Tower Resources Regulatory News (TRP)

19 June 2023

Tower Resources plc

Preliminary Results to 31 December 2022

Tower Resources plc (the "Company", the "Group" or "Tower" (TRP.L, TRP LN)), the AIM listed oil and gas company with its focus on Africa, announces its preliminary results for the 12 months ended 31 December 2022.

Highlights:

· In Cameroon, the Group's exploration and evaluation expenditure on the Thali Production Sharing Contract ("PSC") amounted to $3.1 million (2021: $1.3 million). A formal request for extension of the First Exploration Period of the PSC to 11 May 2024 has been submitted to the Minister of Mines, Industry and Technological Development ("MINMIDT") and the Company has been informed that processing of this extension is underway. Other Cameroon highlights include:

· Discussions continued with rig owners and operators with the aim to secure rig availability in the third and/or fourth quarter of 2023 to drill the NJOM-3 well.

· Discussions continued for asset level financing with several parties, including a term loan of approximately $7 million with BGFI Bank Group.

· Updated resource estimates and risk profiles were developed for the reservoirs connected to the NJOM-1 and the NJOM-2 discovery wells, substantially lowering risk attributed to PS9 Sup and PS3 HW reservoirs, and increasing total risked pMean prospective resources to 35.4 million bbls.

· In South Africa, operator NewAge continued to work towards the acquisition of 3D seismic over the permit area.

· In Namibia Tower has been conducting basin modelling to support technical evaluation of the leads identified to date as part of the work programme for the Initial Exploration Period for PEL 96. The Company is now moving forward with more detailed and focused geological and geophysical analysis aiming to high-grade areas for further seismic data acquisition. Once this work has been completed, Tower is planning to acquire new 3D seismic data over the most promising leads/prospects in line with its work programme.

· Following the favourable VAT rulings from the Upper Tribunal in 2022 with respect to the Group's UK VAT position, of the three remaining appeals outstanding at the year-end, two have been settled with a further appeal remaining under discussion. The Company received £351k ($422k) in settlement of the first two appeals, after the accounts date.

· Administrative costs net of share-based payment charges of $631k (2021: $762k) include legal fees incurred totalling $133k (2021: $263k)

· Cash balance at year-end of $231k (2021: $10k)

Post-reporting period events:

16 January 2023: Facility Agreement with Energy Exploration Capital Partners LLC ("EECP") to raise $1.25 million. The facility provides for further convertible advances of up to $4.75 million subject to certain conditions.

15 February 2023: Issue of 23.2 million warrants in lieu of £30,000 (in aggregate) of Directors fees in respect of the period January-March 2023, to conserve the Company's working capital. The warrants are exercisable at a strike price of 0.175 pence (0.21¢) per share. The warrants are exercisable for a period of five years from the date of issue.

30 March 2023: Share issuance in accordance with the terms of the investment deed with EEPC announced on 16 January 2023, of 102,543,067 ordinary shares of 0.001 pence each. The purchase price of 0.12 pence (0.15¢) per Ordinary Share for the settlement amount of $150,000 had been prepaid by EEPC as part of the 16 January advance.

27 April 2023: Cameroon operational update covering:

· Application for a one-year extension of the initial exploration period of the PSC, following positive discussions with the Minister of Mines, Industry and Technological Development and the Prime Minister of the Republic of Cameroon.

· Ongoing discussions with rig owners and operators with the aim to secure rig availability in the third and fourth quarter of this year to drill at NJOM-3.

· Ongoing negotiations for a term loan of approximately $7 million with BGFI Bank Group and asset-level financing with several other parties.

· Updated resource estimates and risks for the reservoirs connected to the NJOM-1 and the NJOM-2 discovery wells, substantially lowering risk attributed to PS9 Sup and PS3 HW reservoirs, and increasing total risked pMean prospective resources to 35.4 million bbls.

· Deployment of software to conduct detailed attribute analysis of the reprocessed 3D seismic data to identify the oil and gas elements of the reservoirs in the Njonji-1 and Njonji-2 fault blocks, resulting in a clearer picture of the pay zones in both fault blocks.

2 May 2023: Issue of 34.4 million warrants in lieu of £30,000 (in aggregate) of Directors fees in respect of the period April-June 2023, to conserve the Company's working capital. The warrants are exercisable at a strike price of 0.1425 p (0.18¢) per share, a premium of 24% over the mid-point closing share price on 28 April 2023. The warrants are exercisable for a period of five years from the date of issue.

16 May 2023: Placing and subscription of 4,600 million shares to raise £2.3 million ($2.9 million) at a price of 0.05p (0.06¢) per share.

16 June 2023: Namibia technical update setting out initial conclusions from basin modelling work prior to and after the accounts date.

Market Abuse Regulation (MAR) Disclosure

The information contained within this announcement is deemed by the Company to constitute inside information as stipulated under the Market Abuse Regulations (EU) No. 596/2014 as it forms part of UK domestic law by virtue of the European Union (Withdrawal) Act 2018 ('MAR'). Upon the publication of this announcement via Regulatory Information Service ('RIS'), this inside information is now considered to be in the public domain.

Contacts:

CHAIRMAN AND CHIEF EXECUTIVE'S STATEMENT

During 2022 the focus of the oil and gas market shifted away from the pandemic and initially was dominated by the conflict in Ukraine; however, as the year went on, the market became more concerned with longer term questions of supply and demand. The potential for supply shortfalls, which had its origin in the under-investment which preceded the pandemic and continued throughout it, has been highlighted by the events of the last year. However, the risks of global stagflation or recession have weighed on demand expectations, and in the short term the market has remained well balanced mainly due to the continued movement of Russian oil, albeit to new customers and at lower prices. The result has been a market which is currently quite well balanced in the short term, and prices which remain very favourable for the Company's projects, and with the potential for further upside in the years ahead.

Our Cameroon project is still critical to the Company, as it remains the project which is closest to first oil, revenues and cash flow. Our priority is still to get the NJOM-3 well drilled as soon as possible, as this is the gateway to the rest of the development. As discussed in our operational review and in recent announcements, we have had to contend with a shortage of available rigs during 2022 and the first half of 2023, but we now finally have rig options opening up, and so we are optimistic of being able to move ahead with this critical well in 2023.

The Government of Cameroon has continued to be extremely supportive and we are very grateful to them. We are also still in active and detailed discussions and due diligence regarding the financing for the NJOM-3 well, which we hope to have completed in good time for our preferred rig option.

In Namibia we have been greatly encouraged by the basin modelling we have been undertaking both in 2022 and during the first half of 2023, which is discussed in our operational review and also in more detail in our recent Namibia update. Our computer basin modelling simulations, calibrated to the nearby well data, appear to be highly predictive of the source rock maturity and hydrocarbon generative kitchen areas and show clear migration pathways. We are especially excited that these outputs closely fit the actual geochemical well data and predict the oil shows (derived from a mature lacustrine source rock) that we observed in the Norsk Hydro well 1911/15-1, as well as the actual geochemical measurements and data points from the other regional wells. A question we had sought to investigate was the immaturity of the shallower Upper Cretaceous source rocks encountered in that well, and the underlying volcano-clastic rocks that are interbedded with sedimentary series with indications of higher total organic carbon content, but which clearly did not generate the lacustrine oil found in the 1911/15-1 well. Our basin models, together with detailed seismic sequence stratigraphic analysis, reconcile those observations with the lacustrine oil, which clearly originated from deeper and laterally extensive Lower Cretaceous source rocks in the syn-rift series. This is a critical and very positive conclusion for potential charge in our license area.

It was also very nice to see the success of Shell's appraisal drilling at Graff, which among other things has emphasised the enormous potential of stratigraphic traps in the region and how the potential volumes found in those traps can increase as one drills.

In South Africa, our co-venturer and operator NewAge is continuing to explore the options for acquisition of new 3D seismic data over our deep-water Outeniqua basin lead, which continues to attract interest from third parties.

We realise that it has been a frustrating time for all shareholders, as we would all have liked to see the NJOM-3 well drilled already; however, we are continuing to make progress towards that goal and we remain confident we will reach it.

STRATEGIC REPORT

Our strategy over the past several years has been to focus in the near term on lower risk appraisal and development within proven basins where there is still low-risk exploration upside, such as our Thali Production Sharing Contract ("PSC") in Cameroon, while still maintaining selective exposure to longer term and high risk/reward exploration in areas where we have existing relationships, such as Namibia and South Africa.

Even before the current conflict in Ukraine, markets were becoming aware by the end of 2021 that the global underinvestment in exploration and production since 2015 was already having a profound effect on both oil and gas supply, and on prices. This has reinforced the benefits, both short and long term, of a strategy based on achieving short-term production as quickly as we can, while also continuing to develop potential resources for the future.

TotalEnergies' 2020 success in South Africa with its Brulpadda and Luiperd wells in the Outeniqua basin, and its recent success in Namibia at Venus-X1 coupled with Shell's recent success in Namibia with its Graff-1 well and the subsequent appraisal drilling in 2022, all indicate that in Namibia and South Africa we have chosen promising countries for our exposure to high risk, high reward exploration. These successes have also resulted in a renaissance of investor interest in exploration, and especially in these countries, as both the scale of these opportunities and the need for the resulting oil and gas over the next decade have become apparent.

In the near term, our strategy still requires reaching first oil in Cameroon as soon as possible, especially now that production is worth so much more than a few years ago. Our Cameroon license also has substantial exploration upside, but this can only be unlocked once we have the existing discovery appraised and in production.

This activity requires financing, and while there is still non-dilutive financing available (within limits) for producing assets, the equity requirements for the earlier stages of exploration and development usually require some trade-offs between the amount of a project one can retain and the speed with which it can be developed. We always look at the alternatives of financing our activity at the asset level, whether via debt or other non-dilutive financing, or via farm-outs, or at the corporate level, again with debt or equity, in order to achieve the best expected outcome for our shareholders.

Although we have both operated and non-operated interests, our preference is to operate assets, in order to control costs and timing more directly, and to build up our local relationships and internal knowledge of reservoirs and petroleum systems, and this remains the case in 2022 and now.

Over the past few years, keeping costs low and flexible without losing access to our people and their skills has also been critical to survival, and we believe will continue to be critical to success in the future - not merely in being able to keep costs to a minimum in periods where activity is necessarily low, as we have recently seen, but also in being able to ramp up the resources and technology we are able to bring to our projects in the future when needed. This is why our technical-subsurface relationship with EPI, which has served us well since 2015, and our more recent relationship with Bedrock Drilling on well design and management, are an essential part of our strategy.

Finally, as noted in previous annual reports, our strategy remains to enable and to support the wider strategic and environmental plans of each of the countries in which we operate, to increase power generation from cleaner sources, including both renewables and natural gas, both to aid economic development and to displace less efficient diesel and fuel-oil based power generation, and to reduce imports of liquid fuels by increasing local production where possible. These countries' strategic plans depend critically on the continued development of local oil and gas production in the near term, in order to meet the national goals and COP26 and other climate commitments which they have set for the next decade.

OPERATIONAL REVIEW

In 2022 we were able to make progress on all of our licenses, despite a number of headwinds.

In Cameroon we received an extension of the initial exploration period of the Thali PSC to May 2023, and immediately turned our attention to rig negotiations. However, an unexpected consequence of the conflict in Ukraine was the decision of Aramco to charter a large number of jack-up rigs for deployment in the Arabian Gulf, which effectively removed all the surplus capacity from the jack-up market and led to substantial increases in the day-rates for both rigs and associated services. At the time of writing, jack-up rig day-rates, for example, have roughly doubled since the end of 2021. More troubling than the increase in rates was the lack of availability. Most oil and gas operators with rigs on charter and with options to extend at "old" rates, were obviously keen to exercise those options, and rig owners wanted to lock in the new higher rates for as long as possible via new long-term charters and were therefore unwilling to commit to drilling single wells. Nevertheless, we anticipated that gaps in operators' schedules would inevitably arise if we were patient, and although we have had to wait until 2023 for these gaps to appear, it does now seem possible to fit our drilling requirements within other operators' schedules.

In the meantime, we undertook further subsurface work in 2022 which resulted in updated volumetric assessments, and we have continued to refine our subsurface analysis after the accounts date, including the application of enhanced attribute analysis using the Paradise software which we have discussed in recent announcements. We have also worked on the financing options for the NJOM-3 well, and on the budget for the well, in order to mitigate as best we can the inevitable increases in cost.

In Namibia, we continued the basin modelling work that we had begun in 2021. The output from this work in the third quarter of 2022 persuaded us that we should expand the scope of the basin modelling, which continued through the end of 2022 and up until May 2023. We have recently updated investors regarding the initial conclusions of this basin modelling work. This has indicated the potential for mature oil source rocks in the deeper syn-rift sections across the Dolphin Graben, generating predominantly oil phase hydrocarbons in substantial volumes, capable of charging very large structures. It has also identified focused migration pathways from those source rocks and generative kitchens to the giant anticlines in the Western area of the license, and a number of potential stratigraphic trap plays both in the Dolphin Graben itself and along the flanks of the giant structures to the West, which are also capable of containing large volumes of oil. The basin modelling work is very closely calibrated with the actual geochemical data measured in the nearby wells and is highly predictive of hydrocarbon generation, expulsion and migration, and also explains the presence of the lacustrine oil in the Norsk Hydro well 1911/15-1 in our license area. The analysis explains why this oil would originally have been generated and potentially trapped and the subsequent tilting of the area would have caused any trapped hydrocarbons to have migrated elsewhere, explaining the residue of oil in the well and providing us with high confidence in the analysis.

Our next steps in Namibia include an oil seep analysis to put together with the basin modelling and possibly some further attribute analysis, to prioritise the leads we have already identified in the license area and to reassess their likelihood and expected volume of charge. This will allow us to choose the best area over which to acquire new 3D seismic data in due course. We will need an extension of the initial exploration period to accommodate this, and we will apply for that extension in the third quarter of 2023.

In South Africa, our 50% partner NewAge, as operator of the Algoa-Gamtoos block, has continued to negotiate with potential contractors for 3D seismic data acquisition on either a proprietary or a multi-client basis. This is a slow process partly because of the uncertainties created by the new Petroleum Bill and its implementation, and also the associated uncertainty over the environmental consultation process highlighted by the litigation over Shell's delayed plans to acquire 3D seismic over a rather larger area to the East of our license. PASA, the regulatory authority, has been understanding of this situation, and we hope to find a way forward that might entail agreeing on a contractor and an environmental consultation process in the year ahead.

NewAge has also continued to explore farm-out options for the Algoa Gamtoos block and discussions with interested parties continue.

PRELIMINARY RESULTS FOR THE YEAR ENDED 31 DECEMBER 2022

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

The financial statements of Tower Resources plc, registered number 05305345 were approved by the Board of Directors and authorised for issue on 16 June 2023.

Signed on behalf of the Board of Directors

Jeremy Asher - Chairman and Chief Executive

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

1 The share-based payment reserve has been included within the retained loss reserve on the consolidated statement of financial position and is a non-distributable reserve.

CONSOLIDATED STATEMENT OF CASH FLOWS

COMPANY STATEMENT OF FINANCIAL POSITION

In accordance with the provisions of Section 408 of the Companies Act 2006, the Company has not presented a statement of comprehensive income and for the year-ended 31 December 2022 the Company made a loss of $312k (2021: $250k).

The financial statements of Tower Resources plc, registered number 05305345 were approved by the Board of Directors and authorised for issue on 16 June 2023.

Signed on behalf of the Board of Directors

Jeremy Asher - Chairman and Chief Executive

COMPANY STATEMENT OF CHANGES IN EQUITY

1 The share-based payment reserve has been included within the retained loss reserve on the Company statement of financial position and is a non-distributable reserve.

COMPANY STATEMENT OF CASH FLOWS

NOTES TO THE FINANCIAL STATEMENTS

1. Accounting policies

a) General information

Tower Resources plc is a public company incorporated in the United Kingdom under the UK Companies Act. The address of the registered office is 134 Buckingham Palace Road, London, SW1W 9SA. The Company and the Group are engaged in the exploration for oil and gas.

These financial statements are presented in US dollars as this is the currency in which the majority of the Group's expenditures are transacted and the functional currency of the Company and have been prepared in accordance with UK-adopted International Accounting Standards, and in compliance with the requirements of the Companies Act 2006.

b) Basis of accounting and adoption of new and revised standards

Changes in accounting policies

A number of new standards are effective from 1 January 2022 but they do not have material effect on the Group's financial statements.

New and amended standards

The following amended standards and interpretation are effective for financial years commencing on or after 1 January 2023. The Group does not intend to adopt the standards below, before their mandatory application date.

Future accounting pronouncements

The Company intends to adopt the above listed standards and interpretations in its financial statements for the annual period beginning 1 January 2023. The Company does not expect the implementation to have a material impact on the financial statements.

c) Going concern

The Group will need to complete a farm-out and/or another asset-level transaction within the coming months, or otherwise raise further funds, in order to meet its liabilities as they fall due, particularly with respect to the forthcoming drilling programme in Cameroon. The Directors believe that there are a number of options available to them through either, or a combination of, capital markets, farm-outs or asset disposals with respect to raising these funds. There can, however, be no guarantee that the required funds may be raised or transactions completed within the necessary timeframes, which raises uncertainty as to the application of going concern in these accounts. Having assessed the risks attached to these uncertainties on a probabilistic basis, the Directors are confident that they can raise sufficient finance in a timely manner and therefore believe that the application of going concern is both appropriate and correct.

This point is also discussed in note 2 of the financial statements.

d) Basis of consolidation

The consolidated financial statements incorporate the accounts of the Company and its subsidiaries and have been prepared by using the principles of acquisition accounting ("the purchase method") which includes the results of the subsidiaries from their date of acquisition. Intra-group sales, profits and balances are eliminated fully on consolidation.

The results of subsidiaries acquired or disposed of are included in the consolidated statement of comprehensive income from the effective date of acquisition or up to the effective date of disposal, as appropriate.

Where necessary, adjustments are made to the financial statements of subsidiaries to bring the accounting policies used into line with those used by the Group. All intra-group transactions, balances, income and expenses are eliminated on consolidation.

As a Consolidated Statement of Comprehensive Income is published, a separate Statement of Comprehensive Income for the Parent Company has not been published in accordance with section 408 of the Companies Act 2006.

e) Jointly controlled operations

Jointly controlled operations are arrangements in which the Group holds an interest on a long-term basis which are jointly controlled by the Group and one or more ventures under a contractual arrangement. The Group's exploration, development and production activities are sometimes conducted jointly with other companies in this way. Since these arrangements do not constitute entities in their own right, the consolidated financial statements reflect the relevant proportion of costs, revenues, assets and liabilities applicable to the Group's interests.

f) Oil and Gas Exploration and Evaluation Expenditure

Costs incurred before the acquisition of a license or permit to explore an area are expensed to the income statement.

All exploration and evaluation costs incurred following a license or permit to explore being obtained or acquired on the acquisition of a subsidiary are capitalised in respect of each identifiable project area. These costs are classified as intangible assets and are only carried forward to the extent that they are expected to be recouped through the successful development of the area or where activities in the area have not yet reached a stage which permits reasonable assessment of the existence of economically recoverable reserves (successful efforts).

Costs incurred by Directors' and employees of the parent Company on the exploration activities are recharged to the subsidiaries and capitalised as exploration assets accordingly.

Other costs are expensed unless commercial reserves have been established or the determination process has not been completed. Accumulated costs in relation to an abandoned area are written off in full against profit in the year in which the decision to abandon the area is made.

When production commences the accumulated costs for the relevant area of interest are transferred from intangible assets to tangible assets as 'Developed Oil and Gas Assets' and amortised over the life of the area according to the rate of depletion of the economically recoverable costs.

g) Impairment of Oil and Gas Exploration and Evaluation assets

The carrying value of unevaluated areas is assessed when there has been an indication that impairment in value may have occurred. The impairment of unevaluated prospects is assessed based on the Directors' intention with regard to future exploration and development of individual significant areas and the ability to obtain funds to finance such exploration and development.

h) Decommissioning costs

Where a material liability for the removal of production facilities and site restoration at the end of the field life exists, a provision for decommissioning is made. The amount recognised is the present value of estimated future expenditure determined in accordance with local conditions and requirements. An asset of an amount equivalent to the provision is also created and depreciated on a unit of production basis. Changes in estimates are recognised prospectively, with corresponding adjustments to the provision and the associated asset.

i) Property, plant and equipment

Property, plant and equipment is stated at cost less depreciation. Depreciation is provided at rates calculated to write off the cost less estimated residual value of each asset over its expected useful life as follows:

Computers and equipment, fixtures, fittings and equipment: straight line over 4 years.

Leasehold and office refurbishment costs: over duration of lease.

The assets' residual values and useful lives are reviewed and adjusted if necessary at each year-end. Profits or losses on disposals of plant and equipment are determined by comparing the sale proceeds with the carrying amount and are included in the statement of comprehensive income. Items are reviewed for impairment if and when events indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the carrying amount of the asset exceeds its recoverable amount which is the higher of an asset's net selling price and value in use.

j) Investments

The Parent Company's investments in subsidiary companies are stated at cost less any expected credit loss for impairment and are shown in the Company's Statement of Financial Position.

k) Share-based payments

The Company makes share-based payments to certain Directors, employees and consultants by the issue of share options or warrants. The fair value of these payments is calculated either using the Black Scholes option pricing model or by reference to the fair value of the remuneration settled by way of the grant of such options or warrants. The expense is recognised on a straight-line basis over the period from the date of award to the date of vesting, based on the Company's best estimate of shares that will eventually vest.

l) Foreign currency translation

i Functional and presentational currency

Items included in the financial statements are shown in the currency of the primary economic environment in which the Company operates ("the functional currency") which is considered by the Directors to be the U.S Dollar. The exchange rate at 31 December 2022 was £1 / $1.2026 (2021: £1 / $1.3479).

ii Transactions and balances

Foreign currency transactions are translated into the functional currency using the 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 year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of comprehensive income.

Transactions in the accounts of individual Group companies are recorded at the rate of exchange ruling on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated at the rates ruling at the year-end. All differences are taken to the statement of comprehensive income.

m) Taxation

i Current tax

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

ii Deferred taxation

Deferred income taxes are provided in full, using the liability method, for all temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred income taxes are determined using tax rates that have been enacted or substantially enacted and are expected to apply when the related deferred income tax asset is realised or the related deferred income tax liability is settled.

The principal temporary differences arise from depreciation or amortisation charged on assets and tax losses carried forward. Deferred tax assets relating to the carry forward of unused tax losses are recognised to the extent that it is probable that future taxable profit will be available against which the unused tax losses can be utilised.

n) Financial instruments

The Group's Financial Instruments comprise of cash and cash equivalents, loans and receivables. There are no other categories of financial instrument.

i Cash and cash equivalents

Cash and cash equivalents are carried at cost and comprise cash in hand, cash at bank, deposits held at call with banks, and other short-term highly liquid investments with original maturities of three months or less.

ii Receivables

Receivables are measured at amortised cost unless the time value of money is immaterial. A provision for impairment of receivables 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. The amount of the provision is the difference between the assets' carrying amount and the recoverable amount. Expected credit losses for impairment of receivables are included in the statement of comprehensive income.

iii Payables

Payables are recognised initially at fair values and subsequently measured at amortised cost using the effective interest method.

o) Financial liabilities and equity

Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the asset of the Group after deducting all of its liabilities. Equity instruments issued by the Company are recorded at the proceeds received net of direct issue costs.

p) Share capital

Ordinary shares are classified as equity. Proceeds received from the issue of ordinary shares above the nominal value are classified as Share Premium. Costs directly attributable to the issue of new shares are shown in equity as a deduction from the Share Premium account.

q) Provisions

Provisions are recognised when the Group has a present obligation as a result of a past event and it is probable that the Group would be required to settle that obligation. Provisions are measured at the managements' best estimate of the expenditure required to settle the obligation at the reporting date and are discounted to present value where the effect is material.

r) Segment reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision makers. The chief operating decision makers have been identified as the executive Board members.

s) Leases

The Group do not have any leases with a term of 12-months or more that contain an option to purchase or where the underlying asset has anything other than a low value and has elected for exemption to the reporting requirements of IFRS 16 (Leases).

2. Critical accounting judgements and key sources of estimation uncertainty

The preparation of financial statements in conformity with International Financial Reporting Standards requires the use of accounting estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of income and expenses during the reporting period. Although these estimates are based on managements' best knowledge of current events and actions, actual results ultimately may differ from those estimates. IFRS also require management to exercise its judgement in the process of applying the Group's accounting policies.

The prime areas involving a higher degree of judgement or complexity, where assumptions and estimates are significant to the financial statements, are as follows:

Recoverability of inter-company balances

Determining whether inter-company balances are impaired requires an estimation of whether there are any indications that their carrying values are not recoverable details of which are included in note 13.

Impairment of capitalised exploration and evaluation expenditure

The future recoverability of capitalised exploration and evaluation expenditure is dependent on a number of factors, including whether it successfully recovers the related exploration and evaluation asset through sale. Factors which could impact the future recoverability include the level of proved, probable and inferred resources, future technological changes which could impact the cost of drilling and extraction, future legal changes (including changes to environmental restoration obligations), changes to commodity prices and licence renewal dates and commitments.

To the extent that capitalised exploration and evaluation expenditure is determined to be irrecoverable in the future, this will reduce profits and net assets in the period in which this determination is made. In addition, exploration and evaluation expenditure is capitalised if activities in the area of interest have not yet reached a stage which permits reasonable assessment of the existence or otherwise of economically recoverable reserves. To the extent that it is determined in the future that this capitalised expenditure should be written off, this will reduce profits and net assets in the period in which this determination is made. Details of impairments of capitalised exploration and evaluation expenditure are included in note 12.

VAT receivable

Following the favourable ruling from the Upper Tribunal received on 21 May 2021, upholding the First-Tier Tax Tribunal's decision in the Company's favour and dismissing HMRC's appeal against the First-Tier Tax Tribunal's decision, the Company released most of its provisions which had previously been recorded in respect of VAT payable.

At the accounts date there remained three further appeals to the First-Tier Tax Tribunal by HMRC, which were yet to be heard. The two earlier appeals concerned time periods not covered by the original Tribunal decisions, to which HMRC had raised procedural objections which it subsequently withdrew prior to the accounts date, and these appeals were formally settled after the accounts date, resulting in a payment (after the accounts date) to the Company of $422,359 (£351,212) which has been recorded in the accounts as receivable. The third more recent appeal concerns a revised assessment in respect of time periods covered by the Upper Tribunal's 21 May 2021 decision. The legal advice received by the Company is that this revised assessment is incorrect, which is why the Company only recognises a provision for a potential liability in respect of this assessment in the 2022 accounts (as opposed to a liability for VAT in the accounts payable note).

Capital markets / going concern

The Group relies on the UK equities market and the market for equity participations in oil and gas exploration assets in order to raise the funds required to operate as a listed entity and complete the respective work programmes for its oil and gas exploration assets. From time to time, and especially in light of the repercussions of events in the Ukraine, general economic and market conditions may deteriorate to a point where it is not possible to raise equity finance to fund exploration projects, nor debt to develop projects.

Additional financing may therefore not be available to the Group restricting the scope of operations, risking both its long-term expansion programme, its obligations under contracts which may be withdrawn or terminated for non-compliance and ultimately the financial stability of the Group to continue as a going concern.

Please see note 1 (c) for a more detailed discussion of going concern matters.

Share-based payment transactions

The Group measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. The fair value is determined by using the Black Scholes model and by reference to the value of the fees or remuneration settled by way of granting of warrants. The determination of fair value using the Black Scholes methodology is based on the input parameters chosen and will therefore contain an element of judgement and uncertainty. Details of share-based payment transactions are included in note 21.

3. Operating segments

The Group has two reportable operating segments: Africa and Head Office. Non-current assets and operating liabilities are located in Africa, whilst the majority of current assets are carried at Head Office. The Group has not yet commenced production and therefore has no revenue. Each reportable segment adopts the same accounting policies. In compliance with IFRS 8 'Operating Segments' the following table reconciles the operational loss and the assets and liabilities of each reportable segment with the consolidated figures presented in these Financial Statements, together with comparative figures for the year-ended 31 December 2022.

1 Administrative expenses include credits of $nil million (2021: expense $1.4 million) of VAT provision write-backs following the successful defence of VAT claims made against the Company by HMRC at the chambers of the second-tier tax tribunal.

2 Included within total assets of $32.5 million (2021: $28.8 million) are $17.4 million Cameroon (2021: $14.3 million) , $751k Namibia (2021: $368k) and $13.7 million South Africa (2021: $14.1 million).

3 Carrying amounts of segment assets exclude investments in subsidiaries.

4 Carrying amounts of segment liabilities exclude intra-group financing.

4. Group operating profit / (loss)

5. Employee information

The average monthly number of employees of the Group (including Directors) was:

Group employee costs during the year (including executive Directors) amounted to:

During 2022, no awards were made under the Group share incentive scheme.

Key management personnel include the executive and non-executive Directors whose remuneration, including non-cash share-based payment charges of $k243 (2021: $481k), was $243k (2021: $481k); see Directors' Report for additional detail. During the year $271k (2021: $581k) of the full-year share-based payment charge of $363k (2021: $969k) related to employees and their remuneration as employees.

The highest paid Director was Jeremy Asher $187k (2021: $401k).

6. Finance costs

During the year covered by these financial statements the Group incurred finance costs of $2k (2021: $149k). The Company incurred finance costs of $1k (2021: $147k).

7. Taxation

8. Deferred tax

At the reporting date the Group had an unrecognised deferred tax asset of $4.8 million (2021: $4.1 million) relating to unused tax losses. No deferred tax asset has been recognised due to the uncertainty of future profit streams against which these losses could be utilised.

9. Parent company income statement

For the year-ended 31 December 2022 the Parent Company made a loss of $312k (2021: profit of $250k) including financing costs of $1k (2021: $147k). The Company charged finance interest on intercompany loan accounts of $536k (2021: $185k) and fees with respect to the provision of strategic advice and support of $105k (2021: $91k). In accordance with the provisions of Section 408 of the Companies Act 2006, the Parent Company has not presented a statement of comprehensive income.

10. (Loss) / profit per share

The fully diluted weighted average number of shares in issue and to be issued as at 31 December 2022 is 2,165,197,663 (2021: 1,900,696,681). At 31 December 2022 the dilutive effect of share options outstanding was nil (2021: 35,416,521). At 31 December 2022, the fully diluted loss per share has been kept the same as the basic loss per share because the conversion of share options and share warrants would decrease the basic loss per share and is thus anti-dilutive. The number of anti-dilutive shares that were excluded from this computation of profit per share was 7,688,323 (2021: nil).

11. Property, plant and equipment

12. Intangible Exploration and Evaluation (E&E) assets

During the year the Group capitalised amounts totalling $1.5 million (2021: $1.7 million) with respect to the following assets:

Cameroon

The $3.1 million of capitalised expenditure comprised ongoing NJOM-3 appraisal drilling preparation costs plus the capitalised cost of operating the local office in Douala.

In South Africa, Rift Petroleum Limited, Tower's wholly owned subsidiary, and its JV partner and operator New African Global Energy SA (Pty) Ltd, continued to work on planning the forthcoming seismic acquisition. The JV partners also negotiated the settlement of certain charges made to the JV, resulting in a credit of costs historically charged of $565k and a net credit for the year of $415k.

The Directors have not provided for any impairment of the Group's investment in the Thali license, because potential transactions and funding discussions with third parties and the Company's internal cash flow projections for the license support the Directors' view that the current carrying value is recoverable. Furthermore, the operating company, Tower Resources Cameroon SA, has applied for a 12-month extension of the First Exploration Period of the license to May 2024 and has been informed by the Government of the Republic of Cameroon that this extension is being processed. Final formal confirmation of the extension has yet to be received but is expected during Q3 of 2023.

Namibia

The Group made various licence commitment and training payments to the Government of the Republic of Namibia in addition to commencing basin modelling work and other work in line with the work programme commitments.

The Company's investment in the current license is currently just $588k (2021: $368k), which appears well supported by the valuations implied by recent transactions in the region, allowing for the early stage of the evaluation and appraisal process. Furthermore, the Directors continue to believe firmly that the relatively modest amounts of expenditure incurred on acquiring and securing tenure to the licence is fully supported by their initial view of its prospectivity based on the information that is currently available

South Africa

In South Africa, the Petroleum Authority of South Africa ("PASA") formally approved the application to enter the second renewal period, submitted by the Operator NewAge Energy Algoa (Pty) Ltd, on 17 November 2020, having confirmed that the first renewal period work programme had been completed to its satisfaction. The second renewal period commits the JV to the acquisition of 700km of 2D seismic acquisition or the acquisition of 300km of 3D seismic. The minimum spend is $5.0 million in total to the JV and this period will conclude upon the completion of the work programme, representing a commitment to acquire a minimum of 700km 2D or 300km of 3D seismic over the block. Acquiring the additional seismic data in 2023 is now no longer possible, and as a result, the JV partners do not expect to acquire the new 3D seismic data over the block until 2024 at the earliest. The operator has told the Company that PASA accepts this position and merely requires that the seismic acquisition obligation is completed before the JV enters the next renewal period.

The Directors' view is that the recent TotalEnergies discoveries at Brulpadda and Luiperd, and the analysis conducted by the JV indicating that the deepwater lead in the JV license area conducted in 2021, support the current valuation of the license.

Impairment

In accordance with the Group's accounting policies and IFRS 6 'Exploration for and Evaluation of Mineral Resources' the Directors have reviewed each of the exploration license areas for indications of impairment. Having done so, it was concluded that a full impairment review was not required on the Cameroon, South Africa or Namibian licences.

13. Investment in subsidiaries

Included within loans made to subsidiary undertakings during the year of $3.4 million (2021: 2.1 million) are amounts of $2.5 million Cameroon (2021: $1.3 million), $158k South Africa (2021: $394k), $616k Rift Petroleum Holdings (2021: $415k) and $131k (2021: $51k) Namibia.

Loans made by the parent company to subsidiary undertakings are interest-bearing in accordance with loan agreements made in 2015, and are repayable to the parent company on demand.

The subsidiary undertakings at the year-end are as follows (these undertakings are included in the Group accounts):

14. Trade and other receivables

Trade and other receivables include VAT recoverable from HMRC on late appeals owed to the Company totalling £351k ($422k) which was received in May 2023.

15. Trade and other payables

Accruals include UK $59k (2021: $53k); Cameroon $2.1 million (2021: $1.2 million); Namibia $167k (2021: $2k) and South Africa $190k (2021: $723k) and comprise operational and other asset related costs due plus amounts payable to Ministerial bodies with respect to licence tenure, most of which has been settled subsequent to the year-end.

Group creditor payment days are approximately 30 days (2021: 32 days).

16. Provision for liabilities and charges

Following the favourable ruling from the Upper Tribunal received on 21 May 2021, upholding the First-Tier Tax Tribunal's decision in the Company's favour and dismissing HMRC's appeal against the First-Tier Tax Tribunal's decision, the Company released most of its provisions which had previously been recorded in respect of VAT payable.

At the accounts date there remained three further appeals to the First-Tier Tax Tribunal by HMRC, which were yet to be heard. The two earlier appeals concerned time periods not covered by the original Tribunal decisions, to which HMRC had raised procedural objections which it subsequently withdrew prior to the accounts date, and these appeals were formally settled after the accounts date, resulting in a payment (after the accounts date) to the Company of $422,359 (£351,212) which has been recorded in the accounts as receivable. The third more recent appeal concerns a revised assessment in respect of time periods covered by the Upper Tribunal's 21 May 2021 decision. The legal advice received by the Company is that this revised assessment is incorrect, which is why the Company only recognises a provision for a potential liability in respect of this assessment in the 2022 accounts (as opposed to a liability for VAT in the accounts payable note).

17. Borrowings

Total borrowings for the Group and Company are noted below:

During the year, the Group and Company entered into no new facilities (2021: $nil).

On 21 January 2021, the Company repaid in full the $500k loan facility with Shard Merchant Capital Ltd. The terms of the Shard Facility included the issue of 31,446,541 attached three-year warrants at a strike price of 0.6 pence and 5,761,198 shares to pre-pay interest charged at 12% per annum. The loan was secured by a fixed and floating charge over the Company's assets in favour of Shard Merchant Capital Ltd. The repayment of the loan included facility transaction costs of $35k.

On 4 March 2021, the Pegasus Petroleum Limited loan facility, to which Jeremy Asher is a controlling party, was extended to the end of November 2021. Consideration for the extension comprised an increase in the production-based payments, the amount depending on whether the loan would be repaid by 15 July or only in November 2021. Additionally, simple interest would accrue at 12% per annum pro rata, commencing on 4 March 2021, and would only be paid at the end of the facility period. The 15 July date was subsequently extended to 20 August 2021, with the production-based payments effectively limited to 3.75% of the Contractor share of revenues from the production sharing contract, net of the Government share and net of all Petroleum Taxes, and the facility was fully repaid on 20 August 2021.

18. Share capital

The share capital issues during 2022 are summarised as follows:

In January 2022, the Company raised $2.1 million by placing 576,923,077 shares for cash at 0.260 pence per share.

In August 2022, the Company raised $1.9 million by placing 857,142,286 shares for cash at 0.175 pence per share.

In August 2022, the Company raised £30k by placing 11,200,000 shares in settlement of third fees at 0.225 pence per share.

19. Reserves

Reserves within equity are as follows:

Share capital

Amounts subscribed for share capital at nominal value.

Share premium account

The share premium account represents the amounts received by the Company on the issue of its shares which were in excess of the nominal value of the shares.

Retained losses

Cumulative net gains and losses recognised in the Statement of Comprehensive Income less any amounts reflected directly in other reserves.

20. Financial instruments

Capital risk management and liquidity risk

Capital structure of the Group and Company consists of cash and cash equivalents held for working capital purposes and equity attributable to the equity holders of the Parent, comprising issued capital, reserves and retained losses as disclosed in the Statement of Changes in Equity. The Group and Company uses cash flow models and budgets, which are regularly updated, to monitor liquidity risk.

Significant accounting policies

Details of the significant accounting policies and methods adopted, including the criteria for recognition, the basis of measurement and the basis on which income and expenses are recognised, in respect of each material class of financial asset, financial liability and equity instrument are disclosed in note 1 to the financial statements.

Due to the short-term nature of these assets and liabilities such values approximate their fair values at 31 December 2022 and 31 December 2021.

Financial risk management objectives

The Group's and Company's objective and policy is to use financial instruments to manage the risk profile of its underlying operations. The Group continually monitors financial risk including oil and gas price risk, interest rate risk, equity price risk, currency translation risk and liquidity risk and takes appropriate measures to ensure such risks are managed in a controlled manner including, where appropriate, through the use of financial derivatives. The Group and Company does not enter into or trade financial instruments, including derivative financial instruments, for speculative purposes.

Interest rate risk management

The Group and Company borrowings carry a fixed interest rate of 1% per month and are therefore not exposed to any sensitivity risk.

Interest rate sensitivity analysis

The sensitivity analysis below has been determined based on the exposure to interest rates at the reporting date and assuming the amount of the balances at the reporting date were outstanding for the whole year.

A 100-basis point change represents management's estimate of a possible change in interest rates at the reporting date. If interest rates had been 100 basis points higher and all other variables were held constant the Group's profits and equity would be impacted as follows:

The Group's exposure to interest rate risk, which is the risk that a financial instrument's value will fluctuate as a result of changes in market interest rates on classes of financial assets and financial liabilities, was as follows:

Foreign currency risk

The Group's and Company's reporting currency is the US dollar, being the currency in which the majority of the Group's revenue and expenditure is transacted. The US dollar is the functional currency of the Company and the majority of its subsidiaries. Less material elements of its management, services and treasury functions are transacted in pounds sterling. The majority of balances are held in US dollars with transfers to pounds sterling and other local currencies, as required to meet local needs. The Group does not enter into derivative transactions to manage its foreign currency translation or transaction risk as it does not believe such risks are material.

At the year-end the Group and Company maintained the following cash reserves:

Credit risk management

Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Group or Company. The Group and Company reviews the credit risk of the entities that it sells its products to or that it enters into contractual arrangements with and will obtain guarantees and commercial letters of credit as may be considered necessary where risks are significant to the Group or Company.

The Group has cash and cash equivalents of $243k as at 31 December 2022 (2021: $10,054). The cash and cash equivalents are held with financial institutions which are rated below. Wherever possible ratings are provided by Fitch Ratings, however, where no rating was available from either Fitch Ratings or either of the other major international credit rating agencies such as Standard & Poors or Moodys, the bank's local credit rating was used:

21. Share-based payments

The share-based payments include the cost of warrants issued in respect of the company's equity financings and bridging loan, and also share-based payments for a number of services to the Group's various contractors and brokers and payments in lieu of Director fees.

Options

Details of share options outstanding at 31 December 2022 are as follows:

1 These options vest in the beneficiaries in equal tranches on the first, second and third anniversaries of grant.

The following Directors held interests, directly or indirectly, in share options at the year-end:

Warrants

Details of warrants outstanding at 31 December 2022 are as follows: