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.

 

23 May 2024

 

Trinity Exploration & Production plc

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

 

Full Year Results to 31 December 2023

Trinity Exploration & Production plc (AIM: TRIN), the independent E&P company focused on Trinidad and Tobago, announces its final results for the year ended 31 December 2023 ("the Period" or "FY 2023").

2023 was an important year for Trinity with key developments in our ambitious growth programme being progressed:

·    The Company drilled the Jacobin well to test deeper prospectivity in the Lower Cruse Miocene-age turbidite play in our core onshore Palo Seco acreage.  While the well discovered oil in those deeper horizons, flow rates were disappointing, and drilling complexities resulted in significant cost overruns.  Management conservatively decided to write off the entire cost of the well in the year end accounts.  The well has successfully been completed in the Lower Forest horizon and production is expected to commence from this zone shortly.

·    In June, the Company was advised by the Ministry of Energy and Energy Industries ("MEEI") that it had been successful in its bid for the Buenos Ayres block in the 2022 Onshore and Nearshore Competitive Bid Round, immediately to the west of our core Palo Seco acreage.  Buenos Ayres is undrilled and offers considerable potential.  Finalisation of the awards of all of the blocks awarded in the bid round are expected shortly.

·    The ABM-151 well in the Brighton Marine block, offshore the West Coast of Trinidad, was returned to production on 21 March 2023 following an extensive refurbishment of surface facilities and the installation of remote surveillance technology.  Between restart and the end of the year the well flowed at an average rate of 122 bopd, exceeding expectations. 

·    At Galeota, following an extensive Concept-Screening study completed by Petrofac in Q3 2023, Trinity identified a revised infrastructure-led development solution which includes an initial phase of development drilling from existing platforms. Whilst Trinity believes the revised development solution will significantly reduce capital requirement prior to first oil compared to the Echo Field Development Plan, Trinity would need to secure third party financing to take a final investment decision and fund the development.

The fire on the Bravo platform in the Trintes field, represented a significant event for the Company with valuable lessons learned arising from a comprehensive investigation with an associated corrective actions register.  A number of safety improvements have been implemented to date, including those that mitigate the root cause for the fire and improved fire-fighting capabilities in the event of a similar incident.

The Company completed a share buyback programme which commenced on 24 October 2022 and ended on 27 June 2023, having repurchased 1,549,000 shares on the open market for a total cost of USD 2.1 million and Trinity paid its first interim dividend of 0.5 pence per ordinary share on 26 October 2023. 

 

James Menzies has decided not to stand for re-election at this forthcoming Annual General Meeting which coincides with James taking on greater levels of responsibility in other roles outside of Trinity.  The Board expresses its thanks to James for his contribution to the Board since joining in 2017.

 

On 1 May 2024, the boards of directors of Trinity and Touchstone Exploration Inc ("Touchstone") announced the terms of the recommended all share offer (the "Acquisition").  The Acquisition is to be effected by means of a scheme of arrangement under Part 26 of the Companies Act.  Under the terms of the Acquisition, Trinity Shareholders shall be entitled to receive 1.5 New Touchstone Shares for each Trinity share.  Should the Scheme be approved by  Shareholders and sanctioned by the Court, Trinity has an exciting future as part of the enlarged Touchstone organisation.

 

Highlights

·    Group net sales for 2023 were 2,790 bopd (2022: 2,975 bopd)

·    Revenues of USD 69.8 million (2022: USD 92.2 million)

·    Loss before tax of USD (9.5) million (2022: Profit USD 2.5 million)

·    Average price per barrel received was USD 68.6/bbl (2022: USD 84.9/bbl)

·    Adjusted EBITDA (before hedge costs) of USD 19.2 million (2022: USD 35.1 million)

·    Adjusted EBITDA of USD 19.2 million (2022: USD 24.7 million)

·    Operating Profit¹ of USD 9.6million (2022: USD 19.0 million)

·    Cash generated from continuing operations USD 13.2 million (2022: USD 12.0 million)

·    Cash flow used in investing activities USD 15.4 million (2022: USD 15.6 million)

·    Year-end cash USD 9.8 million (2022: USD 12.1 million)

Note:    1    Before SPT, Impairments and Exceptional Items

 

- Ends -

 

Enquiries:

Trinity Exploration & Production plc Jeremy Bridglalsingh, Chief Executive Officer Julian Kennedy, Chief Financial Officer Nick Clayton, Non- Executive Chairman	Via Vigo Consulting
SPARK Advisory Partners Limited (Nominated Adviser) Mark Brady James Keeshan	+44 (0)20 3368 3550
Cavendish Capital Markets Limited (Broker) Leif Powis Derrick Lee Neil McDonald	+44 (0)20 7397 8900 +44 (0)131 220 6939
Vigo Consulting Limited Finlay Thomson Patrick d'Ancona	[email protected] +44 (0)20 7390 0230

 

 

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 licences and, across all of the Group's assets, management's estimate of the Group's 2P reserves as at the end of 2023 was 12.91 mmstb. Group 2C contingent resources are estimated to be 38.68 mmstb. The Group's overall 2P plus 2C volumes are therefore 51.58 mmstb.

 

Trinity is quoted on AIM, a market operated and regulated by the London Stock Exchange Plc, under the ticker TRIN.

 

Qualified Person's Statement 

The technical information contained in the announcement has been reviewed and approved by Mark Kingsley, Trinity's Chief Operating Officer.  Mark Kingsley (BSc (Hons) Chemical Engineering, Birmingham University) has over 35 years of experience in international oil and gas exploration, development and production and is a Chartered Engineer.

 

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.

 

 

Chair & CEO Statement

 

Dear shareholders,

2023 was an important year for Trinity with key developments in our ambitious growth programme being progressed. The Company drilled the Jacobin well in the year to test deeper prospectivity in the Lower Cruse horizons in our core Palo Seco acreage. While the well discovered oil in those deeper horizons, flow rates were disappointing, and drilling complexities resulted in significant cost overruns. The results from the well are being incorporated into further understanding the "Hummingbird" play with independent features still offering future potential as well as the prospectivity of the exploration block, Buenos Ayres. In June, the Company was advised by the Ministry of Energy and Energy Industries ("MEEI") that it had been successful in its bid for the Buenos Ayres block in the 2022 Onshore and Nearshore Competitive Bid Round, immediately to the west of our core Palo Seco acreage. Buenos Ayres is undrilled and offers considerable potential.

The ABM-151 well in the Brighton Marine block, offshore the West Coast of Trinidad, was returned to production on 21 March 2023 following an extensive refurbishment of surface facilities and the installation of remote surveillance technology. Between restart and the end of the year the well flowed at an average rate of 122 bopd, exceeding expectations.

Group net sales for 2023 were 2,790 bopd (2022: 2,975 bopd). Trinity managed to substantially mitigate natural production decline through a programme including six well recompletions ("RCPs"), 98 workovers and swabbing across its asset base. The fire on the Bravo platform in the Trintes field, represented a significant event for the company with valuable lessons learned arising from a comprehensive investigation with an associated corrective actions register. A number of safety improvements have been implemented to date, including those that mitigate the root cause for the fire and improved fire-fighting capabilities in the event of a similar incident.

At Galeota, following an extensive Concept-Screening study completed by Petrofac in Q3 2023, Trinity identified a revised infrastructure-led development solution which includes an initial phase of development drilling from existing platforms. Whilst Trinity believes the revised development solution will significantly reduce capital requirement prior to first oil compared to the Echo Field Development Plan, Trinity would need to secure third party financing to take a final investment decision and fund the development.

In parallel to progressing the Galeota asset development plan project, Trinity assembled a pipeline of investment projects including brownfield development opportunities at the West Coast and onshore assets and a portfolio of exploration prospects across Trinity's Palo Seco assets. Trinity believes that significant capital investment, both debt and equity, will be required to realise the potential of the Company's portfolio.

Our 2023 financial results demonstrate the Company's resilience. Adjusted EBITDA for the year was USD 19.2 million (2022: USD 24.7 million) and cash resources were USD 9.8 million (2022: USD 12.1 million) at year-end. The Company completed a share buyback programme which commenced on 24 October 2022 and ended on 27 June 2023, having repurchased 1,549,000 shares on the open market for a total cost of USD 2.1 million. These shares are held in treasury and are used to settle options exercised. Trinity paid its first interim dividend of 0.5 pence per ordinary share on 26 October 2023.

Angus Winther, having joined the Board in 2017 and completed two full terms as a Non-Executive Director and Chair of the Audit Committee, retired from the Board by rotation in June. In August, we welcomed Jon Cooper as an Independent Non-Executive Director, and the new Chair of the Audit Committee, and Julian Kennedy as an Executive Director, taking on the role of Chief Financial Officer, to the Board. James Menzies has decided not to stand for re-election at this forthcoming Annual General Meeting which coincides with James taking on greater levels of responsibility in other roles outside of Trinity. We want to express our thanks and that of our fellow Directors for his contribution to the Board since joining in 2017. The management team was strengthened by the addition in April 2023 of Mark Kingsley as Chief Operating Officer and in November 2023 of Aida Shafina Abu Bakar as Executive Manager, Subsurface.

It became clear during 2023 that the Group would require new capital to fund its portfolio of development opportunities. In October 2023, the Company engaged a financial adviser, Houlihan Lokey, to assist in exploring strategic and financing alternatives for the Company. On 23 November 2023, Trinity received an unsolicited, conditional non-binding proposal to acquire the issued and to be issued share capital of Trinity from Touchstone Exploration Inc ("Touchstone") and following the execution of a confidentiality agreement, Touchstone was provided access to due diligence information.

On 1 May 2024, following a period of due diligence and negotiation, the boards of directors of Trinity and Touchstone announced the terms of the recommended all share offer (the "Acquisition"). The Acquisition is to be effected by means of a scheme of arrangement under Part 26 of the Companies Act. Under the terms of the Acquisition, Trinity Shareholders shall be entitled to receive 1.5 New Touchstone Shares for each Trinity share. Should the Scheme be approved by Shareholders and sanctioned by the Court, we believe Trinity has an exciting future as part of the enlarged Touchstone organisation.

During what has been an exciting but also challenging period, we would like to thank our staff, the Board and our advisors for their continuing hard work during a particularly busy time for the Company.

 

Nicholas Clayton                               Jeremy Bridglalsingh

Non-Executive Chair                       Chief Executive Officer

 

Operations Review

 

The Group achieved net sales of 2,790 bopd in 2023 (2022: 2,975 bopd) despite no development drilling (2022 three development wells) and six RCPs, (2022 17 RCPs) combined with operational challenges in the East Coast Asset. Investments into production-related activities, such as RCPs, ABM 151 reactivation, production maintenance workovers and swabbing enabled the Company to deliver annual production decline of 6%, below the expected natural field decline range of 7% to 10%.

 

2023 vs 2022 Annual Sales Breakdown

Sales 2022 (Net WI bopd)				Sales 2023 (Net WI bopd)
Assets	Annual	Annual	H1	H2	Q1	Q2	Q3	Q4
WD13	109	91	92	89	97	88	78	99
WD14	100	93	97	88	99	96	87	88
WD2	258	208	224	193	241	206	196	191
WD5/6	1,004	941	935	946	940	930	974	918
PS4	62	56	54	59	60	48	49	69
FZ2	118	106	110	103	111	109	109	97
TAB	4
Onshore	1,655	1,495	1,512	1,478	1,548	1,477	1,493	1,462
TRINTES	1,051	943	1,011	876	1,038	985	843	908
East Coast	1,051	943	1,011	876	1,038	985	843	908
BRIGHTON	158	246	230	263	204	255	268	258
PGB	111	107	108	105	110	107	102	107
West Coast	269	353	338	368	314	362	370	365
TOTAL	2,975	2,790	2,861	2,721	2,899	2,824	2,705	2,736

Note TAB was relinquished on 29 September 2023

 

Onshore Assets

Trinity's onshore assets comprise the lease operatorship ("LO") blocks: WD-5/6, WD-2 and PS-4 (together "Palo Seco") and FZ-2, WD-13, WD-14 (together "Forest Reserve").

Onshore average net sales for 2023 were 1,495 bopd (2022: 1,654 bopd) accounting for approximately 54% of the Group's total annual sales.

Average sales declined by approximately 10% between 2022 and 2023 due to wells drilled in H2 2022 accentuating the decline. Trinity successfully completed six RCPs (2022: 17) and ninety-eight workovers (2022: 87), which contributed to the maintenance of the industry standard decline of between 7-10% for brownfields. In WD-2, the asset experienced a higher-than-expected decline due to increased water production in one well (PS 570) and declining production in the naturally flowing well (PS 571).

In 2024, Trinity intends to manage its base production through further RCP activity, implementation of recommendations from the re-evaluation of the inactive well hopper, and swabbing. Trinity's use of automation to optimise production and costs continues to meet our objectives.

The Jacobin well, 1PS 1524ST3, was drilled to a total depth of 10,021 ft. Geologically, the well intersected stacked pay potential across the PS4 block in both the development and exploration sections of the well. However, reservoir properties in the exploration section were poorer than predicted and, as such, post-drill volumes for the exploration section were below the lower end of the predicted ranges. The rapid decline in reservoir pressures suggests reservoir boundaries are much closer than pre-drill estimates.

The total well cost was USD 9.6 million. An impairment assessment was done on this well, triggered by poorer than expected results and higher costs incurred, the entire Jacobin costs was written off.

Data acquired from the well will be incorporated into our regional model to de-risk and re-prioritise future drilling candidates across our Palo Seco LOs and Buenos Ayres.

Trinity has embarked on an idle well study, with the initial phase including technical reviews of circa 250 wells, with field investigations having commenced on the first 30 of these, which as a result has added more wells to the swabbing program.

 

East Coast Assets

Current East Coast production is generated from the Alpha, Bravo and Delta platforms in the Trintes field located in the Galeota block.

Average net sales for 2023 from the East Coast were 943 bopd (2022: 1,051 bopd) which accounts for approximately 34% of Group sales for the year. A total of 22 workovers in 2023 (2022: 23) were conducted across the assets focusing on optimising and stabilising production from all wells via a data-driven strategy utilising automation. Chemical injection initiatives were also deployed to counteract increased solids deposition in mature wells.

Average sales declined by approximately 10% between 2022 and 2023 due to two main events: the Bravo platform fire in April; and the lower performance of the D9 well, the largest producer in the Trintes field.

The Galeota licence has significant growth potential from undeveloped reserves and resources in the Trintes field and broader development of the Galeota block, including exploration potential.

In July 2023, Trinity initiated a review of the approved Field Development Plan ("FDP") for the TGAL Echo development to reduce capital expenditure, reduce time to first oil and improve financial returns; a new development strategy- concept being created envisaging the use of a mobile operation and production unit ("MOPU").

Trinity appointed Petrofac to undertake a Concept- Screening study for the development of further reserves. This study created a more holistic approach to block development whereby Phase 1 involved drilling horizontal infill wells in Trintes to demonstrate that such wells can be successfully drilled and produced as to date they have not been attempted. Phase 2 then took the learnings from Trintes infill drilling to drill and produce horizontal wells in the TGAL area from a lightweight structure tied back to a leased MOPU. This concept replaces CAPEX with OPEX in the form of lease rate payments and appears - based on screening cost estimates to date - to improve the overall economics of the project materially. This work is progressing with the revision and update of the subsurface studies in 2024.

 

West Coast Assets

West Coast production is generated from the Point Ligoure-Guapo Bay-Brighton Marine ("PGB") and Brighton Marine ("BM") licence areas.

West Coast net sales averaged 353 bopd in 2023 (2022: 269 bopd) which accounted for approximately 13% of the Group's total annual average sales. This was a 31% year on year increase on the 2022 average. The increase was mainly due to the successful execution of the ABM 151 reactivation project. After placing the well on production, ABM 151 produced at a higher initial rate than expected and maintained a lower decline rate than predicted. A total of five workovers in 2023 (2022: 10) were conducted across the assets. There was increased focus on swabbing both on land as well as the introduction of an additional offshore swabbing unit which also assisted in increasing production volumes.

 

Facilities Management and Infrastructure

In 2023, the Facilities team focused on asset integrity, welfare initiatives and projects supporting production.

On Trintes, the Company continued replacing and installing planks and gratings on offshore platform production decks and improved key electrical equipment on the Alpha, Bravo and Delta platforms, for better use of the available space. Automated Tank controls were also introduced.

The construction of a new 10,000 bbl sales tank to accommodate production from the Trintes field was completed in 2023. In 2024 the tank was certified and put into service.

Remedial work following the Trintes Bravo generator fire was completed and upgrades to the safety systems were implemented. This includes upgraded fire suppression systems, replacement of all six generator units (Q1 2024 completed) and introduction of emergency escape systems and advanced fire-fighting training. The automated systems on all of the Trintes platforms were also upgraded with additional redundancy.

Onshore and West Coast operations focused on upgrading welfare facilities, electrical systems as well as oil storage tanks.

The project and maintenance team was reorganised with the introduction of a dedicated maintenance team. This team will focus on fabric maintenance and rotating equipment. In total, the team progressed 22 projects of which 18 were completed by end of 2023 and four rolled over into 2024.

Facilities Management and Infrastructure capex in 2023 was USD 4.1 million (2022 USD 4.5 million).

During 2023 a review of the decommissioning methodology and cost estimates were undertaken. This led to a reduction in well abandonment cost estimates and the overall decommissioning provision to USD 44.4 million (2022: 51.9 million).

 

Reserves and Resources

A comprehensive reserves and resources review of all assets has been completed by Management and the technical work underpinning this management estimate was reviewed by Netherland, Sewell & Associates, Inc which estimates Trinity's current 2P reserves to be 12.91 mmstb at the end of 2023, compared to the year-end 2022 reserve estimate of 17.96 mmstb. This represents a 28% year-on-year decrease. The largest reduction in 2P Reserves at Year-End 2023 is from wells that were categorised as economic 2P Reserves at Year-End 2022 which have been reclassified to 2C Resources due to individual opportunities being considered uneconomic at the date of review. Additional reductions are due to the impact of earlier economic limit truncations and revisions to the Trintes Infill well programme.

The 2C Resources at the end of 2023 are estimated at 38.68 mmstb compared to the end of 2022 resource estimate of 48.88 mmstb. The reduction in 2C Resources is attributed largely to the East Coast block based on the latest interpretation and mapping of reprocessed seismic data which resulted in a view that the field structure is more steeply dipping than in previous interpretations. The Year-End 2023 total 2C for East Coast is 31.3 mmstb (compared to 36.8 mmstb previously). While the 2C Resource estimate for East Coast has been reduced, the impact on the development and exploration plans for the field is minimal.

Management considers the reserves presented in the table below to be its best estimate as at 31 December 2023 of the quantity of reserves that can be recovered from Trinity's current assets. It includes forecast production, which is commercially recoverable, either to licence/ relevant permitted extension end or earlier via the application of the economic limit test. The subsurface review has defined investment programmes and constituent drilling targets to commercialise these reserves as detailed by asset area shown in the table.

2023 2P Reserves

	31-Dec-22	Production	Revisions	31-Dec-23
Net Oil Reserves	mmstb	mmstb	mmstb	mmstb
Asset
Onshore	6.53	(0.55)	(1.72)	4.26
West Coast	2.17	(0.13)	(1.18)	0.86
East Coast	9.26	(0.34)	(1.14)	7.78
Total	17.96	(1.02)	(4.03)	12.91
2023 2C Resources
	31-Dec-22	Production	Revisions	31-Dec-23
Net Oil Resources	mmstb	mmstb	mmstb	mmstb
Asset
Onshore	8.62	N/A	(4.88)	3.74
West Coast	3.45	N/A	0.18	3.63
East Coast	36.81	N/A	(5.50)	31.31
Total	48.88	N/A	(10.20)	38.68
2023 Reserves and Resources
	31-Dec-2022 2P Reserves and 2C Resources	Production	Revisions	31-Dec-2023 2P Reserves and 2C Resources
	mmstb	mmstb	mmstb	mmstb
Asset
Onshore	15.15	(0.55)	(6.60)	8.00
West Coast	5.62	(0.13)	(1.00)	4.49
East Coast	46.07	(0.34)	(6.64)	39.09
Total	66.84	(1.02)	(14.24)	51.58

 

2P Reserves Note:

The 2023 produced volume of 1.02 mmstb accounts for 20% of the overall 2P decrease in 2023 compared to 2022. Other revisions contributing to the overall decrease are:

·      (0.38) mmstb from PS4 and Tabaquite Revision

·      mmstb from Base Revisions

·      (0.22) mmstb from RCP Revisions

·      (2.34) mmstb from Infill Well Revisions

 

2C Resources Note:

Revisions contributing to the overall decrease are:

·      (4.90) mmstb from Appraisal Wells Revisions (Onshore)

·      (8.33) mmstb from TGAL Revision and 2.83 mmstb (Trintes) from re-categorisation and ELT

 

 

 

Financial Review

 

KPIs

During 2023 the Group saw lower realised oil prices compared with 2022. A combination of lower oil price, a six percent reduction in net production and an increase operating break-even resulted in Adjusted EBITDA (before hedge costs) decreasing by USD 15.9 million to USD 19.2 million (2022: USD 35.1 million). The Group delivered a resilient operating performance as shown by its positive Adjusted EBITDA margin (after hedge costs) of 28.1% (2022: 26.8%) and IFRS Operating Profit before SPT of USD 9.6 million (2022: USD 19.0 million) despite a 19% decrease in realised oil price.

A summary of the year-on-year operational and financial highlights are set out below:

		FY 2023	FY 2022	Change %
Average realised oil price1	USD/bbl	68.6	84.9	(19)
Average net production2	bopd	2,790	2,975	(6)
Revenues	USD million	69.8	92.2	(24)
Cash balance	USD million	9.8	12.1	(19)
IFRS Results
Operating Profit before SPT	USD million	9.6	19.0	(49)
Total Comprehensive (loss)/income for the year	USD million	(6.8)	0.1	(7,415)
Earnings Per Share - Diluted	USD cents	0.0	0.0	(100)
APM Results
Adjusted EBITDA (before hedge costs)3	USD million	19.2	35.1	(45)
Adjusted EBITDA (after hedge costs)4	USD million	19.2	24.7	(22)
Adjusted EBITDA (after hedge costs)5	USD/bbl	18.9	22.7	(17)
Adjusted EBITDA margin (after hedge costs)6	%	27.5	26.8	3
Adjusted EBIDA after Current Taxes7	USD million	12.9	12.3	5
Adjusted EBIDA after Current Taxes Per Share - Diluted	US cents	32.3	30.6	5
Consolidated operating break-even8	USD/bbl	38.3	32.1	19
Net cash plus working capital surplus9	USD million	8.6	14.2	(39)

 

Notes:

1.             Average realised price (USD/bbl): Actual price received for crude oil sales per barrel ("bbl").

2.             Average net production (bopd): Production sold in barrels per day in a given year.

3.             Adjusted EBITDA (before hedge) (USD MM): Adjusted EBITDA for the period, before Derivative expense.

4.             Adjusted EBITDA (USD MM): Operating Profit before Taxes for the period, adjusted for non-cash DD&A, SOE, ILFA, FX gain/(loss) and Fair Value Gains/Losses on Derivative Financial Instruments.

5.             Adjusted EBITDA (USD/bbl): Adjusted EBITDA/Annual sales volume.

6.             Adjusted EBITDA margin (%): Adjusted EBITDA/Revenues.

7.             Adjusted EBIDA after Current Taxes: Adjusted EBIDA less Supplemental Petroleum Taxes ("SPT"), Petroleum Profits Tax ("PPT") and Unemployment Levy ("UL").

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

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

See Note 27 to Consolidated Financial Statements - Adjusted EBITDA for further details.

 

 

2023 Trading Summary

A five-year historical summary of realised price, sales, operating break-even, Royalties, Production Costs ("Opex") and General & Administrative ("G&A") expenditure metrics is set out below.

		2019	2020	2021	2022	2023
Realised Price	USD/bbl	58.1	37.7	60.4	84. 9	68.6
Sales
Onshore	bopd	1,616	1,793	1,644	1,655	1,495
West Coast	bopd	185	245	255	269	353
East Coast	bopd	1,208	1,188	1,107	1,051	943
Consolidated	bopd	3,007	3,226	3,006	2,975	2,790
Metrics
Royalties/bbl - Onshore	USD/bbl	22.3	11.5	22.6	35.9	26.8
Royalties/bbl - West Coast	USD/bbl	10.0	6.1	11.1	15.8	12.7
Royalties/bbl - East Coast	USD/bbl	14.1	8.3	13.0	17.9	13.3
Royalties/bbl - Consolidated	USD/bbl	10.7	9.9	18.1	27.7	20.5
Opex/bbl - Onshore	USD/bbl	12.1	12.2	14.4	17.0	20.6
Opex/bbl - West Coast	USD/bbl	26.9	20.3	26.2	30.7	30.1
Opex/bbl - East Coast	USD/bbl	17.1	16.5	18.3	23.2	30.1
Opex/bbl - Consolidated	USD/bbl	14.9	14.0	16.0	17.7	22.0
G&A/bbl - Consolidated1	USD/bbl	5.1	4.3	6.3	6.6	7.2
Operating Break-Even2
Onshore	USD/bbl	16.4	16.5	19.0	19.2	23.9
West Coast	USD/bbl	32.4	24.6	32.2	31.8	31.8
East Coast	USD/bbl	21.9	21.0	23.2	24.4	31.7
Consolidated3	USD/bbl	26.4	20.1	29.2	32.1	38.3

 

Notes

1.             G&A/bbl - Consolidated: Excludes SOE, ILFA, Derivative FV gain/loss and FX gain/loss.

2.             Operating break-even: The realised price where Adjusted EBITDA ([before hedge]) for the respective asset or the entire Group (Consolidated) is equal to zero.

3.             Consolidated operating break-even: Includes G&A but excludes SOE, ILFA, Derivative FV gain/loss and FX gain/loss.

 

 

Review of Financial Statements

Trinity and its subsidiaries' ("the Group") consolidated financial information has been prepared on a going concern basis, in accordance with International Accounting Standards ("IAS") as adopted in the United Kingdom. This consolidated financial information has been prepared under the historical cost convention, modified for fair values under IFRS. The Group's accounting policies and details of accounting judgements and critical accounting estimates are disclosed within Notes 1 to 3 of the Financial Statements.

Throughout this report, reference is made to adjusted results and measures. The Board believes that the selected adjusted measures allow Management and other stakeholders to better compare the normalised performance of the Group between the current and prior year, without the effects of one-off or non-operational items, and better reflects the underlying cash earnings achieved in the year. In exercising this judgment, the Board has taken appropriate regard of IAS 1 "Presentation of financial statements".

In particular, the Alternative Performance Measure ("APM") measure of Adjusted EBITDA excludes the impact of Depreciation, Depletion & Amortisation ("DD&A"), as well as the non-cash impact of Share Option Expense ("SOE"), Impairment losses on financial assets ("ILFA"), FX gain/loss and Fair Value Gains/Losses on Derivative Financial Instruments. Each of these are summarised on the face of the Consolidated Income Statement as well as being described in Note 21 to the consolidated financial statements.

 

Summary of Results for the Year

Lower revenue driven by lower average realised oil price and sales volume in 2023:

The combined impact of a 19% decrease in average oil price realisations to USD 68.6/bbl (2022: USD 84.9/bbl), and a modest 6% decrease in average annual sales 2,790 bopd (2022: 2,975 bopd), resulted in a 24% decrease in revenues to USD 69.8 million (2022: USD 92.2 million).

 

Maintained robust operating profits despite inflationary pressures:

The Group continued to deliver strong operating profits despite the inflationary pressures on goods and services. Operating profit before taxes was USD 9.6 million (2022: USD 19.0 million) and consolidated operating break-even moved up to USD 38.3/bbl (2022: USD 32.1/bbl) demonstrating the Group's ability to be profitable across a broad range of oil prices.

Increased capex investment programme to drive growth:

USD 17.1 million (2022: USD 15.5 million) invested to drive future production growth. This comprised:

·    USD 9.1 million Exploration and Evaluation ("E&E") asset.

·    USD 5.0 million infrastructure Capex including facilities (USD 4.1 million) and ICT (USD 0.9 million).

·    USD 1.1 million production capex comprising, 6 RCP's and production equipment (USD 0.2 million) and the ABM-151 reactivation project (USD 0.9 million).

·    USD 1.6 million subsurface costs.

·    USD 0.3 million in Exploration and Evaluation ("E&E") Environmental Impact Assessment (EIA) to the Buenos Ayres Block.

Refer to Notes to Financial Statements: Note 13 Property, Plant and Equipment - Additions (USD 6.9 million) and Note 15 - Intangible Assets - E&E Additions (USD 10.2 million) inclusive of accruals.

 

Rebuilding the balance sheet:

The Group's cash balances at year end were USD 9.8 million (2022: USD 12.1 million), primarily reflecting positive cash generated from operations of USD 13.2 million, Capex spend of USD (15.4) million and Financing activities of USD (0.2) million. In aggregate, despite these significant cash outflows, the Group's net cash plus working capital surplus stood at USD 8.6 million (2022: USD 14.2 million) and the Group's current ratio was 1.4x (2022: 2.1x). Elements of spend relating to 2023 activities, principally drilling of the Jacobin well, will be settled in 2024. The Company is focused on managing its cost base and activities in 2024 in order to build-back cash on its balance sheet.

 

 

Statement of Comprehensive Income

2023 Financial Highlights

Average realisation of USD 68.6/bbl (2022: USD 84.9/bbl).

Operating Revenues

Operating revenues down 24% to USD 69.8 million (2022: USD 92.2 million).

Operating expenses

Operating expenses decreased by 18% in 2023 to USD (60.2) million reflecting a reduction in crude oil price environment and no hedge costs (2022: USD (73.3) million) and comprised:

Operating Expenses (excluding non-cash items): USD 50.6 million (2022: (67.6) million):

·    Royalties of USD (20.9) million (2022: USD (30.1) million), this decrease being driven by lower average realised oil price and sales production.

·    Opex of USD (22.4) million (2022: USD (19.2) million), the increase mainly due to inflationary costs on goods and services seen in increased repairs and maintenance, vessel, swabbing and workover cost in the year.

·    G&A expenses of USD (7.4) million (2022: USD (7.2) million), the increase mainly due to comprehensive reserve review being commenced during the year and build out of the Management Team net of reduced levies and administrative costs including professional fees.

·    Derivative expense of nil (2022: Derivative expense of USD (10.4) million) being the cash impact of derivative instruments paid out for 2022.

·    Covid 19 expense of nil (2022: USD (0.6) million) being the costs associated with accommodation, testing and sanitisation related to our prevention and response.

·    Cash FX loss USD (0.0) million (2022: USD (0.1) million).

 

Non-Cash Operating Expenses: USD 9.5 million (2022: USD (5.7) million):

·    DD&A of USD (8.9) million (2022: USD (7.6) million).

·    SOE of USD (0.5) million (2022: USD (0.7) million).

·    ILFA USD (0.1) million (2022: USD 0.0 million).

·    FX loss USD (0.0) million (2022: USD (0.3) million).

·    Derivative credit of nil (2022: Derivative expense of USD 2.9 million) being the movement in the FV of derivative instruments held at the beginning and end of the financial year.

 

Operating Profit Before SPT, Impairment, Exceptional Items and Decommissioning Reduction

The operating profit before SPT, impairment, exceptional items and decommissioning reduction for the year amounted to USD 9.6 million (2022: USD 19.0 million) and was mainly due to lower operating revenues resulting lower oil prices despite inflationary pressures on cost.

 

SPT

SPT of USD (5.7) million (2022: USD (9.0) million) mainly due to lower realised oil prices in relation to the Group's operations in 2023. Only offshore assets were subject to SPT in 2023 as the realised oil price throughout the year was lower than USD 75/bbl.

 

Operating Profit before Impairment and Exceptional items

The Group's reported operating profit before impairment and exceptional items was USD 3.9 million (2022: USD 10.0 million). Adjusting for non-cash expenses, the Group's Adjusted EBIDA after Current Taxes was USD 12.9 million (2022: USD 12.3 million) (further details below).

 

Impairment charge

Impairment charges taken were USD (13.5) million (2022: USD (6.1) million) relating to the impairment of Jacobin E&E well and other E&E costs USD (11.8) million and property, plant, and equipment USD (1.7) million.

See Note 3(d and e) to Consolidated Financial Statements - Impairment of Property, Plant and Equipment and Exploration and Evaluation Assets for further details.

 

Exceptional items

Exceptional items were USD (0.3) million cyber incident costs USD (0.2) million (2022: USD (0.2)) and Bravo fire-incident costs USD (0.1) million.

See Note 7 to Consolidated Financial Statements - Exceptional items for further details.

 

Decommissioning reduction

In 2023, there was a reduction of decommissioning provision costs due to revision in decommissioning well cost estimates and the surrender of Tabaquite Block. This resulted in a gain of USD 2.5 million.

See Note 3(b) to Consolidated Financial Statements further details.

 

Finance Income

Finance income is solely related to bank interest income received on short term investments with financial institutions of USD 0.1 million (2022: 0.1 million).

 

Finance Costs

Finance costs amounted to USD (2.2) million (2022: USD (1.3) million) and comprised:

·    Unwinding of the discount rate related to the decommissioning liability USD (2.1) million (2022: USD (1.1) million).

·    Interest on Leases USD (0.1) million (2022: USD (0.1) million).

·    Bank overdraft interest USD 0.0 million (2022: (0.1) million).

See Note 9 to Consolidated Financial Statements - Finance Costs for further details.

 

Income Taxation

Income Taxation net credit for 2023 of USD 2.7 million (2022: USD (2.3) million), comprising the following:

·    Current Taxes:

o  Petroleum Profit Tax ("PPT") USD (0.4) million (2022: (2.4) million).

o  Unemployment Levy ("UL") USD (0.2) million (2022: USD (1.0) million).

·    Increase in Deferred Tax Assets ("DTA") recognised on available tax losses of USD 3.2 million (2022: Increase in DTA of USD 1.0 million).

·    Decrease in Deferred Tax Liabilities ("DTL") USD 0.1 million due to accelerated accounting impairments/depreciation (2022: USD 0.1 million decrease).

See Note 10 to Consolidated Financial Statements - Income Taxation for further details.

 

Total Comprehensive (loss)/income

Total Comprehensive loss for the period was USD (6.8) million (2022: USD 0.1 million income).

 

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, Impairment and Exceptional Items for the year, adjusted for non-cash DD&A, gain or loss on the sale of assets, SOE, ILFA, FX and FV of Derivative Instruments.

The Group presents Adjusted EBITDA after hedge expense at USD 19.2 million and Adjusted EBIDA after Current Taxes at USD 12.9 million as it is used by Management and judged to be a better measure of underlying performance.

 

Statement of Cash Flows

Cash inflow from operating activities

Operating Cash Flow was USD 13.2 million (2022: USD 12.0 million) comprising:

·    Operating cash flow before working capital and income taxes of USD 13.1 million (2022: USD 15.5 million).

·    Changes in working capital resulted in a net increase of USD 0.9 million (2022: USD (0.1) million decrease).

·    Income taxes, PPT and UL paid USD (0.8) million (2022: USD (3.4) million paid) resulting from lower oil price and production.

 

Cash (outflow) from investing activities

Cash outflow from investing activities was USD (15.4) million (2022: USD (15.6) million):

·    Expenditure on exploration and evaluation assets and other intangible assets USD (9.0) million (2022: USD (0.4) million) which includes costs incurred Jacobin well and Galeota.

·    Property, plant and equipment for the year totaling USD (5.9) million (2022: USD (15.0) million).

·    Computer software USD (0.5) million (2022: USD (0.1) million).

·    Performance bond related to the onshore lease operatorship assets nil (2022: USD (0.1) million).

 

Cash (outflow) from financing activities

Cash outflow from financing activities was USD (0.2) million (2022: USD (2.2) million):

·    Increase in Bank overdraft drawdown USD 1.3 million to match outstanding VAT refunds filed as at 31 December 2023 (2022: nil).

·    Principal paid on lease liability USD (0.6) million (2022: (0.5) million).

·    Share buyback of USD (0.6) million (2022: (1.5)).

·    Dividends paid of USD (0.2) million

·    Interest paid on lease liability USD (0.1) million (2022: (0.1) million).

·    Net Finance cost of nil (2022: (0.1) million).

 

Closing Cash Balance

Trinity's cash balance at 31 December 2023 was USD 9.8 million (31 December 2022: USD 12.1 million).

 

Net Cash Plus Working Capital Surplus

(All figures in USD million)		FY 2019 Audited	FY 2020 Audited	FY 2021 Audited	FY 2022 Audited	FY 2023 Audited
A:	Current Assets
	Cash and cash equivalents	13.8	20.2	18.3	12.1	9.8
	Trade and other receivables (including taxes)	9.4	7.2	10.8	10.7	12.2
	Inventories	5.2	5.3	3.8	4.6	3.9
	Derivative Financial Instrument	0.1	0.3	-	-	-
	Total Current Assets	28.5	33.0	32.9	27.4	25.9
B:	Current Liabilities
	Trade and other payables	10.4	7.8	8.8	9.9	13.0
	Bank overdraft	-	2.7	2.7	2.7	4.0
	Lease liability	0.6	0.6	0.6	0.6	0.2
	Taxation payable	0.1	0.2	-	-	0.1
	Dividend payable	-	-	-	-	0.0
C:	Derivative Financial Instrument	-	-	2.9	-	-
D:	Provision for other liabilities			0.1	0.2	0.6
	Total Current Liabilities	11.1	11.3	15.1	13.4	17.9
(A-B+C+D):	Cash plus working capital surplus	17.3	21.4	20.8	14.2	8.6

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

 

Events since year end

1.            Subsequent to 31 December 2023, the Group received VAT refunds of USD 0.8 million. As at 22 May 2024, the Group had USD 5.1 million in VAT refunds recoverable.

2.            On 13 June 2023, Trinity announced its successful bid for the onshore Buenos Ayres block. Subsequent to 31 December 2023, the Group is awaiting finalisation of the exploration and production licence with the MEEI.

3.            Fiscal reforms (Finance Act) - Effective 1 January 2024, SPT rates for Small Shallow Marine Area Producers were introduced. It becomes applicable when the weighted average realised crude oil price exceeds USD 75/bbl, starting at a rate of 18% and goes up to 40% depending on the price.

A Small Shallow Marine Area Producer is defined as a person who carries out petroleum operations in shallow marine areas under a licence, sub-licence or contract and produces less than 4,000 barrels of crude oil per day.

4.            On 1 May 2024, the board of directors of each of Touchstone and Trinity announced that they have reached agreement on the terms of a recommended all share offer pursuant to which Touchstone will acquire the entire issued and to be issued ordinary share capital of Trinity (the "Acquisition"). The Acquisition is to be effected by means of a scheme of arrangement under Part 26 of the Companies Act. Under the terms of the Acquisition, Trinity Shareholders shall be entitled to receive 1.5 New Touchstone Shares for each Trinity share. Further information on the transaction can be found on our website at https://trinityexploration.com/.

 

Consolidated Statement of Comprehensive Income

For the year ended 31 December 2023

(Expressed in United States Dollars)	Note	2023 $'000	2022 $'000
Revenues
Crude oil sales	4	69,819	92,232
Other income		7	7
		69,826	92,239
Operating Expenses
Royalties		(20,864)	(30,091)
Production costs		(22,402)	(19,242)
General & Administrative ("G&A") expenses		(7,375)	(7,181)
Covid-19 expenses*		-	(579)
Depreciation, Depletion & Amortisation ("DD&A")	13-15	(8,935)	(7,617)
Share Option Expense ("SOE")		(528)	(647)
Foreign exchange ("FX") loss		(65)	(394)
Impairment losses on financial assets ("ILFA")/ net reversal		(64)	46
Derivative expenses	6	-	(10,446)
Fair value income derivative instruments	6	-	2,883
		(60,233)	(73,268)
Operating Profit before Supplemental Petroleum Taxes ("SPT")		9,593	18,971
SPT		(5,697)	(9,012)
Operating Profit before Impairment, Exceptional items and Decommissioning reduction		3,896	9,959
Impairment	8	(13,462)	(6,050)
Exceptional items	7	(307)	(161)
Decommissioning reduction	7	2,508	-
Operating (Loss)/Profit		(7,365)	3,748
Finance income	9	50	48
Finance costs	9	(2,214)	(1,339)
(Loss)/Profit Before Income Taxation		(9,529)	2,457
Income taxation credit/(charge)	10	2,725	(2,344)
(Loss)/Profit for the year		(6,804)	113
Other Comprehensive Income/(Expense)
Items that may be subsequently reclassified to profit or loss
Exchange differences on translation of foreign operations		1	(20)
Total Comprehensive (Loss)/Income for the year		(6,803)	93
Earnings per share (expressed in dollars per share)
Basic	11	0.0	0.0
Diluted	11	0.0	0.0

 

*             Covid-19 expenses have been reclassified as Operating Expenses.

 

Consolidated Statement of Financial Position

at 31 December 2023

(Expressed in United States Dollars)	Note	2023 $'000	2022 $'000
ASSETS
Non-current Assets
Property, plant and equipment	13	35,188	44,987
Right-of-Use ("ROU") assets	14	312	838
Intangible assets	15	31,399	33,537
Abandonment fund	16	4,962	4,511
Performance bond	17	606	602
Deferred tax assets ("DTA")	18	15,703	12,465
		88,170	96,940
Current Assets
Inventories	19	3,916	4,615
Trade and other receivables	20	11,709	10,560
Taxation recoverable		509	231
Cash and cash equivalents	22	9,819	12,131
		25,953	27,537
Total Assets		114,123	124,477
EQUITY AND LIABILITIES
Capital and Reserves Attributable to Equity Holders
Share capital	23	399	399
Share based payment reserve	25	2,812	2,990
Reverse acquisition reserve	26	(89,268)	(89,268)
Translation reserve		(1,666)	(1,667)
Treasury shares	24	(1,553)	(1,522)
Retained earnings		138,321	145,199
Total Equity		49,045	56,131
Non-current Liabilities
Lease liability	14	137	341
Deferred tax liabilities ("DTL")	18	1,862	1,940
Provision for other liabilities	28	45,076	52,460
Employee benefits		31	23
		47,106	54,764
Current Liabilities
Trade and other payables	29	13,094	10,045
Bank overdraft	30	4,000	2,700
Lease liability	14	208	584
Provision for other liabilities	28	622	249
Dividend payable	21	5	-
Taxation payable		43	4
		17,972	13,582
Total Liabilities		65,078	68,346
Total Equity and Liabilities		114,123	124,477

 

The financial statements were authorised for issue by the Board of Directors on 22 May 2024 and were signed on its behalf by:

Jeremy Bridglalsingh

Director

22 May 2024

 

Company Statement of Financial Position

at 31 December 2023

(Expressed in United States Dollars)	Note	2023 $'000	2022 $'000
ASSETS
Non-current Assets
Investment in subsidiaries	12	61,342	60,864
Current Assets
Trade and other receivables	20	259	233
Intercompany	20	4,567	2,830
Cash and cash equivalents	22	1,194	2,102
		6,020	5,165
Total Assets		67,362	66,029
EQUITY AND LIABILITIES
Capital and Reserves Attributable to Equity Holders
Share capital	23	399	399
Share based payment reserve		3,596	3,775
Merger reserves		6,552	6,552
Treasury shares	24	(1,553)	(1,522)
Retained earnings		41,635	43,529
Total Equity		50,629	52,733
Current Liabilities
Trade and other payables	29	678	565
Intercompany	31	16,050	12,731
Dividend payable		5	-
		16,733	13,296
Total Liabilities		16,733	13,296
Total Equity and Liabilities		67,362	66,029

 

The Company has elected to take the exemption under section 408 of the Companies Act 2006, to not present the Statement of comprehensive income. The net loss for the parent company was $1.9 million (2022: $9.4 million).

The financial statements were authorised for issue by the Board of Directors on 22 May 2024 and were signed on its behalf by:

Jeremy Bridglalsingh

Director

22 May 2024

Trinity Exploration & Production plc

Registered Number: 07535869

 

Consolidated Statement of Changes in Equity

for the year ended 31 December 2023

Year ended 31 December 2022	Share Capital $'000	Share Based Payment Reserve $'000	Reverse Acquisition Reserve $'000	Treasury Shares $'000	Translation Reserve $'000	Retained Earnings $'000	Total Equity $'000
At 1 January 2022	389	3,784	(89,268)	-	(1,650)	143,666	56,921
Issue of shares	10	-	-	-	-	-	10
LTIPs lapsed (Note 25)	-	(1,416)	-	-	-	1,416	-
Share based payment expense (Note 25)	-	622	-	-	-	-	622
Treasury shares acquired (Note 24)	-	-	-	(1,522)	-	-	(1,522)
Translation adjustment	-	-	-	-	3	4	7
Profit for the year	-	-	-	-	-	113	113
Other comprehensive income/ (expense)
Exchange differences on translation of foreign operations	-	-	-	-	(20)	-	(20)
Total comprehensive income for the year	-	-	-	-	(20)	113	93
At 31 December 2022	399	2,990	(89,268)	(1,522)	(1,667)	145,199	56,131

 

Year ended 31 December 2023
At 1 January 2023	399	2,990	(89,268)	(1,522)	(1,667)	145,199	56,131
Share options exercised/lapsed	-	(698)	-	-	-	698	-
Share based payment expense (Note 25)	-	520	-	-	-	-	520
Treasury shares acquired	-	-	-	(566)	-	-	(566)
Treasury shares issued	-	-	-	535	-	(535)	-
Dividends						(236)	(236)
Translation adjustment	-	-	-	-	-	(1)	(1)
Loss for the year	-	-	-	-	-	(6,804)	(6,804)
Other comprehensive income/ (expense)
Exchange differences on translation of foreign operations	-	-	-	-	1	-	1
Total comprehensive loss for the year	-	-	-	-	1	(6,804)	(6,803)
At 31 December 2023	399	2,812	(89,268)	(1,553)	(1,666)	138,321	49,045

 

Company Statement of Changes in Equity

for the year 31 December 2023

Year ended 31 December 2022	Share Capital $'000	Share Based Payment Reserve $'000	Merger Reserves $'000	Treasury Shares $'000	Retained Earnings $'000	Total Equity $'000
At 1 January 2022	389	4,569	6,552	-	51,526	63,036
Issue of shares	10	-	-	-	-	10
Share based payment charge (Note 25)	-	622	-	-	-	622
Share options exercised/lapsed (Note 25)	-	(1,416)	-	-	1,416	-
Treasury shares (Note 24)	-	-	-	(1,522)	-	(1,522)
Total comprehensive loss for the year	-	-	-	-	(9,413)	(9,413)
At 31 December 2022	399	3,775	6,552	(1,522)	43,529	52,733

 

Year ended 31 December 2023
At 1 January 2022	399	3,775	6,552	(1,522)	43,529	52,733
Share options exercised	-	(698)	-	-	698	-
Share based payment expense (Note 25)	-	519	-	-	-	519
Treasury shares acquired (Note 24)	-	-	-	(566)	-	(566)
Treasury shares issued (Note 24)	-	-	-	535	(535)	-
Dividends	-	-	-	-	(236)	(236)
Total comprehensive loss for the year	-	-	-	-	(1,821)	(1,821)
At 31 December 2023	399	3,596	6,552	(1,553)	41,635	50,629

 

Consolidated Statement of Cash Flows

for the year 31 December 2023

(Expressed in United States Dollars)	Note	2023 $'000	2022 $'000
Operating Activities
(Loss)/Profit before taxation		(9,529)	2,457
Adjustments for:
Foreign exchange ("FX") loss		65	394
Finance cost - loans and interest	9	137	229
Finance income	9	(50)	(48)
Finance cost - decommissioning provision	28	2,077	1,110
Share-based payment expense		528	647
DD&A	13-15	8,935	7,617
Loss on disposal		15	-
Impairment/ (net reversal) of financial assets		64	(46)
Inventory impairment		-	334
Impairment of exploration and evaluation assets		11,766	-
Impairment of property, plant and equipment	13	1,542	5,558
Fair value gain on derivative financial instruments		-	(2,883)
Other impairments	13	147	158
Net release of decommissioning costs		(2,508)	-
		13,189	15,527
Changes In Working Capital
Inventories	19	699	(1,129)
Trade and other receivables	16,20	(1,664)	(376)
Trade and other payables	28,29	1,822	1,353
		857	(152)
Income taxation paid		(831)	(3,390)
Net Cash Inflow from Operating Activities		13,215	11,985
Investing Activities
Purchase of exploration and evaluation ("E&E") assets and investment in research & development	15	(8,972)	(388)
Purchase of computer software	15	(492)	(102)
Purchase of property, plant and equipment	13	(5,917)	(15,016)
Performance bond		-	(130)
Net Cash Outflow from Investing Activities		(15,381)	(15,636)
Financing Activities
Finance income		50	48
Finance cost		(50)	(94)
Proceeds from the issue of shares		0	10
Principal paid on lease liability		(589)	(536)
Interest paid on lease liability		(86)	(135)
Dividends paid		(231)	-
Acquisition of treasury shares		(566)	(1,522)
Bank overdraft		1,300	-
Net Cash Outflow from Financing Activities		(172)	(2,229)
Decrease in Cash and Cash Equivalents		(2,338)	(5,880)
Cash and Cash Equivalents
At beginning of year		12,131	18,312
Effects of foreign exchange rates differences on cash		26	(301)
Decrease in Cash and Cash equivalents		(2,338)	(5,880)

Company Statement of Cash Flows

for the year 31 December 2023

At end of year	22	9,819	12,131
(Expressed in United States Dollars)	Note	2023 $'000	2022 $'000
Operating Activities
Loss before taxation		(1,821)	(9,413)
Adjustments for:
Foreign exchange ("FX") loss		(22)	306
Finance income		(164)	(156)
Share based payment charge		41	107
Impairment loss/ (net reversal) on financial assets		129	(14)
Fair value loss on derivative financial instruments		-	(2,883)
		(1,837)	(12,053)
Changes In Working Capital
Trade and other receivables		(1,893)	521
Trade and other payables		3,432	12,188
		1,539	12,709
Taxation Paid		-	-
Net Cash (Outflow)/ Inflow from Operating Activities		(298)	656
Financing Activities
Finance income		164	156
Issue of shares		0	10
Dividends paid		(231)	-
Treasury shares		(566)	(1,522)
Net Cash Outflow from Financing Activities		(633)	(1,356)
Decrease In Cash and Cash Equivalents		(931)	(700)
Cash and Cash Equivalents
At beginning of year		2,102	3,108
Effects of foreign exchange rates differences on cash		23	(306)
Decrease Cash and Cash equivalents		(931)	(700)
At End of Year	22	1,194	2,102

 

​

 

Notes to the Consolidated Financial Statements

31 December 2023

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 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 Trinidad & Tobago ("T&T").

Basis of preparation

The Group's and Company's financial statements have been prepared and approved by the Board of Directors ("Board") in accordance with international accounting standards as adopted in the United Kingdom.

The preparation of the consolidated financial statements in compliance 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 $1.9 million (2022: $9.4 million loss).

Basis of measurement

The consolidated financial statements have been prepared under the historical cost convention, except certain financial assets and liabilities (including derivative financial instruments) - 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.

Going Concern

The Board adopted the going concern basis in preparing these consolidated financial statements.

In making their going concern assessment, the Board have considered the Group's current financial position, budget and cash flow forecast. The going concern assessment has considered the current operating environment and the potential impact of the volatility of the oil price.

The Group started 2024 with a stable operating and financial position; 2023 average production of 2,790 barrels of oil per day ("bopd"), (2022 2,975 bopd), and cash and short-term investments of $9.8 million as at 31 December 2023 (2022: $12.1 million). The Group's base case going concern assessment is based upon management's best estimate of forward commodity price curves and uses production in line with approved asset plans. The base case forecast was prepared with consideration of the following:

·    Future oil prices are assumed to be in line with the forward curve prevailing as at 2 April 2024. The forward price curve applied in the cash flow forecast starts at a realised price of $75.3/bbl in April 2024, fluctuating each month down to $69.7/bbl in December 2024 through to $65.5/bbl in December 2025.

·    Average forecast production for the years to December 2023 and December 2024 are in line with the Group's asset development plans, with production being maintained by RCPs, WOs and swabbing activities;

·    No SPT is assumed to be incurred on both onshore and offshore assets in 2024 or 2025, as the forecast realised price is below $75.0/bbl;

·    Trinity continuing to progress various growth and business development opportunities; and

·    No derivative instruments being put in place for 2024.

·    No drawdown of working capital overdraft facility

Management considers this is a reasonable base scenario, reflecting a prudent outlook for the future oil price, 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 a separate stressed scenario including:

·    the effect of reductions in Brent oil prices at $60.0/bbl being sustained across the forecast period, noting that the base case pricing is in line with market prices; and

·    the compounded impact of a reduction in production by 10%.

The stressed case cash flow forecast allows for the impact of mitigating actions that are within the Group's control which include:

·    Reducing non-core and discretionary opex and administrative costs across the forecast period.

·    Reducing discretionary capital expenditure and capital returns over the forecast period.

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

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. 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.

The directors of Trinity Exploration & Production Plc have received a letter of support from Trinity Exploration and Production Services Limited confirming that they will not recall related party balances and any loan to the Company for a period of not less than twelve months from the date of signing of Company's statutory accounts unless the Company can repay the related party balances and loan.

 

 

Changes in accounting policies

(a)          New standards, interpretations and amendments adopted from 1 January 2023:

The following amendments are effective for the period beginning 1 January 2023:

·    IFRS 17 Insurance Contracts

·    Disclosure of Accounting Policies (Amendments to IAS 1 Presentation of Financial Statements and IFRS Practice Statement 2 Making Materiality Judgements); Definition of Accounting Estimates (Amendments to IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors); Deferred Tax related to Assets and Liabilities arising from a Single Transaction (Amendments to IAS 12 Income Taxes); and

·    International Tax Reform - Pillar Two Model Rules (Amendment to IAS 12 Income Taxes) (effective immediately upon the issue of the amendments and retrospectively).

These amendments to various IFRS Accounting Standards are mandatorily effective for reporting periods beginning on or after 1 January 2023. There is no impact to the 2023 accounts.

 

(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 are effective for the period beginning 1 January 2024:

·    Liability in a Sale and Leaseback (Amendments to IFRS 16 Leases);

·    Classification of Liabilities as Current or Non-Current (Amendments to IAS 1 Presentation of Financial Statements);

·    Non-current Liabilities with Covenants (Amendments to IAS 1 Presentation of Financial Statements); and

·    Supplier Finance Arrangements (Amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures)

The following amendments are effective for the period beginning 1 January 2025:

·    Lack of Exchangeability (Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates)

The Group is currently assessing the impact of these new accounting standards and amendments. The Group does not believe that the amendments to IAS 1 will have a significant impact on the classification of its liabilities, as the conversion feature in its convertible debt instruments is classified as an equity instrument and therefore, does not affect the classification of its convertible debt as a non-current liability. The Group does not expect any other standards issued by the IASB, but are yet to be effective, to have a material impact on the Group.

Basis of consolidation

The Consolidated Financial Statements comprise the financial statements of the subsidiaries listed in Note 12. 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 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 or utilises shares held in Treasury. 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.

Employee Benefit Trust

The Group established the Trinity Exploration and Production plc Employee Benefit Trust, which is consolidated in accordance with the principles in Note 1 - Basis of consolidation. When the options are exercised, the trust transfers the appropriate amount of shares to the employee. The proceeds received, net of any directly attributable transaction costs, are credited directly to equity.

 

Cash-settled share-based payments

The Group operates a cash-settled share-based plan comprised of reference shares as consideration for services rendered by the Group's employees.

Cash-settled share-based payments result in the recognition of a liability, which is an obligation to make a payment in cash or other assets, based on the price of the underlying equity instrument. At each reporting date, and ultimately at the settlement date, the fair value of the recognised liability is remeasured. Remeasurement applies to the recognised portion of the liability through to vesting date. The full amount is remeasured from vesting date to settlement date. The cumulative net cost and amounts recognised in profit or loss that will ultimately be recognised in respect of the transaction will be equal to the amount paid to settle the liability.

 

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 consolidated 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:

 

		2023		2022
	$	£	$	£
Average rate TTD = $/£	6.750	8.397	6.754	8.357
Closing rate TTD = $/£	6.716	8.550	6.742	8.146

 

(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 the consolidated Statement of Comprehensive Income. 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 the consolidated Statement of Comprehensive Income 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 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, although 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.

Where development costs have been capitalised and Management has determined a strategic change to focus on E&E activities in an asset, these costs are transferred from development costs to E&E assets in the period the strategic change was made. An Impairment assessment is performed prior to the transfer in accordance with IFRS 6 impairment guidance noted below.

 

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 and provisions

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.

Decommissioning provisions are updated at each balance sheet date for changes in the estimates of the amount or timing of future cash flows and changes in the discount rate. Changes to provisions that relate to the removal of an asset are added to or deducted from the carrying amount of the related asset in the current period. However, the adjustments to the asset are restricted. The asset cannot decrease below zero and cannot increase above its recoverable amount:

·    if the decrease in provision exceeds the carrying amount of the asset, the excess is recognised immediately in profit or loss;

·    adjustments that result in an addition to the cost of the asset are assessed to determine if the new carrying amount is fully recoverable or not. An impairment test is required if there is an indication that the asset may not be fully recoverable.

(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 loss 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. 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 positions. 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, DTLs 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")

From 2018 until 2020, PT had been recognised initially at fair value and subsequently measured at amortised cost using the effective interest method. Assessments were 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 were industrial with building rates at 6% and industrial without building rates at 3%.

The Finance Act 2023 amendment waives PT accrued for past years up to 31 December 2023, and so no liability is now being recognised. Refer to note 3 (f).

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"), 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.

The lease term can be described as the non-cancellable period of the lease plus periods covered by an option to extend or an option to terminate if the lessee is reasonably certain to exercise the extension option or not exercise the termination option.

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.

Treasury Shares

Where any Group company purchases the Company's equity instruments, for example as the result of a share buy- back or a share-based payment plan, the consideration paid is deducted from equity attributable to the owners of the Company as treasury shares until the shares are cancelled or reissued. Where such ordinary shares are subsequently reissued, any consideration received is included in equity attributable to the owners of the Company. Shares held by the Company are disclosed as treasury shares and deducted from equity.

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 consolidated 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% (2022: 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% (2022: 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.

	2023 $'000	2022 $'000
Profit/(loss) for the year and Equity
10% strengthening of the US Dollar/ (2022: 10%)	(253)	(269)
10% weakening of the US Dollar/ (2022: 10%)	253	269

 

(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% (2022: 20%) increase and decrease in realised oil prices. 20% (2022: 20%) is the sensitivity rate that best represents Management's assessment of the possible change in the oil prices that may affect the Group. The 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%.

	2023 $'000	2022 $'000
Revenue
20% increase in price/ (2022: 20%)	13,885	18,931
20% decrease in price/(2022: 20%)	(13,885)	(18,931)

 

The Group did not implement any hedge options during the financial year.

 

(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 2023, there were no loan commitments to attract interest rates on foreign currency-denominated borrowings, (2022: nil). During 2023 there was a bank overdraft facility which incurred $0.1 million interest (2022: $0.1 million).

(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 Heritage sales, the ECL was immaterial as all sales payments were made during the stipulated time frame. However, ECL was also calculated on Joint interest billings outstanding, which resulted in a provision of $0.1 million (2022: $0.1 million). 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 (2022: $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 $9.8 million (2022: $12.1 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

At 31 December 2023	Less than 1 year $'000	1 to 2 years $'000	2 to 5 years $'000	Total $'000
Non-derivatives
Trade and other payables	13,094	-	-	13,094
Lease liabilities	208	137	-	345
Bank overdraft	4,000	-	-	4,000
	17,302	137	-	17,439
At 31 December 2022	$'000	$'000	$'000	$'000
Non-derivatives
Trade and other payables	10,045	-	-	10,045
Lease liabilities	584	204	137	925
Bank overdraft	2,700	-	-	2,700
	13,329	204	137	13,670

 

Company

At 31 December 2023	Less than 1 year $'000	Total $'000
Non-derivatives
Trade and other payables	678	678
Intercompany	16,050	16,050
	16,728	16,728
At 31 December 2022	$'000	$'000
Non-derivatives
Trade and other payables	565	565
Intercompany	12,731	12,731
	13,296	13,296

 

(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 Cash/(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).

	2023 $'000	2022 $'000
Net cash	5,819	9,431
Total equity	(49,045)	(56,131)
Total capital	(43,226)	(46,700)
Gearing ratio	(13.5)%	(20.2)%

 

(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.

 

3.   Critical Accounting Estimates and Judgements

The preparation of the consolidated 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 18.

(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:

 

Decommissioning Cost estimates and reversals:

In 2023 there was a refresh of the well abandonment cost methodology which resulted in cost reductions for both onshore and offshore well abandonment costs. The change resulted in a significant decrease ($6.6 million) in well abandonment cost estimates. In addition, during 2023 the Tabaquite licence was relinquished resulting in a $3.0 million release of decommissioning liability. There was no material change to the platform abandonment methodology. The total reduction in decommissioning liability was $9.6 million.

The reduction in decommissioning liability resulted in a reduction in the related decommissioning asset ($ 9.6 million - refer to Note 13) and a net impact to the statement of comprehensive income where decommissioning assets were fully utilised ($2.5 million - refer to Note 7).

 

Decommissioning rates:

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 28: Provision for other liabilities

 

	Bands (years)	2023	2022
Risk free rates	6-11	3.84%	3.96%
	12-18	3.98%	4.04%
	19-21	4.22%	4.14%
	22-23	4.22%	4.09%
Inflation rate		3.20%	3.20%

 

The following table details the Group's sensitivity to a 1% (2022: 1%) increase and decrease in discount and inflation rates. 1% (2022: 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 2023 of a 1% change in these variables is as follows:

	Consolidated Statement of Financial Position: Obligation 2023 $'000	Consolidated Statement of Comprehensive Income/Expense 2023 $'000
Discount rate
1% increase in assumed rate	(6,310)	106
1% decrease in assumed rate	7,595	(273)
Inflation rate
1% increase in assumed rate	7,592	343
1% decrease in assumed rate	(6,419)	(346)

 

(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 Group estimated its own commercial reserves, guided by international Petroleum Resource Management System (PRMS) application guidelines, based on technical 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 notes 13 and 15.

·    Depreciation and amortisation charges in the Statement of Comprehensive Income 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 notes 13 and 15.

·    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 28.

·    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 18.

 

(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 relate 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 2023 an impairment charge of $1.5 million was recognised on the Group's property, plant and equipment (2022: $5.6 million) see Note 8. The impairment charge resulted in the carrying amount of the respective CGUs being written down to their recoverable amount.

 

Oil & Gas Assets $1.5 million (2022: $5.6 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 7-24 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.

	2024	2025	2026	2027	2028	2029
Realised price	64.8	62.1	60.1	58.7	57.8	57.4

 

If the price deck used in the impairment calculation had been 10% lower than Management's estimates at 31 December 2023, the Group would have a $4.1 million increase on impairment of Oil & Gas Assets (2022: $16.1 million increase). If the price deck used in the impairment calculation had been 10% higher than Management's estimates at 31 December 2023, the Group would have a $0.1 million decrease on impairment of the Oil & Gas Assets (2022: $0.6 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 2023, Management's estimate of the Group's cost of capital was 14.4% (2022:15.0%). 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 $0.1 million increase (2022: $0.0 million) change to the impairment position for 2023 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 $0.1 million decrease to the impairment position for 2023 (2022: $0.0 million increase).

(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 2023 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.

·    Impairment of Jacobin Well Cost

Impairment triggers were identified on this asset as at 31 December 2023. An impairment assessment was performed resulting in an impairment of $9.6 million.

·    Impairment of PS 4 E&E costs

In 2022, an E&E asset (reclassified from Oil and Gas developed asset) was recognised for costs relating to the PS-4 acquisition costs. At 31 December 2023, impairment triggers were identified mainly related to the reduction in 2C resources. An assessment was performed and resulted in the impairment of $2.1 million.

(f)   Property tax

PT is assessed on property owned by the Group in T&T governed by the Property Tax Act 2009 and later Property Tax 2018 amendment of T&T. The calculation of the PT is described in note 1 Background and Summary of significant accounting policies.

The Property Tax Act and subsequent Amendments to the Act requires the Board of Inland Revenue to issue a Notice of Assessment on or before 31 March each year. The amendment in the Finance Act 2023 waives the tax up to 31 December 2023.

The collection of the tax will be effective from 2024 for residential properties only, until the valuation roll has been completed and the Notice of Assessment given for the other property types. The Group will continue to monitor developments in the Property tax law and reassess this at each reporting period. As such, the Group has not recognised any PT liabilities to 31 December 2023.

(g)  Share-based payments

The Company has in place a share-based compensation plan (the LTIP) for the Executive Director 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 25 for details.

4.   Segment Information

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 includes the Chief Executive Officer, 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 revenue is generated at a point in time. All non-current assets of the Group are located in T&T.

5.   Operating Profit Before Impairment and Exceptional Items

	2023 $'000	2022 $'000
Operating profit before impairment and exceptional items is stated after taking the following items into account:
DD&A (Note 13)	8,168	6,890
Depreciation on ROU (Note 14)	533	534
Amortisation of computer software (Note 15)	233	193
Employee costs (Note 35)	9,484	8,317
Inventory recognised as expense, charged to operating expenses	66	174

 

Auditors' remuneration

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

	2023 $'000	2022 $'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)	358	220
BDO Limited (T&T and Barbados based)	106	107
-          Fees payable to the Company's auditors' for other services: The audit of Company's subsidiaries	18	16
Audit related assurance services - interim review	37	29
Total assurance and auditors' remuneration	519	372

 

All fees in 2023 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. The professional fees relates to tax services rendered for advice on tax losses.

6.   Derivative expenses

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

	31 December 2023 $'000	31 December 2022 $'000
Derivative expenses (realised)	-	(10,446)
Movement in FV of derivative financial instruments (unrealised)	-	2,883
	-	(7,563)

 

7.   Decommissioning Release/Reduction

Reduction of Decommissioning costs estimates	(114)	-
Release of Decommissioning Liablilty- Tabaquite field	(2,394)	-
Decommissioning release/reduction Total	(2,508)	-

 

·    Reduction of Decommissioning cost estimates $0.1 million

·    Release of Decommissioning cost estimate: $2.4 million in relation to Tabaquite Field surrendered.

See Note 3(b): Critical Accounting Estimates and Judgement

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 consolidated financial statements are highlighted below.

	31 December 2023 $'000	31 December 2022 $'000
ICT incident costs	161	161
Bravo Fire costs	146	-
Exceptional Items Total	307	161

 

·    Charges relating to ICT incident: $0.2 million charge in relation to costs incurred in relation to the cyber incident

·    Charges relating to Bravo Fire incident: $0.1 million charge in relation to costs incurred for the Bravo Fire in April 2023

 

8.   Impairment

	31 December 2023 $'000	31 December 2022 $'000
Impairment of Inventory	-	334
Impairment of Jacobin Well Costs	9,634	-
Impairment of PS4 E&E costs	2,132	-
Impairment of property, plant and equipment	1,549	5,558
Other impairment of property, plant and equipment	147	158
Total expense	13,462	6,050

 

·    Impairment of inventory - No charge in relation to inventory impairment. In 2022 $0.3 million on moving inventory items.

·    Impairment of Jacobin Well Costs - $9.6 million charge on Exploration and Evaluation costs relating to the Jacobin Well (See Note 3(e): Critical Accounting Estimates and Judgement)

·    Impairment of E&E assets - $2.1 million charge on PS4 Exploration and Evaluation costs (See Note 3(e): Critical Accounting Estimates and Judgement)

·    Impairment of property, plant and equipment - $1.5 million charge in relation to property, plant and equipment and cash generating units (See Note 3(d): Critical Accounting Estimates and Judgement)

·    Other impairment of property, plant and equipment - $0.1 million charge in other property, plant equipment costs.

 

9.   Finance income and costs

Recognised in the consolidated statement of comprehensive income

	2023 $'000	2022 $'000
Finance income
Interest Income	50	48

 

	2023 $'000	2022 $'000
Finance costs
Decommissioning - Unwinding of discount (Note 28)	(2,077)	(1,110)
Interest on Leases (Note 14)	(86)	(135)
Interest and other expenses on overdraft	(51)	(94)
	(2,214)	(1,339)

 

10. Income Taxation

	2023 $'000	2022 $'000
Current Taxes
Petroleum profits tax	422	2,404
Unemployment levy	169	960
Deferred Taxes
Current year
Movement in asset due to tax losses recognised (Note 18)	(3,238)	(935)
Movement in liability due to accelerated tax depreciation (Note 18)	(78)	(85)
Income tax (credit)/ expense	(2,725)	2,344

 

The Group's effective tax rate varies from the statutory rate for UK companies of 19% (2022:19%) as a result of the differences shown below:

	2023 $'000	2022 $'000
Loss/ (Profit) before taxation	(9,529)	2,457
Tax calculated at domestic tax rates applicable to profits in the respective countries	(3,101)	4,836
Expenses not deductible for tax purposes	17,005	13,448
Impact on tax losses	(2,327)	(5,671)
Deferred tax on capital allowances in the current period recognised	(11,064)	(9,334)
Tax losses previously generated now recognised in the current period	(3,238)	(935)
Tax (credit)/ charge	(2,725)	2,344

 

Corporate income tax is calculated at 19% (2022: 19%) of the assessable profit for the year for the UK Parent Company, 55% for the operating subsidiaries in Trinidad and Tobago (2022: 55%) and 30% (2022: 30%) for the corporate subsidiaries in Trinidad and Tobago.

Taxation losses at 31 December 2023 available for set off against future taxable profits amounts to approximately

$224.4 million (2022: $227.5 million), with tax losses recognised of $31.4 million at the end of 2023. These losses do not have an expiry date. While Management have filed Returns, these have not yet been confirmed by the Board of Inland Revenue ("BIR") or His Majesty's Revenue and Customs ("HMRC"). Tax losses carried forward by companies engaged in petroleum production business in Trinidad and Tobago are restricted to set off in a year of in a year of income 75% of the otherwise chargeable profits.

 

11. 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.

Year ended 31 December 2023	(Loss)/Profit for the year $'000	Weighted Average Number of Shares '000	Earnings Per Share $
Basic	(6,804)	38,687	0.0
Diluted	(6,804)	38,687	0.0

 

Year ended 31 December 2022
Basic	113	39,094	0.0
Diluted	113	40,524	0.0

 

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 note 25) are considered potential ordinary shares.

There was no impact on the weighted average number of shares outstanding during 2023 as 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 2023.

The basic shares balance was amended through the net effect of the issuance of new shares (following exercise of Options) and the repurchase of shares through the share buyback programme in 2023 (See notes 23 and 24).

 

12. Investment In Subsidiaries

Company
	2023 $'000	2022 $'000
Opening balance	60,864	60,347
Share based payment forfeiture	(69)	-
Share based payment	547	517
Closing balance	61,342	60,864

 

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 2023 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	99.99998%
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%
Trinity Midstream Limited	Trinidad address	Oil and Gas	100%
Trinity Exploration and Production (Erin 1) Limited	Trinidad address	Oil and Gas	100%
Trinity Exploration and Production (Erin 2) Limited	Trinidad address	Oil and Gas	100%
Trinity Exploration and Production (Forest 1) Limited	Trinidad address	Oil and Gas	100%
Trinity Exploration and Production (Forest 2) Limited	Trinidad address	Oil and Gas	100%
Trinity Exploration and Production (Forest 3) Limited	Trinidad address	Oil and Gas	100%
Trinity Renewable Resources Limited	Trinidad address	Oil and Gas	100%
Trinity Exploration and Production plc Employee Benefit Trust	c/o Pinsent Masons LLP 1 Park Row, Leeds, LS1 5AB, UK	Employee Benefit Trust	100%

 

13. Property, Plant and Equipment

Year ended 31 December 2023	Plant & Equipment $'000	Leasehold & Buildings $'000	Oil & Gas Assets $'000	Total $'000
Opening net book amount at 1 January 2023	4,255	1,271	39,461	44,987
Additions	1,573	27	5,306	6,906
Transfers (Note 15)	-	-	319	319
Disposals	(21)	-	(6)	(27)
Tabaquite decommissioning asset relinquishment	-	-	(632)	(632)
Reduction to decommissioning estimate (Note 3(b))	-	-	(6,508)	(6,508)
Impairment charge	(36)	-	(1,653)	(1,689)
DD&A charge for year	(630)	(192)	(7,346)	(8,168)
Closing net book amount at 31 December 2023	5,141	1,106	28,941	35,188

 

At 31 December 2023
Cost	19,709	3,510	327,454	350,673
Accumulated DD&A and impairment	(14,568)	(2,404)	(298,513)	(315,485)
Closing net book amount	5,141	1,106	28,941	35,188

 

Year ended 31 December 2022	Plant & Equipment $'000	Leasehold & Buildings $'000	Oil & Gas Assets $'000	Total $'000
Opening net book amount at 1 January 2022	2,919	1,388	45,200	49,507
Additions	1,999	71	13,062	15,132
Transfers (Note 3(h))	-	-	(2,451)	(2,451)
Adjustment to decommissioning estimate (Note 28)	-	-	(4,595)	(4,595)
Impairment charge	(62)	-	(5,654)	(5,716)
DD&A charge for year	(601)	(188)	(6,101)	(6,890)
Closing net book amount at 31 December 2022	4,255	1,271	39,461	44,987

 

At 31 December 2022
Cost	18,193	3,483	323,497	345,173
Accumulated DD&A and impairment	(13,938)	(2,212)	(284,036)	(300,186)
Closing net book amount	4,255	1,271	39,461	44,987

 

1                     An impairment loss of $1.7 million (2022: $5.7 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.

 

14. 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 2023 $'000	31 December 2022 $'000
Right-of-use assets
Non-current assets	312	838
Lease Liabilities
Current	208	584
Non-current	137	341
	345	925

 

The ROU assets relate to motor vehicles, office building, rental house 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:

	2023 $'000	2022 $'000
Depreciation charge of ROU assets
Depreciation	(533)	(534)
Interest expense (including finance cost)	(86)	(135)

 

The total cash outflow for leases in 2023 was $0.7 million (2022: $0.7 million)

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

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.

15. Intangible Assets

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

Year ended 31 December 2023	Exploration and Evaluation assets $'000	Computer software $'000	Research and Development $'000	Total $'000
Opening net book amount at 1 January 2023	32,903	405	229	33,537
Additions	9,421	492	267	10,180
Transfers	(319)	-	-	(319)
Impairment charge	(11,766)	-	-	(11,766)
Amortisation charge for year	-	(233)	-	(233)
Closing net book amount at 31 December 2023	30,239	664	496	31,399

 

At 31 December 2023
Cost	30,239	1,471	496	32,206
Accumulated amortisation	-	(807)	-	(807)
Closing net book amount	30,239	664	496	31,399

 

Year ended 31 December 2022	Exploration and Evaluation assets $'000	Computer software $'000	Research and Development $'000	Total $'000
Opening net book amount at 1 January 2022	30,217	496	46	30,759
Additions	235	102	183	520
Transfers (Note 3(h))	2,451	-	-	2,451
Amortisation charge for year	-	(193)	-	(193)
Closing net book amount at 31 December 2022	32,903	405	229	33,537

 

At 31 December 2022
Cost	32,903	979	229	34,111
Accumulated amortisation	-	(574)	-	(574)
Closing net book amount	32,903	405	229	33,537

·    E&E assets: Represents the cost for the TGAL 1 exploration well. The Group tests whether E&E assets have suffered any impairment triggers on an annual basis and there was an impairment loss of $11,766 (2022: nil). See reference 3 (e) (impairment of intangible E&E assets).

·    Computer Software: In 2023, costs incurred in connection with the acquisition of software.

·    Research and Development: In 2023, there were costs associated for various initiatives in connection with reducing carbon emissions.

 

16. Abandonment fund

	2023 $'000	2022 $'000
At 1 January	4,511	4,021
Additions	451	490
At 31 December	4,962	4,511

 

17.  Performance bond

	2023 $'000	2022 $'000
At 1 January and 31 December	606	602

 

The Group's Lease Operatorship Assets ("LOA") licences were renewed in June 2021. New Performance Bonds for each of the LOA were put in place totaling $0.47 million at a bond fee of 1.75% executed with First Citizens Bank Trinidad and Tobago Limited and effective until 31 December 2030. A performance bond of $0.13 million for PS-4 block was also executed with First Citizens Bank Trinidad and Tobago Limited in 2022 effective 31 December 2030 at a bond fee of 1.75%. These funds have been restricted to fixed deposits for the period of the respective LOA licences at varying rates of interest.

18. Deferred Income Taxation

Group

The analysis of DTA is as follows:

	2023 $'000	2022 $'000
DTA:
DTA to be recovered in more than 12 months	(11,507)	(7,774)
DTA to be recovered in less than 12 months	(4,196)	(4,691)
DTL:
DTL to be settled in more than 12 months	1,862	1,940
Net DTA	(13,841)	(10,525)

 

The movement on the deferred income tax is as follows:

	2023 $'000	2022 $'000
At beginning of year	(10,525)	(9,505)
Movement for the year	(3,238)	(935)
Unwinding of deferred tax on fair value uplift	(78)	(85)
Net DTA	(13,841)	(10,525)

 

The deferred tax balances are analysed below:

	2021 $'000	Movement $'000	2022 $'000	Movement $'000	2023 $'000
Acquisition	(33,436)	-	(33,436)	-	(33,436)
Tax losses recognised	(45,009)	(935)	(45,944)	(3,238)	(49,182)
Tax losses derecognised	66,915		66,915	-	66,915
	(11,530)	(935)	(12,465)	(3,238)	(15,703)

 

	2021 $'000	Movement $'000	2022 $'000	Movement $'000	2023 $'000
DLT
Accelerated tax depreciation and non- current asset impairment	(19,375)	-	(19,375)	-	(19,375)
Acquisitions	19,580	-	19,580	-	19,580
Fair value uplift	1,820	(85)	1,735	(78)	1,657
	2,025	(85)	1,940	(78)	1,862

 

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 $3.2 million have been recognised (2022: $0.9 million was recognised) based on estimated future taxable profits. The Group has unrecognised deferred tax assets amounting to $82.5 million which have no expiry date.

DTL have decreased by $0.1 million related to unwinding of assets.

·    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). The Group has no legal right to offset any DTA and DTL.

·    Tax losses - At the end of 2023 the Group had gross tax losses carried forward of $224.4 million (2022: $227.5 million) represented by corporate tax losses in the UK of $34.7 million (2022: $33.2 million) and PPT and Corporate tax losses in Trinidad and Tobago of $189.7 million (2022: $194.3 million). In the UK corporation tax losses may be carried forward indefinitely. Similarly, in Trinidad and Tobago PPT and corporate tax losses may be carried forward indefinitely to reduce the taxes in future years. As of 1 January 2020, however, PPT losses can only be utilised to shelter a maximum of 75 percent of PPT per annum.

 

19. Inventories

	Crude oil $'000	Materials and supplies $'000	Total $'000
At 1 January 2023	125	3,851	3,976
Net inventory movement	25	(85)	(60)
At 31 December 2023	150	3,766	3,916
At 1 January 2022	96	3,724	3,820
Impairment (see note 8)	-	(334)	(334)
Net inventory movement	29	1,100	1,129
At 31 December 2022	125	4,490	4,615

 

(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. In the current year there was no impairment of inventory items (2022: $0.3 million).

20. Trade and Other Receivables

	Group		Company
	2023 $'000	2022 $'000	2023 $'000	2022 $'000
Due within 1 year
Amounts due from related parties (Note 31 (d))			4,567	2,830
Trade receivables	4,393	4,643	-	-
Less: provision for impairment of trade and intercompany receivables	(26)	(4)	-	-
Trade receivables: net	4,367	4,639	4,567	2,830
Prepayments	1,005	969	158	198
VAT recoverable	6,015	4,657	101	29
Other receivables	420	351	-	6
Less: provision for Impairment of other receivables	(98)	(56)	-	-
	11,709	10,560	4,826	3,063

 

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. Since the Joint Interest Billing ("Jibs") balances are outstanding, an ECL was calculated at 31 December 2023 of $0.1 million (31 December 2022: $0.1 million) against Other receivables.

VAT recoverable (gross) - As at 31 December 2022 the VAT recoverable amount was $4.7 million. During the period ending 31 December 2023, the Group generated future refunds of $5.2 million, refunds received amounted to $3.9 million.

All trade receivables are with the Group's only customer, Heritage. Ageing analysis of these trade receivables as at 31 December 2023 is as follows:

	2023 $'000	2022 $'000
Up to 30 days	4,313	4,544
>60 days	-	-
>180 days	54	95
	4,367	4,639

 

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

	Group		Company
	2023 $'000	2022 $'000	2023 $'000	2022 $'000
USD	3,378	3,381	4,724	2,873
GBP	260	260	102	190
TTD	8,071	6,919	-	-
	11,709	10,560	4,826	3,063

 

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
	2023 $'000	2022 $'000	2023 $'000	2022 $'000
Trade receivables
Counterparties without external credit rating:
Existing customers with no defaults in the past	11,709	10,560	-	-

 

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 2023, trade receivables of $4.4 million (2022: $4.6 million) were therefore considered to be fully performing.

At the end of 2023 a total of $0.1 million was outstanding from Petrotrin (2022: $0.1 million). An ECL of $0.0 million was applied to the outstanding $0.1 million receivables amount due from Petrotrin.

For other Joint Interest Billing receivable amounts from Heritage, an ECL of $0.1 million (2022: $0.1 million) was calculated.

21. Dividend Payable

The Company declared dividends of US$ 0.2 million (2022: nil) for the six months ended 30 June 2023. As at 31 December 2023, US$ 0.0 million remains payable to shareholders.

	As at 31 December 2023 $'000	As at 31 December 2022 $'000
Dividend declared	236
Dividend paid	(231)	-
Dividend payable	5	-

 

22. Cash and Cash Equivalents

	Group		Company
	2023 $'000	2022 $'000	2023 $'000	2022 $'000
Short term investment	245	1,033	245	1,033
Cash and cash equivalents	9,574	11,098	949	1,069
	9,819	12,131	1,194	2,102

 

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.

23. Share Capital and Share Premium

Group

	Number of shares	Ordinary shares $'000	Share premium $'000	Total $'000
As at 1 January 2023	39,884,637	399	-	399
Shares Issued at Nominal value	15,176	0	-	0
As at 31 December 2023	39,899,813	399	-	399

 

24. Treasury Shares

Treasury shares are shares in the Company that are held by the Company. From September 2022 to June 2023, three share buyback programmes were executed.

Group and Company

	Number of shares	Cost $'000	Total $'000
As at 1 January 2023	1,072,000	1,522	1,522
Share buybacks	477,000	566	566
Shares issued out of Treasury	(377,313)	(535)	(535)
As at 31 December 2023	1,171,687	1,553	1,553

 

25. 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 2023 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:

	2023 $'000	2022 $'000
At 1 January	2,990	3,784
Share based payment expense:
Exercised/lapsed options realised to retained earnings	(698)	(1,416)
LTIP expense	520	622
At 31 December	2,812	2,990

 

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:

			2022		2021
Grant-Vest	Expiry Date	Exercise price per Share Options	Number of Options	Exercise price per Share Options	Number of Share Options
2012-2015	2022		-	GBP8.60	168,554
2013-2016	2023		28,954	GBP12.00	28,954
			28,954		197,508

 

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 11.90	GBP 12.00
Average Exercise price	GBP 12.00	GBP 8.90
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 Executive Directors and other members of 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 One off Award

One Off LTIP awards were granted in August 2017 over 2,541,600 ordinary shares and in June 2020 over a further 142,296 ordinary shares (the "2017 One Off Award"). The 2017 One Off Award vested in full on 30 June 2022, 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 49.8 pence per share. If the three-month volume-weighted price ("VWAP") at the testing date is 350 pence or more per share, this part of the award will vest in full. If the VWAP at the testing date is 49.8 pence per share or less, this part of the award will not vest at all. If the VWAP at the testing date is between 49.8 pence and 350 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 One Off Award was $2.6 million and was expensed over the vesting period with the full charge pro-rated over the period up to 30 June 2022. However, the 2017 One Off Award could vest in full or in part on 30 June 2020 or 2021 with the appropriate charge being taken over that vesting period. The fair value at grant date was 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 the 2017 One Off Award were as follows:

Grant Date	24 August 2017	30 June 2020
Share price at grant date	GBP 107.50p	GBP 79.00p
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

 

The final vesting of the 2017 One Off Award was due to occur on 30 June 2022. However, as the three-month average VWAP to 30 June 2022 of 130.0p was below that prevailing at 30 June 2021, the remaining 1,214,744 unvested options lapsed.

 

2017 and 2018 LTIP Award

In January 2019 Options over 282,400 ordinary shares and in May 2019 Options over 383,282 ordinary shares were granted under the LTIP awards in accordance with the policy announced to the market on 25 August 2017 in respect of the performance of the Company in the financial years ended 31 December 2017 and 2018 respectively. These awards vested on 1 January 2021 and the May 2019 awards vested on 2 January 2022 subject to meeting the performance criteria set out in the table below and continued employment with the Company.

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

 

These awards were 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 amounts stated above represent the maximum possible opportunity.

The total fair value at grant date of the LTIP awards granted during the period ended 31 December 2019 was $0.9 million and this was expensed over the vesting period with the full charge pro-rated 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 LTIP awards granted during the period ended 31 December 2019 included:

	2017 LTIP Award	2018 LTIP Award
Grant Dates	2 January 2019	9 May 2019
Share price at grant dates	GBP167.7p	GBP146.6p
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

 

2019 LTIP Award

On 25 June 2020 and 30 October 2020 Options over a total of 481,586 ordinary shares were granted under the LTIP in accordance with the policy announced to the market on 25 August 2017 in respect of the performance of the Company in the financial year ended 31 December 2019. These LTIP awards vested on 2 January 2023, subject to meeting the performance criteria set out in the table below and continued employment with the Company.

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

 

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

The total fair value at grant date of the LTIP awards granted during the period ended 31 December 2020 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 LTIP awards granted during the period ended 31 December 2020 included:

	2019 LTIP Award	2019 LTIP Award
Grant Dates	25 June 2020	30 October 2020
Share price at grant dates	GBP79.0	GBP77.0
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

 

2020 LTIP Award

On 13 August 2021, Options over a total of 325,000 ordinary shares were granted under the LTIP in accordance with a revised LTIP scheme (the Revised LTIP") in respect of the performance of the Company in the financial year ended 31 December 2020. These LTIP awards will vest on 1 January 2024, subject to meeting the performance criteria set and continued employment in the Company.

The performance targets set for awards made under the Revised LTIP during the period ended 31 December 2021 will be measured considering both the Company's absolute TSR performance and the Company's relative TSR performance over a three-year period, commencing with the current financial year of the Company (i.e. a measurement period of 1 January 2021 to 31 December 2023). TSR calculations will be determined by reference to the volume weighted three- month average price prior to the start and end of the measurement period (with the starting average price adjusted for the Share Consolidation). The three-month volume weighted average price at the start of the performance period was 88p (adjusted for the Share Consolidation).

The performance targets provide that:

·    No portion of a distinct one-half of the LTIP Award (the "Absolute TSR Part") may vest unless the Company's compound annual growth rate of TSR over the performance period is at least 10% p.a., for which 30% of the Absolute TSR Part may vest, rising on a straight-line basis for full vesting of the Absolute TSR Part if the Company's compound annual growth rate of TSR over the performance period equals or exceeds 25% p.a.

·    No portion of the other distinct one-half of the LTIP Award (the "Relative TSR Part") may vest unless the Company's TSR over the performance period ranks at least median relative to the TSR performance within a comparator group of companies, for which 30% of the Relative TSR Part may vest, rising on a straight line basis for full vesting of the Relative TSR Part if the Company's TSR over the performance period ranks upper quartile or better relative to the TSR performance within a comparator group. However, an underpin term applies to the Relative TSR Part which provides that, regardless of relative TSR performance, no vesting may ordinarily accrue in respect of the Relative TSR Part unless the Company's compound annual growth rate of TSR over the performance period is at least 10% per annum.

The total fair value at grant date of the LTIP awards granted during the period ended 31 December 2021 was $0.7 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 LTIP awards granted during the period ended 31 December 2021 included:

	2020 LTIP Award
Grant Date	13 August 2021
Share price at grant dates	GBP146.00p
Exercise price	GBP0.00
Expected volatility	6.3%
Risk-free interest rates	(0.20%)
Expected dividend yields	0%
Vesting dates	1 January 2024

 

2021 LTIP Award

On 6 June 2022, 24 October 2022 and 9 December 2022 Options over a total of 415,000 ordinary shares were granted in accordance with the Revised LTIP in respect of the performance of the Company in the financial year ended 31 December 2021. The earliest vesting date for the Award will be 1 January 2025, subject to meeting the performance criteria set and continued employment in the Company.

The performance targets set for awards made under the Revised LTIP during the period ended 31 December 2022 will be measured considering both the Company's absolute TSR performance and the Company's relative TSR performance over a three-year period, commencing with the current financial year of the Company (i.e. a measurement period of 1 January 2022 to 31 December 2024). TSR calculations will be determined by reference to the volume weighted three month average price prior to the start and end of the measurement period (with the starting average price adjusted for the Share Consolidation). The three-month volume weighted average price at the start of the performance period was £1.38 (adjusted for the Share Consolidation).

The performance targets provide that:

·    No portion of a distinct one-half of the LTIP Award (the "Absolute TSR Part") may vest unless the Company's compound annual growth rate of TSR over the performance period is at least 10% p.a., for which 30% of the Absolute TSR Part may vest, rising on a straight line basis for full vesting of the Absolute TSR Part if the Company's compound annual growth rate of TSR over the performance period equals or exceeds 20% p.a.

·    No portion of the other distinct one-half of the LTIP Award (the "Relative TSR Part") may vest unless the Company's TSR over the performance period ranks at least median relative to the TSR performance within a comparator group of companies, for which 30% of the Relative TSR Part may vest, rising on a straight line basis for full vesting of the Relative TSR Part if the Company's TSR over the performance period ranks upper quartile or better relative to the TSR performance within a comparator group. However, an underpin term applies to the Relative TSR Part which provides that, regardless of relative TSR performance, no vesting may ordinarily accrue in respect of the Relative TSR Part unless the Company's compound annual growth rate of TSR over the performance period is at least 10% per annum.

The total fair value at grant date of the LTIP awards granted in the period ended 31 December 2022 was $0.6 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 LTIP awards granted during the period ended 31 December 2022 included:

	2021 LTIP Award
Grant Date	Jun/Oct/Dec 2022
Share price at grant dates	GBP135p/120p/108p
Exercise price	GBP0.00
Expected volatility	79%
Risk-free interest rates	1.83%/3.59%/3.28%
Expected dividend yields	0%
Vesting dates	1 January 2025

 

2022 LTIP Award

On 22 August 2023, the Company announces that 565,000 options have been granted under the LTIP in respect of the Company's performance in the year to 31 December 2022 (the "2022 LTIP Award"), including 100,000 options granted to Jeremy Bridglalsingh, Chief Executive Officer, 175,000 options granted to Julian Kennedy, Chief Financial Officer, (CFO) (of which 100,000 are one-off options granted on joining the Board), and 100,000 one-off options granted to the new Chief Operating Officer, (COO) who joined earlier this year. The 2022 Annual LTIP Award represents 1.42% of the Company's current issued share capital. Excluding the one-off options issued to the CFO and COO concerning their appointments, the 2022 Annual LTIP Award represents 0.91 per cent of the current issued share capital of the Company.

The performance targets set for awards made under the 2022 Annual LTIP Award will be measured considering both the Company's absolute TSR performance and the Company's relative TSR performance over a three-year period, commencing with the current financial year of the Company (i.e. a measurement period of 1 January 2023 to 31 December 2025). TSR calculations will be determined by reference to the three-month average closing price prior to the start and end of the measurement period. The three-month average closing price at the start of the performance period for the 2022 Annual LTIP Award was £1.15.

The performance targets provide that:

·    No portion of a distinct one-half of the 2022 Annual LTIP Award (the "Absolute TSR Part") may vest unless the Company's compound annual growth rate of TSR over the performance period is at least 10% p.a., for which 30% of the Absolute TSR Part may vest, rising on a straight line basis for full vesting of the Absolute TSR Part if the Company's compound annual growth rate of TSR over the performance period equals or exceeds 20% p.a.

·    No portion of the other distinct one-half of the 2022 Annual LTIP Award (the "Relative TSR Part") may vest unless the Company's TSR over the performance period ranks at least median relative to the TSR performance within a comparator group of companies, for which 30% of the Relative TSR Part may vest, rising on a straight line basis for full vesting of the Relative TSR Part if the Company's TSR over the performance period ranks upper quartile or better relative to the TSR performance within a comparator group. However, an underpin term applies to the Relative TSR Part which provides that, regardless of relative TSR performance, no vesting may ordinarily accrue in respect of the Relative TSR Part unless the Company's compound annual growth rate of TSR over the performance period is at least 10% per annum.

The total fair value at grant date of the LTIP awards granted in the period ended 31 December 2023 was $0.8 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 LTIP awards granted during the period ended 31 December 2023 included:

	2022 LTIP Award
Grant Date	August 2023
Share price at grant dates	GBP 90p
Exercise price	GBP0.00
Expected volatility	52%
Risk-free interest rates	5.01%
Expected dividend yields	0%
Vesting dates	1 January 2026

 

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

	2023 Average exercise price per Share Option	Number of Options	2022 Average exercise price per Share Option	Number of Options
At 1 January	GBP 0.00	1,430,360	GBP 0.00	3,381,299
Forfeited/Lapsed	GBP 0.00	(231,930)	GBP 0.00	(1,360,733)
Granted1	GBP 0.00	565,000	GBP 0.00	415,000
Exercised	GBP 0.00	(463,608)	GBP 0.00	(1,005,206)
At 31 December	GBP 0.00	1,299,822	GBP 0.00	1,430,360

1 Weighted average fair value of LTIPs granted GBP 1.15

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

Grant-Vest	Expiry date	Exercise price	2023	2022
24/8/2017 - 30/6/2022	24/08/2027	GBP 0.00	-	167,037
2/1/2019 - 1/1/2021	1/1/2024	GBP 0.00	-	50,858
9/5/2019 - 2/1/2021	2/1/2025	GBP 0.00	-	90,879
25/6/2020 - 2/1/2023	2/1/2026	GBP 0.00	94,822	381,586
13/8/2021 - 31/12/2023	2/1/2027	GBP 0.00	275,000	325,000
6/6/2022 - 1/1/2025	1/1/2027	GBP 0.00	365,000	415,000
22/8/2023 - 1/1/2026	1/1/2028	GBP 0.00	565,000	-

 

26. Merger and Reverse Acquisition Reserves

	Reverse Acquisition Reserve $'000	Merger Reserve $'000	Total $'000
At 1 January 2023	(89,268)	-	(89,268)
Capital re-organisation/reduction	-	-	-
Translation differences	-	-	-
At 31 December 2023	(89,268)	-	(89,268)
At 1 January 2022	(89,268)	-	(89,268)
Capital re-organisation/reduction	-	-	-
Translation differences	-	-	-
At 31 December 2022	(89,268)	-	(89,268)

 

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.

27. 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, FX Gain/(Loss) and the movement in the FV of Derivative Financial Instruments.

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:

	2023 $'000	2022 $'000
Operating Profit Before SPT, Impairment and Exceptional Items	9,593	18,971
DD&A (note 13 - 15)	8,935	7,617
ILFA (Note 20)	64	(46)
SOE (Note 24)	528	647
FX (loss)/gain	65	394
Loss on disposal	15	-
Movement in FV of Derivative Financial Instruments (Note 6)	-	(2,883)
Adjusted EBITDA	19,200	24,700

 

	'000	'000
Weighted average ordinary shares outstanding - basic	38,867	39,094
Weighted average ordinary shares outstanding - diluted	39,987	40,524

 

	$	$
Adjusted EBITDA per share - basic	0.50	0.64
Adjusted EBITDA per share - diluted	0.48	0.61

 

Adjusted EBIDA after Current Taxes (the impact of SPT and PPT/UL) is calculated as follows:

	2023 $'000	2022 $'000
Adjusted EBITDA	19,200	24,700
SPT	(5,697)	(9,012)
PT	(591)	(3,365)
Adjusted EBIDA After Current Taxes	12,912	12,323

 

	'000	'000
Weighted average ordinary shares outstanding - basic	38,687	39,094
Weighted average ordinary shares outstanding - diluted	39,987	40,524

 

	$	$
Adjusted EBIDA After Current Taxes per share - basic	0.33	0.32
Adjusted EBIDA After Current Taxes per share - diluted	0.32	0.31

 

28. Provision for Other Liabilities

(a)          Non-current:

Year ended 31 December 2022	Decommissioning provision $'000	Closure of pits $'000	Total $'000
Opening amount as at 1 January 2023	51,857	603	52,460
Unwinding of discount (Note 9)	2,077	-	2,077
Revision to estimates (Note 13)	(9,638)	-	(9,638)
Additions	-	40	40
Translation differences	137	-	137
Closing balance at 31 December 2023	44,433	643	45,076
Year ended 31 December 2022
Opening amount as at 1 January 2022	55,220	470	55,690
Unwinding of discount (Note 9)	1,110	-	1,110
Revision to estimates (Note 13)	(4,595)	-	(4,595)
Additions	-	138	138
Translation differences	122	(5)	117
Closing balance at 31 December 2022	51,857	603	52,460

 

Decommissioning provision

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 - 3.20% (2022: 3.20%)

b.            Risk free rate - 3.84% - 4.22% (2022: 3.96% - 4.14%)

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.

Closure of Pits

Closure of pits relate to the remedy and closure of pits associated with drilling new onshore wells. It is an environmental regulatory requirement set by the Environmental Management Authority ("EMA") that all open drill pits for onshore drilling must be closed after sufficient testing has deemed it safe to close the pit.

(b)          Current:

Year ended 31 December 2023	Litigation claims $'000	Other provisions $'000	Total $'000
Opening amount as at 1 January 2022	137	112	249
Payments	(15)	(112)	(127)
Additions	-	500	500
Closing balance at 31 December 2023	122	500	622
Year ended 31 December 2022
Opening amount as at 1 January 2021	46	-	46
Additions	91	112	203
Closing balance at 31 December 2022	137	112	249

 

Litigation claims

Other provisions

There was a provision of $0.5 million in relation to drilling costs for the Jacobin well.

29. Trade and Other Payables

	Group		Company
Current	2023 $'000	2022 $'000	2023 $'000	2022 $'000
Trade payables	3,154	2,605	256	136
Accruals	5,747	4,661	422	429
VAT payable	245	113
Other payables	2,560	500	-	-
SPT	1,388	2,166	-	-
	13,094	10,045	678	565

 

30. Bank overdraft

	31 December 2023 $'000	31 December 2022 $'000
Bank Overdraft	4,000	2,700
	4,000	2,700

An on-demand operating (overdraft) line of $8.0 million exists 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 6.50% per annum, effective rate 7.75%. Interest is payable monthly.

·    Repayment: Upon demand at CIBC's discretion.

·    Debenture: Floating charge debenture giving the lender a first ranking floating charge over inventory and trade receivables only.

·    Covenant: Current Ratio not less than 1.25:1.

The credit limit on the facility is $8.0 million of which $4.0 million was drawn as at 31 December 2023.

31.      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
	2023 $'000	2022 $'000
Company subsidiaries:
Trinity Exploration and Production Services Limited	4,600	10,510
Bayfield Energy Limited	1	80
Trinity Exploration and Production (Trinidad and Tobago) Limited	-	1,800
Trinity Exploration and Production Services Limited (UK) Limited	35	1,100
	4.636	13,490

 

(b)          Transfer of funds to related parties

Company
	2023 $'000	2022 $'000
Company subsidiaries:
Trinity Exploration and Production Services Limited	(1,000)	-
Bayfield Energy Limited	(75)	-
Trinity Exploration and Production Services Limited (UK) Limited	(2,079)	(1,265)
	(3,154)	(1,265)

 

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
	2023 $'000	2022 $'000
Salaries and short-term employee benefits	857	876
Post-employment benefits	40	30
Share-based payment expense	196	279
	1,093	1,185

 

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

Company
	2023 $'000	2022 $'000
Receivables from related parties:
Trinity Exploration & Production (UK) Limited	80	40
Trinity Exploration and Production (Galeota) Limited	15	2
Bayfield Energy Limited	204	122
Trinity Exploration and Production Services (UK) Limited	4,384	2,652
Total intercompany receivables	4,683	2,816
(Provision for impairment)/Reversal of provision for impairment	(116)	14
Closing intercompany receivables (Note 20)	4,567	2,830

 

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 (2022: 0.1 million).

Company
	2023 $'000	2022 $'000
Payables to related parties:
Trinity Exploration and Production Services Limited	14,135	10,683
Trinity Exploration and Production (Trinidad & Tobago) Ltd	1,779	1,779
Oilbelt Services Limited	136	269
Total intercompany payables	16,050	12,731

 

32. Taxation Payable

	2023 $'000	2022 $'000
Taxation payable
PPT	31	4
UL	12	-
	43	4

 

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.

33. Financial Instruments by Category

At 31 December 2023 and 2022, the Group held the following financial assets at amortised cost:

	Group		Company
	2023 $'000	2022 $'000	2023 $'000	2022 $'000
Trade and other receivables - current*	5,199	5,165	-	6
Abandonment fund - non current	4,962	4,511	-	-
Intercompany	-	-	4,567	2,830
Cash and cash equivalents	9,819	12,131	1,194	2,102
	19,980	21,807	5,761	4,938

Note (*): Excludes prepayments and VAT recoverable

At 31 December 2023 and 2022, the Group held the following financial liabilities at amortised cost:

	Group		Company
	2023 $'000	2022 $'000	2023 $'000	2022 $'000
Accounts payable and accruals	8,901	9,932	677	565
Intercompany	-	-	16,050	12,731
Bank overdraft	4,000	2,700	-	-
	12,901	12,632	16,727	13,296

 

At 31 December 2023 and 2022, the Group held no financial liabilities at fair value through profit or loss.

34. 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 28: Provision for other liabilities.

b)            Contingent Liabilities

i)             Parent Company Guarantee:

a)            PGB - 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.

b)            Galeota - A Letter of Guarantee has been established in substance over the Galeota Block where a subsidiary of Trinity is obliged to carry out a Minimum Work Programme to the value of $0.9 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 the subsidiary of Trinity delivers to the Guarantor a certificate duly issued and signed by the Minister of the MEEI. The Letter of Guarantee was effective from 14 July 2021 until the earlier of performance of Minimum Work Programme or the Guarantor has paid the Guarantee amount.

ii)            Jacobin drilling disputed cost: There is a disputed drilling cost of $2.4 million with a supplier in relation to the Jacobin well, where Management has included a provision for $0.5 million which it believes is appropriate based on external advice obtained. $1.9 million is disclosed as a contingent liability.

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 consolidated financial statements.

35. Employee Costs

	Group		Company
	2023 $'000	2022 $'000	2023 $'000	2022 $'000
Employee costs for the Group during the year
Wages and salaries	8,489	7,245	432	483
Other pension costs	467	425	70	-
Share based payment expense	528	647	41	107
	9,484	8,317	543	590

 

Average monthly number of people

(including Executive and Non-Executive Directors') employed by the Group

	2023 number	2022 number	2023 number	2022 number
Executive and Non-Executive Directors	5	6	6	6
Administrative staff	107	102	-	-
Operational staff	170	168	-	-
	282	276	6	6

 

36. Events after the Reporting Period

1.    Subsequent to 31 December 2023, the Group received VAT refunds of USD 0.8 million. As at 22 May 2024, the Group had USD 5.1 million in VAT refunds recoverable.

2.    On 13 June 2023, Trinity announced its successful bid for the onshore Buenos Ayres block. Subsequent to 31 December 2023, the Group is awaiting finalisation of the exploration and production licence with the MEEI.

3.    Fiscal reforms (Finance Act) - Effective 1 January 2024, SPT rates for Small Shallow Marine Area Producers were introduced. It becomes applicable when the weighted average realised crude oil price exceeds US$75/bbl, starting at a rate of 18% and goes up to 40% depending on the price.

A Small Shallow Marine Area Producer is defined as a person who carries out petroleum operations in shallow marine areas under a licence, sub-licence or contract and produces less than 4,000 barrels of crude oil per day.

4.    On 1 May 2024, the board of directors of each of Touchstone and Trinity announced that they have reached an agreement on the terms of a recommended all share offer pursuant to which Touchstone will acquire the entire issued and to be issued ordinary share capital of Trinity (the "Acquisition"). The Acquisition is to be effected by means of a scheme of arrangement under Part 26 of the Companies Act. Under the terms of the Acquisition, Trinity Shareholders shall be entitled to receive 1.5 New Touchstone Shares. Further information on the transaction can be found on our website at https://trinityexploration.com/.