Block Energy P. Regulatory News (BLOE)

Block Energy Plc

("Block" or the "Company")

Audited Results for the Year Ended 31 December 2021

Block Energy plc, the development and production company focused on Georgia, is pleased to announce its audited results for the year ended 31 December 2021.

Block's Annual Report is available on the Company's website at www.blockenergy.co.uk and will be sent to shareholders later today.

Highlights:

· Successfully integrated the SRCL assets acquired from Schlumberger and defined an asset wide field development and production enhancement plan

· Commenced gas sales in February 2021, following completion of the Early Production Facility and associated gas gathering line

· Delivered on multipleobjectives set for 2021:

o Fully integrated the substantial technical data base, following completion of the acquisition of SRCL, 

o Completed a risking and ranking process, focussed on short term drilling and production enhancement opportunities across the enlarged portfolio,

o Defined a two-well drilling programme consisting of a new horizontal well, designed to appraise areas of low fracture density in the XIF license and a side track of an existing well, in the newly acquired XIB license, whilst simultaneously executing a workover programme structured to reverse the natural decline of our baseline production

· Well JKT-01Z drilled and brought into production at 344 boepd, with rapid pay-back of drilling capex

· Production enhancement programme, continues to deliver restoring and enhancing baseline production

· Information gathered via the drilling of well WR-B01a and well JKT-01Z have directly supported the Project I development plan of 5 oil wells, due to commence in 2022 

· Asset wide study has defined two further projects:

o Project II - the infill development of the Middle Eocene oil reservoir in the Patardzeuli oil field in Block XIB, and

o Project III - the appraisal and development of the natural gas resources in the Lower Eocene throughout the XIF and XIB license areas.

· Over 399,000 operational man man-hours worked during the year, without any lost time incidents

· Development of a 3 Project strategy, tailored to provide additional short & medium term cashflows and unlock significant gas potential.

Block Energy plc's Chief Executive Officer, Paul Haywood, said:

"The Company swiftly integrated and advanced the appraisal and development opportunities throughout its enlarged portfolio in 2021. It also delivered on a key milestones, including commencing gas sales and execution of a multi well drilling campaign."

"This relentless drive to advance the Company and maintain consistent momentum has placed it in a stronger position to continue to create value for all shareholders in the current year. The planned three project strategy is designed to efficiently deploy existing cash reserves into further development drilling, throughout the XIF and XIB licenses."

"This, combined with our enhanced understanding of the subsurface and the Company being profitable, sets the stage for what we forecast to be a rewarding year and we look forward to updating shareholders on short and medium term milestones as we advance".

THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION AS STIPULATED UNDER THE UK VERSION OF THE MARKET ABUSE REGULATION NO 596/2014 WHICH IS PART OF ENGLISH LAW BY VIRTUE OF THE EUROPEAN (WITHDRAWAL) ACT 2018, AS AMENDED. ON PUBLICATION OF THIS ANNOUNCEMENT VIA A REGULATORY INFORMATION SERVICE, THIS INFORMATION IS CONSIDERED TO BE IN THE PUBLIC DOMAIN.

For further information please visit http://www.blockenergy.co.uk/ or contact:

Chairman's Statement

Despite the challenges posed by the ongoing pandemic, we delivered on our key milestones during the year 2021, placing us in a good position to make solid progress this year and beyond.

Our main objectives for 2021 were:

· to build on our understanding of the subsurface, to support future drilling and production success; and

· to deliver a two-well drilling programme and a workover programme, to augment the existing production from existing wells.

The first objective was of strategic importance. By using attribute analysis of the 3D-seismic survey that we acquired on West Rustavi Block XIF and the data acquired by a previous operator on Block XIB, our geoscience team has made a significant improvement in understanding the nature of our complex Eocene oil and gas reservoirs.

This understanding has enabled us to make the investment case for Block Energy in 2022 by defining three appraisal and development projects:

· Project I, the development of the Middle Eocene oil reservoir in the West Rustavi/Krtsanisi field which straddles Blocks XIF and XIB;

· Project II, the infill development of the Middle Eocene oil reservoir in the Patardzeuli oil field in Block XIB; and

· Project III, the appraisal and development of the natural gas resources throughout the Eocene in Blocks XIF and XIB.

Projects I and II will provide additional cash flow in the short to medium term from the sale of crude oil and natural gas while Project III promises to add significant value by better defining and ultimately monetising the extensive natural gas resources that lie under our portfolio of leases. This makes an attractive investment case, particularly at current oil prices, which should work well in Georgia, where the complexity of the subsurface geology is offset by the positive and supportive regulatory framework. The result, we believe, is an excellent balance of risk and reward.

We appreciate that the risk relating to individual development wells is significant when compared to many other regions of the world where reservoirs are simpler. We think the best way to look at Block Energy is to consider the totality of the opportunities in the planned portfolio of wells, rather than on a well-by-well basis. The nature of the geological risk means that some wells will always be more successful than others, but our operations team is driving costs down by a combination of careful planning, hard-nosed contracting and the introduction of innovative techniques. This will make payback on the successful wells rapid, particularly at the current oil price, as well as reducing the cost of any less successful wells. So, providing each portfolio of new wells is successful as a whole in adding to production, we, the shareholders, will see material returns on the investments made and our strategy going forward is to increase the number and frequency of wells that we drill.

We plan to commence Project I later this year which entails drilling five oil wells in the Krtsanisi anticline, newly recognised in the West Rustavi/Krtsanisi field.

The achievement of the second objective for 2021, reflected in the success of well JKT-01Z, in terms of cost, placement of the horizontal and production rate, and, ironically, the disappointing production rate from WR-B1 also was an important contributor to the first strategic objective.

None of this, of course, would be possible without the dedication and commitment shown by our team of 120 people in Georgia and six in London; a commitment that is reflected in their readiness to learn and adapt to deliver for us as the shareholders of our Company. I congratulate our people on quickly coming together after the acquisition of the Schlumberger subsidiary to form a unified and effective team. On behalf of the Board and shareholders, I take the opportunity to thank them for their dedication and the tremendous effort they make.

Despite the challenges of last year, your Company now has a stronger platform on which to realise its potential. On behalf of the Board, I would like to thank you all for your support. We look forward to engaging with you with further updates as the rest of the year unfolds.

Philip Dimmock

Non- Executive Chairman

Chief Executive Officer's Statement

In 2021, we saw a material improvement in the global demand for oil and gas. This really took hold in the latter part of the year as the world emerged from Covid-19 and economies began to recover. The Company benefits from much improved oil pricing, which strengthens our business case and enhances the platform to deliver Projects .

Despite the challenging environment last year, the Board considered it vital to continue with prudent investments to progress the business. Now, a year later, we are seeing the benefits of those decisions, with the Company's revenue more than covering cash costs and enabling us to reinvest more revenue in future development.

Operations

Following the acquisition and integration of Blocks IX and XIB, our Company embarked on two key initiatives during 2021, both aimed at maximising production from our enlarged portfolio. These initiatives included a two-well drilling programme to enhance production levels and a workover programme tailored to maximise production from our existing well stock.

These two initiatives came on the back of actions put in place in 2020 to monetise gas production; the success of which was realised in 2021, with gas sales commencing in February through the the Early Production Facility ("EPF") and associated gas gathering line installed in 2020. The Company's investment in these facilities paid further dividends in 2021 and 2022, with the immediate tie-in and monetising of oil and gas produced from the WR-B01a and JKT-01Z wells.

Two Well Programme

Planning for the first of the two wells commenced early in 2021, with the aim of drilling WR-B01 around mid-year.

The objective of well WR-B01, Georgia's first horizontal well, was to establish consistent production by targeting an area of the reservoir that was less prone to fractures, . We learnt that the limited extent of the fracture networks adversely affected the overall well productivity.

The information received from drilling the WR-B01a well enabled the Company to calibrate its subsurface model, ahead of drilling the second well in the programme, JKT-01Z. 

JKT-01Z was spudded in December 2021. The well was delivered early in 2022, significantly ahead of time and under budget.

The rapid tie-in and monetisation of production from well JKT-01Z was made possible by the recently installed infrastructure at an adjacent well, KRT-39, which has been in production for over 20 years. JKT-01Z produced at a rate of 344 boepd, validating the Company's improved understanding of the reservoir. It remains a solid contributor to the Company's overall production and cash flow profile, having already paid back the well-drilling capex in line with forecast, whilst directly informing the Project I development plan.

Workover and Other Programmes

Through 2021, the operations team continued to execute well maintenance and production enhancement intervention . This followed a well-by-well opportunity review that took place early in the year.

As part of that programme, well WR-38Z and WR-16aZ were both brought back into production in Q1, and both wells required further work during the year to support ongoing production. WR-16aZ produced intermittently during the first half and was supported by the installation of artificial lift in Q3. WR-38Z was on production more consistently, but experienced natural decline, which was more than offset by the production gains from installing the rod pump on WR-16aZ.

Later in the year, we undertook a production enhancement programme, comprising technical well interventions, such as wellbore cleaning and replacing artificial lift components. This programme was focussed on supporting near-term production, whilst informing our technical evaluation of the mature development areas throughout Block XIB, specifically the Patardzeuli field (which produced 100 MMbbls of oil). The team have since designed a staged infill development programme, which seeks to recover over 97 million barrels of remaining oil from undrained areas of this once-prolific field (Project II).

In a separate initiative, upgrading surface facilities at well KRT-39 in Block XIB enabled the monetisation from January 2022 of the associated gas production from KRT-39 and JKT-01Z, boosting the Company's revenue whilst supporting strategic plans to advance the appraisal and development of the significant contingent gas resources across our portfolio (Project III).

Health & safety and ESG

Over 399,000 operational man man-hours were worked by staff and contractors over during the year, without any lost time incidents. This is a significant achievement and reflects the Company's importance on health and safety. It also demonstrates the quality and diligence of the management team on-site and their ongoing dedication to working to the highest standards within the industry.

As part of the drive to improve the Company's ESG credentials, we were pleased to be accepted into the UN Global Compact Network ("UNGCN"). The UNGCN is a global platform promoting engagement on human rights, labour, environmental and anti-corruption standards. 

Through its increased focus on gas, the transition fuel, over the course of 2021, Block also reduced its emissions on a sales-weighted basis. By selling associated gas produced, Block no longer has to flare it. Furthermore, by selling gas into the automobile fuel market, the Company reduces regional transport emissions by displacing higher carbon and more emissions-intensive alternative fuels. 

Outlook

The Company is now benefitting from the various initiatives undertaken during 2021 to support production growth and a broader oil development and gas appraisal programme. The Company has built an excellent portfolio of assets and the exercise of strict capital discipline, combined with the benefits from higher oil and gas prices, places us in a great position to develop them further in the year ahead. Supported by our cash flow positive business and non-dilutive development financing options being explored, we plan to step up the rate of drilling in 2022 and 2023, to increase oil production and appraise the deeper gas play within our licences, which we believe contains substantial gas resources. The robust domestic and regional demand for gas, and the unrestricted direct access to European markets support the development of as much gas as possible.

Paul Haywood

Chief Executive Officer

Chief Financial Officer's Statement

Balance sheet - acquisitions, capital expenditure, equity placing and asset growth

In November 2020, Block Energy Plc acquired 100% of the shares of Block Rustaveli Limited (formerly Schlumberger Rustaveli Company Limited), which holds the PSCs to Blocks IX and XIB in Georgia, for $6.8 million consideration, which comprised $7.1 million in nil-cost options to acquire shares in Block Energy Plc less $0.3 million cash from the seller to adjust the consideration for liabilities that were for the seller's account. The assets and liabilities acquired, which are detailed in note 12 to the consolidated financial statements include the following fair values: $6.3 million of development and production assets, $1.0 million of crude oil inventory, $1.5 million of materials inventory, $1.6 million of decommissioning liabilities and $0.9 million of other liabilities.

The Group's net assets have decreased from $29,694,000 as at 31 December 2020 to $27,065,000 as at 31 December 2021. At the end of the year, the Group's cash balance was $1,244,000 (2020: $6,331,000).

Income statement

The Group's revenue increased to $6,114,000 (2020: $1,255,000) and other income included $5,000 (2020: $100,000) for sales of materials. The current year revenue from sales of crude oil of $5,518,000 (2020: $1,255,000) comprised the sale of 86,700 barrels (2020: 34,421barrels) of oil, which equated to average revenue of $63.65 (2020: $36.45) per barrel.

During the year, the Group produced 108,000 barrels of crude oil (2020: 25,000 barrels), with the increase in production being due primarily to oil and gas produced from the wells in Block XIB (acquired in late 2020) and from new wells/sidetracks. This gross production includes the state of Georgia's share of production.

In addition, the Group had over 20,000 barrels of crude oil inventory as at 31 December 2021 (31 December 2020: over 28,000 barrels). Following the year end, during the quarter ended 31 March 2022, the Group sold 24,413 barrels of crude oil inventory for net revenue of $2.168 million, which equates to average revenue of $88.80 per barrel (Q1 2021: sold 26,349 barrels for $1.374 million or $52.18 per barrel).

The Group commenced gas sales on 15 February 2021 and, during the period from 15 February 2021 to 31 December 2021, it sold 191.5 Mcf of gas for net revenue of $596,000, which equates to an average gas price of $3.11 per Mcf (2020: sold nil Mcf).

The loss for the year was $4,783,000 as compared with a $5,512,000 loss in the prior year. During the year, the Group had not yet achieved sufficient scale for the revenue to cover the Group's costs.

Future prospects

During Q1 2022, the Company produced 32.1 Mbbls of oil and 14.0 Mboe of gas, resulting in a combined total of 46.1 Mboe of oil and gas (Q1 2021: produced 29.8 Mbbls of oil and 14.6 Mboe of gas, resulting in a combined total of 44.4 Mboe of oil and gas). The average production rate for Q1 2022 was 512 boepd (Q1 2021: 493 boepd).

The Company has always been focused on controlling administration costs and continues to keep these to a minimum. We maintain a low-cost operation, and our Georgian portfolio offers a low-cost short-cycle production base.

Liquidity, counterparty risk and going concern

The Group monitors its cash position, cash forecasts and liquidity regularly and has a conservative approach to cash management, with surplus cash held on term deposits with major financial institutions.

The directors have prepared cash flow forecasts for a period of 18 months from the date of signing these financial statements. The Group's forecasts are reviewed regularly to assess whether any actions to curtail expenditure or cut costs are required. The Group is in the final stages of preparing to drill a horizontal sidetrack in the WR-B01 well followed by sidetracks of other wells. The forecasts assume the wells will produce oil and gas, which would be sold, and indicate the Group has sufficient funds to complete the drilling of the wells and to meet its liabilities as they fall due until December 2023. However, if any of the new wells do not produce commercial quantities of oil or gas, the Group would immediately revisit its plans to drill subsequent wells. The financial benefit of any additional capital projects would be assessed against capital requirements and balanced with ensuring that the Group and the Company can continue to meet their liabilities and commitments through to December 2023. The Company's forecasts are considered together with the Group's forecasts.

The Group's operations presently generate sufficient revenues to cover operating costs and capital expenditures, supporting the continued preparation of the Group's accounts on a going concern basis. The directors are nevertheless conscious that oil prices have risen rapidly during the past twelve months due in part to recent global political uncertainty, and could rise further but could also fall back in the year ahead, and that future production levels depend in part on the success of future drilling. As part of their going concern assessment, the directors have performed a reverse stress test on a low oil price scenario in which future drilling is inhibited or unsuccessful, and have concluded that it remains possible that future revenues in such a scenario might not cover all operating costs and planned capital expenditures, creating a material uncertainty that may cast doubt over the Group's ability to continue as a going concern. Whilst acknowledging this material uncertainty, the directors remain confident of making further cost savings and/or raising finance when required, and therefore the directors consider it appropriate to prepare the financial statements on a going concern basis. The financial statements do not include the adjustments that would result if the Group were unable to continue as a going concern.

Results and dividends

The results for the year and the financial position of the Group are shown in the following financial statements. The Group has incurred a pre-tax loss of $4,783,000 (2020: loss of $5,512,000).

The Group has net assets of $27,065,000 (2020: net assets of $29,694,000).

The directors do not recommend the payment of a dividend (2020: $nil).

William McAvock

Chief Financial Officer

Consolidated Statement of Comprehensive Income

for the year ended 31 December 2021

All activities relate to continuing operations.

The notes on the following pages form part of these consolidated financial statements.

The financial statements were approved by the Board of Directors and authorised for issue on 30 June 2022 and were signed on its behalf by:

William McAvock Paul Haywood

Director Director

The notes on the following pages form part of these consolidated financial statements.

Consolidated Statement of Changes in Equity

at 31 December 2021

The notes on the following pages form part of these consolidated financial statements.

Consolidated Statement of Cashflows

for the year ended 31 December 2021

The notes on the following pages form part of these consolidated financial statements.

Significant non-cash transactions

The only significant non-cash transactions were the issue of shares and share options detailed in notes 19 and 23.

Notes forming part of the Consolidated Financial Statements

Corporate information

Block Energy Plc ("Block Energy") gained admission to AIM on the 11 June 2018, trading under the symbol of BLOE.

The Consolidated financial statements of the Group, which comprises Block Energy Plc and its subsidiaries, for the year ended 31 December 2021 were authorised for issue in accordance with a resolution of the directors on 30 June 2022. Block Energy is a Company incorporated in the UK whose shares are publicly traded. The address of the registered office is given in the officers and advisers section of this report. The Company's administrative office is in London, UK.

The nature of the Company's operations and its principal activities are set out in the Strategic Report on pages 3 to 21 and the Report of the Directors on pages 22 to 24.

1. Significant Accounting policies

IAS 8 requires that management shall use its judgement in developing and applying accounting policies that result in information which is relevant to the economic decision-making needs of users, that are reliable, free from bias, prudent, complete and represent faithfully the financial position, financial performance and cash flows of the entity.

Basis of preparation

The principal accounting policies adopted in the preparation of these consolidated financial statements are set out below. The policies have been consistently applied to all the years presented, unless otherwise stated. In the prior year, the Group changed its presentational currency from the pound sterling to the US dollar, which represented a change in accounting policy. All amounts presented are in thousands of US dollars unless otherwise stated. Foreign operations are included in accordance with the policies set out below.

The consolidated financial statements have been prepared in accordance with UK international accounting standards and in conformity with the requirements of the Companies Act 2006. The Financial Statements have also been prepared under the historical cost convention, as modified by the revaluation of financial assets at fair value through profit or loss.

The preparation of financial statements in conformity with IFRS requires management to make judgements, estimates and assumptions that affect the application of policies and reported amounts of assets and liabilities, income and expenses. The estimates and associated assumptions are based on historical experience and factors that are believed to be reasonable under the circumstances, the results of which form the basis of making judgements about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Changes in accounting estimates may be necessary if there are changes in the circumstances on which the estimate was based, or as a result of new information or more experience. Such changes are recognised in the period in which the estimate is revised.

New and amended standards adopted by the Group

There were no new or amended accounting standards adopted by the Group for the year ended 31 December 2021.

New accounting standards issued but not yet effective

The standards and interpretations that are relevant to the Group, issued, but not yet effective, up to the date of the Financial Statements are listed below. The Group intends to adopt these standards, if applicable, when they become effective.

The Directors have evaluated the impact of transition to the above standards and do not consider that there will be a material impact of transition on the financial statements.

Basis of consolidation

Where the Company has control over an investee, it is classified as a subsidiary. The Company controls an investee if all three of the following elements are present: power over the investee, exposure to variable returns from the investee, and the ability of the investor to use its power to affect those variable returns. Control is reassessed whenever facts and circumstances indicate that there may be a change in any of these elements of control. De-facto control exists in situations where the Company has the practical ability to direct the relevant activities of the investee without holding the majority of the voting rights. In determining whether de-facto control exists the Company considers all relevant facts and circumstances, including:

· The size of the Company's voting rights relative to both the size and dispersion of other parties who hold voting rights;

· Substantive potential voting rights held by the Company and by other parties;

· Other contractual arrangements; and

· Historic patterns in voting attendance.

Business combinations and Goodwill

The consolidated financial statements incorporate the results of business combinations using the purchase method. In the consolidated statement of financial position, the acquiree's identifiable assets, liabilities and contingent liabilities are initially recognised at their fair values at the acquisition date. The difference between the consideration paid and the acquired net assets is recognised as goodwill. The results of acquired operations are included in the consolidated income statement from the date on which control is obtained. Any difference arising between the fair value and the tax base of the acquiree's assets and liabilities that give rise to a deductible difference results in recognition of deferred tax liability. No deferred tax liability is recognised on goodwill. For the purposes of the current period of reporting the figures related to the transaction accounting are considered provisional as permitted under the requirements of the accounting standards. These figures will be finalised within a period of twelve months from the acquisition date of the transaction.

Acquisitions

The Group and Company measure goodwill at the acquisition dates as:

· The fair value of the consideration transferred; plus

· The recognised amount of any non-controlling interests in the acquiree

· Plus, if the business combination is achieved in stages, the fair value of the existing equity interest in the acquiree; less the net recognised amount (generally fair value) of the identifiable assets acquired and liabilities assumed.

When the excess is negative, a bargain purchase gain is recognised immediately in profit or loss.

Cost related to the acquisition, other than those associated with the issue of debt or equity securities, that the Group incurs in connection with a business combination, are expensed as incurred.

Asset Acquisition

Acquisitions of mineral exploration licences through the acquisition of non-operational corporate structures that do not represent a business, and therefore do not meet the definition of a business combination, are accounted for as the acquisition of an asset. An example of such would be increases in working interests in licences.

The consideration for the asset is allocated to the assets based on their relative fair values at the date of acquisition.

Going concern

The Group's operations presently generate sufficient revenues to cover operating costs and capital expenditures, supporting the continued preparation of the Group's accounts on a going concern basis. The directors are nevertheless conscious that oil prices have risen rapidly during the past twelve months due in part to recent global political uncertainty, and could rise further but could also fall back in the year ahead, and that future production levels depend in part on the success of future drilling. As part of their going concern assessment, the directors have performed a reverse stress test on a low oil price scenario in which future drilling is inhibited or unsuccessful, and have concluded that it remains possible that future revenues in such a scenario might not cover all operating costs and planned capital expenditures, creating a material uncertainty that may cast doubt over the Group's ability to continue as a going concern. Whilst acknowledging this material uncertainty, the directors remain confident of making further cost savings and/or raising finance when required and, therefore, the directors consider it appropriate to prepare the financial statements on a going concern basis. The financial statements do not include the adjustments that would result if the Group were unable to continue as a going concern.

Intangible Assets

Exploration and evaluation costs

The Group applies the full cost method of accounting for Exploration and Evaluation (E&E) costs, having regard to the requirements of IFRS 6 'Exploration for and Evaluation of Mineral Resources'. Under the full cost method of accounting, costs of exploring and evaluating properties are accumulated and capitalised by reference to appropriate cash generating units ("CGUs"). Such CGU's are based on geographic areas such as a licence area, type or a basin and are not larger than an operating segment - as defined by IFRS 8 'Operating segments.

E&E costs are initially capitalised within 'Intangible assets'. Such E&E 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 an area, which are expensed directly to the statement of comprehensive income as they are incurred. Plant and equipment assets acquired for use in exploration and evaluation activities are classified as property, plant and equipment.

However, to the extent that such an asset is consumed in developing an unproven oil and gas asset, the amount reflecting that consumption is recorded as part of the cost of the unproven oil and gas asset.

Exploration and unproven oil and gas assets related to each exploration license/prospect are not amortised but are carried forward until the technical feasibility and commercial feasibility of extracting a mineral resource are demonstrated.

Impairment of Exploration and Evaluation assets

All capitalised exploration and evaluation assets and property, plant and equipment are monitored for indications of impairment. Where a potential impairment is indicated, assessment is made for the Group of assets representing a cash generating unit.

In accordance with IFRS 6 the Group firstly considers the following facts and circumstances in their assessment of whether the Group's exploration and evaluation assets may be impaired, whether:

· the period for which the Group has the right to explore in a specific area has expired during the period or will expire in the near future, and is not expected to be renewed;

· unexpected geological occurrences render the resource uneconomic;

· a significant fall in realised prices or oil and gas price benchmarks render the project uneconomic; or

· an increase in operating costs occurs.

If any such facts or circumstances are noted, the Group perform an impairment test in accordance with the provisions of IAS 36.

The aggregate carrying value is compared against the expected recoverable amount of the cash generating unit. The recoverable amount is the higher of value in use and the fair value less costs to sell. An impairment loss is reversed if the asset's or cash-generating unit's recoverable amount exceeds its carrying amount. A reversal of impairment loss is recognised in the profit or loss immediately.

Property, plant and equipment - development and production (D&P) assets

Capitalisation

The costs associated with determining the existence of commercial reserves are capitalised in accordance with the preceding policy and transferred to property, plant and equipment as development assets following impairment testing. All costs incurred after the technical feasibility and commercial viability of producing hydrocarbons have been demonstrated are capitalised within development assets on a field-by-field basis. Subsequent expenditure is only capitalised where it either enhances the economic benefits of the development asset or replaces part of the existing development asset (where the remaining cost of the original part is expensed through the income statement). Costs of borrowing related to the ongoing construction of development and production assets and facilities are capitalised during the construction phase. Capitalisation of interest ceases once an asset is ready for production.

Depreciation

Capitalised oil assets are not subject to depreciation until commercial production starts. Depreciation is calculated on a unit-of-production basis in order to write off the cost of an asset as the reserves that it represents are produced and sold. Any periodic reassessment of reserves will affect the depreciation rate on a prospective basis. The unit-of-production depreciation rate is calculated on a field-by-field basis using proved, developed reserves as the denominator and capitalised costs as the numerator. The numerator includes an estimate of the costs expected to be incurred to bring proved, developed, not-producing reserves into production. Infrastructure that is common to a number of fields, such as gathering systems, treatment plants and pipelines are depreciated on a unit-of-production basis using an aggregate measure of reserves or on a straight line basis depending on the expected pattern of use of the underlying asset.

Proven oil and gas properties

Oil and gas properties are stated at cost less accumulated depreciation and impairment losses. The initial cost comprises the purchase price or construction cost including any directly attributable cost of bringing the asset into operation and any estimated decommissioning provision.

Once a project reaches the stage of commercial production and production permits are received, the carrying values of the relevant exploration and evaluation asset are assessed for impairment and transferred to proven oil and gas properties and included within property plant and equipment.

Proven oil and gas properties are accounted for in accordance with provisions of the cost model under IAS 16 "Property Plant and Equipment" and are depleted on unit of production basis based on the estimated proven and probable reserves of the pool to which they relate.

Impairment of development and production assets

A review is performed for any indication that the value of the Group's D&P assets may be impaired such as:

· significant changes with an adverse effect in the market or economic conditions which will impact the assets; or

· obsolescence or physical damage of an asset; or

· an asset becoming idle or plans to dispose of the asset before the previously expected date; or

· evidence is available from internal reporting that indicates that the economic performance of an asset is or will be worse than expected.

For D&P assets when there are such indications, an impairment test is carried out on the CGU. CGUs are identified in accordance with IAS 36 'Impairment of Assets', where cash flows are largely independent of other significant asset Groups and are normally, but not always, single development or production areas. When an impairment is identified, the depletion is charged through the Consolidated Statement of Comprehensive Income if the net book value of capitalised costs relating to the CGU exceeds the associated estimated future discounted cash flows of the related commercial oil reserves.

The CGU's identified by the company are Corporate along with West Rustavi, Rustaveli, Satskhenisi and Norio given they are independent projects under individual Production Sharing Contracts ("PSCs"). An assessment is made at each reporting as to whether there is any indication that previously recognised impairment charges may no longer exist or may have decreased. If such an indication exists, the Group estimates the recoverable amount. A previously recognised impairment charge is reversed only if there has been a change in the estimates used to determine the assets recoverable amount since the last impairment charge was recognised. If this is the case the carrying amount of the asset is increased to its recoverable amount, not to exceed the carrying amount that would have been determined, net of depreciation, had no impairment charges been recognised for the asset in prior years.

Property, plant and equipment and depreciation

Property, plant and equipment which are awaiting use in the drilling campaigns, and storage, are recorded at historical cost less accumulated depreciation. Property, plant and equipment are depreciated using the straight line method over their estimated useful lives, as follows:

· PP&E - 6 years

The carrying value of Property, plant and equipment is assessed annually and any impairment charge is charged to the Consolidated Statement of Comprehensive income.

Leases

In the current year, the Group adopted 'IFRS 16: Leases', which requires operating and finance leases to be accounted for in a consistent manner. There was no material impact on the Group from the adoption of this standard year-on-year.

The Group assesses whether a contract is or contains a lease, at inception of the contract. The Group recognises a right-of-use asset and a corresponding lease liability with respect to all lease arrangements in which it is the lessee, except for short-term leases (defined as leases with a lease term of 12 months or less) and leases of low value assets (such as tablets and personal computers, small items of office furniture and telephones). For these leases, the Group recognises the lease payments as an operating expense on a straight-line basis over the term of the lease unless another systematic basis is more representative of the time pattern in which economic benefits from the leased assets are consumed.

Inventories

Crude oil inventories are stated at the lower of cost and net realisable value. The cost of crude oil is the cost of production, including direct labour and materials, depreciation and an appropriate portion of fixed overheads allocated based on normal operating capacity of the production facilities, determined on a weighted average cost basis. Net realisable value of crude oil is based on the market price of similar crude oil at the balance sheet date and costs to sell, adjusted if the sale of inventories after that date gives additional evidence about its net realisable value at the balance sheet date.

The cost of crude oil is expensed in the period in which the related revenue is recognised.

Inventories of drilling tubulars and drilling chemicals are valued at the lower of cost or net realisable value, where cost represents the weighted average unit cost for inventory lines on a line by line basis. Cost comprises all costs of purchase, costs of conversion and other costs incurred in bringing the inventories to their present location and condition.

Decommissioning provision

Provisions for decommissioning are recognised in full when wells have been suspended or facilities have been installed.

A corresponding amount equivalent to the provision is also recognised as part of the cost of either the related oil and gas exploration and evaluation asset or property, plant and equipment as appropriate. The amount recognised is the estimated cost of decommissioning, discounted to its net present value, and is reassessed each year in accordance with local conditions and requirements.

Changes in the estimated timing of decommissioning or decommissioning cost estimates are dealt with prospectively by recording an adjustment to the provision, and a corresponding adjustment to the related asset.

The unwinding of the discount on the decommissioning provision is included as a finance cost.

Taxation and deferred tax

Income tax expense represents the sum of the current tax and deferred tax charge for the period.

The Group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the reporting date.

Deferred tax is recognised on differences between the carrying amounts of assets and liabilities in the financial information and the corresponding tax bases and is accounted for using the balance sheet liability method.

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.

Judgement is applied in making assumptions about future taxable income, including oil and gas prices, production, rehabilitation costs and expenditure to determine the extent to which the Group recognises deferred tax assets, as well as the anticipated timing of the utilisation of the losses.

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

Foreign currencies

Monetary assets and liabilities denominated in foreign currencies are translated into US dollars at the rates of exchange prevailing at the reporting date: $1.3523/£1 (2020: $1.3678/£1). Transactions in foreign currencies are translated at the exchange rate ruling at the date of the transaction. Exchange differences are taken to the Statement of Comprehensive Income.

The Company's functional currency is the pound sterling and its presentational currency is the US dollar and accordingly the financial statements have also been prepared in US dollars. The functional currencies of Block Norioskhevi Ltd, Satskhenisi Limited, Georgia New Ventures Inc and Block Rustaveli Limited are the US dollar and the functional currencies of their branches in Georgia are the Georgian Lari.

Foreign operations

The assets are translated into US dollars at the exchange rate at the reporting date and income and expenses of the foreign operations are translated at the average exchange rates. Exchange differences arising on translation are recognised in other comprehensive income and presented in the other reserves category in equity.

Determination of functional currency and presentational currency

The determination of an entity's functional currency is assessed on an entity by entity basis. A company's functional currency is defined as the currency of the primary economic environment in which the entity operates. The functional currency of the Parent Company is the pound sterling, because it operates in the UK, where the majority of its transactions are in pounds sterling. The functional currencies of Block Norioskhevi Ltd, Satskhenisi Limited, Georgia New Ventures Inc and Block Rustaveli Limited are the US dollar, because the majority of their transactions by value is in US dollars, and the functional currencies of their branches in Georgia are the Georgian Lari, because the majority of their transactions by value is in Georgian Lari.

The presentational currency of the Group for year ended 31 December 2021 is US dollars. The presentational currency is an accounting policy choice.

Revenue

Revenue from contracts with customers is recognised when the Group satisfies its performance obligation of transferring control of oil or gas to a customer. Transfer of control is usually concurrent with both transfer of title and the customer taking physical possession of the oil or gas, which is determined by reference to the oil or gas sales agreement. This performance obligation is satisfied at that point in time.

The transaction price is agreed between the Group and the customer, with the amount of revenue recognised being determined by considering the terms of the Production Sharing Contract ("PSC") and the oil sales agreement for each oil sale or the gas sales agreement for each gas sale.

Finance income and expenses

Finance costs are accrued on a time basis, by reference to the principal outstanding and at the effective interest rate applicable. Finance expenses comprise interest or finance costs on borrowings.

Financial instruments

The amendments to IFRS 9 clarify that for the purpose of assessing whether a prepayment feature meets the 'solely payments of principal and interest' (SPPI) condition, the party exercising the option may pay or receive reasonable compensation for the prepayment irrespective of the reason for prepayment. In other words, financial assets with prepayment features with negative compensation do not automatically fail SPPI.

Financial assets and financial liabilities are recognised on the Group's balance sheet when the Group becomes party to the contractual provisions of the instrument.

Fair value

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. All assets and liabilities, for which fair value is measured or disclosed in the Financial Statements, are categorised within the fair value hierarchy, described as follows, based on the lowest-level input that is significant to the fair value measurement as a whole:

Level 1 - quoted (unadjusted) market prices in active markets for identical assets or liabilities;

Level 2 - valuation techniques for which the lowest-level input that is significant to the fair value measurement is directly or indirectly observable; and

Level 3 - valuation techniques for which the lowest-level input that is significant to the fair value measurement is unobservable.

Financial assets

Financial assets are initially recognised at fair value, and subsequently measured at amortised cost, less any allowances for losses using the expected credit loss model, being the difference between all contractual cash flows that are due to the Group in accordance with the contract and all the cash flows that the Group expects to receive.

Impairment provisions for receivables from related parties and loans to related parties are recognised based on a forward looking expected credit loss model. The methodology used to determine the amount of the provision is based on whether there has been a significant increase in credit risk since initial recognition of the financial asset.

For those where the credit risk has not increased significantly since initial recognition of the financial asset, twelve month expected credit losses along with gross interest income are recognised. For those for which credit risk has increased significantly, lifetime expected credit losses along with the gross interest income are recognised. For those that are determined to be credit impaired, lifetime expected credit losses along with interest income on a net basis are recognised.

Financial liabilities

Financial liabilities are classified as either financial liabilities at fair value through profit and loss (FVTPL) or as other financial liabilities. The Group derecognises financial liabilities when, and only when, the Group's obligations are discharged or cancelled, or they expire.

Financial liabilities are classified at FVTPL when the financial liability is either held for trading or it is designated at FVTPL. A financial liability is classified as held for trading if it has been incurred principally for the purpose of repurchasing it in the near term or is a derivative that is not a designated or effective hedging instrument.

Financial liabilities at FVTPL are measured at fair value, with any gains or losses arising on changes in fair value recognised in profit or loss. The net gain or loss recognised in profit or loss incorporates any interest paid on the financial liability.

Other financial liabilities, including borrowings, are initially measured at fair value, net of transaction costs and are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis.

The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability, or, where appropriate, a shorter period, to the net carrying amount on initial recognition.

Share based payments

The fair value of options granted to directors and others in respect of services provided is recognised as an expense in the Statement of Comprehensive Income with a corresponding increase in equity reserves - 'other reserves'.

On exercise or cancellation of share options, the proportion of the share based payment reserve relevant to those options is transferred from other reserves to the accumulated deficit. On exercise, equity is also increased by the amount of the proceeds received.

The fair value is measured at grant date and charged over the accounting periods which the option becomes unconditional.

The fair value of options are calculated using the Black-Scholes model, taking into account the terms and conditions upon which the options were granted. Vesting conditions are non-market and there are no market vesting conditions. These vesting conditions are included in the assumptions about the number of options that are expected to vest. At the end of each reporting period, the Company revises its estimate of the number of options that are expected to vest. The exercise price is fixed at the date of grant and no compensation is due at the date of grant. Where equity instruments are granted to persons other than employees, the statement of comprehensive income is charged with the fair value of the goods and services received.

Warrants issued for services rendered are accounted for in accordance with IFRS 2 recognising either the costs of the service if it can be reliably measured or the fair value of the warrant (using the Black-Scholes model). The fair value is recognised as an expense in the accounting period that the warrant is granted and there is no revision to this estimate in future accounting periods.

Warrants issued as part of share issues have been determined as equity instruments under IAS 32. Since the fair value of the shares issued at the same time is equal to the price paid, these warrants, by deduction, are considered to have been issued at nil value.

2. Critical accounting judgments, estimates and assumptions

The Group makes estimates and assumptions regarding the future. Estimates and judgements are continuously evaluated based on historical experiences and other factors, including expectations of future events that are believed to be reasonable under the circumstances. In the future, actual experience may deviate from these estimates and assumptions. The key assumptions concerning the future and other key sources of estimation uncertainty at the reporting date that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are described below.

Recoverable value of Development & Production assets -judgement, estimates and assumptions

Costs capitalised in respect of the Group's development and production assets are required to be assessed for impairment under the provisions of IAS 36. Such an estimate requires the Group to exercise judgement in respect of the indicators of impairment and also in respect of inputs used in the models which are used to support the carrying value of the assets. Such inputs include estimates of oil and gas reserves, production profiles, oil price, oil quality discount, capital expenditure (including an allocation of salary costs), inflation rates, and pre-tax discount rates that reflect current market assessments of (a) the time value of money; and (b) the risks specific to the asset for which the future cash flow estimates have not been adjusted. The directors concluded that there was no indication of impairment in the current year (an impairment of $172,000 on the carrying value of the development and production assets at Satskhenisi oilfield was recognised in the prior year).

Asset Decommissioning Provisions -estimates and assumptions

The Group's activities are subject to various laws and regulations governing the protection of the environment. The Group recognises management's best estimate of the asset decommissioning costs in the period in which they are incurred. Such estimates of costs include pre-tax discount rates that reflect current market assessments of (a) the time value of money; and (b) the risks specific to the asset for which the future cash flow estimates have not been adjusted. Actual costs incurred in future periods could differ materially from the estimates.

Additionally, future changes to environmental laws and regulations, life of development and production assets, estimates and discount rates could affect the carrying amount of this provision. The Board assessed the extent of decommissioning required as at 31 December 2021 and concluded that a provision of $2,040,000 (2020: $1,917,000) should be recognised in respect of future decommissioning obligations at Rustaveli, West Rustavi, Satskhenisi and Norio (refer note 15).

Share Options - estimates and assumptions

Share options issued by the Group relates to the Block Energy Plc Share Option Plan. The grant date fair value of such options is calculated using a Black-Scholes model whose input assumptions are derived from market and other internal estimates.

The key estimates include volatility rates and the expected life of the options, together with the likelihood of non-market performance conditions being achieved. Refer note 23.

Accounting for business combinations and fair value - estimates and assumptions

Business combinations are accounted for at fair value. The assessment of fair value is subjective and depends on a number of assumptions. These assumptions include assessment of discount rates, and the amount and timing of expected future cash flows from assets and liabilities. In addition, the selection of specific valuation methods for individual assets and liabilities requires judgment. The specific valuation methods applied will be driven by the nature of the asset or liability being assessed. The consideration given to a seller for the purchase of a business or a company is accounted for at its fair value. When the consideration given includes elements that are not cash, such as shares or options to acquire shares, the fair value of the consideration given is calculated by reference to the specific nature of the consideration given to the seller. See note 12.

3. Segmental disclosures

IFRS 8 requires segmental information for the Group on the basis of information reported to the chief operating decision maker for decision making purposes. The Company considers this role as being performed by the Board of Directors. The Group's operations are focused on oil and gas development and production activities (Oil Extraction segment) in Georgia and has a corporate head office in the UK (Corporate segment). Based on risks and returns the directors consider that there are two operating segments that they use to assess the Group's performance and allocate resources being the Oil Extraction in Georgia, and the Corporate segment including unallocated costs.

The segmental results are as follows:

4. Revenue

5. Depreciation and Depletion on Oil and Gas assets

6. Expenses by nature

7. Directors and employees

The share based payments comprised the fair value of options granted to directors and employees in respect of services provided.

Wages and salaries include amounts that are recharged between subsidiaries. Some of these costs are then capitalised as development and production assets and others are administration expenses.

The average monthly number of employees during 2021 was 176 (2020:102) split as follows:

Key management and personnel are considered to be the directors.

8. Finance Income

9. Other income

During the year, materials to be used in the construction of the gas pipeline from the Early Production Facility at West Rustavi were sold for $5,000 (2020: $100,000).

10. Taxation

Based on the results for the year, there is no charge to UK or foreign tax. This is reconciled to the accounting loss as follows:

The Group offsets deferred tax assets and liabilities if, and only if, it has a legally enforceable right to offset current tax assets and current tax liabilities and the deferred tax assets and deferred tax liabilities related to corporation taxes levied by the same tax authority. Due to the tax rates applicable in the jurisdictions of the Group's subsidiary entities (being 0%) no deferred tax liabilities or assets are considered to arise.

For any other jurisdictions which the Group has not recognised deferred income tax assets for tax losses carried forward for entities in which it is not considered probable that there will be sufficient future taxable profits available for offset. Unrecognised deferred income tax assets related to unused tax losses. The Company has UK corporation tax losses available to carry forward against future profits of approximately$18,591,000 (2020: $13,808,000).

11. Loss per share

The calculation for loss per Ordinary Share (basic and diluted) is based on the consolidated loss attributable to the equity shareholders of the Company is as follows:

Loss and diluted loss per Ordinary Share are calculated using the weighted average number of Ordinary Shares in issue during the year. Diluted share loss per share has not been calculated as the options and warrants have no dilutive effect given the loss arising in the year.

12. Acquisition of Subsidiaries and associated PSC interests

Acquisition of Block Rustaveli Limited ("BRL") in prior year

On 23 November 2020, the Company acquired 100% of the share capital of Schlumberger Rustaveli Company Limited ("SRCL"). The completion of the acquisition means the Company now holds licences for Georgian onshore blocks IX and XIB. The Company changed the name of the acquired company to Block Rustaveli Limited on 9 December 2020. The principal activity is oil and gas extraction and it was acquired for the purposes of expanding the Company's production and development business in Georgia.

On acquisition, the Company issued Schlumberger one US dollar and an option to acquire 120 million 0.25p Ordinary Shares in Block Energy Plc, at a nil exercise price, representing 16% of Block's enlarged ordinary share capital (at 31 December 2020). The Options are exercisable between 12 and 24 months from 23 November 2020.

The fair value of the 120 million share options issued was based on the published closing price of the Ordinary Shares in Block Energy Plc on 23 November 2020 of 4.45p per share. Following the acquisition, the finalisation of the completion statement led to a payment by Schlumberger of $278,190 to Block Energy Plc, which has been recognised as a reduction in the fair value of the consideration paid by Block Energy Plc for this acquisition, because the payment was a contractual working capital adjustment to compensate Block Energy Plc for liabilities that were deemed to be for the seller's account.

Under IFRS 3, a business must have three elements: inputs, processes and outputs. BRL has these three elements and, therefore, this transaction has been accounted for as a business combination.

The amounts recognised in respect of the identifiable assets acquired and liabilities assumed of the business combination are as set out in the table below:

Since the acquisition of BRL on 23 November 2020, BRL contributed $308,000 and $183,000 in the year ended 31 December 2020 to the Group revenue and loss respectively. If the acquisition had occurred on 1 January 2020, consolidated pro-forma revenue and loss for the year ended 31 December 2020 would have been $483,000 and $7,534,000 respectively.

All of the identifiable assets acquired and liabilities assumed were fair valued. PP&E and spare parts inventory were fair valued based on the items' condition and application of an industry accepted discount to the original cost. The oil inventory was fair valued by management based on the net realisable value at the acquisition date. Given the subjectivity in valuing undeveloped reserves and unevaluated acreage, a market approach was used to fair value the development and production assets, whereby the seller marketed the business for sale and the acquisition price paid was deemed to be the fair value of the sum of the identifiable assets acquired and liabilities assumed. Therefore, the fair value of the development and production assets was calculated as the difference between the acquisition price paid and the fair value of the other identifiable assets acquired and liabilities assumed.

13.  Property, Plant and Equipment

Carrying amount of property plant and equipment by cash generative unit:

At the end of the current year, the directors concluded there were no impairment indicators in the current year that warranted impairment testing to be prepared with respect to the carrying value of the assets of the Group.

14.  Inventory

Inventories recognised in cost of sales during the year amounted to $(279,000), (2020: $886,000).

15.  Provisions

Decommissioning provisions are based on management estimates of work and the judgement of the directors. By its nature, the detailed scope of work required, and timing of such work is uncertain.

The baseline oil liability arose from the acquisition of BRL during the prior year. Under the production sharing contract for Block XIB, BRL is obliged to deliver a certain quantity of oil to the State of Georgia in quarterly instalments by May 2022. As at 31 December 2021, BRL owed 586 tonnes of baseline oil with a present value of $262,000 to the State of Georgia.

16.  Trade and other receivables

In prior year, other receivables included proceeds receivable from the share issue on 30 December 2020 amounting to $1,314,000 and $278,000 receivable from Schlumberger following the Completion Statement and acquisition of BRL.

17.  Cash and cash equivalents

Cash and cash equivalents consist of balances in bank accounts used for normal operational activities. The vast majority of the cash was held at year end in an institution with a Fitch's credit rating of BB-.

18.  Trade and Other Payables

Trade and other payables principally comprise amounts outstanding for corporate services and operational expenditure.

19.  Share capital

On 4 January 2021, the Company issued 617,571 Ordinary Shares to a service provider in lieu of cash settlement for services provided to the Company with a total value of £20,984 ($28,509).

On 12 January 2021, the Company issued 397,904 Ordinary Shares to a Chris Brown, Non-executive Director, on exercise of his nil cost options.

On 1 February 2021, the Company issued 839,996 Ordinary Shares to six service providers in lieu of cash settlement for services provided to the Company with a total value of £29,251 ($40,914).

On 15 February 2021, the Company issued 180,715 Ordinary Shares to a former employee/director on exercise of their nil cost options.

On 1 March 2021, the Company issued 232,248 Ordinary Shares to four service providers in lieu of cash settlement for services provided to the Company with a total value of £7,542 ($10,395).

On 12 March 2021, the Company issued 865,896 Ordinary Shares to Philip Dimmock, Chairman and a Contractor, on exercise of their nil cost options.

On 16 March 2021, the Company issued 4,400,000 Ordinary Shares to Paul Haywood, Executive Director, on exercise of his options, at an exercise price of 2.5 pence per share. Additionally on this date, the Company issued 2,190,707 Ordinary Shares to a service provider in lieu of cash settlement for services provided to the Company with a total value of £72,134 ($100,000).

On 7 April 2021, the Company issued 58,972 Ordinary Shares to one service provider in lieu of cash settlement for services provided to the Company with a total value of £1,717 ($2,372).

On 5 May 2021, the Company issued 171,715 Ordinary Shares to two service providers in lieu of cash settlement for services provided to the Company with a total value of £4,751 ($6,765).

On 7 June 2021, the Company issued 125,696 Ordinary Shares to two service providers in lieu of cash settlement for services provided to the Company with a total value of £3,234 ($4,468).

On 2 July 2021, the Company issued 1,355,805 Ordinary Shares to a former employee on exercise of their nil cost options at a value of $44,269 to the Company as it met the income tax cost of this issue.

On 2 September 2021, the Company issued 62,005 Ordinary Shares to a service provider in lieu of cash settlement for services provided to the Company with a total value of £155 ($209).

On 15 September 2021, the Company issued 24,877,230 Ordinary Shares at their nominal value to the Employee Benefit Trust.

On 4 October 2021, the Company issued 746,668 Ordinary Shares to four service providers in lieu of cash settlement for services provided to the Company with a total value of £20,148 ($27,589).

On 8 October 2021, the Company issued 299,412 Ordinary Shares to a former Director, on exercise of their nil cost options.

On 2 November 2021, the Company issued 262,403 Ordinary Shares to two service providers in lieu of cash settlement for services provided to the Company with a total value of £5,533 ($7,367).

On 5 December 2021, the Company issued 522,489 Ordinary Shares to two service providers in lieu of cash settlement for services provided to the Company with a total value of £8,033 ($10,863).

On 2 June 2020, the Company issued 1,654,824 Ordinary Shares, details of which are set out below:

150,731 Ordinary Shares have been allotted to Philip Dimmock, Chairman, at an average price of 3.98p in settlement of fees amounting to £6,000 due to him and 100,486 Ordinary Shares have been allotted to Chris Brown, Non-Executive Director, at an average price of 3.98p in settlement of fees of £4,000 due to him.

1,124,058 Ordinary Shares have been allotted to two consultants to the Company as settlement for services provided on the Georgian operations during the period from February 2019 to March 2020 with a total value of £57,229.

75,000 Ordinary Shares have been allotted to Timothy Parson, former Non-Executive Director of the Company, as settlement for services provided on the Georgian operations during 2017 with a total value of £3,000.

204,549 Ordinary Shares have been allotted to an adviser to the Company in lieu of cash settlement for services provided to the Company during the two months period from 1 April 2020 to 31 May 2020 with a total value of £3,433.

On 10 June 2020, the Company issued 39,609,348 new Ordinary Shares at their nominal value to the EBT.

On 1 July 2020, the Company issued 188,435 Ordinary Shares to two service providers in lieu of cash settlement for series provided to the Company with a total value £4,417 ($5,513).

On 3 August 2020, the Company issued 407,374 Ordinary Shares of 0.25p each to three service providers in lieu of cash settlement for services provided to the Company with a total value of £10,000 ($13,088).

On 2 September 2020, the Company issued 544,400 Ordinary Shares 0.25p each to three service providers in lieu of cash settlement for services provided to the Company with a total value of £13,184 ($17,574).

On 2 October 2020, the Company issued 724,433 Ordinary Shares 0.25p each to four service providers in lieu of cash settlement for services provided to the Company with a total value of £19,212 ($24,853).

On 2 November 2020, the Company issued 450,451 Ordinary Shares 0.25p each to four service providers in lieu of cash settlement for services provided to the Company with a total value of £11,268 ($14,565).

On 2 December 2020, the Company issued 524,076 Ordinary Shares 0.25p each to seven service providers in lieu of cash settlement for services provided to the Company with a total value of £15,819 ($21,177).

On 30 December 2020, the Company raised gross proceeds of £5,280,000 ($7,068,287) through the placing of 176,000,000 Ordinary Shares at 3p per share.

The Ordinary Shares consist of full voting, dividend and capital distribution rights and they do not confer any rights for redemption. The Deferred Shares have no entitlement to receive dividends or to participate in any way in the income or profits of the Company, nor is there entitlement to receive notice of, speak at, or vote at any general meeting or annual general meeting.

20.  Share premium account

21.  Reserves

The following describes the nature and purpose of each reserve within owners' equity.

22.  Warrants

As at 31 December 2021, all warrants were available to exercise and were exercisable at prices between 3p and 12.5p (31 December 2020: 3p and 12.5p). The weighted average life of the warrants is 2.65 years (31 December 2020: 3.6 years). No new warrants were issued and no existing warrants were exercised or lapsed during the year. The additions during the prior year represent warrants issued with 5 year terms. The fair value of additions during the year was $nil (2020: $376,000).

23.  Share based payments

During the year, the Group operated a Block Energy Plc Share Option Plan (Share Option Scheme).

Under IFRS 2, an expense is recognised in the statement of comprehensive income for share based payments, to recognise their fair value at the date of grant. The application of IFRS 2 gave rise to a charge of $1,494,000 for the year ended 31 December 2021. The equivalent charge for the year ended 31 December 2020 was $641,000. The Group recognised total expenses (all of which related to equity settled share-based payment transactions) under the current plans of:

Share Option Scheme

The vesting period varies between 0 days to 3 years. The options expire if they remain unexercised after the exercise period has lapsed and have been valued using the Black Scholes model.

The following table sets out details of all outstanding options granted under the Share Option Scheme.

The weighted average exercise price of the share options exercisable at 31 December 2021 is $0.03 (31 December 2020: $0.01). The weighted average contractual life of the share based payments outstanding at 31 December 2021 is 9.8 years (31 December 2020: 3.6 years).

The estimated fair values of options which fall under IFRS 2, and the inputs used in the Black-Scholes model to calculate those fair values are as follows:

All share based payment charges are calculated using the fair value of options.

For the options granted prior to 30 June 2018, expected volatility was determined by reviewing benchmark values from comparator companies. For the options granted after 30 June 2018, expected volatility was determined by reference to the volatility of historic trading prices of the Company's shares.

24.  Financial instruments

Capital Risk Management

The Company manages its capital to ensure that entities in the Group will be able to continue as a going concern while maximising the return to stakeholders. The overall strategy of the Company and the Group is to minimise costs and liquidity risk.

The capital structure of the Group consists of equity attributable to equity holders of the parent, comprising issued share capital, foreign exchange and other reserves and retained earnings as disclosed in the Consolidated Statement of Changes of Equity.

The Group is exposed to a number of risks through its normal operations, the most significant of which are interest, credit, foreign exchange and liquidity risks. The management of these risks is vested to the Board of Directors.

The sensitivity has been prepared assuming the liability outstanding was outstanding for the whole period. In all cases presented, a negative number in profit and loss represents an increase in finance expense / decrease in interest income.

Fair Value Measurements Recognised in the Statement of Financial Position

The following provides an analysis of the Group's financial instruments that are measured subsequent to initial recognition at fair value, grouped into Levels 1 & 2 based on the degree to which the fair value is observable.

- Level 1 fair value measurements are those derived from inputs other than quoted prices that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices).

- Level 2 fair value measurements are those derived from valuation techniques that include inputs for the asset or liability that are not based on observable market data (unobservable inputs).

- Level 3 assets are assets whose fair value cannot be determined by using observable inputs or measures, such as market prices or models. Level 3 assets are typically very illiquid, and fair values can only be calculated using estimates or risk-adjusted value ranges.

Credit risk

Credit risk is the risk that the Group will suffer a financial loss as a result of another party failing to discharge an obligation and arises from cash and other liquid investments deposited with banks and financial institutions and receivables from the sale of crude oil.

For deposits lodged at banks and financial institutions these are all held through a recognised financial institution. The maximum exposure to credit risk is $1,244,000 (2020: $6,331,000). The Group does not hold any collateral as security.

The carrying value of cash and cash equivalents and financial assets represents the Group's maximum exposure to credit risk at year end. The Group has no material financial assets that are past due.

The Company has made unsecured interest-free loans to its subsidiary companies. Although the loans are repayable on demand, they are unlikely to be repaid until the projects become successful and the subsidiaries start to generate revenues. An assessment of the expected credit loss arising on intercompany loans is detailed in note 6 to the parent Company financial statements.

Market risk

Market risk arises from the Group's use of interest bearing and foreign currency financial instruments. It is the risk that future cash flows of a financial instrument will fluctuate because of changes in interest rates (interest rate risk), and foreign exchange rates (currency risk).

There are no variable interest bearing loans in the Group. No risk therefore identified.

Currency risk

Foreign currency risk can only arise on financial instruments that are denominated in a currency other than the functional currency in which they are measured. Translation-related risks are therefore not included in the assessment of the entity's exposure to currency risks. Translation exposures arise from financial and non-financial items held by an entity (for example, a subsidiary) with a functional currency different from the group's presentation currency. However, foreign currency-denominated inter-company receivables and payables which do not form part of a net investment in a foreign operation would be included in the sensitivity analysis for foreign currency risks; this is because, even though the balances eliminate in the consolidated balance sheet, the effect on profit or loss of their revaluation under IAS 21 is not fully eliminated.

A 10% increase in the strength of the pound sterling against the US dollar would cause an estimated increase of $480,000 (2020: $629,000 increase) in the loss after tax of the Group for the year ended 31 December 2021, with a 10% weakening causing an equal and opposite decrease. The impact on equity is the same as the impact on loss after tax.

The Group's cash and cash equivalents and liquid investments are mainly held in US dollars, pounds sterling and Georgian Lari. At 31 December 2021, 3% of the Group's cash and cash equivalents and liquid investments were held in pounds sterling, 88% in Georgian Lari and the remainder in US dollars, Euros and Canadian dollars (31 December 2020: 90% in pounds sterling).

Liquidity risk

Liquidity risk arises from the possibility that the Group and its subsidiaries might encounter difficulty in settling its debts or otherwise meeting its obligations related to financial liabilities. In addition to equity funding, additional borrowings have been secured in the past to finance operations. The Company manages this risk by monitoring its financial resources and carefully plans its expenditure programmes. Financial liabilities of the Group comprise trade payables which mature in less than twelve months.

25.  Categories of financial instruments

In terms of financial instruments, these solely comprise of those measured at amortised cost and are as follows: