Trinity Exploration & Production Plc-

Consolidated and Company Financial Statements

(Expressed In United States Dollars)

 

Company Statement of Cash Flows for the year ended 31 December 2020

	Note	2020		2019
		$'000		$'000
Operating Activities
Loss before taxation		(116)		(1,707)
Adjustments for:
Translation differences		--		1
Finance income		(126)		(233)
Share based payment charge		248		221
		6		(1,718)
Changes In Working Capital
Trade and other receivables		(1,074)		(4,015)
Trade and other payables		(27)		6,730
		(1,101)		2,715
Taxation Paid		--		--
Net Cash (Outflow)/Inflow from Operating Activities		(1,095)		997
Financing Activities
Finance income		126		233
Net Cash Inflow from Financing Activities		126		233
(Decrease)/Increase In Cash and Cash Equivalents		(969)		1,230
Cash and Cash Equivalents
At beginning of year		5,286		4,056
(Decrease)/Increase Cash and Cash equivalents		(969)		1,230
At End of Year	20	4,317		5,286

 

 

Trinity Exploration & Production Plc-

Consolidated and Company Financial Statements

(Expressed In United States Dollars)

 

Notes to the Consolidated Financial Statements 31 December 2020

 

1       Background and Summary of significant accounting policies

 

The principal accounting policies applied in the preparation of this consolidated financial information are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated. The financial statements are for the Trinity Exploration & Production plc ("Trinity" or "the Company" or "Parent") and its subsidiaries (together "the Group").

 

Background

 

Trinity is an independent energy company limited by shares and listed on the Alternative Investment Market ("AIM") market of the London Stock Exchange ("LSE"). The Company is incorporated and domiciled in England and the address of the registered office is C/o Pinsent Masons LLP 1 Park Row, Leeds LS1 5AB, United Kingdom ("UK"). The Group is involved in the exploration, development and production of oil reserves in T&T.

 

Basis of preparation

 

The financial information of the Group set out above does not constitute "statutory accounts" for the purposes of Section 435 of the Companies Act 2006. The financial information for the year ended 31 December 2020 has been extracted from the Group's audited financial statements which were approved by the Board of directors on 17 May 2021 and will be delivered to the Registrar of Companies for England and Wales in due course. The financial information for the year ended 31 December 2020 has been extracted from the Group's audited financial statements for that period which have been delivered to the Registrar of Companies for England and Wales.

 

The reports of the auditors on both these financial statements were unqualified, did not include any references to any matters to which the auditors drew attention by way of emphasis without qualifying their report and did not contain a statement under Section 498(2) or Section 498(3) of the Companies Act 2006. Whilst the financial information included in this preliminary announcement has been prepared in accordance with the recognition and measurement criteria of International Financial Reporting Standards ('IFRSs'), this announcement does not itself contain sufficient information to comply with those IFRSs. This financial information has been prepared in accordance with the accounting policies set out in the December 2020 report and financial statements.

 

The Group's financial statements have been prepared and approved by the Board of Directors ("Board") in accordance with International Financial Reporting Standards, International Accounting Standards and Interpretations (collectively "IFRS") applied in accordance with the provisions of the Companies Act 2006. This consolidated financial information has been prepared under the historical cost convention, except certain financial assets and liabilities (including derivative financial instruments) and certain classes of property, plant and equipment - which are measured at fair value through the Consolidated Statement of Comprehensive Income. Accounting policies have been applied consistently, other than where a new accounting policy has been adopted.

 

The preparation of the consolidated financial information in conformity with IFRS requires the use of certain critical accounting estimates. It also requires the Board and Executive Management Team ("EMT") (together "Management") to exercise its judgement in the process of applying the Group's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial information are disclosed in Note 3: Critical Accounting Estimates and Assumptions.

 

The Company has taken advantage of the exemption in Section 408 of the Companies Act 2006 not to present its own income statement or Statement of Comprehensive Income. The loss for the Company for the year was $0.04 million (2019: $1.7 million loss).

 

Prior year comparatives

 

During the year ended 31 December 2020 a classification error was identified in the prior year Consolidated Statement of Cash Flows, whereby cash flows from investing activities included non-cash accruals which were not adjusted from changes in working capital. As a result the net cash inflow from operating activities and net cash outflow from investing activities were both overstated by $1.2 million. To correct the error, amounts in the prior year consolidated financial statements have been reclassified, resulting in a $1.2 million decrease in net cash inflows from operations and a $1.2 million decrease in net cash outflows from investing activities. There is no profit or net asset impact as a result of the prior year restatement. See note 33 for further details.

 

Going Concern

 

The Board have adopted the going concern basis in preparing the Financial Statements.

 

In making their going concern assessment, the Board have considered the Group's current financial position, budget and cash flow forecast.  The past twelve months has seen the Group's measured response to the COVID-19 pandemic where there were no forced shut-ins or interruptions affecting the Group's operations.  The Board have considered the continued potential impact of the COVID-19 pandemic on the Group's operational capabilities, liquidity and financial position over the next twelve month period and beyond. The going concern assessment has considered the current measures put in place by the Group to preserve cash and the ability to reduce discretionary expenditure during a period when the Group has to adapt to a volatile oil price environment.

 

The Group started 2021 with a strong operating and financial position; 2020 average production of 3,226 barrels of oil per day ("bopd") (2019: 3,007 bopd), cash in hand and at bank of $20.2 million as at 31 December 2020 (2019: $13.8 million), and Derivative financial instruments in place protecting a significant proportion of near-term production.  In making their going concern assessment, the Board have considered a cash flow forecast based on expected future oil prices, production volumes and discretionary expenditure reductions which could be implemented in response to oil price volatility.  The base case forecast was prepared with consideration of the following:

 

·      Future oil prices assumed to be in line with the forward curve prevailing as at May 2021, with an average realised oil price of $58.6/bbl in the period to December 2021.  The forward price curve applied in the cash flow forecast starts at $59.5/bbl in May 2021, fluctuating each month down  to $57.3/bbl in December 2021 through to $55.3/bbl in June 2022

·      Average forecast production for the year to December 2021 of 3,067 bopd and for the six months to June 2022 of 3,057 bopd with production being maintained by Recompletions ("RCPs"), Workovers ("WOs") and swabbing activities and no new drilling;

·      No SPT incurred on the onshore assets, as the SPT threshold for small onshore has been increased to $75.0/bbl;

·      The purchase of Onshore PS 4 block being completed;

·      Trinity continuing with various growth and business development opportunities; and

·      Although derivative instruments are in place to protect a portion of cashflows against declining oil prices, no derivative income is assumed to be received over the forecast period.

 

Management considers this is a reasonable base scenario, reflecting the outlook of the future oil price, current production profile and costs. The cash flow forecast showed that the Group will remain in a strong financial position for at least the next twelve months, and as such being able to meet its liabilities as they fall due. 

 

Management has considered separate stressed scenarios including:

 

·      the effect of reductions in oil prices as low as $10.0/bbl being sustained across the forecast period, noting that the base case pricing is in line with market prices; and

 

·      the impact of temporary disruption from localised COVID-19 cases reducing forecast production by 15%, albeit operations have continued uninterrupted to date and the nature of the operations reduces the risk of such an eventuality.

 

All reasonably possible forecasts demonstrate that the Group's cash balances are maintained under such scenarios and being sufficient to meet the Group's obligations as they fall due.

 

Based on the cash flow forecast, when combined with mitigating actions that are within the Group's control, and having considered the potential impact of COVID-19 pandemic, together with the Government of Trinidad and Tobago's ("GORTT's") response to date, the Board currently believe the Group can maintain sufficient liquidity and a healthy positive cash balance, and remain in operational existence, for at least the next twelve months.

 

As a result, at the date of approval of the financial statements, the Board have a reasonable expectation that the Group has sufficient and adequate resources to continue in existence for at least twelve months post approval of these financial statements and is poised for continued growth as it expects market conditions to improve. For this reason, the Board have concluded it is appropriate to continue to adopt the going concern basis of accounting in the preparation of the consolidated and company financial statements.

 

Changes in accounting policies

 

(a)   New standards, interpretations and amendments adopted from 1 January 2020:

 

New standards impacting the Group that have been adopted in the annual financial statements

for the year ended 31 December 2020 are:

 

•       Definition of a Business (Amendments to IFRS 3); and

•       COVID-19-Related Rent Concessions (Amendments to IFRS 16).

 

The application of these standards has had no impact on the disclosures or the amounts recognised in the Group's consolidated financial statements.

 

Other standards

 

New standards that have been adopted in the annual financial statements for the year ended 31 December 2020, but have not had a significant effect on the Group are:

•       IAS 1 Presentation of Financial Statements and IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors (Amendment - Disclosure Initiative - Definition of Material); and

•       Revisions to the Conceptual Framework for Financial Reporting.

 

 

(b)   New standards, interpretations and amendments not yet effective

 

There are a number of standards, amendments to standards, and interpretations which have been issued by the IASB that are effective in future accounting periods that the Group has decided not to adopt early.

 

The following amendments will become effective for the period beginning 1 January 2022:

 

•       Interest Rate Benchmark Reform - IBOR 'phase 2' (Amendments to IFRS 9, IAS 39 and IFRS 7);

•       Onerous Contracts - Cost of Fulfilling a Contract (Amendments to IAS 37);

•       Property, Plant and Equipment: Proceeds before Intended Use (Amendments to IAS 16); and

•       Annual Improvements to IFRS Standards 2018-2020 (Amendments to IFRS 1, IFRS 9, IFRS 16 and IAS 41).

 

In January 2020, the IASB issued amendments to IAS 1, which clarify the criteria used to determine whether liabilities are classified as current or non-current. These amendments clarify that current or non-current classification is based on whether an entity has a right at the end of the reporting period to defer settlement of the liability for at least twelve months after the reporting period. The amendments also clarify that 'settlement' includes the transfer of cash, goods, services, or equity instruments unless the obligation to transfer equity instruments arises from a conversion feature classified as an equity instrument separately from the liability component of a compound financial instrument.

 

The amendments were originally effective for annual reporting periods beginning on or after 1 January 2022.  However, in May 2020, the effective date was deferred to annual reporting periods beginning on or after 1 January 2023. The Group is currently assessing the impact of these new accounting standards and amendments.

 

Basis of consolidation 

 

The Consolidated Financial Statements comprise the financial statements of the subsidiaries listed in Note 10. The financial information incorporates the financial information of the Group made up to 31 December each year. Control is achieved where the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. The results of subsidiaries acquired or disposed of during the year are included in the Consolidated Statement of Comprehensive Income from the effective date of acquisition and up to the effective date of disposal, as appropriate.

 

The acquisition method of accounting is used to account for the acquisition of subsidiaries by the Group. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date, irrespective of the extent of any non-controlling interest. If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognised directly in the Statement of Comprehensive Income. Costs related to an acquisition are expensed as incurred.

 

Uniform accounting policies have been adopted across the Group. All intra-group transactions, balances, income and expenses are eliminated on consolidation.

 

Share-based payments

 

The Group operates a number of equity-settled, share-based compensation plans comprised of Share Options and Long-Term Incentive Plans ("LTIPs") as consideration for services rendered by the Group's employees. The fair value of the services received in exchange for the grant of share-based payments is recognised as an expense. The total amount to be expensed is determined by reference to the fair value of the options or LTIP awards granted:

•        including any market performance conditions (for example, an entity's share price);

•        excluding the impact of any service and non-market performance vesting conditions; and

•        including the impact of any non-vesting conditions.

 

Non-market performance and service conditions are included in assumptions about the number of share-based payments that are expected to vest. The total expense is recognised over the vesting period, which is the period over which all of the specified vesting conditions are to be satisfied.

 

At the end of each reporting period, the Group revises its estimates of the number of options or LTIP awards that are expected to vest based on the non-market vesting conditions. It recognises the impact of the revision to original estimates, if any, in the Consolidated Statement of Comprehensive Income, with a corresponding adjustment to equity. When the options are exercised, the Group issues new shares. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium.

 

The grant by the Company of options and LTIPs over its equity instruments to the employees of subsidiary undertakings in the Group is treated as a capital contribution. The fair value of employee services received, measured by reference to the grant date fair value, is recognised over the vesting period as an increase to investment in subsidiary undertakings, with a corresponding credit to equity.

 

Foreign currency translation

 

(a)                                                                                  Functional and presentation currency

 

Company:  The functional and presentation currency of the Company is United States Dollars ("USD" or "$").

 

Group:  The functional currencies of the Group operating entities are Trinidad & Tobago Dollars ("TTD") and United States dollars as these are the currencies of the primary economic environment in which the entities operate. The presentation currency is USD which better reflects the Group's business activities and improves the ability of users of the financial statements to compare financial results with others in the international Oil and Gas industry. The Consolidated Statement of Financial Position is translated at the closing rate and Consolidated Statement of Comprehensive Income is translated at the average rate from both USD and Great British Pound ("GBP" or "£") currencies. The following exchange rates have been used in the preparation of these financial statements:

 

	2020		2019
	$	£	$	£
Average rate TTD= $/£	6.758	8.646	6.759	8.617
Closing rate TTD= $/£	6.761	9.213	6.762	8.965

 

                                 

(b)                                                                                  Transactions and balances

 

Foreign currency transactions are translated into the functional currency using the exchange rates at the dates of the transactions. FX gains/losses resulting from the settlement of such transactions and from the translation of monetary assets and liabilities denominated in foreign currencies at year end exchange rates are generally recognised in profit or loss. They are deferred in equity if they relate to qualifying cash flow hedges and qualifying net investment hedges or are attributable to part of the net investment in a foreign operation.

 

Non-monetary items that are measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined. Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss. For example, translation differences on non-monetary assets and liabilities such as equities held at fair value through profit or loss are recognised in profit or loss as part of the fair value gain or loss and translation differences on non-monetary assets.

 

(c)                  Group companies

 

The results and financial position of foreign operations (none of which has the currency of a hyperinflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

-  assets and liabilities for each Statement of Financial Position presented are translated at the closing rate at the date of that Consolidated Statement of Financial Position

-  income and expenses for each statement of profit or loss and Statement of Comprehensive Income are translated at average exchange rates (unless this is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions), and

-  all resulting exchange differences are recognised in other comprehensive income.

 

On consolidation, exchange differences arising from the translation of any net investment in foreign entities, and of borrowings and other financial instruments designated as hedges of such investments, are recognised in other comprehensive income. When a foreign operation is sold or any borrowings forming part of the net investment are repaid, the associated exchange differences are reclassified to profit or loss, as part of the gain or loss on sale.

 

(d)                 Translation differences

 

Differences arising from retranslation of the financial statements at the year-end are recognised in the Translation reserve through "Other comprehensive income".

 

Intangible assets

 

(a)     Exploration and Evaluation ("E&E") assets

i)        Capitalisation

E&E assets are initially classified as intangible assets. Such costs include those directly associated with an exploration area. Upon discovery of commercial reserves capitalisation is recognised within Property, Plant and Equipment.

Oil and natural gas E&E expenditures are accounted for using the successful efforts method of accounting. Under this method, costs are accumulated on a prospect-by-prospect basis and capitalised upon discovery of commercially viable mineral reserves. If the commercial viability is not achieved or achievable, such costs are charged to expense.

Costs incurred in the E&E of assets includes:

-   Licence and property acquisition costs

Exploration and property leasehold acquisition costs are capitalised within E&E assets.

 

-   E&E expenditure

Costs directly associated with an exploration well are capitalised until the determination of reserves is evaluated. Such costs include topographical, geological, geochemical, and geophysical studies, exploratory drilling costs, trenching, sampling and activities in relation to evaluating the technical feasibility and commercial viability of extracting mineral resources. Capitalisation is made within property, plant and equipment or intangible assets according to its nature however a majority of such expenditure is capitalised as an intangible asset. If commercial reserves are found, the costs continue to be carried as an asset. If commercial reserves are not found, E&E expenditures are written off as a dry hole when that determination is made.

 

Once commercial reserves are found, E&E assets are tested for impairment and transferred to development tangible and intangible assets as applicable. No depreciation and/or amortisation are charged during the E&E phase.

 

ii)     Impairment

 

E&E assets are tested for impairment (in accordance with the criteria set out in IFRS 6: Exploration for and Evaluation of Mineral Resources) whenever facts and circumstances indicate impairment. An impairment loss is recognised for the amount by which the E&E assets' carrying amount exceed their recoverable amount. The recoverable amount is the higher of the E&Es assets' Fair Value Less Costs of Disposal ("FVLCD") and their Value In Use ("VIU"). For the purposes of assessing impairment, the E&E assets subject to testing are grouped with existing Cash Generating Units ("CGU") of related production fields located in the same geographical region. The geographical region is the same as that used for reserves reporting purposes.

 

The following indicators are evaluated to determine whether these assets should be tested for impairment:

-  The period for which the Group has the right to explore in the specific area has lapsed.

-  Whether substantive expenditure on further E&E in the specific area is budgeted or planned.

-  Whether E&E in the specific area have not led to the discovery of commercially viable quantities and the Company has decided to discontinue such activities in the specific area; and/or

-  Whether sufficient data exists to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the E&E asset is unlikely to be recovered in full from successful development or by sale.

 

(b)      Computer software

Computer software is initially recognised at cost, once it is purchased. Internally generated software is capitalised once it is proven technological feasibility, probable future benefits, intent and ability to use the software, resources to complete the software, and ability to measure cost. It is amortised over its four year useful life, based on pattern of benefits (straight-line is the default) and charge recognised under DD&A.

 

Property, plant and equipment

 

(a)      Oil & Gas Assets

i)      Development and Producing Assets - Capitalisation

Development expenditures are costs incurred to obtain access to proven reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. These costs include transfers from E&Es subsequent to finding commercially viable reserves, development drilling and new reserve type, infrastructure costs and development Geological and Geophysical ("G&G") costs. Acquisitions of oil and gas properties are accounted for under the acquisition method where the transaction meets the definition of a business combination.

Transactions involving the purchases of an individual field interest, or a group of field interests, that do not meet the definition of a business (and therefore do not apply business combination accounting) are treated as asset purchases, irrespective of whether the specific transactions involve the transfer of the field interests directly, or the transfer of an incorporated entity. Accordingly, the consideration is allocated to the assets and liabilities purchased on a relative fair value basis.

 

Proceeds on disposal are applied to the carrying amount of the specific asset or development and production assets disposed of. Any excess is recorded as a gain on disposal in the Consolidated Statement of Comprehensive Income and any shortfall between the proceeds and the carrying amount is recorded as a loss on disposal in the Consolidated Statement of Comprehensive Income.

 

Development expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development commercially proven wells is capitalised according to its nature. When development is completed on a specific field it is transferred to Production Assets. No depreciation and/or amortisation are charged during the development phase.

 

Expenditure on G&G surveys used to locate and identify properties with the potential to produce commercial quantities of oil and gas as well as to determine the optimal location for development wells are capitalised.

ii)     Development and Producing Assets - Impairment

 

An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount. Impairment triggers include but are not limited to, declining long term market prices for oil and gas, significant downward reserve revisions, increased regulations or fiscal changes, market capitalisation being below net assets, deteriorating local conditions such that it become unsafe to continue operations) and obsolescence.

 

The carrying value is compared against the expected recoverable amount. The recoverable amount is the higher of an asset's FVLCD and the VIU. For the purposes of assessing impairment, assets are grouped at the lowest levels (its CGU) for which there are separately identifiable cash flows. The CGU applied for impairment test purposes is generally the field. These fields are the same as that used for reserves reporting purposes.

 

iii)    Producing Assets - DD&A

The provision for DD&A of developed and producing Oil & Gas Assets are calculated using the unit-of-production method. Oil & Gas Assets are depreciated generally on a field-by-field basis using the unit-of-production method which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future development costs. Changes in the estimates of commercial reserves or future development costs are dealt with prospectively. 

 

iv)    Decommissioning asset

 

Provision for decommissioning is recognised in accordance with the contractual obligations at the commencement of oil and gas production. The amount recognised is the net present value of the estimated cost of decommissioning at the end of the economic producing lives of the wells and the end of the useful lives of refinery and storage units. Such costs include removal of equipment and restoration of land or seabed. The unwinding of the discount on the provision is included in the Consolidated Statement of Comprehensive Income within finance costs.

 

A corresponding asset is also created at an amount equal to the provision. This is subsequently depleted as part of the capital costs of the production assets. Any change in the present value of the estimated expenditure or discount rates are reflected as an adjustment to the provision and the asset and dealt with prospectively.

 

(b)      Non-Oil & Gas Assets

All property, plant and equipment are recorded at historical cost less accumulated depreciation and any impairment losses. Historical cost includes the original purchase price of the asset and expenditure that is directly attributable to bringing the asset to its working condition for its intended use. Subsequent costs are included in the asset's carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably.

The provision for depreciation with respect to operations other than oil and gas producing activities is computed using the straight-line method based on estimated useful lives as follows:

 

Leasehold and buildings	20 years
Plant and equipment	4 years
Other	4 years

 

The assets' residual values and useful lives are reviewed and adjusted if appropriate at each Statement of Financial Position date. An asset's carrying amount is written down immediately to its recoverable amount if the asset's carrying amount is greater than its estimated recoverable amount. Gains and losses on disposals are determined by comparing proceeds with carrying amounts and are included in the Consolidated Statement of Comprehensive Income.

 

Repairs and maintenance are charged to the Consolidated Statement of Comprehensive Income during the financial period in which they are incurred. The cost of major renovations is included in the carrying amount of the asset when it is probable that future economic benefits in excess of the originally assessed standard of performance of the existing assets will flow to the Group. Major renovations such as leasehold improvements are depreciated over the remaining useful life of the related asset.

 

Impairment of non-financial assets

At each reporting date, assets that are subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's FVLCD and VIU. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (CGUs). Non-financial assets that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.

 

Inventories

Crude oil is stated at the lower of cost and net realisable value. Cost is determined by the average cost method. Net realisable value is the estimated selling price in the ordinary course of business, less applicable variable selling expenses. Materials and supplies used mainly in drilling wells, RCPs and WOs are stated at lower of cost and net realisable value. Cost is determined using the weighted average cost method.

 

Cash and Cash equivalents

For the purpose of presentation in the Consolidated Statement of Cash Flows, Cash and Cash equivalents includes cash on hand, deposits held at call with financial institutions, other short-term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.

 

Trade receivables

Trade receivables are amounts due from customers for crude oil sold in the ordinary course of business. They are generally due for settlement within thirty days and therefore are all classified as current. Trade receivables are recognised initially at the amount of consideration that is unconditional unless they contain significant financing components, when they are recognised at fair value.

 

The Group applies the simplified approach to determine impairment of trade receivables. The simplified approach requires expected lifetime losses to be recognised from initial recognition of the receivables. This involves determining the expected loss rates using a provision matrix that is based on the historical default rates observed over the expected life of the receivable and adjusted forward-looking estimates. This is then applied to the gross carrying amount of the receivable to arrive at the lost allowance for the period.

 

Trade payables

Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.

 

Impairment of Financial Assets

 

The financial assets within the Group are subject to the Expected Credit Losses ("ECL") model. However, the Group applies the ECL model to trade receivables for sales of inventory and from the provision of consulting services as well as Intercompany receivables.  While Cash and Cash equivalents are also subject to the impairment requirements of IFRS 9, the identified impairment loss was immaterial.

 

(i)     Trade receivables

 

The Group applies the IFRS 9 simplified approach to measuring ECL which uses a lifetime expected loss allowance for all trade receivables.

 

Financial assets recognition of impairment provisions under IFRS 9 is based on the ECL model. The ECL model is applicable to financial assets classified at amortised cost and contract assets under IFRS 15: Revenue from Contracts with Customers. The measurement of ECL reflects an unbiased and probability weighted amount that is available without undue cost or effort at the reporting date, about past events, current conditions and forecasts of future economic conditions. The Group applied the simplified approach to determine impairment of its trade and other receivables. The simplified approach requires expected lifetime losses to be recognised from initial recognition of the receivables. This involves determining the expected loss rates using a provision matrix that is based on the Group's historical default rates observed over the expected life of the receivables and adjusted forward looking estimates. This is then applied to the gross carrying amount of the receivables to arrive at the loss allowance for the period.

 

(ii)    Intercompany receivables

 

The Company applies IFRS 9 through the recognition of ECL for intercompany. Intercompany positions eliminate in the consolidated financial statements. In measurement of the ECL, IFRS 9 notes that the maximum period over which expected impairment losses is measured is the longest contractual period where the Company is exposed to credit risk. The three stage general impairment model was used, Probability of Default ("PD") x Loss Given Default ("LGD") x Exposure at Default ("EAD"). Measurement of the ECL at a probability-weighted amount that reflects the possibility of a credit loss occurs, and the possibility that no credit loss occurs and even if the possibility of a credit loss occurring is low.

 

Income tax

 

The income tax expense or credit for the period is the tax payable on the current period's taxable income based on the applicable income tax rate for each jurisdiction adjusted by changes in DTA and DTL attributable to temporary differences and to unused tax losses.

 

The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the end of the reporting period in the countries where the Company's subsidiaries and associates operate and generate taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities.

 

Deferred income tax is provided in full, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial statements. However, DTL are not recognised if they arise from the initial recognition of goodwill. Deferred income tax is also not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit/loss. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the end of the reporting period and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.

 

DTA are recognised only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses.

 

DTL and DTA are not recognised for temporary differences between the carrying amount and tax bases of investments in foreign operations where the Company is able to control the timing of the reversal of the temporary differences and it is probable that the differences will not reverse in the foreseeable future.

 

DTA and DTL are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the deferred tax balances relate to the same taxation authority. Current tax assets and tax liabilities are offset where the entity has a legally enforceable right to offset and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.

 

Current and deferred tax is recognised in profit or loss, except to the extent that it relates to items recognised in other comprehensive income or directly in equity. In this case, the tax is also recognised in other comprehensive income or directly in equity, respectively.

 

Property Tax ("PT")

 

PT is recognised initially at fair value and subsequently measured at amortised cost using the effective interest method. Assessments are based on the Annual Rental Value ("ARV") of property. The Annual Taxable Value ("ATV") is the ARV subject to deductions and allowances in respect of voids and loss of rent multiplied by the respective PT rate. The PT rates applicable to the Group are industrial with building rates at 6% and industrial without building rates at 3%.

 

Revenue recognition

 

IFRS 15 Revenue from Contracts with Customers requires that revenue is recognised by performance obligation, as or when each performance obligation is satisfied, and that variable elements of pricing are recognised and to the extent that it is not highly probable they will be reversed.

 

The Group has evaluated its customer contract with the Heritage Petroleum Company Limited ("Heritage"), formerly the Petroleum Company of Trinidad and Tobago Limited ("Petrotrin"), to identify the performance obligations, the timing of the revenue recognition and the treatment of variable elements of pricing. Sales revenue represents the sales value of the Group's oil sold in the year.

 

Revenue associated with the sale of crude oil is measured based on the consideration specified in contracts with customers.

 

Revenue is recognised when control is transferred from the Group to its customer and the Group has the present right to payment. The transfer of control of crude oil coincides with title passing to the customer and the customer taking physical possession. Typically, payment for the sale of the oil is received by the end of the month following the month in which the sale is recognised.

 

Prices are based on prices determined by Heritage, with agreed contractual adjustments for quality. Revenue is measured at the fair value of the consideration received or receivable, and represents amounts receivable for oil and gas products in the normal course of business.

 

Provisions

Provisions are recognised when the Group has a present legal or constructive obligation as a result of past events, where it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made. Provisions are not recognised for future operating losses. Where there are a number of similar obligations, the likelihood that an outflow will be required in settlement is determined by considering the class of obligations as a whole. A provision is recognised even if the likelihood of an outflow with respect to any one item included in the same class of obligations may be small.

Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to passage of time is recognised as a finance cost.

 

Leases

All leases are accounted for by recognising a right-of-use asset and a lease liability except for:

-      Leases of low value assets; and

-      Leases with a duration of 12 months or less.

 

Lease liabilities were measured at the present value of the contractual payments due to the lessor over the lease term, with the discount rate determined by reference to the group's incremental borrowing rate.  The lease payments are discounted using the Group's incremental borrowing rate, being the rate that the Group would have to pay to borrow the funds necessary to obtain an asset of similar value to the ROU asset in a similar economic environment with similar terms, security and conditions. To determine the incremental borrowing rate, Trinity received an indicative third party lending rate from Central Bank of Trinidad and Tobago.

 

Right of use assets were initially measured at the amount of the lease liability. Subsequent to initial measurement lease liabilities increase as a result of interest charged at a constant rate on the balance outstanding and are reduced for lease payments made.  Right-of-use assets are amortised on a straight-line basis over the remaining term of the lease.

 

In 2020 the Group revised its estimates due to the lease term of the copiers being renewed in August 2020 for an additional 36 months. As a result, there was an adjustment in the carrying amount of the lease liability to reflect the payments to be made over the revised term, which was discounted using a revised discount rate. Equivalent adjustment is made to the carrying value of the right-of-use asset, with the revised carrying amount being amortised over the remaining (revised) lease term.

 

Extension and termination options are included in a few leases entered into by the Group. These are used to maximise operational flexibility in terms of managing the assets used in the Group's operations. The majority of extension options held are exercisable only by the Group and not by the respective lessor. 

 

In determining the lease term, Management considers all facts and circumstances that create an economic incentive to exercise an extension option, or not exercise a termination option. Extension options (or periods after termination options) are only included in the lease term if the lease is reasonably certain to be extended (or not terminated).

 

Share capital

Ordinary shares are classified as equity. The nominal value of any shares issued is recognised in share capital with the excess above the nominal amount paid being shown within share premium.

Incremental costs directly attributable to the issue of new ordinary shares are shown in equity. Where, on issuing shares, share premium has been recognised, the expenses of issuing those shares and any commission paid on the issue of those shares have been written off against the share premium account.

 

Derivative financial Instruments and hedging activities

 

Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re-measured to their fair value at the end of each reporting period. The accounting for subsequent changes in fair value depends on whether the derivative is designated as a hedging instrument, and if so, the nature of the item being hedged. The Group has not applied hedge accounting and all oil price derivative financial instruments (categorised as Derivative Income/(Expenses)) are measured at fair value through profit and loss.

 

Financial assets at fair value through profit or loss are classified in this category if acquired principally for the purpose of selling in the short term. Derivatives are also categorised as held for trading unless they are designated as hedges. Assets in this category are classified as current assets if expected to be settled within twelve months, otherwise they are classified as non-current. Financial assets are derecognised when the rights to the cash flows expire, risks and rewards are transferred or control of the asset is transferred.

 

A financial liability is removed from the Statement of Financial Position only when it is extinguished; that is, when the obligation specified in the contract is discharged, cancelled or expired.

 

Investments

 

Investments are shown at cost less provision for any impairment in value. The Company performs impairment reviews in respect of investments whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. An impairment loss is recognised when the higher of the investment's net realisable value and fair value less cost of disposal is less than the carrying amount.

 

Exceptional Items

 

Exceptional items are disclosed separately in the financial statements where it is necessary to do so to provide further understanding of the financial performance of the Group. They are distinct from routine operations which are material items of income or expense that have been shown separately due to the non-recurring nature and in the significance of their nature or amount.

 

 

2       Financial Risk Management

 

 Financial risk factors

 

The Group's activities expose it to a variety of financial risks. The Group's overall Risk Management program seeks to minimise potential adverse effects on the Group's financial performance.

 

Management is responsible for Group Risk Management and for identifying and evaluating financial risks.

 

(a)     Market risk

 

(i)         Foreign currency ("FX") risk

 

The Group is exposed to FX risk primarily with respect to the United States dollar. FX risk arises from future commercial transactions and recognised assets and liabilities which are denominated in a currency that is not the entity's functional currency.

 

Foreign currency sensitivity

 

The Group is mainly exposed to the currency fluctuations of the US dollar. The sensitivity analysis principally arises on FX gain/loss on translation of the USD denominated receivables. The following table details the Group's sensitivity to a 10% (2019: 10%) increase and decrease in the functional currency (TT Dollar) of the main operating subsidiary against the US Dollar with all other variables held constant. 10% (2019: 10%) is the sensitivity rate that best represents Management's assessment of the possible change in the foreign exchange rates affecting the Group. A positive number below indicates an increase in profit and equity when the US dollar weakens against the functional currency. For a strengthening of the US Dollar against the functional currency, there would be an equal and opposite impact on the profit and equity, and the balances below would be negative.  

 

 

	2020	2019
	$'000	$'000
Profit/(loss) for the year and Equity
10% strengthening of the US Dollar/ (2019: 10%)	(168)	(303)
10% weakening of the US Dollar/ (2019: 10%)	168	303

 

(ii)        Price risk

 

The Group is exposed to commodity price risk regarding its sales of crude oil which is an internationally traded commodity.

 

Price risk sensitivity

 

The Group is a price taker and is mainly exposed to the risk relating to price fluctuations. The following table details the Group's sensitivity to a 20% (2019: 20%) increase and decrease in realised oil prices.  20% (2019 20%) is the sensitivity rate that best represents Management's assessment of the possible change in the oil prices that may affect the Group. A positive number below indicates an increase in revenue, while there would be an equal and opposite impact on revenue if there is a decrease in prices by 20%.

 

	2020	2019
	$'000	$'000
Profit/(loss) for the year
20% increase in price/ (2019: 20%)	11,702	12,701
20% decrease in price/ (2019: 20%)	(11,702)	(12,701)

 

The Group implemented crude derivatives during the financial year, the purpose of which is to offer protection in the event of oil prices declining significantly.

 

(iii)       Cash flow and fair value interest rate risk

 

The Group's main interest rate risk arises from borrowings which expose the Group to cash flow interest rate risk. The Group manages risk by limiting the exposure to floating interest rates and maintaining a balance between floating and fixed contract rates.

 

At 31 December 2020, there were no loan commitments to attract interest rates on foreign currency-denominated borrowings, (2019: nil). During 2020 there was a bank overdraft facility which incurred $0.1 million interest (2019:nil).

 

(b)     Credit risk

 

Credit risk arises from Cash and Cash equivalents, deposits with banks and financial institutions, as well as credit exposures to customers, including outstanding receivables. For banks and financial institutions, Management determines the placement of funds based on its judgement and experience to minimise risk.

 

All sales are made to a state-owned entity, Heritage.

 

The Group applies an IFRS 9 simplified model for measuring the ECL which uses a lifetime expected loss allowance and are measured on the days past due criterion. Having reviewed past payments combined with the credit profile of its existing trade debtors in order to assess the potential for impairment, Management made the decision in keeping with the standard to calculate a provision for long outstanding receivables associated with the Petrotrin outstanding ORR incentive receipts. The ECL for those sales were assessed at the end of the year and was immaterial.  A provision matrix was applied to determine the historical and forward-looking loss rates which was used to ultimately calculate an ECL allowance, which resulted in a provision being made of $0.01 million.

 

For the Heritage sales, the ECL was immaterial as all sales payments were made during the stipulated time frame. However, ECL was also calculated on other receivable balances and a provision of $0.9 million was derived. Similar to sales a provision matrix was applied to determine the historical and forward-looking loss rates which was used to ultimately calculate an ECL allowance.

 

The Company also assessed impairment through the three stage approach to derive at the ECL. Through assessing impairment via this method, a provision amount of $0.1 million was calculated. 

 

(c)     Liquidity risk

 

Prudent liquidity risk management implies maintaining sufficient cash and short-term funds and the availability of funding through an adequate amount of committed credit facilities. Management monitors rolling forecasts of the Group's liquidity and Cash and Cash equivalents on the basis of expected cash flow. At the end of the year the Group held cash at bank of $20.2 million (2019: $13.8 million).

 

Management monitors rolling forecasts of the Group's Cash and Cash equivalents on the basis of expected cash flows. This is carried out at the Group level in accordance with practice and limits set by the Group, refer to the disclosures in Note 1: Background and accounting policies - Going Concern for more information regarding the factors considered by the Company in managing liquidity risk.

 

The table below analyses the Group's and Company's financial liabilities into relevant maturity groupings based on their contractual maturities for:

 

(a)     All non-derivative financial liabilities, and

(b)     Net and gross settled derivative financial instruments for which the contractual maturities are essential for an understanding of the timing of the cash flows.

 

       The following table sets out the contractual maturities (representing undiscounted contractual

cash-flows) of financial liabilities.

 

Group	Less than 1 year	1 to 2 years	2 to 5 years	Total
At 31 December 2020
	$'000	$'000	$'000	$'000
Non-derivatives
Trade and other payables	7,803	--	--	7,803
Lease liabilities	614	442	23	1,079
	8,417	442	23	8,882
At 31 December 2019	$'000	$'000	$'000	$'000
Non-derivatives
Trade and other payables	10,386	--	--	10,386
Lease liabilities	637	447	393	1,477
	11,023	447	393	11,863

 

 

Company	Less than 1 year	Total
At 31 December 2020
	$'000	$'000
Non-derivatives
Trade and other payables	481	481
	481	481
At 31 December 2019	$'000	$'000
Non-derivatives
Trade and other payables	508	508
	508	508

 

 

(d)     Capital risk

 

The Group's objectives when managing capital are to safeguard the Group's ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. In order to maintain or adjust the capital structure, the Group may adjust the amount of dividends paid to shareholders, issue new shares or sell assets to reduce debt.

 

Consistent with others in the industry, the Group monitors capital on the basis of the gearing ratio. This ratio is calculated as net debt divided by total capital. Net Cash/(Debt) is calculated as total borrowings less Cash and Cash equivalents.  Borrowing relates to the overdraft facility where all covenants (current ratio not less than 1.25:1) were met. Total capital is calculated as 'equity' as shown in the Consolidated Statement Of Financial position plus Net Cash/(Debt)

	2020	2019
	$'000	$'000
Net cash	(17,537)	(13,810)
Total equity	48,552	50,425
Total capital	31,015	36,615
Gearing ratio	(56.5)%	(37.7)%

 

(e)     Fair value estimation

 

The Group and Company have classified financial instruments into the three levels prescribed under the accounting standards.

 

§  Level 1: The fair value of financial instruments traded in active markets (such as publicly traded derivatives, and equity securities) is based on quoted market prices at the end of the reporting period. The quoted market price used for financial assets held by the Group is the current bid price. These instruments are included in level 1.

§  Level 2: The fair value of financial instruments that are not traded in an active market (for example, over-the-counter derivatives) is determined using valuation techniques which maximise the use of observable market data and rely as little as possible on entity-specific estimates. If all significant inputs required to fair value an instrument are observable, the instrument is included in level 2. 

§  Level 3: If one or more of the significant inputs is not based on observable market data, the instrument is included in level 3. This is the case for unlisted equity securities. See Note 19 for details.        

 

 

        3. Critical Accounting Estimates and Judgements

 

The preparation of the financial statements requires the use of accounting estimates which, by definition, seldom equal the actual results. Management also exercise judgement in applying the Group's and the Company's accounting policies. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below:

 

(a)   Recoverability of DTA

 

DTA mainly arise from tax losses and are recognised only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those DTA are likely to reverse, and a judgement as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability on key estimates of future cost, production volumes, price and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the level of DTA recognised which can result in a charge or credit during the period in which the change occurs. The Group has concluded that the DTA recognised will be recoverable using approved business plans and budgets for the specific subsidiaries in which the DTA arose. See note 16.

 

(b)   Provision for decommissioning costs

 

      This provision is significantly affected by changes in technology, laws and regulations which may affect the actual cost and timing of decommissioning to be incurred at a future date. The estimate is also impacted by the discount rates used in the provisioning calculations. The discount rates used are the Group's risk-free rate and the core inflation rate applicable. The provision has been estimated using a rate based on maturity and a core inflation rate. See Note 25: Provision for other liabilities

 

	Bands (years)	2020	2019
Risk free rates	9-12	3.14%	2.13%
	13-18	3.17%	3.07%
	19-24	2.42%	2.91%
Inflation rate		2%	2%

      

 

 

The following table details the Group's sensitivity to a 1% (2019: 1%) increase and decrease in discount and inflation rates. 1% (2019 1%) is the sensitivity rate that best represents Management's assessment of the possible change in the rates that may affect the Group. A positive number below indicates an increase in provisions and finance costs, while a negative number indicates a decrease in provisions and finance costs. The impact in 2020 of a 1% change in these variables is as follows:

 

	Consolidated Statement of Financial Position: Obligation	Consolidated Statement of Comprehensive: Income/Expense
	2020	2020
	$'000	$'000
Discount rate
1% increase in assumed rate	(7,790)	181
1% decrease in assumed rate	9,679	(289)
Inflation rate
1% increase in assumed rate	9,638	231
1% decrease in assumed rate	(7,903)	(194)

 

 

 

(c)              Estimation of reserves

 

All reserve estimates involve some degree of uncertainty, which depends chiefly on the amount of reliable geological and engineering data available at the time of the estimate. Generally, reserve estimates are revised as additional data becomes available. The Group's reserve estimates are also evaluated when required by independent external reserve evaluators. The last independent external reserve valuation was done in 2012. Since 2012 up to and including 2020 the Group estimated its own commercial reserves based on information compiled by appropriately qualified persons relating to the geological and technical data on the size, depth, shape and grade of the hydrocarbon body and suitable production techniques and recovery rates.

 

The key assumptions used in the estimation of reserves are as follows:

-  Technical production profiles for the various assets onshore and offshore held by the Group.

-  Economic assumptions such as forecast period, discount rate, crude price, operating cost, capital expenditure and fiscal structure.

 

As the economic assumptions used may change, and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may also change. Such changes may impact the Group's reported financial position and results, which include:

 

-  The carrying value of E&E assets, oil and gas properties, property and plant and equipment, may be affected due to changes in estimated future cash flows. See note 11 and 13.

-  Depreciation and amortisation charges in profit or loss are depreciated on a unit of production basis at a rate calculated by reference to proved and probable ("2P") reserve estimates and incorporating the estimated future cost of developing and extracting those reserves. There may be changes where such charges are determined using the unit of production method, or where the useful life of the related assets change. See note 11 and 13.

-  Provisions for decommissioning may change - where changes to the reserve estimates affect expectations about when such activities will occur and the associated cost of these activities. See note 25.

-  The recognition and carrying value of DTA may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets. See note 16.

 

As at 31 December 2020 all subsidiaries onshore and offshore 2P reserve estimates were re-evaluated by the EMT and approved by the Board.

 

(d)       Impairment of Property, Plant And Equipment

 

Management performs impairment assessments on the Group's property, plant and equipment once there are indicators of impairment. Triggers for impairment relates to changes in the key factors that impact on impairment which are production, oil price, capital expenditures and operating expenditures. In order to test for impairment, the higher of FVLCD and VIU calculations are prepared and an estimate of the timing and amount of cash flows expected respectively to arise from the CGU. A CGU represents an individual field or asset held by the Group. During 2020 an impairment charge of $1.1 million was recognised on the Group's property, plant and equipment (2019: $15.2 million) see Note 11. The impairment charge resulted in the carrying amount of the respective CGUs being written down to their recoverable amount.

 

        Oil & Gas Assets $1.1 million (2019: $15.2 million) impairment

 

Management has carried out an impairment test on the Oil & Gas Assets classified as property, plant and equipment. This test compares the carrying value of the assets at the reporting date with the recoverable amount for each CGU. The recoverable amount is the higher of the FVLCD and VIU. The FVLCD is the amount that a market participant would pay for the CGU less the cost of disposal. The FVLCD approach utilised a discounted cash flow based on the 2P reserve estimates of the CGUs of the Group.  VIU is the present value of the future cash flows expected to be derived from an asset or CGU in its current condition. The period over which Management has projected its cash flow forecast, ranges between 9-24 year economic lives based on the field economic life profile. The field economic life profile was derived by using licence extension data which is permitted in accordance with the Society of Petroleum Engineers ("SPE") reserves reporting guidelines outlined in the 2019 Petroleum Resource Management System ("PRMS"). While there is the risk that licences may not be renewed upon expiry, Management considers this to be very low based on historic precedent.  For the discounted cash flows to be calculated, Management has used a production profile based on its best estimate of proven and probable reserves of each CGU and a range of assumptions, including an external oil and gas price profile and a discount rate which, taking into account other assumptions used in the calculation, Management considers to be reflective of the risks. The impairment calculation considers the decommissioning asset and liability used to derive the impairment charge.

 

The discounted cash flow approach assessment involves judgement as to the likely commerciality of the asset. For the discounted cash flows to be calculated, Management has used a production profile based on its 2P reserve estimate of the assets and a range of assumptions (see note 3(c). Its 2P reserves which are estimated using standard recognised evaluation techniques on a fully funded basis; future revenues and estimated development costs and decommissioning liabilities pertaining to the CGU's; and a discount rate utilised for the purposes of deriving a recoverable value.

 

	2021	2022	2023	2024	2025	2026
Realised price	46.3	44.3	43.0	42.2	41.8	41.8

 

If the price deck used in the impairment calculation had been 10% lower than Management's estimates at 31 December 2020, the Group would have a $1.0 million increase on impairment of Oil & Gas Assets (2019: $3.5 million increase). If the price deck used in the impairment calculation had been 10% higher than Management's estimates at 31 December 2020, the Group would have a $0.6 million decrease on impairment of the Oil & Gas Assets (2019: $6.0 million decrease). The valuation is considered to be a level 3 in the fair value hierarchy due to unobservable inputs used in the valuation.

 

For the year ended 31 December 2020, Management's estimate of the Group's cost of capital was 12% (2019:13%).  If the estimated cost of capital used in determining the post-tax discount rate for the CGU's had been 1% lower than Management's estimates the Group would have a $0.2 million decrease on impairment position for 2020 (2019: $0.7 million decrease) against Oil & Gas Assets within property, plant and equipment. If the estimated cost of capital had been 1% higher than Management's estimates the Group would have a $0.2 million increase on impairment for 2020 (2019: $0.7 million).

 

(e)      Impairment of intangible E&E assets

 

In estimating the recoverability of exploration assets, Management considers contingent resources associated with certain evaluation assets as estimated by the Group's internal experts. Furthermore, Management factors in future development plans and licence expiries into the assessment. Exploration assets remain capitalised as long as sufficient progress is being made in assessing whether petroleum production is technically feasible and commercially viable. This assessment requires significant Management judgement, as exploration assets are subject to regular internal review to confirm the continued intent to establish the technical feasibility and commercial viability of a project. At the end of 2020 a review for impairment triggers was carried out and there were no impairment losses realised against the carrying values of the Group's E&E assets.

 

The Group reviews the carrying values of intangible E&E assets when there are impairment indicators which would tell whether an E&E asset has suffered any impairment. The amounts of intangible E&E assets represent the costs of active projects the commerciality of which is unevaluated until reserves can be appraised.

 

(f)       Property Tax accrual

 

Property Tax is assessed on property owned by the Group in Trinidad and Tobago governed by the Property Tax Act 2009 and later Property Tax (Amendment) Act 2018 of Trinidad and Tobago.  The calculation of the Property Tax is described in note 1 Background and Summary of significant accounting policies.

 

At the end of 2020 the Property Tax accrued for the period 2018 to 2020 within Trade and other payables was $1.5 million (2019: $1.0 million).  Property Tax has been accrued using Management's best estimate, as the administration arrangements of the Property Tax under the Valuation of Land Act is not in place and the actual method for calculating the Property Tax is therefore unavailable.  There is sentiment, based on government communication, that until the administration arrangements are put in place by the Government of Trinidad and Tobago the Property Tax will not be collected over those respective years (2018-2020) and a waiver might be forthcoming. As at 31 December 2020 and the date of this report that waiver has not been enacted and Management's judgement is to continue to assess that a liability is required based on the current tax law enacted. 

 

(g)      Share based payments

 

The Company has in place a share-based compensation plan (the LTIP), for Executive Directors and the EMT which is designed to provide long term incentives to align interests with shareholders.  The Company measures the cost of these equity-settled transactions by reference to the fair value of the equity instruments at the date at which they are granted. The fair value of share-based payments is measured using a Monte Carlo or Black-Scholes option pricing model. The measurement inputs to this model, including expected volatility, weighted average expected life of the instruments, expected dividends and risk-free interest rate, rely on Management judgements. See note 22 for details.

 

4      Segment Information

 

The Steering Committee provides support, guidance and oversight on the progression of the Company through various project that may be undertaken. The committee is led by the Group's chief operating decision-maker. Management has determined the operating segments which are Onshore, West Coast and East Coast reported in a manner consistent with the internal reporting provided to the chief operating decision maker. The chief operating decision maker is responsible for making strategic decisions inclusive of; allocating resources and assessing performance of the operating segments. The chief operating decision maker has been identified as the EMT (which comprises the Executive Chairman, Managing Director, Chief Financial Officer, Chief Operations Officer and Chief of Staff & General Counsel), which makes strategic decisions in accordance with Board policy. 

 

Management have considered the requirements of IFRS 8 Operating Segments, in regard to the determination of operating segments, and concluded that the Group has only one significant operating segment being the exploration and development, production and extraction of hydrocarbons.

 

All revenue is generated from crude oil sales in T&T to one customer, Heritage. All non-current assets of the Group are located in T&T.

 

5      Operating Profit Before Impairment and Exceptional Items

 

	2020 $'000	2019 $'000
Operating profit before exceptional items is stated after taking the following items into account:
DD&A (Note 11)	7,566	9,218
Depreciation on ROU (Note 12)	502	477
Amortisation of computer software (Note 13)	106	77
Employee costs (Note 32)	7,662	7,773
Inventory recognised as expense, charged to operating expenses	330	104

 

Auditors' remuneration

During the year the Group (including its overseas subsidiaries) obtained the following services from the Company's Auditors as detailed below:

 

	2020 $'000	2019 $'000
- Fees payable to the Company's auditors' and their affiliated firms for the audit of the parent Company and consolidated financial statements:
BDO LLP (UK based) *	93	153
BDO Limited (T&T based)*	127	124
- Fees payable to the Company's auditors' for other services: The audit of Company's subsidiaries	13	20
Audit related assurance services - interim review	29	38
Total assurance and auditors' remuneration	262	335

* - Please note that prior year relates to previous auditors

 

All fees in 2020 are in respect of services provided by BDO LLP and their affiliated firms. The independence and objectivity of the external auditors are considered on a regular basis by the Audit Committee, with particular regard to the level of non-audit fees incurred.

 

6      Exceptional Items

 

Items that are material either because of their size, their nature, or that are non-recurring are considered as exceptional items and are presented within the line items to which they best relate.  During the current period, exceptional items as detailed below have been included in the Consolidated Statement of Comprehensive Income. An analysis of the amounts presented as exceptional items in these financial statements are highlighted below.

 

	2020	2019
Exceptional items:	$'000	$'000
Reversal of Impairment on equipment	(126)	--
Fees relating to corporate restructuring advice	83	--
Exceptional Income	(43)	--

 

 

Exceptional items 2020₁: 

 

§  Reversal of Impairment on equipment: ($0.1) million credit in relation to reversal of impairment for Pumping Unit

§  Fees relating to corporate restructuring advice: $0.1 million charge in relation to professional advice on a potential corporate restructuring

_{1 Impairment losses on property, plant and equipment have been reclassified from exceptional items in 2020 and 2019 comparative}

 

7      Finance income and costs

 

Recognised in the consolidated statement of comprehensive income

 

Finance income
	2020	2019
	$'000	$'000
Interest Income	108	138

 

Finance costs	2020	2019
	$'000	$'000
Decommissioning - Unwinding of discount (Note 25)	(1,221)	(1,198)
Interest on Leases	(140)	(174)
Interest on overdraft	(55)	--
	(1,416)	(1,372)

 

8      Income Taxation 

 

	2020	2019
	$'000	$'000
Current tax
Petroleum profits tax	817	--
Unemployment levy	333	390
Deferred Tax
- Current year
Movement in asset due to tax losses recognised (Note 16)	3,365	(3,389)
Movement in liability due to accelerated tax depreciation (Note 16)	(1,577)	(1,409)
Income tax expense/(credit)	2,938	(4,408)

 

 

The Group's effective tax rate varies from the statutory rate for UK companies of 19% (2019:19%) as a result of the differences shown below:

 

	2020	2019
	$'000	$'000
Profit/(loss) before taxation	103	(14,055)
Tax calculated at domestic tax rates applicable to profits in the respective countries	741	(6,236)
Expenses not deductible for tax purposes	2,163	9,833
Impact on tax losses	(2,187)	(2,962)
Deferred tax on capital allowances in the current period recognised	(1,389)	(2,044)
Tax losses previously generated now recognised in the current period	3,365	(3,389)
Other reconciling differences	245	390
Tax charge	2,938	(4,408)

 

 

Corporate income tax is calculated at 19% (2019: 19%) of the assessable profit for the year for the UK parent company, 55% for the operating subsidiaries in Trinidad and Tobago (2019: 55%) and 30% (2019: 30%) for the corporate subsidiaries in Trinidad and Tobago.

 

Taxation losses at 31 December 2020 available for set off against future taxable profits amounts to approximately $237.2 million (2019: $240.2 million), with tax losses recognised of $12.0 million in 2020. These losses do not have an expiry date and have not yet been confirmed by the Board of Inland Revenue ("BIR") and the Her Majesty's Revenue and Customs ("HMRC"). The 2019 reconciliation was revised using the same method as 2020.

 

 

9      Earnings Per Share

 

Basic earnings per share is calculated by dividing the earnings attributable to ordinary Shareholders by the weighted average number of ordinary shares outstanding during the year. Diluted earnings per share is calculated using the weighted average number of ordinary shares adjusted to assume the conversion of all potentially dilutive ordinary shares.

	Loss $'000	Weighted Average Number Of Shares '000'	Earnings Per Share $
Year ended 31 December 2020
Basic	(2,835)	386,233	(0.01)
Diluted	(2,835)	386,233	(0.01)

 

Year ended 31 December 2019
Basic	(9,647)	384,049	(0.03)
Diluted	(9,647)	384,049	(0.03)

 

Impact of dilutive ordinary shares:

 

Diluted earnings per share is calculated by adjusting the weighted average number of ordinary shares outstanding to assume conversion of all dilutive potential ordinary shares.  The awards issued under the Company's LTIP (see movements in number of LTIPs in note 22 below) are considered potential ordinary shares. Share Options of 1,975,084 are considered potential ordinary shares and have not been included as the exercise hurdle would not have been met.

 

There was no impact on the weighted average number of shares outstanding during 2020 as all Share Options and LTIP's were excluded from the weighted average dilutive share calculation because their effect would be anti-dilutive and therefore both basic and diluted earnings per share are the same in 2020.

 

10   Investment In Subsidiaries

	Company
	2020	2019
	$'000	$'000
Opening balance	59,306	58,489
Share based payment	715	817
Closing balance	60,021	59,306

 

The investment in subsidiaries is recognised initially at the fair value of the consideration paid.  The Group subsequently measures the investment in subsidiaries at cost less impairments.  Increases in the investment in subsidiaries relate to capital contributed by the Company to its subsidiary undertakings. 

 

 

Listing of Subsidiaries 

 

The Group's subsidiaries at 31 December 2020 are listed below:

 

 

Name	Registered Address/Country of Incorporation	Nature of Business	% Shares held by the Group
Bayfield Energy Limited	c/o Pinsent Masons LLP, 1 Park Row, Leeds, LS1 5AB, UK	Holding Company	99.99%
Trinity Exploration & Production (UK) Limited	13 Queen's Road, Aberdeen, AB15 4YL, UK	Holding Company	100 %
Trinity Exploration and Production Services (UK) Limited	c/o Pinsent Masons LLP, 1 Park Row, Leeds,  LS1 5AB, UK	Service Company	100 %
Bayfield Energy do Brasil Ltda	Av. Presidente Vargas 509, Rio de Janeiro, 20071-003, Brazil	Dormant	100 %
Trinity Exploration & Production (Barbados) Limited	Ground Floor, One Welches, Welches, St. Thomas BB22025, Barbados	Holding Company	100 %
Trinity Exploration and Production (Trinidad and Tobago) Limited	3rd Floor Southern Supplies Limited Building, 40 -44 Sutton Street, San Fernando, Trinidad & Tobago ("Trinidad address")	Holding Company	100 %
Trinity Exploration and Production (Galeota) Limited	Trinidad address	Oil and Gas	100 %
Oilbelt Services Limited	Trinidad address	Oil and Gas	100 %
Trinity Exploration and Production Services Limited	Trinidad address	Service Company	100 %
Tabaquite Exploration & Production Company Limited	Trinidad address	Oil and Gas	100 %
Trinity Exploration and Production (GOP) Limited	Trinidad address	Oil and Gas	100 %
Trinity Exploration and Production (GOP-1B) Limited	Trinidad address	Oil and Gas	100 %

 

 

 

11   Property, Plant and Equipment

	Plant & Equipment	Leasehold & Buildings	Oil & Gas Assets	Other	Total
Year ended 31 December 2020	$'000	$'000	$'000	$'000	$'000
Opening net book amount at 1 January 2020	1,141	1,652	39,587	--	42,380
Disposals	--	(2)	--	--	(2)
Additions	1,124	(16)	2,983	--	4,091
Adjustment to decommissioning estimate (Note 24)	--	--	(152)	--	(152)
Impairment reversal equipment	126	--	--	--	126
Impairment charge1	(116)	--	(1,005)	--	(1,121)
DD&A charge for year	(247)	(153)	(7,166)	--	(7,566)
Closing net book amount at 31 December 2020	2,028	1,481	34,247	--	37,756
At 31 December 2020
Cost	14,894	3,338	300,857	336	319,425
Accumulated DD&A and impairment	(12,866)	(1,857)	(266,610)	(336)	(281,669)
Closing net book amount	2,028	1,481	34,247	--	37,756
	Plant & Equipment	Leasehold & Buildings	Oil & Gas Assets	Other	Total
Year ended 31 December 2019	$'000	$'000	$'000	$'000	$'000
Opening net book amount at 1 January 2019	962	1,705	50,932	--	53,599
Additions	369	111	11,676	--	12,156
Adjustment to decommissioning estimate (Note 25)	--	--	1,031	--	1,031
Impairment1	--	--	(15,187)	--	(15,187)
DD&A charge for year	(190)	(164)	(8,864)	--	(9,218)
Translation difference	--	--	(1)	--	(1)
Closing net book amount at 31 December 2019	1,141	1,652	39,587	--	42,380
At 31 December 2019
Cost	13,760	3,356	298,879	336	316,331
Accumulated DD&A and impairment	(12,619)	(1,704)	(259,291)	(336)	(273,950)
Translation difference	--	--	(1)	--	(1)
Closing net book amount	1,141	1,652	39,587	--	42,380

 

1         An impairment loss of $1.1 million (2019: $15.2 million) was recognised on Oil & Gas Assets (see Note 3 (d)) as a result of the carrying value being higher than the recoverable amount. The recoverable amount was determined by assessing its fair value less costs of disposal.

12     Leases

 

   The Group has recognised ROU assets and lease liabilities

 

(i)          Amounts recognised in the Consolidated Statement of Financial Position

 

   The Consolidated Statement of Financial Position shows the following amounts relating to leases:

	31 December 2020	31 December 2019
	$'000	$'000
Right-of-use assets
Non-current assets	1,014	1,402
Lease Liabilities
Current	614	637
Non-current	465	841
	1,079	1,478

  

The ROU assets relate to Motor vehicles, Office building, Staff housing and Office equipment leases that met the recognition criteria of a Lease under IFRS 16.

 

 

(ii)      Amounts recognised in the Consolidated Statement of Comprehensive Income

 

   The Consolidated Statement of Comprehensive Income shows the following amounts relating to leases:

	2020	2019
	$'000	$'000
Depreciation charge of ROU assets
Depreciation	(502)	(477)
Interest expense (including finance cost)	(140)	(173)

 

     The total cash outflow for leases in 2020 was $0.6 million (2019: $0.6 million)

 

(iii)     The Group's leasing activities and how these are accounted for

 

The Group leases various offices, equipment, staff housing and vehicles. Rental contracts are typically made for fixed periods of 6 months to 4 years.

 

Contracts may contain both lease and non-lease components. There were no non-lease components identified and as such the Group allocates the consideration in the contract to a single lease component based on their relative stand-alone prices.

 

Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The lease agreements do not impose any covenants other than the security interests in the leased assets that are held by the lessor. Leased assets may not be used as security for borrowing purposes. 

 

 

13     Intangible Assets

 

The carrying amounts and changes in the year are as follows:

 

	Exploration and Evaluation assets	Computer software	Total
Year ended 31 December 2020	$'000	$'000	$'000
Opening net book amount at 1 January 2020	25,987	268	26,255
Additions	1,055	145	1,200
Amortisation charge for year	--	(106)	(106)
Closing net book amount at 31 December 2020	27,042	307	27,349
At 31 December 2020
Cost	27,042	520	27,562
Accumulated amortisation	--	(213)	(213)
Closing net book amount	27,042	307	27,349
	Exploration and Evaluation assets	Computer software	Total
Year ended 31 December 2019	$'000	$'000	$'000
Opening net book amount at 1 January 2019	25,511	246	25,757
Additions	476	99	575
Amortisation charge for year	--	(77)	(77)
Closing net book amount at 31 December 2019	25,987	268	26,255
At 31 December 2019
Cost	25,987	375	26,362
Accumulated amortisation	--	(107)	(107)
Closing net book amount	25,987	268	26,255

 

Computer Software:  In 2020, capital cost incurred for software acquisition.

 

E&E assets:  Represents the cost for the TGAL 1 exploration well and further field E&E cost.  The Group tests whether E&E assets has suffered any impairment triggers on an annual basis and there were no impairment triggers (2019: nil)

 

 

14     Abandonment fund

 

	2020	2019
	$'000	$'000
At 1 January	3,378	2,979
Additions	112	399
At 31 December	3,490	3,378

 

Abandonment funds are restricted cash put aside in escrow for abandonment and environmental purposes in accordance with contractual obligations to be used in accordance with the contract.

15     Performance bond

 

	2020	2019
	$'000	$'000
At 1 January and 31 December	253	253

 

A Performance Bond in favour of Heritage was put in place on 3 July 2017 of $0.3 million at 1.75% rate per annum, executed with First Citizens Bank Trinidad and Tobago Limited and effective until 31 December 2020. These funds have been restricted to a Fixed Deposit for 36 months at the agreed interest rate of 1.25%. The Performance Bond is a requirement under the Lease Operatorship Agreement ("LOAs") as Trinity is the Operator of the FZ2, WD2, WD5/6, WD13 and WD14 fields.

                                                            

16   Deferred Income Taxation

 

Group

 

The analysis of DTA is as follows:

	2020	2019
	$'000	$'000
DTA:
-DTA to be recovered in more than 12 months	(4,447)	(5,127)
-DTA to be recovered in less than 12 months	(1,550)	(4,235)
DTL:
-DTL to be settled in more than 12 months	2,611	4,188
Net DTA	(3,386)	(5,174)

 

The movement on the deferred income tax is as follows:

	2020	2019
	$'000	$'000
At beginning of year	(5,174)	(375)
Movement for the year	1,879	(4,725)
Unwinding of deferred tax on fair value uplift	(91)	(74)
Net DTA	(3,386)	(5,174)

 

 

The deferred tax balances are analysed below:

 

	2018	Movement	2019	Movement	2020
	$'000	$'000	$'000	$'000	$'000
DTA
Acquisition	(33,436)	--	(33,436)	--	(33,436)
Tax losses recognised	(36,087)	(3,389)	(39,476)	--	(39,476)
Tax losses derecognised	63,550	--	63,550	3,365	66,915
	(5,973)	(3,389)	(9,362)	3,365	(5,997)

 

	2018	Movement	2019	Movement	2020
DTL	$'000	$'000	$'000	$'000	$'000
Accelerated tax depreciation and non-current asset impairment	(16,043)	(1,337)	(17,380)	(1,487)	(18,867)
Acquisitions	19,580	--	19,580	--	19,580
Fair value uplift	2,061	(73)	1,988	(90)	1,898
	5,598	(1,410)	4,188	(1,577)	2,611

 

DTA are recognised for tax loss carry-forwards to the extent that the realisation of the related tax benefit through future taxable profits are probable. Deferred tax assets of $3.4 million have been derecognised (2019: $3.4 million was recognised) based on future taxable profits. The Group has unrecognised deferred tax asset amounting to $102.2 million which have no expiry date.

 

DTL have decreased by $1.6 million as the temporary difference between the accounting values of property, plant and equipment and intangible assets and tax values decreased compared to 2019-year end 

 

-  DTA and DTL can only be offset in the Consolidated Statement of Financial Position if an entity has a legal right to settle current tax amounts on a net basis and Deferred Tax amounts are levied by the same tax authority (as per IAS 12).

 

-  Tax losses - At the end of 2020 the Group had gross tax losses carried forward of $237.2 million (2019: $240.2 million) represented by corporate tax losses in the UK of $16.6 million (2019: $16.3 million) and PPT and Corporate tax losses in Trinidad and Tobago of $220.6 million (2019: $223.9 million).  In Trinidad and Tobago PPT losses and corporate tax losses may be carried forward indefinitely to reduce the taxes in future years. As of 1 January 2020, PPT losses can only be utilised to shelter a maximum of 75 percent of PPT per annum.

 

17   Inventories     

	Crude oil	Materials and supplies	Total
	$'000	$'000	$'000
At 1 January 2020	89	5,054	5,143
Net inventory movement	(22)	146	124
At 31 December 2020	67	5,200	5,267
At 1 January 2019	89	3,649	3,738
Impairment	--	(49)	(49)
Net inventory movement	--	1,454	1,454
At 31 December 2019	89	5,054	5,143

 

(i)     Assigning costs to inventories

 

The costs of individual items of inventory within the category material and supplies are determined using weighted average costs. The cost assigned for crude oil is based on the lower of cost and net realisable value. There were no obsolete inventories written off during the year.

 

18     Trade and Other Receivables

       

	Group		Company
	2020 $'000	2019 $'000	2020        $'000	2019 $'000
Due within 1 year
Amounts due from related parties (Note 28 (d))	--	--	4,418	3,722
Trade receivables	3,357	5,307	--	--
Less: provision for impairment of trade and intercompany receivables	(6)	(225)	(100)	(91)
Trade receivables/amounts due from related parties - net	3,351	5,082	4,318	3,631
Prepayments	862	859	149	147
VAT recoverable	2,467	2,932	125	71
Other receivables	1,413	847	150	--
Less: provision for Impairment of other receivables	(854)	(383)	--	--
	7,239	9,337	4,742	3,849

All trade receivables are with the Group's only customer, Heritage. Ageing analysis of these trade receivables as at 31 December 2020 is as follows:

 

	2020 $'000	2019 $'000
Up to 30 days	3,217	4,491
>60 days	--	104
>180 days	140	712
	3,357	5,307

 

The carrying amount of the Group's trade and other receivables are denominated in the following currencies:

	Group		Company
	2020 $'000	2019 $'000	2020 $'000	2019 $'000
USD	4,567	4,200	4,589	3,690
GBP	191	159	252	159
TTD	2,481	4,978	--	--
	7,239	9,337	4,841	3,849

 

The maximum exposure to credit risk at the reporting date is the value of each class of receivable as shown above. The Group does not hold any collateral as security.

 

The credit quality of the financial assets that are neither past due nor impaired can be assessed by reference to historical information about the counterparty default rates:

	Group		Company
	2020	2019	2020	2019
	$'000	$'000	$'000	$'000
Trade receivables
Counterparties without external credit rating:
Existing customers with no defaults in the past	7,239	9,337	--	--

 

The fair value of trade and other receivables approximate their carrying amounts.

 

The Group applies the IFRS 9 simplified model for measuring expected credit losses ("ECL") using a lifetime expected loss provision for trade and other receivables. The expected loss rates are based on the Group's historical credit losses experienced over a period prior to the period end. The historical loss rates are then adjusted for current and forward-looking information on key macroeconomic factors affecting the Group's customer including GDP, foreign exchange rates, WTI crude oil price and inflation rates.  In calculating an ECL, two default loss rates are established; default loss rate 1 which is calculated through the ageing profiles of sales, and default loss rate 2 which is default loss rate 1 adjusted based on forward looking information.

 

Having reviewed past payment performance combined with the credit rating of Heritage (and its predecessor, Petrotrin), a Provision matrix was completed to calculate a potential impairment on the receivable balances. Trade receivables that are less than six months past due are not considered impaired and at 31 December 2020, trade receivables of $3.4 million (2019: $4.8 million) were therefore considered to be fully performing. 

 

Although all Heritage revenue payments have been received on a timely basis, the Joint Interest billings has not. For other receivables, which relate to Joint Interest Billing receivable amounts from Heritage, an ECL of  $0.9 million (2019: $0.4 million) was therefore calculated.                                                                                                           

 

At the end of 2020 a total of $0.1 million was outstanding from Petrotrin (2019: $0.5 million), with $0.4 million of the outstanding amounts having been received during 2020. An ECL of $0.0 million was applied to the outstanding $0.1 million receivables amount due from Petrotrin.

 

 

 

19     Derivative financial assets

 

The following table compares the carrying amounts and fair values of the Group's financial assets and financial liabilities as at 31 December 2020.

-      

	As at 31 December 2020		As at 31 December 2019
	$'000		$'000
Derivative asset	266		85
Total	266		85

 

The Group considers that the carrying amount of the following financial assets and financial liabilities are a reasonable approximation of their fair value:

-       Trade receivables

-       Trade payables

-       Cash and cash equivalents

 

Fair Value Hierarchy

       

The level in the fair value hierarchy within which the derivative financial asset is categorised is determined on the basis of the lowest level input that is significant to the fair value measurement.

 

The derivative financial assets are classified in their entirety into only one of the three levels.

 

The fair value hierarchy has the following level:

 

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

 

-       Level 2 - inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices)

 

-       Level 3 - inputs for the asset or liability that are not based on observable market data (unobservable inputs).

 

Level 2 recurring fair value measurements:

	As at 31 December 2020       $'000
Opening balance	85
Derivative instrument purchased	946
Derivative asset expensed	(765)
Closing balance	266

 

 

On 31 December 2020 the crude derivative contracts were valued using a mark to market report. The report provides forward looking value on the existing crude derivatives held at 31 December 2020.

 

The net gain in fair value is recognised in the Consolidated Statement of Comprehensive Income during the year:

 

		31 December 2020	31 December 2019
		$'000	$'000
Derivative expense		(765)	(126)
Derivative income		2,333	48
Total income/(expense)		1,568	(78)

 

Net derivative income/(expense)	1,302	(78)
FV of derivative financial instruments	266	--
	1,568	(78)

 

20     Cash and Cash Equivalents

 

	Group		Company
	2020	2019	2020	2019
	$'000	$'000	$'000	$'000
Short term investment	4,055	5,081	4,055	5,081
Cash and cash equivalents	16,182	8,729	261	205
	20,237	13,810	4,317	5,286

 

Cash and Cash equivalents disclosed above and in the Consolidated Statement of Cash Flows exclude restricted cash and are available for general use by the Group. 

 

 

21     Share Capital and Share Premium

 

 

Group

 

		Number of shares	Share capital $'000	Share premium $'000	Total   $'000
As at 1 January and 31 December 2019		478,489,232	97,692	139,879	237,571
As at 1 January 2020		478,849,232	97,692	139,879	237,571
LTIPs exercised*		4,745,056	--	--	--
As at 31 December 2020		483,594,288	97,692	139,879	237,571

 

-  The Company does not have a limited amount of authorised share capital.

-  Within the number of shares shown above there are 94,799,986 deferred shares of USD 0.99 each totalling $93.9 million of share capital.  The deferred shares have no voting or dividend rights and on a return of capital on a winding up have no valuable economic rights. 

-  The remaining 388,794,302 Ordinary shares in issue as at 31 December 2020 have a par value of USD 0.01 per share.

 

Year ended 31 December 2020	Number of shares	Ordinary shares	Deferred shares	Share premium	Total
		$'000	$'000	$'000	$'000
At 1 January 2020	478,849,232	3,840	93,852	139,879	237,571
LTIPs exercised*	4,745,056	--	--	--	--
At 31 December 2020	483,594,288	3,840	93,852	139,879	237,571
Note: $:GBP rate 1.312:1

 

*LTIPs exercised - 4,745,056 LTIPs were exercised during the year ended 31 December 2020.  These shares were issued for nil consideration and therefore for less than the nominal value of the shares which was in contravention of s580 of the UK Companies Act.  Following the 31 December 2020 year end the Directors have sought legal advice with regards to this breach of UK company law and are in the process of implementing a remedy.  Given remedial action can be taken, the Directors do not consider this to be a material breach of UK company law.  The shares have been issued and therefore the number of shares in issue has been appropriately reflected in the table above.  There is no corresponding increase to the value of share capital as they were issued below nominal value.

 

22   Share Based Payment Reserve

 

The share-based payments reserve is used to recognise:

-  The grant date fair value of options issued to employees but not exercised

-  The grant date fair value of share awards issued to employees

-  The grant date fair value of deferred share awards granted to employees but not yet vested; and

-  The issue of shares held by the Employee Share Trust to employees.

 

During 2020 the Group had in place share-based payment arrangements for its employees and Executive Directors, the LTIP. The Share Option Plan referenced below is fully vested and expensed. The current year charge for share based payments are solely in relation to the LTIP arrangements shown below, with further details of each scheme following:

 

	2020	2019
	$'000	$'000
At 1 January	14,328	13,290
Share based payment expense:
LTIP exercised	(527)	--
LTIP expense	963	1,038
At 31 December	14,764	14,328

 

Share Option Plan

 

Share Options were granted to Executive Directors and to selected employees. The exercise price of the granted option was equal to Management's best estimate of the fair value of the shares at the time of the award of the options. The Group has no legal or constructive obligation to repurchase or settle the options in cash.  These Share Options were fully vested in 2015 and 2016 with nil exercised and expiry dates in 2022 and 2023. The table below gives details:

               

		2020		2019
Grant-Vest	Expiry Date	Exercise price per Share Options	Number of Options	Exercise price per Share Options	Number of Share Options
2012-2015	2022	GBP0.86	1,685,540	GBP0.86	1,685,540
2013-2016	2023	GBP1.20	289,544	GBP1.20	289,544
			1,975,084		1,975,084

 

 

 

The inputs into the Black-Scholes model for options granted in prior periods were as follows:

Grant date	29 May 2013	14 February 2013
Share price	GBP 1.19	GBP 1.20
Average Exercise price	GBP 1.20	GBP 0.89
Expected volatility	55%	78%
Risk-free rates	4.5%	4.5%
Expected dividend yields	0%	0%
Vesting period	3 years	3 years

 

LTIP

 

LTIP awards are designed to provide long-term incentives for the EMT to deliver long-term shareholder returns. Under the plan, participants are granted options which only vest if certain performance standards are met. Participation in the plan is at the Board's discretion and no individual has a contractual right to participate in the plan or to receive any guaranteed benefits.

 

2017 LTIPs

One off LTIP awards were granted in August 2017 over 25,415,998 ordinary shares and in June 2020 over a further 1,422,961 ordinary shares (the "2017 LTIP Awards"). The 2017 LTIP awards, which ordinarily vest on 30 June 2022, partially vested on 30 June 2020 and may vest in full or in part on 30 June 2021, subject to meeting performance targets relating to the following:

 

•        In respect of 70% of the award, the Company's share price growth from the 2017 placing price of 4.98 pence per share. If the three month volume-weighted price ("VWAP") at the testing date is 35 pence or more per share, this part of the award will vest in full. If the VWAP at the testing date is 4.98 pence per share or less, this part of the award will not vest at all. If the VWAP at the testing date is between 4.98 pence and 35 pence per share, this part of the award will vest on a pro-rated straight-line basis;

 

•        In respect of 20% of the award, repayment of the amount due to the BIR in accordance with the terms of the Creditors Proposal approved in 2017. The final payment occurred in 2018; and

 

•        In respect of 10% of the award, redemption of all the Convertible Loan Notes ("CLN") issued in January 2017 before the second anniversary of their issue.  All of the CLNs were redeemed in 2018.

 

The total fair value of the 2017 LTIP Award is $2.6 million and will be expensed over the vesting period with the full charge pro-rated over the period up to 30 June 2022. However, the LTIP Award may vest in full or in part on 30 June 2020 or 2021 with the appropriate charge being taken over the vesting period. The fair value at grant date is independently determined using an adjusted form of the Black Scholes Model which includes a Monte Carlo simulation model that takes into account the exercise price, the term of the option, the share price at grant date and expected price volatility of the underlying share, the expected dividend yield, the risk free interest rate for the term of the option and the correlations and volatilities of the peer group companies.

 

The model inputs for LTIP Awards granted in 2017:

 

Grant Date	25 August 2017	25 June 2020
Share price at grant date	GBP 10.75	GBP 7.90
Exercise price	GBP 0.00	GBP 0.00
Expected volatility	73.3%	84.9%
Risk-free interest rates	0.44%	(0.07%)
Expected dividend yields	0%	0%
Vesting period 1	30 June 2020	--
Vesting period 2	30 June 2021	--
Vesting period 3	30 June 2022	30 June 2022

 

2019 LTIPs

In January 2019 Options over 2,824,000 ordinary shares and in May 2019 Options over 3,832,824 ordinary shares were granted under the LTIP in accordance with the policy announced to the market on 25 August 2017.  The LTIP awards are designed to provide long-term incentives for the EMT to deliver long-term shareholder returns. Under the plan, participants were granted options which only vest if certain performance standards are met. Participation in the plan is at the Board's discretion and no individual has a contractual right to participate in the plan or to receive any guaranteed benefits.

 

The January 2019 LTIP awards vested on 1 January 2021, while the May 2019 awards will vest on 2 January 2022 subject to meeting the performance criteria set out in the table below and continued employment with the Company. The Options are exercisable at nil cost by the participants.

 

 

Performance targets	January 2019 LTIPs	May 2019 LTIPs
Below the Median	None of the award will vest	None of the award will vest
Median (50th percentile)	30% of the maximum award will vest	30% of the maximum award will vest
Between Median and Upper Quartile	Straight-Line basis between these points	Straight-Line basis between these points
Upper Quartile (75%) and above	100% of the maximum award will vest	100% of the maximum award will vest

The total fair value at grant date of the 2019 LTIP awards was $0.9 million and this will be expensed over the vesting period with the full charge pro-rated over the vesting period. The 2019 LTIP Awards are subject to the achievement of relative Total Shareholder Return ("TSR") performance targets measured over a 3-year performance period ending on 1 January 2021 and 31 December 2021 respectively. 

 

The fair value at grant date was determined using a Monte Carlo simulation model that takes into account the exercise price, the term of the option, the share price at grant date and expected price volatility of the underlying share, the expected dividend yield, the risk free interest rate for the term of the option and the correlations and volatilities of the peer group companies. The model inputs for the 2019 LTIP awards granted during the period ended 31 December 2019 included:

 

	January 2019 LTIPs	May 2019 LTIPs
Grant Dates	2 January 2019	9 May 2019
Share price at grant dates	GBp16.77	GBp14.66
Exercise price	GBP0.00	GBP0.00
Expected volatility	113.9%	113.9%
Risk-free interest rates	0.73%	0.73%
Expected dividend yields	0%	0%
Vesting period	1 January 2021	2 January 2022

 

2020 LTIPs

On 25 June 2020 and 30 October 2020 Options over a total of 3,815,856 ordinary shares and 1,000,000 ordinary shares respectively were granted under the LTIP in accordance with the policy announced to the market on 25 August 2017 to members of the EMT in respect of the performance of the Company in the financial year ended 31 December 2019.  The LTIP awards are designed to provide long-term incentives for the EMT to deliver long-term shareholder returns. Under the plan, participants were granted options which only vest if certain performance standards are met. Participation in the plan is at the Board's discretion and no individual has a contractual right to participate in the plan or to receive any guaranteed benefits.

 

These LTIP awards will vest on 2 January 2023, subject to meeting the performance criteria set and continued employment in the Company. The Options are exercisable at nil cost by the participants.

 

The LTIP Awards are subject to the achievement of relative Total Shareholder Return ("TSR") performance targets measured over a three-year performance period ending on 31 December 2022.  The amounts stated above represent the maximum possible opportunity.

 

TSR is the increase in share price plus the value of any dividends paid over a period of time and captures the full return shareholders see on an investment. Relative TSR is the comparison of these returns against peer companies over a set period of time. For Trinity, the performance will be assessed over a three year period.

 

The Relative TSR ranking will be determined by calculating the three month average TSR to the end of the performance period and dividing this by the three month average TSR to the beginning of the performance period for all companies in the agreed comparator group. Companies will be ranked on this basis with the highest performing company ranked first. The share price used to calculate the start of the TSR calculation in respect of these awards is based on the three-month average TSR leading into 31 December 2019, being 9.683p.

 

The amount of the award which will vest at the end of the three year period is based on performance against a comparator group. Threshold vesting occurs when Trinity is ranked at median against the comparator group and maximum vesting occurs when Trinity is ranked at upper quartile (or above). The table below shows the level of vesting at threshold and maximum:

 

Vesting occurs on a straight line basis between threshold and maximum.

 

Performance	Vesting
Below the Median	None of the award will vest
Median (50th percentile)	30% of the maximum award will vest
Between Median and Upper Quartile	Straight Line basis between these points
Upper Quartile (75%)	100% of the maximum award will vest.
Above the Upper Quartile	100% of the maximum award will vest

 

 

The total fair value at grant date of the 2020 LTIP awards was $0.4 million and this will be pro-rated and expensed over the vesting period. The fair value at grant date was determined using a Monte Carlo simulation model that takes into account the exercise price, the term of the option, the share price at grant date and expected price volatility of the underlying share, the expected dividend yield, the risk free interest rate for the term of the option and the correlations and volatilities of the peer group companies. The model inputs for the 2020 LTIP awards granted during the period included:

 

	June 2020 LTIPs	October 2020 LTIPs
Grant Dates	25 June 2020	30 October 2020
Share price at grant dates	GBP7.90	GBP7.70
Exercise price	GBP0.00	GBP0.00
Expected volatility	84.9%	84.9%
Risk-free interest rates	(0.07%)	(0.07%)
Expected dividend yields	0%	0%
Vesting dates	2 January 2023	2 January 2023

 

Movements in the number of LTIPs outstanding and their related weighted average exercise prices are as follows:

 

	2020 Average exercise price per Share Option	Number of Options	2019 Average exercise price per Share Option	Number of Options
At 1 January	GBP 0.00	31,789,818	GBP 0.00	25,415,998
Forfeited	GBP 0.00	(1,720,592)	GBP 0.00	(283,004)
Granted1	GBP 0.00	6,238,817	GBP 0.00	6,656,824
Exercised2	GBP 0.00	(4,745,056)	GBP 0.00	--
At 31 December	GBP 0.00	31,562,987	GBP 0.00	31,789,818

_{1 Weighted average fair value of LTIPs granted GBP 0.07}

_{2 Weighted average share price at the date of exercise GBP 0.08}

 

 

LTIPs outstanding at the end of the year have the following expiry date and exercise prices:

Grant-Vest	Expiry date	Exercise price	2020	2019
24/8/2017 - 30/6/2022	24/8/2027	GBP 0.00	21,030,319	25,415,998
2/1/2019 - 1/1/2021	1/1/2023	GBP 0.00	2,525,101	2,824,000
9/5/2019 - 2/1/2022	2/1/2024	GBP 0.00	3,191,712	3,549,820
25/6/2020 - 2/1/2023	2/1/2025	GBP 0.00	4,815,856	--

 

 

 

23   Merger and Reverse Acquisition Reserves

 

	Reverse Acquisition Reserve	Merger Reserve	Total
	$'000	$'000	$'000
At 1 January 2020	(89,268)	75,467	(13,801)
Movement	--	--	--
Translation differences	--	--	--
At 31 December 2020	(89,268)	75,467	(13,801)
At 1 January 2019	(89,268)	75,467	(13,801)
Movement	--	--	--
Translation differences	--	--	--
At 31 December 2019	(89,268)	75,467	(13,801)

 

The issue of shares by the Company as part of the reverse acquisition (February 2013) met the criteria for merger relief such that no share premium was recorded. As allowed under the UK Companies Act 2006 and required by IAS 27 ('Consolidated and separate financial statements'), a merger reserve equal to the difference between the fair value of the shares acquired by the Company and the aggregation of the nominal value of the shares issued by the Company has been recorded.

 

 

24   Adjusted EBITDA

 

Adjusted EBITDA is a non-IFRS measure used by the Group to measure business performance. It is calculated as Operating Profit before SPT, PT, Impairment and Exceptional Items for the period, adjusted for DD&A, ILFA, SOE, and FX Gain/(Loss).

 

The Group presents Adjusted EBITDA as it is used in assessing the Group's growth and operational efficiencies as it illustrates the underlying performance of the Group's business by excluding items not considered by Management to reflect the underlying operations of the Group.

 

Adjusted EBITDA is calculated as follows:

	2020		2019
	$'000		$'000
Operating Profit Before SPT, PT, Impairment and Exceptional Items	2,965		10,271
DD&A (note 11 - 13)	8,174		9,772
ILFA (note 18)	252		608
SOE (note 22)	963		1,038
FX (loss)/gain	(7)		76
Adjusted EBITDA	12,347		21,765
	'000		'000
Weighted average ordinary shares outstanding - basic	386,233		384,049
Weighted average ordinary shares outstanding - diluted	417,796		415,840
	$		$
Adjusted EBITDA per share - basic (note 9)	0.032		0.057
Adjusted EBITDA per share - diluted (note 9)	0.030		0.052
Adjusted EBITDA after the impact of SPT & PT is calculated as follows:
	2020		2019
	$'000		$'000
Adjusted EBITDA	12,347		21,765
SPT	153		(7,413)
PT	(532)		(492)
Adjusted EBITDA After SPT & PT	11,968		13,860
	'000		'000
Weighted average ordinary shares outstanding - basic	386,233		384,049
Weighted average ordinary shares outstanding - diluted	417,796		415,840
	$		$
Adjusted EBITDA After SPT & PT per share - basic	0.031		0.036
Adjusted EBITDA After SPT & PT per share - diluted	0.029		0.033

 

 

25   Provision for Other Liabilities

 

(a)           Non-current:	Decommissioning provision
	$'000
Year ended 31 December 2020
Opening amount as at 1 January 2020	44,330
Unwinding of discount (Note 7)	1,221
Revision to estimates	(152)
Translation differences	6
Closing balance at 31 December 2020	45,405
Year ended 31 December 2019
Opening amount as at 1 January 2019	41,802
Unwinding of discount (Note 7)	1,198
Increase in provision for new wells	755
Revision to estimates	380
Decommissioning contribution	195
Closing balance at 31 December 2019	44,330

 

 

Decommissioning cost

 

The Group operates Oil fields and this cost represents an estimate of the amounts required for abandonment of the Group's wells, platforms, gathering station and pipeline infrastructures. The amounts are calculated based on the provisions of existing contractual agreements with Heritage and MEEI. Furthermore, liabilities for decommissioning costs are recognised when the Group has an obligation to dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reasonable estimate of that liability can be made. An obligation for decommissioning may also crystallise during the period of operation of a facility through a change in legislation or through a decision to terminate operations.

 

The amount recognised is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. A corresponding item of property, plant and equipment of an amount equivalent to the provision is also created. This is subsequently depreciated as part of the capital costs of the facility or item of plant. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding property, plant and equipment. Some of the key assumptions made in the present value decommissioning calculation include the following:

a.      Core inflation rate - 2.00% (2019: 2.00%) 

b.      Risk free rate - 2.42% - 3.17% (2019: 2.13% - 3.07%)

c.       Estimated market value/decommissioning cost

d.      Estimated life of each asset

      

 See Note 3(b): Critical Accounting Estimates and Assumptions for the rates used and sensitivity analysis.

 

(b)           Current:
	Litigation claims	Closure of  Pits	Total
	$'000	$'000	$'000
Year ended 31 December 2020
Opening amount as at 1 January 2020	46	472	518
Decrease in provision	--	(2)	(2)
Closing balance at 31 December 2020	46	470	516
Year ended 31 December 2019
Opening amount as at 1 January 2019	115	232	347
Decrease in provision	(69)	--	(69)
Increase in provision	--	240	240
Closing balance at 31 December 2019	46	472	518

 

 

Litigation claims

                                                                                                                                                                                  

In 2020 there were no litigation settlements.

 

Closure of Pits

 

In 2020 there was a decrease in the provision of $0.0 million relating to the revision to remedy and closure of pits associated with drilling new onshore wells. It is an environmental regulatory requirement set by the EMA that all open drill pits for onshore drilling must be closed after sufficient testing has deemed it safe to close the pit. Testing period can last up to or over a year depending on the testing criteria.

 

 

26   Trade and Other Payables

 

	Group		Company
Current	2020 $'000	2019 $'000	2020 $'000	2019 $'000
Trade payables	2,024	2,123	130	87
Accruals	3,793	5,039	351	421
Other payables	471	619	--	--
SPT & PT	1,515	2,605	--	--
	7,803	10,386	481	508

 

 

27   Bank overdraft

	31 December 2020	31 December 2019
	$'000	$'000
Bank Overdraft	2,700	--
	2,700	--

 

During the year, an on demand operating (overdraft) line of $2.7 million was entered with FirstCaribbean International Bank (Trinidad & Tobago) Limited ("CIBC"). 

 

Details of the overdraft facility:

-  Description: Demand revolving credit

-  Interest Rate: United States dollar prime rate minus 6.30 % per annum, effective rate 4.95%

-  Repayment: Upon demand at CIBC's discretion

-  Debenture: Floating charge debenture over inventory and Trade Receivables only

-  Covenant:  Current Ratio not less than 1.25:1

 

On 2 April 2020 the Company drew down the $2.7 million in full.

 

 

 28   Related Party Transactions

 

Group

The following transactions were carried out with the Group's subsidiaries and related parties. These transactions comprise sales and purchases of goods and services and funding provided in the ordinary course of business during the year. The following are the major transactions and balances with related parties:

 

      (a) Transfers of funds from related parties

	Company
	2020 $'000	2019 $'000
Company subsidiaries:
Trinity Exploration and Production Services	--	14
Trinity Exploration & Production (UK) Limited	10	4
Trinity Exploration and Production (Galeota) Limited	26	120
Bayfield Energy Limited	61	29
Oilbelt Services Limited	170	--
Trinity Exploration and Production (Trinidad and Tobago) Limited	--	4
Galeota Oilfield Services Limited	3	3
Trinity Exploration and Production Services Limited (UK) Limited	899	--
	1,169	174

 

 

(b) Transfer of funds to related parties

	Company
	2020 $'000	2019 $'000
Company subsidiaries:
Trinity Exploration and Production Services	(473)	--
Oilbelt Services Limited	--	(338)
Trinity Exploration and Production Services Limited (UK) Limited	--	(2,744)
	(473)	(3,082)

      

 

Related party transactions comprise of the transfer of funds to and from related parties which are payable on demand. Positive balances indicate increase in funds transferred to the entities, while negative balances indicate repayment to entities.

 

(c)    Key Management and Directors' compensation: Key Management includes Board (Executive & Non-Executive). The compensation paid or payable to Key Management for employee services is shown below:

 

	Group
	2020 $'000	2019 $'000
Salaries and short-term employee benefits	1,219	1,305
Post-employment benefits	26	41
Share-based payment expense1 (Note 22)	469	697
	1,714	2,043

 

_{1 During 2020 LTIPs with a market value of $0.4 million were exercised by Key Management, refer to Directors remuneration report.}

 

      (d) Year-end balances arising from transfer to and from related parties

	Company
	2020 $'000	2019 $'000
Receivables from related parties:
Trinity Exploration and Production Services Limited	408	881
Trinity Exploration & Production (UK) Limited	28	18
Trinity Exploration and Production (Galeota) Limited	159	133
Bayfield Energy Limited	104	43
Oilbelt Services Limited	1,029	859
Galeota Oilfield Services Limited	4	4
Trinity Exploration and Production (Trinidad and Tobago) Limited	414	411
Trinity Exploration and Production Services (UK) Limited	2,272	1,373
Total intercompany receivables (Note 18)	4,418	3,722
Less: provision for impairment of intercompany receivables	(100)	(91)
Closing intercompany receivables (Note 18)	4,318	3,631

 

Company

-  The receivables from related parties arise mainly from inter-group recharges. The receivables are unsecured and bear no interest. An ECL provision was calculated $0.1 million  (2019: 0.1 million).

 

29   Taxation  Payable

	Group
	2020	2019
	$'000	$'000
Taxation payable
PPT	144	--
UL	58	80
	202	80

 

Trinidad and Tobago statutory petroleum profit tax ("PPT") and unemployment levy ('UL") are a combined rate of 55% of taxable income. PPT has a tax charge of 50%, while UL has a tax charge of 5% on taxable profits.

 

 

                       

30   Financial Instruments by Category

 

At 31 December 2020 and 2019, the Group held the following financial assets at amortised cost:

	Group		Company
	2020	2019	2020	2019
	$'000	$'000	$'000	$'000
Trade and other receivables - current*	3,910	5,546	150	-
Abandonment fund - non current	3,490	3,378	--	--
Intercompany	--	--	4,318	3,631
Cash and Cash equivalents	20,237	13,810	4,317	5,286
	27,637	22,734	8,785	8.917

^{Note (*): Excludes prepayments and VAT recoverable}

 

At 31 December 2020 and 2019, the Group held the following financial liabilities at amortised cost:

	Group		Company
	2020	2019	2020	2019
	$'000	$'000	$'000	$'000
Accounts payable and accruals	7,803	10,386	481	508
Bank overdraft	2,700	--	--	--
	10,503	10,386	481	508

 

At 31 December 2020 and 2019, the Group held the following financial asset at fair value through profit or loss:

	Group		Company
	2020	2019	2020	2019
	$'000	$'000	$'000	$'000
Derivative financial instrument	266	85	266	85
	266	85	266	85

 

31   Commitments and Contingencies

 

a)     Commitments

 

There are commitments for decommissioning costs of the wells and facilities under the Group's agreements with Heritage, which have been provided for as described in Note 25: Provision for other liabilities.

 

b)     Contingent Liabilities

 

i)      The East Coast Galeota, West Coast Point Ligoure, Guapo Bay & Brighton Marine Outer ("PGB") licences and the Farm-Out Agreement for the Tabaquite Block (held by Coastline International Inc.) has expired. There may be additional liabilities and commitments arising when a new agreement is finalised, but these cannot be presently quantified until a new agreement is available.

ii)     Parent Company Guarantee.  A Letter of Guarantee was established in substance over the PGB Block where a subsidiary of Trinity is obliged to carry out a Minimum Work Programme to the value of $8.4 million. The guarantee shall be reduced at the end of the twelve month period contingent upon specific clause within the Letter of Guarantee. The clause implied that Guarantor may reduce the Guarantee Sum available for payment to the MEEI under the Letter of Guarantee on an obligation by obligation basis provided PGB delivers to the Guarantor a certificate duly issued and signed by the MEEI. The PGB licence has expired (see note 31(b)(i)).

iii)    The Group is party to various claims and actions. Management has considered the matters and where appropriate has obtained external legal advice. No material additional liabilities are expected to arise in connection with these matters, other than those already provided for in these financial statements.

iv)    The Group's Lease Operatorship Assets ("LOA") for WD 5/6, WD 2, WD 13 and WD 14 blocks expired on 31 December 2020, and are in final stages of being renewed with Heritage as of the date of this report and following their renewal a new performance bond will be put in place.

 

 

32   Employee Costs

	Group		Company
Employee costs for the Group during the year	2020 $'000	2019 $'000	2020 $'000	2019 $'000
Wages and salaries	6,266	6,393	910	910
Other pension costs	358	342	--	--
Share based payment expense (Note 22)	963	1,038	248	221
	7,662	7,773	1,158	1,131
Average monthly number of people (including Executive and Non-Executive Directors') employed by the Group	2020 number	2019 number	2020 number	2019 number
Executive and Non-Executive Directors	6	6	6	6
Administrative staff	85	78	--	--
Operational staff	131	130	--	--
	222	214	6	6

 

 

33   Restatement

 

During 2020, a presentation error was identified in the prior year Cashflow Statement whereby the Cashflow from investing activities included non-cash accruals and these were not adjusted from the working capital movement (Trade and other payables). As a result, the cash inflow from operations and cashflow outflow from investing activities were overstated in the prior year financial statements by equivalent amounts. To correct the error, a reclassification was done as at 31 December 2019, resulting in a $1.2 million decrease in net cash inflows from operations and a $1.2 million decrease in net cash outflows from investing activities.

 

There is no profit or net asset impact as a result of the prior year restatement.

 

 

The adjustment is reflected in the statement below:

 

	2019		Impact of		2019
	$'000		Prior period Adjustment		$'000
	As previously reported		$'000		Restated
Operating Activities	13,113				13,113
Changes In Working Capital
Inventories	(1,454)				(1,454)
Trade and other receivables	3,638				3,638
Trade and other payables	1,797		(1,192)		605
	17,094		(1,192)		15,902
Tax Paid	(316)				(316)
Investing Activities
Purchase of Exploration and Evaluation ("E&E") assets	(476)		56		(420)
Purchase of computer software	(99)				(99)
Purchase of property, plant and equipment	(12,156)		1,136		(11,020)
Net Cash Outflow From Investing Activities	(12,731)		1,192		(11,539)
Net Cash (Outflow)/Inflow From Financing Activities	(438)				(438)
Increase/(Decrease) in Cash and Cash Equivalents	3,609				3,609
At end of year	13,810				13,810

 

 

34   Events after the Reporting Year

 

1.     Derivative Financial Instruments

In addition to the crude oil derivatives put in place during 2020, the Company has put in place a number of crude oil derivative financial instruments post the year end to protect a portion of its revenue against fluctuation in oil prices.  The crude oil derivative financial instruments currently in place are as follows:

 

 

Type of Derivatives	Index	Sell Put	Buy Put	Sell Call	Production	Effective Date	Expiry Date	Execution Date	Premium USD MM
		USD/bbl	USD/bbl	USD/bbl	Monthly Barrels
Put Spread	WTI	20.0	30.0	-	15,000	01-Jan-21	31-Dec-21	21-Jul-20	0.36
Put Spread	WTI	20.0	30.0	-	15,000	01-Jan-21	31-Dec-21	17-Nov-20	0.25
Put Spread	Dated Brent	32.5	42.5	-	15,000	01-Jan-21	30-Jun-21	25-Nov-20	0.19
2-Way Cost Collar	ICE Brent		42.5	64.4	15,000	01-Jul-21	31-Dec-21	5-Feb-21	-
3-Way Cost Collar	ICE Brent	50.0	60.0	66.9	10,000	01-Jan-22	30-Jun-22	4-Mar-21	-

 

 

2.     CIBC overdraft facility

 

Trinity fully drew down its $2.7 million overdraft credit facility with CIBC effective 2 April 2020 as part of its strategy of maximising available cash during the Covid-19 pandemic, and this remains outstanding. The facility was increased on 5 January 2021 by $2.3 million to a total of $5.0 million.  This additional portion remains fully undrawn to date.

 

The facility is a revolving overdraft credit available to Trinity which is repayable upon demand to CIBC. Interest is payable monthly at an interest rate equivalent to US Prime (currently 9%) minus 4.05% per annum, with present effective rate of 4.95% and subject to a floor rate of 3.95%.

 

3.     Fiscal Reforms

 

The revised threshold for Supplemental Petroleum Tax ("SPT") for small onshore producers has now been implemented via The Finance Act No. 30 of 2020 which came into effect on 1 January 2021.  As a result, the threshold at which SPT would be due for individual producers producing less than 2,000 barrels of crude oil per day has now increased from $50.0 /bbl to $75.0/bbl for the financial years 2021 and 2022.

 

Trinity expects to be exempt from SPT across all of its onshore licences below $75.0/bbl, which will have a significant positive impact on future cash flows. Based on current onshore production levels, Trinity estimates that SPT of c. $3.5 million per annum or more would previously have been payable if realisations were above $50.01/bbl (although this could be partially mitigated by the Investment Tax Credit ("ITC") shelter). The confirmation of these reforms therefore represents a considerable boost to potential cash generation from Trinity's onshore licences should realisations average above $50.01/bbl for any calendar quarter during 2021 and 2022. 

 

4.     Acquisition of onshore block PS-4

 

On 4 May 2021, Trinity announced that it had entered into a sale and purchase agreement with Moonsie Oil Company Limited to acquire an operated 100% interest in the PS-4 onshore block for a headline cash consideration of $3.5 million, to be funded from the Group's existing cash resources.  The Group anticipates that the transaction will complete towards the end of Q2 2021.