Half-year Report

RNS Number : 7819L

Trinity Exploration & Production

15 September 2021

This announcement contains inside information as stipulated under the UK version of the Market Abuse Regulation No 596/2014 which is part of English Law by virtue of the European (Withdrawal) Act 2018, as amended. On publication of this announcement via a Regulatory Information Service, this information is considered to be in the public domain.

Trinity Exploration & Production plc

("Trinity" or "the Company" or "the Group")

Interim Results

Strong operating and financial resilience continue to underpin the Group's pursuit of multiple initiatives to meaningfully scale the business

Trinity, the independent E&P company focused on Trinidad & Tobago ("T&T"), announces its unaudited interim results for the six-month period ended 30 June 2021 ("H1 2021" or "the period").

2021 Year to Date Strategic Highlights

H1 2021 saw continued financial and operating resilience, but more importantly significant progression of a number of important strategic initiatives as the Group positions itself to deliver a step change in scale - establishing a broader opportunity set from which to grow.

Onshore

The new 10 year Lease Operatorship Agreements ("LOAs") and less onerous Supplemental Petroleum Tax ("SPT") regime for onshore producers, provides a much improved commercial backdrop for our extensive efforts to scale-up our Onshore operations. With an operating break-even price of USD 17.9/bbl across our Onshore base, adding incremental production offers the potential to generate significant free cash flow. To this end, the onshore 3D Seismic interpretation is progressing at pace, with a dedicated team maturing plays and drilling candidates, and the Onshore opportunity set will be expanded further when the pending PS-4 acquisition is completed (now expected early Q4 2021). The 3D Seismic work is also of significant benefit for our review of the potentially high impact onshore North West District ("NWD") bid process which we are progressing alongside our partner.

East Coast

The combination of the new 25 year Galeota Licence (with Trinity now having a 100% working interest ("WI")), and improved commercial arrangements with Heritage (most notably a material reduction in overriding royalty rates and a more transparent oil pricing formula), has created a much enhanced commercial backdrop for this asset. The improved certainty and visibility of Galeota's value to Trinity and potential funding partners will enable Trinity to progress a farm-down process, with marketing now expected to commence in Q4 2021.

Corporate

The tragic passing of our founder and Executive Chairman, Bruce Dingwall, has - understandably - been a great personal and professional loss to everyone at Trinity, but we are determined to build on his legacy, realising the full potential of the strong position which the Group is now in. Since Bruce's passing, Jeremy Bridglalsingh has stepped up to become Chief Executive Officer and Nick Clayton has taken on the role of Non-Executive Chairman. Jeremy leads a highly capable, six strong Executive Management Team, having been expanded in July 2021 with the appointment of Denva Seepersad as Finance Director and Dr Ryan Ramsook as Executive Manager, Sub Surface. The recent appointment of Derek Hudson to the Board brings strong industry relationships, strategic insight and significant knowledge and understanding of the oil and gas business in Trinidad. The proposed establishment of a Technical Committee, chaired by Non-Executive Director, James Menzies, will further boost the commercial and technical expertise and support available to the Board and Executive Management Team. Furthermore, the completion of the Capital Reorganisation in July 2021 clears the way for future dividend payments and/or share buy backs when deemed appropriate.

H1 2021 Key Performance Indicators

Trinity assesses the Group's performance using both International Financial Reporting Standards ("IFRS") and the Alternative Performance Measures Guidelines ("APM") governed by the European Securities and Markets Authority ("ESMA"). Management believes that analysis of both performance measures delivers improved guidance to Management for operational and strategic decision making purposes. The Group was profitable in H1 2021 under both the IFRS and APM basis. Higher oil price realisations more than offset the modest and expected decline in net production, leading to a 69% increase in Adjusted EBITDA to USD 10.3 million (H1 2020: USD 6.1 million) enabling the period-end cash balance to being broadly maintained at USD 19.0 million (H1 2020: USD 19.7 million) despite investment made to support future growth during the period. A summary of the period-on-period operational and financial highlights are set out below:

		H1 2021	H1 2020	Change %
Average realised oil price¹	USD/bbl	55.9	36.3	54
Average net production²	bopd	3,032	3,282	(8)
Revenues	USD million	30.7	21.5	43
Cash balance	USD million	19.0	19.7	(4)
IFRS Results
Operating Profit before SPT & PT	USD million	3.2	1.9	63
Total Comprehensive Income/Loss	USD million	1.6	(1.6)	200
Earnings per share - diluted	USD cents	3.8	(3.8)	200
APM Results
Adjusted EBITDA³	USD million	10.3	6.1	69
Adjusted EBITDA⁴	USD/bbl	18.7	10.2	83
Adjusted EBITDA margin⁵	%	33.6	28.3	19
Adjusted EBITDA after Current Taxes⁶	USD million	7.0	6.0	17
Adj. EBITDA after Current Taxes per share - diluted	US cents	16.7	14.3	17
Consolidated operating break-even	USD/bbl	27.8	24.7	13
Net cash plus working capital surplus⁸	USD million	22.3	21.4	4

Notes:

1. Realised price: Actual price received for crude oil sales per barrel ("bbl").

2. Average net production: This refers to average production attributable to Trinity per day for all operations; lease operatorships, farm-out operations and joint ventures.

3. Adjusted EBITDA: Operating Profit before Taxes for the period, adjusted for Depreciation, Depletion & Amortisation ("DD&A") and other non-cash expenses, namely Share Option Expenses, Impairment of Financial Assets, FX Gains/Losses and Fair Value Gains/Losses on Derivative financial instruments.

4. Adjusted EBITDA (USD/bbl): Adjusted EBITDA/production over the period.

5. Adjusted EBITDA Margin (%): Adjusted EBITDA/Revenues.

6. Adjusted EBITDA after Current Taxes: Adjusted EBITDA less Supplemental Petroleum Taxes ("SPT"), Property Taxes ("PT"), Petroleum Profits Tax ("PPT") and Unemployment Levy ("UL").

7. Group operating break-even: The realised price/bbl where the Adjusted EBITDA/bbl for the Group is equal to zero.

8. Net cash plus working capital surplus: Current Assets less Current Liabilities (other than Derivative financial asset / liability and Provision for other liabilities).

H1 2021 Strategic Highlights

· The first step towards the long anticipated reform of SPT came into effect during H1 2021, with the threshold at which SPT becomes payable for onshore oil producers producing less than 2,000 barrels of crude oil per day increasing from USD 50.0/bbl to USD 75.0/bbl for the fiscal years 2021 and 2022.

· Renewal of LOAs for WD-2, WD-5/6, WD-13 and WD-14 blocks:

o Combination of improved terms and a longer tenure (10 versus 5 years previously) offer the potential to deliver greater value from existing licence areas. The aggregate increase in NAV across the Onshore portfolio from these changes is estimated at between 4-14% depending on where realised prices are between USD 30.0/bbl to USD 65.0/bbl (12% increase based on the current forward curve).

· Proposed acquisition of the PS-4 Block, announced in May 2021 and now expected to complete early in Q4 2021, will further enhance the Company's onshore acreage and offer additional drilling opportunities:

o Contiguous to WD-5/6 block which is Trinity's largest and most prolific onshore block.

o 80% of the PS-4 block is covered by Trinity's 3D seismic cube.

o Enables Trinity to expand the area of coverage for the 3D seismic sequence stratigraphic interpretation, offering significant opportunities to add reserves and production on a meaningful scale.

o Creates a broader opportunity set from which the Group can high-grade development candidates and identify new exploration and appraisal prospects.

o Provides substantial synergies from a financial, operational and technical perspective.

o Funded from existing cash resources and immediately accretive to operating and free cash flow.

· The Galeota Asset Development (offshore East Coast) was progressed with the submission of the Galeota Field Development Plan ("FDP") to the Ministry of Energy and Energy Industries ("MEEI") in May 2021.

· Continued to work in the Jubilee data room, a potentially meaningful offshore West Coast development opportunity.

· Short-listed with our partner for the North West District ("NWD") onshore exploration bid round from Heritage.

· Commitment to explore and develop new energy projects demonstrated via the Memorandum of understanding ("MOU") with The University of the West Indies ("UWI"), St. Augustine, focused on building capacity in renewables while challenging and reducing carbon output across the region.

H1 2021 Financial Highlights

· Average realisation of USD 55.9/bbl for H1 2021 (H1 2020: USD 36.3/bbl).

· Revenues up 43% to USD 30.7 million (H1 2020: USD 21.5 million).

· Cash operating costs of USD 15.2/bbl (H1 2020: USD 14.3/bbl).

· Cash balance of USD 19.0 million as at 30 June 2021 (YE 2020: USD 20.2 million). Operating cash flow before working capital movements of USD 7.7 million generated and reinvested in scaling the business as follows:

- USD 0.7 million prepayment towards PS-4 acquisition, and USD 3.5 million of other working capital movements and income taxes paid during H1 2021.

- USD 4.5 million of capex, including the Onshore Seismic acquisition, Galeota Asset Development and Infrastructure related spend.

· Ongoing execution of our crude oil price derivative strategy to provide downside protection to Group revenues. The Group took advantage of the increase in oil prices to execute additional derivative instruments during H1 2021.

· Robust production levels combined with rigorous control of costs helped maintain an operating break-even of USD 27.8/bbl for H1 2021 (H1 2020: USD 24.7/bbl). The Group remains on track to meet its target for an average operating break-even of below USD 30.0/bbl for FY 2021.

H1 2021 Operational Highlights

· H1 2021 average net production volumes of 3,032 bopd (H1 2020: 3,282 bopd) with no new wells being drilled since 2019 and despite the operational challenges posed by the COVID-19 pandemic.

o 8% decrease relative to the corresponding period last year - which aligns to typical natural decline.

· Effective response to the challenges presented by the ongoing COVID-19 restrictions:

o Tiered workforce to ensure that Critical/Front-line operatives were vaccinated as a priority

o To date, 74% of the workforce has been fully vaccinated, and vaccines have also been offered to contractors

o Rigorous COVID-19 internal response plans put in place to provide operational continuity

· Three recompletions ("RCPs") (H1 2020: 6) and 43 workovers and reactivations ("WOs") (H1 2020: 56) were completed during the period, with swabbing continuing across the onshore and west coast assets.

o Ready to execute 12 RCPs in H2 2021, of which 40% are already approved by the relevant regulatory bodies.

· Continued focus on well performance and optimisation.

o The Company is on track to meet its target of having 31 wells automated at its largest onshore field, WD-5/6, during H2 2021

· Galeota Field Development Plan ("FDP") submitted in May 2021 with MEEI decision in Q4 2021.

· Initial results from onshore 3D seismic interpretation are very encouraging with several, potentially meaningful, new plays and leads already identified.

o Several high-angle well ("HAW") drilling leads already identified, as we aim to transition to drilling fewer conventional vertical wells and a higher number of HAWs, and ultimately full horizontal wells.

o HAWs have the potential to increase average initial production ("IP") rates by 2-3x

o Resumption of new drilling targeted for early H1 2022

· Production volumes for the remainder of 2021 will be dependent on a number of factors including operational constraints imposed by COVID-19. However, net average production for 2021 is still expected to be in the range of 2,900 - 3,100 bopd.

Post Period End Highlights

· Completion of Capital Reorganisation in July 2021.

o Clears the way for future dividend payments and/or share buy backs when deemed appropriate.

· New 25 year Galeota Exploration and Production Licence

o Heritage's 35% working interest across the Galeota Licence has been converted to an overriding royalty ("ORR")

o Previously Trinity held a 100% WI only over the Trintes producing area and a 65% WI across the wider Block. Trinity now has a 100% WI over the entire Block and can therefore recognise 100% of the reserves and resources across the entire Galeota Licence.

o Moving to a 100% WI will also enable Trinity to apply the bulk of its substantial Group tax losses of USD 232.7 million across the entire Galeota Licence, enabling them to be utilised more quickly

o New Crude Oil Sales Agreement ("COSA") signed for the Galeota Licence, giving greater pricing clarity to Trinity and potential funding partners

o Improved Joint Operating Agreement ("JOA") now more aligned to international standards

o The aggregate increase in NAV across the Galeota licence is estimated at between 25-94% dependent on where realised prices are between USD 30.0/bbl to USD 65.0/bbl (75% increase based on the current forward curve).

· Agreement of a new 25 year Licence and the improved commercial terms are crucial milestones that enable Trinity to attract funding partners as part of a farm-down process and move towards a Final Investment Decision ("FID") to bring the Echo development to fruition.

· Galeota farm-down process to commence Q4 2021 with the appointment of an Acquisition and Divestiture advisor.

· Responding to the tragic and unexpected passing of our founder and Executive Chairman, Bruce Dingwall, CBE:

o Jeremy Bridglalsingh appointed Chief Executive Officer and Nick Clayton appointed as Non-Executive Chairman

o Jeremy heads a highly capable, six strong Executive Management Team which was recently expanded to include Denva Seepersad as Finance Director and Dr Ryan Ramsook as Executive Manager Sub Surface.

o Derek Hudson, a Trinidadian national, joined the Trinity Board in September 2021 as an independent Non-Executive Director, bringing over 30 years senior level experience in the oil and gas industry, operating globally with multi-national organisations and state enterprises.

o Establishment of a New Technical Committee to be chaired by James Menzies (Non-Executive Director) and to comprise both Board member(s) and other Industry experts to boost the commercial and technical expertise available to the Board and Executive Management Team.

Outlook

We have continued to make progress since the period end, and the Company is well positioned to embark upon an exciting phase of growth underpinned by a robust, low cost, cash generative production platform.

The extension of existing licences on improved commercial terms, the broader opportunity set being developed via the 3D seismic interpretation, opportunities to act as a consolidator in Trinidad and the potential to work with partners to access more material opportunities, all provide excellent prospects for the second half and beyond.

Nicholas Clayton, Non-Executive Chairman of Trinity, commented:

"I am incredibly proud of the resilience demonstrated by the Trinity team in the wake of the sudden passing of Bruce Dingwall and the ongoing challenges to the business posed by the COVID-19 pandemic. On behalf of the entire Board, I would like to express my sincere thanks to everyone at Trinity for their continued dedication throughout this challenging period.

"The continued hard work and dedication of our team ensures continued focus on profitably scaling the business by acting as a consolidator onshore, working with partners to access larger opportunities that we could not contemplate by ourselves, and diversifying our revenue streams where opportunities exist to enhance the economics of our core asset base.

"Our strong cash generation, high margin operating model and growing reputation in the region mean that we are extremely well placed to take advantage of an attractive set of new business opportunities.

"It goes without saying that the tragic loss of Bruce last month affected everyone at Trinity, but we are determined to build on his legacy, realising the full potential of the strong position which the Group is now in."

Analyst Briefing:

A briefing for Analysts will be held at 13.00 (BST) today via web conference. Analysts wishing to join should contact trinityexploration@walbrookpr.com for details.

Investor Presentation:

The Company will be hosting a presentation through the digital platform Investor Meet Company at 16.00 (BST) this afternoon. Investors can sign up to Investor Meet Company for free and add to meet Trinity Exploration via the following link https://www.investormeetcompany.com/trinity-exploration-production-plc/register-investor

Enquiries

Trinity Exploration & Production

Nick Clayton, Non-Executive Chairman

Jeremy Bridglalsingh, Chief Executive Officer

Tracy Mackenzie, Corporate Development Manager

+44 (0)131 240 3860

SPARK Advisory Partners Limited (Nominated Adviser & Financial Adviser)

Mark Brady

James Keeshan

+44 (0)20 3368 3550

Cenkos Securities PLC (Broker)

Leif Powis (Corporate Broking)

Neil McDonald

+44 (0)20 7397 8900

+44 (0)131 220 6939

Walbrook PR Limited

Nick Rome/Nicholas Johnson

trinityexploration@walbrookpr.com +44 (0)20 7933 8780

Competent Person's Statement

All reserves and resources related information contained in this announcement has been reviewed and approved by Dr. Ryan Ramsook, Trinity's Executive Manager, Subsurface. Dr. Ramsook is also a Senior Lecturer at the University of the West Indies and Fellow of the Geological Society (FGS) of London. He is a Geologist by background with 16+ years' experience.

About Trinity ( www.trinityexploration.com )

Trinity is an independent oil production company focused solely on Trinidad and Tobago. Trinity operates producing and development assets both onshore and offshore, in the shallow water West and East Coasts of Trinidad. Trinity's portfolio includes current production, significant near-term production growth opportunities from low risk developments and multiple exploration prospects with the potential to deliver meaningful reserves/resources growth. The Company operates all of its nine licences and, across all of the Group's assets, management's estimate of the Group's 2P reserves as at the end of 2020 was 19.55 mmbbls. Group 2C contingent resources are estimated to be 31.06 mmbbls. The Group's overall 2P plus 2C volumes are therefore 50.61 mmbbls.

Trinity is listed on the AIM market of the London Stock Exchange under the ticker TRIN.

Disclaimer

This document contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil exploration and production business. Whilst the Group believes the expectation reflected herein to be reasonable in light of the information available to it at this time, the actual outcome may be materially different owing to macroeconomic factors either beyond the Group's control or otherwise within the Group's control.

OPERATIONAL REVIEW

The COVID-19 pandemic's impact on the demand for oil, the subsequent fall in oil prices, and the potential operating disruption to oil and gas companies is an extremely challenging and evolving situation.

The pandemic's ramifications have impacted Trinity alongside all businesses within the energy sector and wider business environment. To date the Company has recorded 20 positive cases which were mainly distributed amongst the West Coast and Onshore assets with all employees fully recovered and back to work. The Company has effectively reallocated resources to ensure operational continuity to negate operational disruptions and revised the COVID-19 Response Plans for the sustenance of employee safety and base production maintenance.

The Company has accomplished these objectives by executing the following key initiatives:

· Pre-access screening of all employees, contractors, sub-contractors and suppliers to anticipate suspected and potential cases

· Increased PPE protocols to negate cross-contamination potential

· Increased COVID-19 detection testing

· Implemented screens in shared transportation vehicles

· Improved contact tracing methods

· Established "bio-bubbles" within the operational segments

· Tiered approach to business continuity was established to scale the response based on criteria such as case loading, vaccination capacity etc.

The Group continues to preserve and grow a diversified production, development, appraisal and exploration base. The asset portfolio includes current production and further opportunities from a significant number of wells within multiple fields both onshore and offshore and so is not reliant on any one well or field. Ensuring that it has a wide and growing suite of measures that minimise natural decline and base production volatility, whilst growing production from new drilling, is core to the Company's strategy.

Despite the challenges being faced in the industry, the Company continued during H1 2021 with its RCP programme, routine WOs, reactivations, swabbing and increased automation, resulting in a relatively modest 8% period-on-period decline. This aligns to typical natural decline rates and was achieved despite constrained operational conditions (COVID-19 restrictions). COVID-19 impacted Trinity's operations by reducing the speed at which we have been able to react to wells going offline. However, reservoir deliverability remains very encouraging, and the Company looks forward to bringing the affected wells back online during Q4 2021.

The H2 2021 activity set is expected to lead to continued strong production levels going into 2022.

Onshore operations

· H1 2021 average net production was 1,656 bopd (H1 2020: 1,815 bopd). The 9% decrease was as a result of natural declines on base production. A total of 37 WOs were completed in H1 2021 (H1 2020: 49) in conjunction with the interrupted RCP programme, with only 3 RCPs completed in H1 2021(H1 2020: 6).

· Technological strategies are being implemented using SCADA to:

o Provide a solution application for Sucker Rod Pumps and Progressive Cavity Pumps (support predicative analysis through real time surveillance and support well optimisation).

o Reduce time taken to detect Electrical Shut Downs ("ESDs") from field power losses through to the implementation of r eal time monitoring tools to potentially limit the amount of down time on wells.

· The implementation of Well-Site Generators for ESD protection on both clusters and single wells that are significant contributors (WD-2 and WD-5/6) will occur during H2 2021.

· Improved sand management strategies commenced in June 2021 and are expected to continue during H2 2021 through the study and implementation of sand control in high producing wells prone to excessive sand production.

· H2 2021 planned work programme anticipates 7 RCPs, 4 Sand controls and ongoing base management via WOs, reactivations and increased swabbing across all onshore fields.

East Coast operations

· H1 2021 average net production was 1,123 bopd (H1 2020: 1,225 bopd). The 8% decrease in production levels was as a combined result of natural declines, mechanical failures of downhole pumps and delayed WOs due to COVID-19 related resource reallocations. A total of 6 WOs were undertaken during H1 2021 (H1 2020: 7 WOs).

· Trinity continues to invest in maintaining production levels via better power generation management, continued pump optimisation and the review of alternative artificial lift technologies to augment production.

· Well optimisation strategies are being further implemented using the SCADA approach to reduce current spend on real time monitoring and data aggregation of Electrical Submersible Pumps ("ESPs").

· H2 2021 work programme to consist of routine WOs and reactivations.

West Coast operations

· H1 2021 average net production was 253 bopd (H1 2020: 242 bopd). The 5% increase in production was the result of continued focus on preserving base production, including increased swabbing and optimisation activities in the field. There were no workovers conducted during this period, but increased emphasis on base enhancement activities on the Brighton Marine asset.

· H2 2021 planned work programme is expected to include 4 WOs.

FINANCIAL REVIEW

Income Statement Analysis

	H1 2021	H1 2020	Change
Production
Average realised oil price (USD/bbl)	55.9	36.3	19.6
Average net production (bopd)	3,032	3,282	(250)

Statement of Comprehensive Income	USD'000	USD'000	USD'000
Operating revenues	30,663	21,531	9,132
Operating expenses (excluding Non-cash items, SPT & PT)	(20,374)	(16,490)	(3,884)
Operating profit before Non-cash items, SPT & PT	10,289	5,041	5,248
DD&A	(3,656)	(4,362)	706
Other Non-Cash Items	(3,460)	1,172	(4,632)
Operating profit before SPT & PT	3,173	1,851	1,322
SPT	(1,971)	153	(2,124)
PT	(288)	(266)	(22)
Operating profit before impairment and exceptional items	914	1,738	(824)
Impairment	-	(160)	160
Exceptional items	(356)	63	(419)
Operating profit/(loss) after exceptional items and SPT & PT	558	1,641	(1,083)
Finance income	62	44	18
Finance cost	(748)	(743)	(5)
(Loss)/profit for the period	(128)	942	(1,070)
Income Taxation credit/(expense)	1,772	(2,573)	4,345
Total Comprehensive Income/(Loss) for the period	1,644	(1,631)	3,275
Currency translation	3	(3)	6
Total Comprehensive Income/(expense)	1,647	(1,634)	3,281

Operating Revenues

Operating revenues of USD 30.7 million (H1 2020: USD 21.5 million) increased due to higher realised oil price despite an 8% decline in production volumes for the period .

Operating expenses (excluding Non-cash items)

Operating expenses (excluding non-cash items) of USD (20.4) million (H1 2020: USD (16.5) million) comprised:

· Royalties of USD (9.4) million (H1 2020: USD (5.8) million), due to higher oil prices

· P roduction costs ("Opex") of USD (8.1) million (H1 2020: USD (8.5) million), due to a decrease in crude transportation fees and fewer workovers conducted.

· G&A expenditure of USD (2.8) million (H1 2020: USD (2.2) million), due to return to pre-low oil price cost structure similar to 2019 which was USD (2.7) million.

Non-cash operating expenses

Non-cash operating expenses comprised:

· Depreciation, Depletion and Amortisation ("DD&A") charges of USD (3.7) million (H1 2020: USD (4.4) million)

· Impairment of financial assets of USD (1.0) million (H1 2020: USD (0.4) million)

· Share option expense USD (0.3) million (H1 2020: USD (0.4) million)

· Foreign exchange loss USD (0.1) million (H1 2020: USD (0.1) million)

· Derivative (expenses)/income USD (2.1) million (H1 2020: USD 2.1 million income) comprising the movement in the fair valuation of executed crude oil derivatives during the period

Operating Profit Before Supplemental Petroleum Taxes ("SPT") and Property Tax ("PT")

The operating profit before SPT and PT for the period amounted to USD 3.2 million (H1 2020: USD 1.9 million) and was due to higher operating revenues resulting from the higher oil prices.

SPT & PT

The Group incurred SPT charges in relation to its offshore assets in H1 2021 of USD (2.0) million (H1 2020: 0.2 million credit), on account of the realised oil price being higher than USD 50.0/bbl throughout the period. In H1 2020 the credit of USD 0.2 million in H1 2020 arose as a result of a surplus Investment Tax Credit from the prior year being refunded. An accrual for PT of USD (0.3) million arose for the period (H1 2020: USD (0.3) million). SPT and PT are classified as "operating expenses" rather than "income taxation" under IFRS.

Impairment and Exceptional items

Impairment and Exceptional items charge of USD (0.4) million (H1 2020: USD (0.1) million) relate to:

· COVID-19 related costs USD (0.3) million (H1 2020: nil) based on the Trinity's COVID-19 response plan and initiatives implemented (refer to Operational Review section)

· Capital Reorganisation costs USD (0.1) million (H1 2020: USD (0.0) million)

· Impairment loss on property, plant and equipment nil (H1 2020: USD (0.2) million)

· Impairment reversal on property, plant and equipment nil (H1 2020: USD 0.1 million)

Net Finance Cost

Net finance costs for the period totalled USD (0.7) million (H1 2020: USD (0.7) million), comprising:

· Unwinding of the discount rate on the decommissioning provision of USD (0.6) million (H1 2020: USD (0.6) million)

· Net Interest and expenses on bank overdraft - USD (0.1) million (H1 2020: USD (0.0) million)

· Interest on leases - USD (0.0) million (H1 2020: USD (0.1) million)

Income Taxation

Taxation credit for the period was USD 1.8 million (H1 2020: USD (2.6) million charge), comprising:

· Increase in deferred tax assets of USD 2.2 million (H1 2020: USD (3.2) million expense), due to an increase in projected oil prices and taxable profits

· Reduction in deferred tax liability of USD 0.6 million (H1 2020: USD 0.6 million)

· Petroleum Profits Tax ("PPT") of USD (0.7) million (H1 2020: nil)

· Unemployment Levy ("UL") of USD (0.3) million (H1 2020: (0.0) million)

As at 30 June 2021, the Group had unrecognised tax losses of USD 216.3 million (H1 2020: 226.3 million) which have no expiry date.

Total Comprehensive Income/(Loss)

Total Comprehensive Income for the period was USD 1.6 million (H1 2020: USD (1.6) million loss).

Cash Flow Analysis

Opening Cash Balance

Trinity began the year with an initial cash balance of USD 20.2 million (2020: USD 13.8 million).

Summary of Statement of Cash Flows
	H1 2021	H1 2020
	USD'000	USD'000
Opening cash balance	20,237	13,810
Cash movement
Cash inflow from operating activities	7,670	5,853
Changes in working capital	(2,955)	330
Income taxation paid	(1,201)	(86)
Net cash inflow from operating activities	3,514	6,097
Net cash outflow from investing activities	(4,461)	(2,667)
Net cash inflow/(outflow) from financing activities	(316)	2,439
Increase in cash and cash equivalents	(1,263)	5,869
Closing cash balance	18,974	19,679

Net cash inflow from operating activities

Net cash inflow from operating activities was USD 3.5 million (H1 2020: USD 6.1 million):

· Operating activities for H1 2021 generated an operating cash flow before changes in working capital and income taxes of USD 7.7 million (H1 2020: USD 5.9 million)

· Changes in working capital resulted in a net decrease of USD (3.0) million (H1 2020: increase of USD 0.3 million) and included a prepayment of USD 0.7 million for the acquisition of the PS-4 block and a further increase in the Group's VAT receivable to USD 3.7 million (H1 2020 USD 1.4 million)

· Income Taxation - PPT and UL paid USD (1.2) million (H1 2020: USD (0.1) million) resulting from higher oil price

Cash outflow from investing activities

Investing cash outflows for H1 2021 was USD (4.5) million (H1 2020: USD (2.7) million) which included acquisition of Onshore Seismic USD (1.1) million, Galeota asset development USD (1.0) million and infrastructure investment on its East Coast assets.

Net cash (outflow)/inflow from financing activities

Financing cash outflows for H1 2021 was USD (0.3) million comprising USD (0.4) million cash payment on leases and USD 0.1 million in finance income from short-term deposits (H1 2020: USD 2.4 million resulting primarily from the draw-down of the bank overdraft facility of USD 2.7 million less the cash payment on leases of USD (0.3) million).

Closing Cash Balance

Trinity's cash balance at 30 June 2021 was USD 19.0 million (31 December 2020: USD 20.2 million).

Statement of Financial Position Analysis

	H1 2021	YE 2020	Change
	USD'000	USD'000	USD'000

Assets:
Non-current Assets	78,893	75,859	3,034
Current Assets	34,460	33,009	1,451

Liabilities:
Non-Current Liabilities	48,857	48,481	376
Current Liabilities	14,020	11,835	2,185

Equity and Reserves:
Capital and Reserves to Equity Holders	50,476	48,552	1,924

Cash plus working capital surplus	22,328	21,424	904

Non-current Assets

Non-current assets increased by 4% to USD 78.9 million at H1 2021 from USD 75.9 million at YE 2020:

· Property, plant and equipment USD 37.8 million (YE 2020: USD 37.8 million)

· Intangible assets USD 28.3 million (YE 2020: USD 27.3 million) - investment in Galeota Asset Development

· Deferred tax asset of USD 8.2 million (YE 2020: USD 6.0 million), due to the increase in the forecast oil prices

· Abandonment funds and performance bond of USD 3.8 million (YE 2020: USD 3.7 million)

· Right of use asset of USD 0.8 million (YE 2020: USD 1.0 million) relating to motor vehicles, office building, staff house and office equipment leases that met the recognition criteria of a lease under IFRS 16.

Current Assets

Current assets increased by 4% to USD 34.5 million at H1 2021 from USD 33.0 million at YE 2020:

· Cash and cash equivalents decreased by 6% to USD 19.0 million (YE 2020: USD 20.2 million)

· Trade and other receivables of USD 10.1 million (YE 2020: USD 7.2 million)

o Trade and other receivables (less impairment) of USD 4.2 million (YE 2020: USD 3.4 million)

o VAT recoverable of USD 3.7 million (YE 2020: 2.4 million)

o Prepayments and other receivables (less impairment) of USD 2.2 million (YE 2020: USD 1.4 million)

· Inventories increased by 2% to USD 5.4 million (YE 2020: USD 5.3 million)

Non-current Liabilities

Non-current liabilities increased to USD 48.9 million at H1 2021 from USD 48.5 million at YE 2020, primarily due to:

· Provision for other liabilities of USD 46.6 million (YE 2020: USD 45.4 million)

· Deferred tax liabilities of USD 2.1 million (YE 2020: USD 2.6 million)

· Lease liability of USD 0.2 million (YE 2020: USD 0.5 million)

Current Liabilities

Current liabilities increased by 18% to USD 14.0 million at H1 2021 (YE 2020: USD 11.8 million) primarily due to:

· Trade and other payables of USD 8.8 million (YE 2020: USD 7.8 million)

o Trade payables of USD 2.1 million (YE 2020: USD 2.0 million)

o Accruals and other payables of USD 3.5 million (YE 2020: USD 4.3 million)

o SPT & PT of USD 3.2 million (YE 2020: USD 1.5 million)

· CIBC bank overdraft facility USD 2.7 million (YE 2020: USD 2.7 million)

· The non-cash fair value of derivative instruments declined at H1 2021, creating a current liability of USD 1.8 million (YE 2020: nil). These instruments are implemented to hedge against potential fall in oil prices.

Cash plus Working Capital Surplus

Cash plus working capital surplus calculated as Current Assets less Current Liabilities (excluding Provisions for other liabilities and Derivative assets/(liabilities)) increased by 4% to USD 22.3 million (YE 2020: USD 21.4 million)

APPENDIX 1: TRADING SUMMARY

A summary of realised price, production, operating break-evens, Opex and G&A expenditure metrics is set out below:

Trading Summary Table

Details	H1 2021	H1 2020	Change %

Realised price (USD/bbl)	55.9	36.3	54
Production (bopd)
Onshore	1,656	1,815	(9)
West Coast	253	242	5
East Coast	1,123	1,225	(8)
Group Consolidated	3,032	3,282	(8)

Operating break-even (USD/bbl)
Onshore	17.9	16.5	8
West Coast	28.1	25.6	10
East Coast	23.2	22.5	3
Group Consolidated	27.8	24.7	13

Metrics (USD/bbl)
Opex/bbl - Onshore	12.8	12.0	7
Opex/bbl - West Coast	22.2	21.1	5
Opex/bbl - East Coast	17.3	17.5	(1)
Opex/bbl - Group Consolidated	15.2	14.3	6
G&A/bbl	5.3	3.7	43

Notes: Group consolidated operating break-even: The realised price/bbl for which the adjusted EBITDA/bbl exclusive of net derivative expense/income for the Group is equal to zero

INDEPENDENT REVIEW REPORT TO TRINITY EXPLORATION & PRODUCTION plc

Report on the Condensed Consolidated Interim Financial Statements

Introduction

We have been engaged by the Company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2021 which comprises the Consolidated Statement of Comprehensive Income, Consolidated Statement of Financial Position, Consolidated Statement of Changes in Equity and Consolidated Cash Flow Statement.

We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

Directors' responsibilities

The interim report, including the financial information contained therein, is the responsibility of and has been approved by the directors. The directors are responsible for preparing the interim report in accordance with the rules of the London Stock Exchange for companies trading securities on AIM which require that the half-yearly report be presented and prepared in a form consistent with that which will be adopted in the Company's annual accounts having regard to the accounting standards applicable to such annual accounts.

Our responsibility

Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.

Scope of review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, ''Review of Interim Financial Information Performed by the Independent Auditor of the Entity'', issued by the Financial Reporting Council for use in the United Kingdom. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2021 is not prepared, in all material respects, in accordance with the rules of the London Stock Exchange for companies trading securities on AIM.

Use of our report

Our report has been prepared in accordance with the terms of our engagement to assist the Company in meeting the requirements of the rules of the London Stock Exchange for companies trading securities on AIM and for no other purpose. No person is entitled to rely on this report unless such a person is a person entitled to rely upon this report by virtue of and for the purpose of our terms of engagement or has been expressly authorised to do so by our prior written consent. Save as above, we do not accept responsibility for this report to any other person or for any other purpose and we hereby expressly disclaim any and all such liability

BDO LLP

Chartered Accountants

London

14 September 2021

BDO LLP is a limited liability partnership registered in England and Wales (with registered number OC305127).

STATEMENT OF DIRECTORS' RESPONSIBILITY

The Directors confirm that this condensed consolidated interim financial information has been prepared in accordance with International Accounting Standards ("IAS") and that the interim management report includes:

· an indication of important events that have occurred during the first six (6) months and their impact on the condensed set of financial statements, and a description of the principal risks and uncertainties for the remaining six (6) months of the financial year; and

· the management report, which is incorporated into the directors' report, includes a fair review of the development and performance of the business and the position of the Company and the undertakings included in the consolidation taken as a whole, together with a description of the principal risks and uncertainties that they face; and

· material related party transactions in the first six (6) months and any material changes in the related-party transactions described in the last annual report.

A list of the current Directors is maintained on the Trinity Exploration & Production plc website www.trinityexploration.com.

By order of the Board

Jeremy Bridglalsingh

Chief Executive Officer

14 September 2021

Trinity Exploration & Production plc Condensed Consolidated Statement of Comprehensive Income for the period ended 30 June 2021 (Expressed in United States Dollars)
	Notes	6 months to 30 June 2021	6 months to 30 June 2020 (Restated)	Year ended 31 December 2020 (Restated)
		$'000	$'000	$'000
		(unaudited)	(unaudited)	(audited)
Operating Revenues
Crude oil sales		30,663	21,531	44,074
Other income		--	--	4
		30,663	21,531	44,078
Operating Expenses
Royalties		(9,387)	(5,798)	(11,746)
Production costs		(8,139)	(8,509)	(16,458)
Depreciation, depletion and amortisation	8-10	(3,656)	(4,362)	(8,174)
General and administrative expenses		(2,848)	(2,183)	(5,095)
Impairment of financial assets		(993)	(365)	(252)
Share option expense	14	(307)	(446)	(963)
Foreign exchange (loss)/gain		(52)	(138)	7
Derivative (expense)/income*	3,12	(2,108)	2,121	1,568
		(27,490)	(19,680)	(41,113)
Operating Profit Before Supplemental Petroleum Taxes ("SPT") and Property Tax ('PT")		3,173	1,851	2,965

SPT		(1,971)	153	153
PT		(288)	(266)	(532)
Operating Profit Before Impairment and Exceptional Items		914	1,738	2,586

Impairment	4	--	(160)	(1,218)
Exceptional items*	5	(356)	63	43
Operating Profit After Impairment and Exceptional Items		558	1,641	1,411

Finance Income	7	62	44	108
Finance cost	7	(748)	(743)	(1,416)

(Loss)/Profit Before Income Taxation		(128)	942	103

Income Taxation credit/(expense)	6	1,772	(2,573)	(2,938)

Profit/(Loss) for the period		1,644	(1,631)	(2,835)

Other Comprehensive Income/(Expense)
Currency Translation		3	(3)	(1)

Total Comprehensive Income/(Expense) for the period		1,647	(1,634)	(2,836)
Earnings per share (expressed in dollars per share)
Basic*	20	0.04	(0.04)	(0.07)
Diluted*	20	0.04	(0.04)	(0.07)

* See notes 3, 5 and 20 regarding restatements as a result of reclassification of balances (notes 3 & 5) and share reorganisation (note 20).

Trinity Exploration & Production plc Condensed Consolidated Statement of Financial Position for the period ended 30 June 2021 (Expressed in United States Dollars)
	Notes	As at 30 June 2021	As at 30 June 2020	As at 31 December 2020
ASSETS		$'000	$'000	$'000
		(unaudited)	(unaudited)	(audited)
Non-current Assets
Property, plant and equipment	8	37,769	39,708	37,756
Right-of-use assets	9	762	1,287	1,014
Intangible assets	10	28,320	26,606	27,349
Abandonment fund		3,571	3,427	3,490
Performance bond (Investment held to maturity)		253	253	253
Deferred tax asset	15	8,218	6,144	5,997
		78,893	77,425	75,859
Current Assets
Inventories		5,366	5,067	5,267
Trade and other receivables	11	10,120	6,192	7,239
Derivative financial assets	12	--	1,039	266
Cash and cash equivalents		18,974	19,679	20,237
		34,460	31,977	33,009
Total Assets		113,353	109,402	108,868

Equity
Capital and Reserves Attributable to Equity Holders
Share capital	13	97,692	97,692	97,692
Share premium	13	139,879	139,879	139,879
Share based payment reserve	14	3,586	14,773	14,764
Reverse acquisition reserve		(89,268)	(89,268)	(89,268)
Merger reserves		--	75,467	75,467
Translation reserve		(1,647)	(1,652)	(1,650)
Accumulated deficit		(99,766)	(187,655)	(188,332)
Total Equity		50,476	49,236	48,552

Non-current Liabilities
Lease liabilities	9	232	735	465
Deferred tax liability	15	2,062	3,538	2,611
Provision for other liabilities	16	46,563	45,068	45,405
		48,857	49,341	48,481
Current Liabilities
Trade and other payables	17	8,826	6,968	7,803
Bank overdraft	18	2,700	2,700	2,700
Lease liabilities	9	606	641	614
Derivative financial liability	12	1,842	--	--
Taxation payable	6	--	--	202
Provision for other liabilities	16	46	516	516
		14,020	10,825	11,835
Total Liabilities		62,877	60,166	60,316
Total Shareholders' Equity and Liabilities		113,353	109,402	108,868

Trinity Exploration & Production plc

Condensed Consolidated Statement of Changes in Equity

for the period ended 30 June 2021

(Expressed in United States Dollars)

	Share Capital	Share Premium	Share Based Payment Reserve	Reverse Acquisition Reserve	Merger Reserve	Translation Reserve	Accumulated Deficit	Total
	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000

Balance at 1 January 2020	97,692	139,879	14,328	(89,268)	75,467	(1,649)	(186,024)	50,425
Share based payment charge	--	--	445	--	--	--	--	445
Translation difference	--	--	--	--	--	(3)	--	(3)
Total comprehensive loss for the period	--	--	--	--	--	--	(1,631)	(1,631)
Balance at 30 June 2020 (unaudited)	97,692	139,879	14,773	(89,268)	75,467	(1,652)	(187,655)	49,236

Balance at 1 January 2021	97,692	139,879	14,764	(89,268)	75,467	(1,650)	(188,332)	48,552
Share based payment charge	--	--	307	--	--	--	--	307
Capital Reorganisation¹			(11,485)	--	(75,467)	--	86,952	--
Translation difference	--	--	--	--	--	3	(30)	(27)
Total comprehensive profit for the period	--	--	--	--	--	--	1,644	1,644
Balance at 30 June 2021 (unaudited)	97,692	139,879	3, 586	(89,268)	--	(1,647)	(99,766)	50,476

¹ During the period ended 30 June 2021 the Group executed a Capital Reorganisation for the purpose of creating distributable reserves. The steps had not all been completed at the period end. The steps which had been completed were (1) in relation to certain subsidiaries within the Group, reallocation of historic impairment losses taken against Investment in subsidiaries previously recorded in the accumulated deficit to their respective merger reserve (2) capitalisation of unrealised share-based payment reserve and subsequent reduction in the accumulated deficit. The final steps in the Capital Reorganisation were completed after the period end, following the approval of the High Court on 14 July 2021, which eliminated the Accumulated Deficit and created distributable reserves for the Company, thereby technically enabling dividend payments and/or share buybacks to be undertaken when it is deemed prudent to do so.

Trinity Exploration & Production plc

Condensed Consolidated Statement of Cashflows

for the period ended 30 June 2021

(Expressed in United States Dollars)

	Notes	6 months to 30 June 2021	6 months to 30 June 2020	Year end 31 December 2020
		$'000	$'000	$'000
		(unaudited)	(unaudited)	(audited)
Operating Activities
(Loss)/Profit before taxation		(128)	942	103
Adjustments for:
Translation difference		48	3	83
Finance Income		(62)	(44)	(108)
Finance cost	7	137	133	195
Share option expense		307	446	963
Finance cost - decommissioning provision	7	611	610	1,221
Depreciation, depletion and amortisation	8-10	3,656	4,362	8,174
Impairment of property, plant and equipment¹	8	--	160	1,121
Reversal of impairment¹	5	--	(126)	(126)
Impairment losses on financial assets		993	406	515
Fair value on derivative financial instrument²		2,108	(1,039)	(266)
Loss on disposal of assets		--	--	2
		7,670	5,853	11,877

Changes In Working Capital
(Increase)/Decrease in Inventory		(99)	76	(124)
(Increase)/Decrease in Trade and other receivables		( 3,954)	2,816	1,556
Increase/(Decrease) in Trade and other payables		1,098	(2,562)	(1,985)
		(2,955)	330	(553)
Income taxation paid		(1,201)	(86)	(1,028)

Net Cash Inflow From Operating Activities		3,514	6,097	10,296
Investing Activities
Exploration and Evaluation Assets		(1,079)	(287)	(1,062)
Purchase of property, plant & equipment		(3,382)	(2,380)	(4,979)
Net Cash Outflow From Investing Activities		(4,461)	(2,667)	(6,041)

Financing Activities
Finance income		62	44	108
Finance cost		(87)	(18)	(55)
Principal paid on lease liability³		(241)	(172)	(441)
Interest paid on lease liability³		(50)	(115)	(140)
Bank overdraft		--	2,700	2,700
Net Cash (Outflow)/Inflow From Financing Activities		(316)	2,439	2,172

(Decrease)/Increase in Cash and Cash Equivalents		(1,263)	5, 869	6,427
Cash And Cash Equivalents
At beginning of period		20,237	13,810	13,810
Effects of foreign exchange rates on cash		(29)	(103)	(14)
(Decrease)/Increase		(1,234)	5,972	6,441
At end of period		18,974	19,679	20,237

^{1 - The 30 June 2020 balance was split between impairment of property, plant and equipment and reversal of impairment for consistency with comparative statements}

^{2 - The December 2020 balance was reclassified from the Working capital movement to align with the current period presentation.}

^{3 - The lease payment was split between Principal and interest in the current period for consistency with comparative statements}

Trinity Exploration & Production plc

Notes to the Condensed Consolidated Financial Statements for the period ended 30 June 2021

1 Background and Accounting Policies

Background

Trinity Exploration & Production plc ("Trinity") is incorporated and registered in England and trades on the Alternative Investment Market ("AIM"), a market operated by London Stock Exchange plc. Trinity ("the Company") and its subsidiaries (together "the Group") are involved in the exploration, development and production of oil reserves in Trinidad.

Basis of Preparation

These Condensed Consolidated interim financial statements for the six months ended 30 June 2021 have been prepared in accordance with International Financial Reporting Standards ("IFRS") on a going concern basis. The condensed interim financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2020, which have also been prepared in accordance with IFRS.

The results for the six months ended 30 June 2021 and 30 June 2020 have been reviewed, not audited, and do not comprise statutory accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 December 2020 were approved by the board of directors and delivered to the Registrar of Companies. The report of the independent auditors on those accounts was unqualified. The interim report has been reviewed by the auditor.

Going Concern

In making their going concern assessment, the Board have considered the Group's current financial position, budget and cash flow forecast. The Directors have considered the 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 Group started H2 2021 with a steady operating and strong financial position; H1 2021 average production of 3,032 bopd (2020: 3,226 bopd), cash in hand and at bank of $19.0 million as at 30 June 2021 (31 December 2020: $20.2 million (audited)), and crude oil hedges in place protecting a significant proportion of near-term production. In making their going concern assessment, the Directors have considered a cash flow forecast based on expected future oil prices, production volumes and expenditure. A base case and stressed case forecast was prepared with consideration of the following:

Base case assumptions:

· Future oil prices assumed to be in line with the forward curve prevailing as at August 2021, with an average realised oil price of $61.4/bbl in the period to December 2021. The forward price curve applied in the cash flow forecast starts at $62.7/bbl in August 2021, fluctuating each month down to $60.1/bbl in December 2021 through to $57.2/bbl in August 2022

· Average forecast production for the year to December 2021 of 3,017 bopd and for the eight months to August 2022 of 3,049 bopd with production being maintained by RCPs, 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;

· Base forecast assumes the purchase of Onshore PS 4 block completes in H2 2021;

· 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, under the base scenario no derivative income is assumed to be received over the forecast period.

Management considers this to be a reasonable base scenario, reflecting the current 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.

Stressed case assumptions:

· the effect of reductions in oil prices as low as $35.0/bbl being sustained across the forecast period, noting that the base case pricing is in line with market prices. The impact of the low oil price assumed in the stressed case scenario is partially mitigated by the derivative instruments currently in place; and

· the impact of possible disruption from localised COVID-19 cases reducing forecast production by 15%, albeit operations have continued without significant interruption to date and the nature of the operations reduces the risk of such an eventuality.

Under the stressed case scenario, the Group's cash balances are maintained and are 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. 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 condensed consolidated interim financial statements.

Accounting policies

The accounting policies adopted are consistent with those of the previous financial year 31 December 2020 and corresponding interim reporting period, except for those set out in the standards below:

- New standards and amendments effective for periods beginning on 1 January 2021 and therefore relevant to these condensed consolidated interim financial statements

· Interest Rate Benchmark Reform ("IBOR Reform") and its Effects on Financial Reporting - Phase 2

This standard address issues that might affect financial reporting during the reform of an interest rate benchmark, including the effects of changes to contractual cash flows or hedging relationships arising from the replacement of an interest rate benchmark with an alternative benchmark rate.

The Phase 2 amendments apply only to changes required by the interest rate benchmark reform to financial instruments and hedging relationships.

· There are certain new accounting standards, amendments to accounting standards and interpretations which have been published that are not mandatory for 31 December 2021 reporting periods and have not been early adopted by the Group. These standards are not expected to have a material impact on the entity in the current or future reporting periods and on foreseeable future transactions.

Estimates

The preparation of condensed consolidated interim financial statements requires management to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expenses. Actual results may differ from these estimates.

In preparing these condensed consolidated interim financial statements, the significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were the same as those that applied to the consolidated financial statements for the year ended 31 December 2020.

Cash and cash equivalents

For the purpose of presentation in the condensed consolidated statement of cash flows, cash and cash equivalents includes cash on hand, deposits held at call with financial institutions, and other short-term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash.

Trade receivables

Trade receivables are amounts due from the Group's sole customer for crude oil sold in the ordinary course of business. They are generally due for settlement within 30 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.

Impairment of financial assets

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 for forward looking estimates. This is then applied to the gross carrying amount of the receivables to arrive at the loss allowance for the period.

Financial assets recognition of impairment provisions under IFRS 9 is based on the expected credit losses ("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.

Trade and other payables

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

Segment Information

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 Trinidad and Tobago ("T&T") to one customer, Heritage. All non-current assets of the Group are located in T&T.

Derivative financial instruments and hedging activities

The Company has not applied hedge accounting and all derivatives are measured at fair value through profit and loss.

2 Financial risk management

Financial risk factors

The Group's activities expose it to a variety of financial risks: market risk (including currency risk, fair value interest rate risk, cash flow interest rate risk and price risk), credit risk and liquidity risk. The Group's overall risk management program seeks to minimise potential adverse effects on the Group's financial performance.

The condensed consolidated interim financial statements do not include all financial risk management information and disclosures required in the annual financial statements; they should be read in conjunction with the Group's annual financial statements for 2020, which can be found at www.trinityexploration.com .

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 June 2021, the Group held cash at bank of $18.9 million (2020: $20.2 million).

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 Petroleum Company Limited.

3 Derivative (expense)/income

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000
Net derivative (expense)/income	--	1,082	1,302
FV of derivative financial instruments	(2,108)	1,039	266

Total (expense)/income	(2,108)	2,121	1,568

*Restatement

Comparative figures have been reclassified to conform with changes in presentation in the current year. Comparative figures were adjusted to reclassify the fair value gain on derivative financial instruments to derivative income/(expenses) line. There was no impact to opening accumulated deficit nor cash generated from operations. The impact of the restatement is summarised below:

	30 June 2020	30 June 2020
	$'000	$'000
	Restated	Prior period

Other operating income/(expenses)	--	1,082

FV gain on derivative financial instruments	--	1,039


Derivative income/(expense)	2,121	--

	2,121	2,121

4 Impairment

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000
Impairment of property, plant and equipment	--	160	1,218

There were no impairment charges in the current period. In June 2020 and year end 2020, the impairment related to charges for impairment losses on cash generated units. Also, see note 5 (restatement section of note), for details on restatement connected to the reclassification of the Impairment note from Exceptional items.

5 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 condensed consolidated statement of comprehensive income. An analysis of the amounts presented as exceptional items in these condensed consolidated financial statements are highlighted below.

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000
Impairment reversal	--	126	126
Covid-19 costs	(261)	--	--
Fees relating to Capital Reorganisation	(95)	(63)	(83)

Exceptional (charge)/credit	(356)	63	43

· Covid-19 costs - ($0.3 million): Charge in relation to Covid-19 costs incurred by the group for 2021

· Fees relating to capital reorganisation - ($0.1 million): Charge in relation to professional advice on the capital reorganisation. See note 13

*Restatement

Comparative figures have been reclassified to conform with changes in presentation in the current year. Comparative figures were adjusted to reclassify impairment expense from exceptional items. There was no impact to opening accumulated deficit nor cash generated from operations. The impact of the restatement is summarised below:

	30 June 2020	30 June 2020
	$'000	$'000
	Restated	Prior period
Impairment (see note 4)	(160)	--
Exceptional items	63	(97)

	(97)	(97)

6 Income taxation credit/(expense)

a. Taxation	30 June 2021	30 June 2020	31 December 2020
Current tax	$'000	$'000	$'000

Petroleum profits tax	(713)	--	(817)
Unemployment levy	(285)	(6)	(333)

Deferred tax
- Current period
Movement in asset due to tax losses recognised (Note 15)	2,221	(3,218)	(3,365)
Movement in liability due to accelerated tax depreciation (note 15)	549	651	1,577
Income tax credit/(expense)	1,772	(2,573)	(2,938)

Current tax: The Group's effective tax rate varies based on jurisdiction

Tax rates:	30 June 2021	30 June 2020
	$'000	$'000
Corporation Tax UK	19%	19%
Corporation Tax TT	30%	30%
Petroleum Profits Tax	50%	50%
Unemployment levy	5%	5%

Deferred tax: The Group has a deferred tax asset of $8.2 million on its condensed consolidated statement of financial position which is the amount it expects to recover within 3 years based on the expected taxable profits generated by Group companies over that period.

The increase in the deferred tax asset is related to the increase in realised price as well as the improved terms of the Group's LOAs which were renewed during the period.

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000
b. Taxation payable current
Unemployment Levy("UL") Petroleum Profit Tax ("PPT")	-- --	--	58 144
Taxation payable	--	--	202

7 Finance income

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000
Interest income	62	44	108

Finance costs

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000
Decommissioning - Unwinding of discount	(611)	(610)	(1,221)
Interest and other expenses on overdraft	(87)	(18)	(55)
Interest on leases	(50)	(115)	(140)
	(748)	(743)	(1,416)

8 Property, Plant and Equipment

	Plant & Equipment	Leasehold & Buildings	Oil & Gas Property	Other	Total
	$'000	$'000	$'000	$'000	$'000
Opening net book amount at 1 January 2021	2,028	1,481	34,247	--	37,756
Additions	641	10	2,694	--	3,345
DD&A charge for period	(187)	(83)	(3,065)	--	(3,335)
Translation difference	--	--	3	--	3
Closing net book amount at 30 June 2021	2,482	1,408	33,879	--	37,769

At 30 June 2021
Cost	15,569	3,348	303,696	336	322,949
Accumulated DD&A and impairment	(13,087)	(1,940)	(269,820)	(336)	(285,183)
Translation difference	--	--	3	--	3
Closing net book amount at 30 June 2021	2,482	1,408	33,879	--	37,769
	Plant & Equipment	Leasehold & Buildings	Oil & Gas Property	Other	Total
	$'000	$'000	$'000	$'000	$'000
Opening net book amount at 1 January 2020	1,141	1,652	39,587	--	42,380
Additions	810	(3)	604	--	1,411
Impairment loss	--	--	(160)	--	(160)
Impairment reversal (note 4)	126	--	--	--	126
DD&A charge for period	(94)	(70)	(3,888)	--	(4,052)
Translation difference	--	--	3	--	3
Closing net book amount 30 June 2020	1,983	1,579	36,146	--	39,708

Period ended 30 June 2020
Cost	14,696	3,353	299,483	336	317,868
Accumulated DD&A and impairment	(12,713)	(1,774)	(263,340)	(336)	(278,163)
Translation difference	--	--	3	--	3
Closing net book amount 30 June 2020	1,983	1,579	36,146	--	39,708
	Plant & Equipment	Leasehold & Buildings	Oil & Gas Assets	Other	Total
	$'000	$'000	$'000	$'000	$'000
Year ended 31 December 2020
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 for decommissioning estimate	--	--	(152)	--	(152)
Impairment reversal equipment	126	--	--	--	126
Impairment charge	(116)	--	(1,005)	--	(1,121)
DD&A charge for year	(247)	(153)	(7,166)	--	(7,566)
Closing net book amount 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

9 Leases

(i) Amounts recognised in the condensed consolidated statement of financial position

The condensed consolidated statement of financial position shows the following amounts relating to leases:

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000
Right-of-use assets
Non-current assets	762	1,287	1,014

Lease Liabilities
Current	606	641	614
Non-current	232	735	465
	838	1,376	1,079

The ROU assets relate to motor vehicles, office building, staff house and office equipment leases that met the recognition criteria of a Lease under IFRS 16.

(ii) Amounts recognised in the condensed consolidated statement of comprehensive

The condensed consolidated statement of comprehensive income shows the following amounts relating to leases:

	30 June 2021	30 June 2020	01 January 2020
	$'000	$'000	$'000
Depreciation charge of ROU assets
Depreciation	(251)	(261)	(502)


Interest expense (including finance cost)	(50)	(115)	(140)

The total cash outflow for leases in June 2021 was $0.3 million (June 2020: $0.3 million)

10 Intangible Assets

	Computer Software	Exploration and evaluation assets	Total
	$'000	$'000	$'000
Opening net book amount at 1 January 2021	307	27,042	27,349
Additions	111	930	1,041
Amortisation charge for the year	(70)	--	(70)
At 30 June 2021	348	27,972	28,320

Opening net book amount at 1 January 2020	268	25,987	26,255
Additions	51	349	400
Amortisation charge for the year	(49)	--	(49)
Closing net book amount at 30 June 2020	270	26,336	26,606

Opening net book amount at 1 January 2020	268	25,987	26,255
Additions	145	1,055	1,200
Amortisation charge for the year	(106)	--	(106)
Closing net book amount at 31 December 2020	307	27,042	27,349

The exploration and evaluation asset relates to the Galeota Asset Development.

11 Trade and Other Receivables

	30 June 2021	30 June 2020	31 December 2020
Due within one year	$'000	$'000	$'000
Trade receivables	4,545	3,059	3,357
Less: provision for impairment of trade receivables¹	(350)	(205)	(6)
Trade receivables: net	4,195	2,854	3,351
Prepayments	1,886	1,120	862
VAT recoverable	3,677	1,191	2,467
Other receivables*	1,865	1,187	1,413
Less: Provision for Impairment of other receivables¹	(1,503)	(160)	(854)
	10,120	6,192	7,239

₁- The total provision for impairment of trade and other receivables is $1.9 million as at 30 June 2021 (31 December 2020: $0.9 million)

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

The Group applies the IFRS 9 simplified model for measuring ECL which uses a lifetime expected loss allowance and are measured on the days past due criterion.

Trade receivables - Heritage net sales receipts have been collected on a timely basis. However, there is an overriding royalty incentive balance outstanding from Heritage for which an ECL was calculated of $0.3 million.

Prepayments - Included within prepayments is a $0.7 million deposit for the acquisition of block PS-4.

Other receivables - This relates to Joint Interest Billings ("JIB") to Heritage for the Galeota Asset Development comprising costs of $1.7 million and tax recoverable of $0.2 million. As the JIB balances are long outstanding an ECL was calculated at 30 June 2021 of $1.5 million (31 December 2020: $0.9 million) against Other receivables.

* Comparative figures in 30 June 2020 have been reclassified to conform with changes in presentation in the current year. Comparative figures for the prior period showed the other receivables net of the provision for their impairment.

12 Derivative financial assets and Liabilities

The following table compares the carrying amounts and fair values of the group's financial assets and financial liabilities as at 30 June 2021.

	As at 30 June 2021	As at June 2020	As at 31 December 2020
	$'000	$'000	$'000

Derivative (Liability)/Asset	(1,842)	1,039	266
Total	(1,842)	1,039	266

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 30 June 2021 $'000	As at 30 June 2020 $'000	As at 31 December 2020 $'000
Opening balance	266	85	85
Opening derivative instrument realised	--	(85)	(85)
Derivative expense (loss/gain in fair value)	(2,108)	1,039	266
Closing balance	(1,842)	1,039	266

On 30 June 2021 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 30 June 2021 which were as follows:

Type of Hedge	Index	Sell Put	Buy Put	Sell Call	Buy Call	Production	Effective Date	Expiry Date	Fair Value
		USD/ bbl	USD/ bbl	USD/ bbl	USD/bbl	Monthly Barrels			$'000
Put Spread	WTI	20.00	30.00	--	--	15,000	01-Jan-21	31-Dec-21	1
Put Spread	WTI	20.00	30.00	--	--	15,000	01-Jan-21	31-Dec-21	1
2-way collar	Brent	--	42.50	64.35	--	15,000	01-Jul-21	31-Dec-21	(885)
3-way collar	Brent	50.00	60.00	66.90	--	10,000	01-Jan-22	30-Jun-22	(394)
3-way collar	Brent	50.00	60.00	74.40	--	12,500	01-Jan-22	31-Dec-22	(395)
4-way collar	Brent	59.00	68.00	72.00	82.00	15,000	01-Jul-21	31-Dec-21	(170)
									(1,842)

The loss in fair value is recognised in the condensed consolidated statement of comprehensive income during the period. The carrying amount of the derivative financial assets and financial liabilities are a reasonable approximation of their fair value.

13 Share Capital

	Number of shares	Share capital $'000	Share premium $'000	Total $'000
As at 1 January 2021	483,594,288	97,692	139,879	237,571
Share consolidation	(435,234,859)	--	--	--
As at June 2021	48,359,429	97,692	139,879	237,571

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

- As part of the Capital Reorganisation the existing 388,794,303 ordinary shares and 94,799,986 deferred shares of $0.01 was consolidated on a 10:1 basis into new ordinary shares and new deferred shares of $0.10 each.

- After the consolidation, within the final share amount of 48,359,429, there are 38,879,430 new ordinary shares and 9,479,999 new deferred shares. The new deferred shares have no voting or dividend rights and on a return of capital on a winding up have no valuable economic rights.

14 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 2021 the Group had in place share-based payment arrangements for its employees and Executive Directors, the LTIP. The Share Option Plan is fully vested and expensed. The current year charge through share based payments are in relation to the pre-existing LTIP arrangements shown below:

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000
At 1 January	14,764	14,328	14,328
LTIPS exercised	--	--	(527)
Share capital reorganisation	(11,485)	--	--
Share based payment expense:
Long term incentive plan	307	445	963
At 30 June/31 December	3,586	14,773	14,764

- During the period following completion of the share consolidation described in note 13 above the number of options and LTIPs outstanding have also been consolidated on a 10:1 basis.

15 Deferred Income Taxation

The analysis of deferred income taxes is as follows:

	30 June 2021	30 June 2020	31 December 2020
Deferred tax assets:	$'000	$'000	$'000
-Deferred tax assets to be recovered in more than 12 months	(8,218)	(6,144)	(5,997)
Deferred tax liabilities:
-Deferred tax liabilities to be settled in more than 12 months	2,062	3,538	2,611
Net impact	(6,156)	(2,606)	(3,386)

The movement on the deferred income tax is as follows:

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000
At beginning of year	(3,386)	(5,174)	(5,174)
Movement for the year	(2,729)	2,615	1,879
Unwinding of deferred tax on fair value uplift	(41)	(47)	(91)
Net impact	(6,156)	(2,606)	(3,386)

The deferred tax balances are analysed below:

	1 January		30 June		31 Dec		30 June
	2020	Movement	2020	Movement	2020	Movement	2021
	$'000	$'000	$'000	$'000	$'000	$'000	$'000
Deferred tax assets
Acquisition	(33,436)	--	(33,436)	--	(33,436)	--	(33,436)
Tax losses recognised	(39,476)		(39,476)		(39,476)	(2,221)	(41,697)
Tax losses derecognised	63,550	3,218	66,768	147	66,915		66,915
	(9,362)	3,218	(6,144)	147	(5,997)	(2,221)	(8,218)

Deferred tax liabilities
Accelerated tax depreciation	15,834	(604)	15,230	(883)	14,347	(508)	13,839
Non-current asset impairment	(33,214)	--	(33,214)	--	(33,214)	--	(33,214)
Acquisitions	19,580	--	19,580	--	19,580	--	19,580
Fair value uplift	1,988	(46)	1,942	(44)	1,898	(41)	1,857
	4,188	(651)	3,538	(927)	2,611	(549)	2,062

Deferred income tax assets are recognised for tax loss carry-forwards to the extent that the realisation of the related tax benefit through future taxable profits are probable. The Group recognises deferred tax assets over a 3 year outlook which is conservative and consistent with prior periods. There was an increase in the deferred tax assets of $ 2.2 million in the current year (2020: $ 0.1 million decrease). Deferred tax liabilities have reduced by $ 0.5 million (2020: $ 0.7 million decrease) as the temporary differences between the accounting values and tax values decreased to prior period. The Group has unrecognised tax losses amounting to $ 216.3 million which have no expiry date (2020: $ 226.3 million).

Deferred tax assets and liabilities can only be offset in the condensed 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).

16 Provisions and Other Liabilities

Non-Current:	Decommissioning cost	Closure of pits¹	Total
	$'000	$'000	$'000
6 months ended 30 June 2021
Opening amount as at 1 January 2021	45,405	470	45,875
Unwinding of discount	611	--	611
Translation differences	77	--	77
Closing balance as at 30 June 2021	46,093	470	46,563

6 months ended 30 June 2020
Opening amount as at 1 January 2020	44,330	--	44,330
Unwinding of discount	610	--	610
Translation differences	128	--	128
Closing balance as at 30 June 2020	45,068	--	45,068

Year ended 31 December 2020
Opening amount as at 1 January 2020	44,330	--	44,330
Unwinding of discount	1,221	--	1,221
Revision to estimates	(152)	--	(152)
Translation differences	6	--	6
Closing balance at 31 December 2020	45,405	--	45,405

Current:	Litigation claims	Closure of pits¹	Total
	$'000	$'000	$'000
6 months ended 30 June 2021
Opening amount as at 1 January 2021	46	--	46
Closing balance as at 30 June 2021	46	--	46

6 months ended 30 June 2020
Opening amount as at 1 January 2020	46	472	518
Decrease in provision	--	(2)	(2)
Closing balance as at 30 June 2020	46	470	516

Year ended 31 December 2020
Opening amount as at 1 January 2020	46	472	518
	--	(2)	(2)
Closing balance at 31 December 2020	46	470	516

¹There was a change in estimate whereby the Closure of pits provision was reclassified from current to non-current liabilities for the period to 30 June 2021 as management obtained new information in the current period estimating that the liability may extend beyond 12 months.

17 Trade and Other Payables

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000

Trade payables	2,141	1,952	2,024
Accruals	2,931	3,280	3,793
Other payables	543	483	471
SPT & PT	3,211	1,253	1,515
	8,826	6,968	7,803

18 Bank Overdraft

	30 June 2021	30 June 2020	31 December 2020
	$'000	$'000	$'000

Bank Overdraft	2,700	2,700	2,700
	2,700	2,700	2,700

A demand operating (overdraft) line of $2.7 million was entered with FirstCaribbean International Bank (Trinidad & Tobago) Limited ("CIBC") during 2020. The facility was increased on 5 January 2021 by $2.3 million to a total of $5.0 million, and the additional $2.3 million remains undrawn to date.

Details of the overdraft facility:

- Description: $5 million demand revolving credit facility

- Interest Rate: United States Prime rate (currently 9%) minus 4.05 % per annum, with a present effective rate 4.95%, subject to a floor rate of 3.95%

- 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

19 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 for the period, adjusted for mainly non-cash items being DD&A, ILFA, SOE, Fair value gain/loss on Derivatives and Foreign exchange gain/loss.

The Group presents Adjusted EBITDA as it is used in assessing the Group's operating performance as management believes it better illustrates the underlying performance of the Group's business by excluding non-cash items not considered by management to reflect the underlying operations of the Group.

Adjusted EBITDA is calculated as follows:

	6 months to 30 June 2021	6 months to 30 June 2020	Year ended December 2020
	$'000	$'000	$'000
Operating Profit Before SPT & PT	3,173	1,851	2,965

Depreciation, depletion and amortisation	3,656	4,362	8,174
Share option expense	307	446	963
Impairment of financial assets	993	365	252
Fair value of derivative instruments	2,108	(1,039)	(266)
Foreign exchange loss/ (gain)	52	138	(7)
Adjusted EBITDA	10,289	6,123	12,081


	'000	'000	'000
Weighted average ordinary shares outstanding - basic	38,879	38,405	38,623
Weighted average ordinary shares outstanding - diluted	42,036	41,936	41,780
	$	$	$
Adjusted EBITDA per share - basic	0.26	0.16	0.31
Adjusted EBITDA per share - diluted	0.24	0.15	0.29

Adjusted EBITDA after the impact of Current Taxes (SPT, PT, UL and PPT) is calculated as follows:

	6 months to 30 June 2021	6 months to 30 June 2020	Year ended December 2020
	$'000	$'000	$'000
Adjusted EBITDA	10,289	6,123	12,081
SPT	(1,971)	153	153
PT	(288)	(266)	(532)
PPT	(713)	--	(817)
UL	(285)	(6)	(333)

Adjusted EBITDA after Current Taxes	7,032	6,004	10,552

	'000	'000	'000
Weighted average ordinary shares outstanding - basic	38,879	38,405	38,623
Weighted average ordinary shares outstanding - diluted	42,036	41,936	41,780
	$	$	$
Adjusted EBITDA after Current Taxes per share - basic	0.18	0.16	0.27
Adjusted EBITDA after Current Taxes per share - diluted	0.17	0.14	0.25

*Restatement

Comparative figures have been recalculated to conform with changes in presentation in the current year. The comparative figures were recalculated to show the impact on the Adjusted EBITDA per share resulting from the 10:1 share consolidation which reduced the number of ordinary shares from 388,794,303 to 38,879,430 (refer to note 13). The impact of the restatement is summarised below:

	30 June 2020	30 June 2020	31 December 2020	31 December 2020
	$	$	$	$
	Restated	Prior period	Restated	Prior period
Adjusted EBITDA

Adjusted EBITDA per share - basic	0.16	0.01	0.31	0.03
Adjusted EBITDA per share - diluted	0.15	0.01	0.29	0.03


Adjusted EBITDA after Current Taxes

Adjusted EBITDA after Current Taxes per share - basic	0.16	0.02	0.27	0.03
Adjusted EBITDA after Current Taxes per share - diluted	0.14	0.02	0.25	0.03

20 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 period. Diluted earnings per share is calculated using the weighted average number of ordinary shares adjusted to assume the conversion of all dilutive potential ordinary shares.

	Profit/(Loss) $'000	Weighted Average Number Of Shares '000	Earnings Per Share $
Period ended 30 June 2021
Basic	1,644	38,879	0.04
Diluted	1,644	42,036	0.04

Period ended 30 June 2020
Basic	(1,631)	38,405	(0.04)
Diluted	(1,631)	38,405	(0.04)

Year ended 31 December 2020
Basic	(2,835)	38,623	(0.07)
Diluted	(2,835)	38,623	(0.07)

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 are considered potential ordinary shares. Share Options of 1,975,084 are also considered potential ordinary shares but 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 were the same in 2020.

*Restatement

Comparative figures have been recalculated to conform with changes in presentation in the current year. The comparative figures were recalculated to show the impact on EPS resulting from the share consolidation which reduced the number of ordinary shares from 388,794,303 to 38,879,430 (refer to note 13). The impact of the restatement is summarised below:

	Profit/(Loss) $'000	Weighted Average Number Of Shares '000	Earnings Per Share $
Period ended 30 June 2020
Basic (restated)	(1,631)	38,405	(0.04)
Diluted (restated)	(1,631)	38,405	(0.04)
Basic	(1,631)	384,049	(0.00)
Diluted	(1,631)	384,049	(0.00)

Year ended 31 December 2020
Basic (restated)	(2,835)	38,623	(0.07)
Diluted (restated)	(2,835)	38,623	(0.07)
Basic	(2,835)	386,233	(0.01)
Diluted	(2,835)	386,233	(0.01)

21 Contingent Liabilities

i) The East Coast Galeota and the West Coast Point Ligoure, Guapo Bay and Brighton Marine Outer ("PGB") licences and the Farm-Out Agreement for the Tabaquite Block (held by Coastline International Inc.) have expired. There may be additional liabilities and commitments arising when new agreements are finalised, but these cannot be presently quantified until new agreements are available. The Galeota licence was renewed subsequent to the period end (see note 22 point 3).

ii) Parent Company Guarantee. A Letter of Guarantee has been 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. A clause within the Letter of Guarantee implies that the 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.

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 condensed consolidated financial statements.

iv) The Group's Lease Operatorship Assets ("LOA") licences were renewed during the period ended 30 June 2021 with Heritage, effective 1 January 2021. On 3 June 2017 a Performance Bond in the form of a cash deposit of $0.3 million in the name of Heritage was established for due and punctual observance of the conditions, things and matters under the LOA effective until 31 December 2020. A new Performance Bond has been put in place subsequent to the period end post renewal of the LOA in 2021.

22 Events after the Reporting Period

1. Derivative Financial Instruments

In addition to the crude oil derivatives in place as at 30 June 2021, which are shown in note 12 above, the Company has put in place the following crude oil derivative financial instruments post the period end to further protect a portion of its revenue against fluctuation in oil prices:

Type of Hedge	Index	Sell Put	Buy Put	Sell Call	Buy Call	Production	Effective Date	Expiry Date	Execution Date
		USD/ bbl	USD/ bbl	USD/ bbl	USD/ bbl	Monthly Barrels
4-way collar	Brent	59.00	68.00	72.00	82.00	15,000	01-Jan-22	30-June-22	5-Jul-21
3-way collar	Brent	40.00	50.00	80.50	--	15,000	01-Jan-22	31-Dec-22	27-Aug-21

2. Capital Reduction

The Capital Reduction approved by the Company's shareholders at its Annual General Meeting held on 18 June 2021 was sanctioned by the High Court of Justice in England and Wales on 13 July 2021. The Capital Reduction will result in the cancellation of the entire deferred share capital and the entire share premium account of the Company, with the cancellation amount being credited to distributable reserves.

The Company confirms that, following the Capital Reduction, the issued ordinary share capital of the Company remains at 38,879,431 ordinary shares of US$0.01 each, with no ordinary shares held in treasury. The total number of voting rights in the Company also remains at 38,879,431.

3. Galeota licence renewal

On 19 July 2021, the Company announced that a new 25 year exploration and production licence had been issued by the Ministry of Energy and Energy Industries (MEEI) and that Trinity has agreed new and improved commercial terms with Heritage, its partner for the Block. See updated terms:

- New 25 year licence commencing on 14^th July 2021 (initial 6 year term with 19 year extension) covering an area of 19,280 acres (7,802 hectares) with significantly reduced minimum work obligations and performance guarantees

- Heritage 35% working interest across the Galeota licence has been converted to an overriding royalty (ORR)

- The conversion also results in a material reduction in ORR rates across both the producing Trintes field and wider block

- New Crude Sales Agreement (COSA) signed for the Galeota licence, giving greater pricing clarity to Trinity

- Improved Joint Operating Agreement more aligned to international standards

4. Directorate Changes

Following the tragic passing of Bruce Dingwall CBE, Executive Chairman, on 3 August 2021, Mr. Nicholas Clayton assumed the role of Non-Executive Chairman and Jeremy Bridglalsingh assumed the role of Chief Executive Officer of the Group. On 14 September 2021, the Company announced that Derek Hudson had joined the board as a Non-Executive Director.

5. Partial vesting of LTIP awards and new LTIP grant

On 13 August 2021 Trinity announced the partial vesting of LTIP awards which had been granted in 2017 and 2019, the revision of the LTIP and the new 2021 Annual LTIP Award granted under the revised LTIP. The terms of the Revised LTIP will apply to the 2021 Annual LTIP Award and subsequent issues, but will not alter the terms of any previous awards made under the LTIP.

A total of 471,131 options vested in respect of the LTIP award granted in 2017 and 167,018 options vested in respect of the LTIP award granted in 2019. None of these options have been exercised to date.

A total of 325,000 options have been granted under the Revised LTIP in respect of the Company's performance in the year to 31 December 2020 (the "2021 Annual LTIP Award"). The 2021 Annual LTIP Award represents 0.84% of the Company's current issued share capital.

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Trinity Exploration & Production (TRIN)

Thursday, 21st November 2024

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