statement category comprises financial liabilities that are either held for trading or are designated to eliminate or significantly reduce a measurement or recognition inconsistency that would otherwise arise. Derivatives are also classified as held for trading unless they are designated as hedges. There were no financial liabilities classified under this category.

The Group determines the classification of its financial liabilities at initial recognition and re-evaluate the designation at each financial year end.

A financial liability is derecognised when the obligation under the liability is discharged, cancelled or expires.

When an existing financial liability is replaced by another from the same party on substantially different terms, or the terms of an existing liability are substantially modified, such an exchange or modification is treated as a de-recognition of the original liability and the recognition of a new liability, and the difference in the respective carrying amounts is recognised in the income statement.

Provisions

Provisions are recognised when the Company has a present obligation as a result of a past event, and it is probable that the Company will be required to settle that obligation. Provisions are measured at the directors' best estimate of the expenditure required to settle the obligation at the statement of financial position date, and are discounted to present value where the effect is material.

Financial instruments

Non-derivative financial instruments comprise investments in equity and debt securities, trade and other receivables, cash and cash equivalents, loans and borrowings, and trade and other payables.

Non-derivative financial instruments are recognised initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transactions costs, except as described below. Subsequent to initial recognition non-derivative financial instruments are measured as described below.

A financial instrument is recognised when the Group becomes a party to the contractual provisions of the instrument. Financial assets are derecognised if the Group's contractual rights to the cash flows from the financial assets expire or if the Group transfers the financial assets to another party without retaining control or substantially all risks and rewards of the asset. Regular purchases and sales of financial assets are accounted for at trade date, i.e. the date that the Group commits itself to purchase or sell the asset. Financial liabilities are derecognised if the Group's obligations specified in the contract expire or are discharged or cancelled.

Foreign currencies

i) Functional and presentation currency

Items included in the financial statements of the Group are measured using the currency of the primary economic environment in which the entity operates (the functional currency), which are mainly in Pounds Sterling (£), US Dollars (USD), and Peruvian Nuevo Sol (PEN). The financial statements are presented in Pounds Sterling (£), which is the Group's presentation currency.

ii) Transactions and balances

Foreign currency transactions are translated into the presentational currency using exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the income statement.

iii) Group companies

The results and financial position of all Group entities (none of which has the currency of a hyper-inflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

(a) assets and liabilities for each statement of financial position presented are translated at the closing rate at the date of that statement of financial position;

(b) income and expenses for each income statement are translated at average exchange rates (unless this average is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the rate on the dates of the transactions); and

(c) all resulting exchange differences are recognised as a separate component of equity.

On consolidation, exchange differences arising from the translation of the net investment in foreign operations, and of borrowings and other currency instruments designated as hedges of such investments, are taken to shareholders' equity. When a foreign operation is partially disposed of or sold, exchange differences that were recorded in equity are recognised in the income statement as part of the gain or loss on sale.

Goodwill and fair value adjustments arising on the acquisition of a foreign entity are treated as assets and liabilities of the foreign entity and translated at the closing rate.

Management of capital

The Group's policy is to ensure that it will always have sufficient cash to allow it to meet its liabilities when they become due. The principal liabilities of the Group arise in respect of committed expenditure in respect of its ongoing exploration work. To achieve this aim, it seeks to raise new equity finance and debt sufficient to meet the next phase of exploration and where relevant development expenditure.

The Board receives cash flow projections on a monthly basis as well as information on cash balances. The Board will not commit to material expenditure in respect of its ongoing exploration work prior to being satisfied that sufficient funding is available to the Group to finance the planned programmes.

Dividends cannot be issued until there are sufficient reserves available.

Critical accounting judgments and key sources of estimation uncertainty

The preparation of the consolidated financial statements requires management to make estimates and assumptions concerning the future that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The resulting accounting estimates will, by definition, differ from the related actual results.

Valuation of oil and gas properties: judgements regarding timing of regulatory approval, the general economic environment, and the ability to finance future activities has an impact on the impairment analysis of intangible exploration and evaluation assets. All these factors may impact the viability of future commercial production from unproved properties, and therefore may be a need to recognise an impairment. The timing of an impairment review and the judgement of when there could be a significant change affecting the carrying value of the intangible exploration and and evaluation asset is a critical accounting judgement in itself.

Commercial reserves estimates

Oil and gas reserve estimates: estimation of recoverable reserves include assumptions regarding commodity prices, exchange rates, discount rates, production and transportation costs all of which impact future cashflows. It also requires the interpretation of complex geological and geophysical models in order to make an assessment of the size, shape, depth and quality of reservoirs and their anticipated recoveries. The economic, geological and technical factors used to estimate reserves may change from period to period. Changes in estimated reserves can impact developed and undeveloped property carrying values, asset retirement costs and the recognition of income tax assets, due to changes in expected future cash flows. Reserve estimates are also integral to the amount of depletion and depreciation charged to income.

Decommissioning costs

Asset retirement obligations: the amounts recorded for asset retirement obligations are based on each field's operator's best estimate of future costs and the remaining time to abandonment of oil and gas properties, which may also depend on commodity prices.