Trinity Exploration - Full Year Results to 31 December 2023
23/05/2024 11:45
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RNS Number : 5747P Trinity Exploration & Production 23 May 2024
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 Profit(1) 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 Via Vigo Consulting
Jeremy Bridglalsingh, Chief Executive Officer
Julian Kennedy, Chief Financial Officer
Nick Clayton, Non- Executive Chairman
SPARK Advisory Partners Limited +44 (0)20 3368 3550
(Nominated Adviser)
Mark Brady
James Keeshan
Cavendish Capital Markets Limited (Broker) +44 (0)20 7397 8900
Leif Powis +44 (0)131 220 6939
Derrick Lee
Neil McDonald
Vigo Consulting Limited trinity@vigoconsulting.com (mailto:trinity@vigoconsulting.com)
Finlay Thomson +44 (0)20 7390 0230
Patrick d'Ancona
About Trinity (www.trinityexploration.com (http://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 Sales 2023
(Net WI bopd) (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 31-Dec-2023
2P Reserves 2P Reserves
and 2C Resources Production Revisions 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 price(1) USD/bbl 68.6 84.9 (19)
Average net production(2) 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 Taxes(7) 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-even(8) USD/bbl 38.3 32.1 19
Net cash plus working capital surplus(9) 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 - Consolidated(1) USD/bbl 5.1 4.3 6.3 6.6 7.2
Operating Break-Even(2)
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
Consolidated(3) 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 FY 2020 FY 2021 FY 2022 FY 2023
Audited Audited Audited Audited 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/
(https://trinityexploration.com/) .
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2023
(Expressed in United States Dollars) Note 2023 2022
$'000 $'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 2022
$'000 $'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 2022
$'000 $'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
Share Based Payment Reserve Reverse Acquisition Reserve Treasury Shares Translation Reserve Retained Earnings
Share Capital $'000 $'000 $'000 $'000 $'000 Total Equity
Year ended 31 December 2022 $'000 $'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
Share Based Payment Reserve Merger Reserves Treasury Shares Retained Earnings
Share Capital $'000 $'000 $'000 $'000 Total Equity
Year ended 31 December 2022 $'000 $'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 2022
$'000 $'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
2023 2022
(Expressed in United States Dollars) Note $'000 $'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 2022
$'000 $'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 2022
$'000 $'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 1 to 2 years 2 to 5 years Total
$'000 $'000 $'000 $'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 Total
$'000 $'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 2022
$'000 $'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: Consolidated Statement of Comprehensive Income/Expense
Obligation 2023
2023 $'000
$'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 2022
$'000 $'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 2022
$'000 $'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 31 December
2023 2022
$'000 $'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 31 December
2023 2022
$'000 $'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 31 December
2023 2022
$'000 $'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 2022
$'000 $'000
Finance income
Interest Income 50 48
2023 2022
$'000 $'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 2022
$'000 $'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 2022
$'000 $'000
Loss/ (Profit) before taxation (9,529) 2,457
Tax calculated at domestic tax rates applicable to profits in the respective (3,101) 4,836
countries
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.
(Loss)/Profit for the year Weighted Average Number Earnings Per
$'000 of Shares Share
Year ended 31 December 2023 '000 $
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 2022
$'000 $'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, Holding Company 99.99998%
LS1 5AB, UK
Trinity Exploration & Production (UK) Limited 13 Queen's Road, Aberdeen, Holding Company 100%
AB15 4YL, UK
Trinity Exploration and Production Services (UK) Limited c/o Pinsent Masons LLP, 1 Park Row, Leeds, Service Company 100%
LS1 5AB, UK
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, Holding Company 100%
40-44 Sutton Street,
San Fernando, Trinidad & Tobago ("Trinidad address")
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, Employee Benefit Trust 100%
LS1 5AB, UK
13. Property, Plant and Equipment
Plant & Equipment Leasehold & Buildings Oil & Gas Assets Total
Year ended 31 December 2023 $'000 $'000 $'000 $'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
Plant & Equipment Leasehold & Buildings Oil & Gas Assets Total
Year ended 31 December 2022 $'000 $'000 $'000 $'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 31 December
2023 2022
$'000 $'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 2022
$'000 $'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:
Exploration and Evaluation assets Computer software Research and Development Total
Year ended 31 December 2023 $'000 $'000 $'000 $'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
Exploration and Evaluation assets Computer software Research and Development Total
Year ended 31 December 2022 $'000 $'000 $'000 $'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 2022
$'000 $'000
At 1 January 4,511 4,021
Additions 451 490
At 31 December 4,962 4,511
17. Performance bond
2023 2022
$'000 $'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 2022
$'000 $'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 2022
$'000 $'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 Movement 2022 Movement 2023
$'000 $'000 $'000 $'000 $'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 Movement 2022 Movement 2023
$'000 $'000 $'000 $'000 $'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 Materials and Total
$'000 supplies $'000
$'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 2022 2023 2022
$'000 $'000 $'000 $'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 2022
$'000 $'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 2022 2023 2022
$'000 $'000 $'000 $'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 2022 2023 2022
$'000 $'000 $'000 $'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 As at 31 December
2023 2022
$'000 $'000
Dividend declared 236
Dividend paid (231) -
Dividend payable 5 -
22. Cash and Cash Equivalents
Group Company
2023 2022 2023 2022
$'000 $'000 $'000 $'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 Share premium Total
$'000 $'000 $'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 Total
$'000 $'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 2022
$'000 $'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
Exercise price per Share Options Exercise price per Share Options
Number of Options Number of Share Options
Grant-Vest Expiry Date
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 2022 Average exercise price per Share Option
Number of Options 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)
Granted(1) 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 Merger Reserve
$'000 $'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 2022
$'000 $'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 2022
$'000 $'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:
Decommissioning Closure of pits Total
Year ended 31 December 2022 provision $'000 $'000
$'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:
Litigation claims Other provisions Total
Year ended 31 December 2023 $'000 $'000 $'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
2023 2022 2023 2022
Current $'000 $'000 $'000 $'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 31 December
2023 2022
$'000 $'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 2022
$'000 $'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 2022
$'000 $'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 2022
$'000 $'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 2022
$'000 $'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 2022
$'000 $'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 2022
$'000 $'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 2022 2023 2022
$'000 $'000 $'000 $'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 2022 2023 2022
$'000 $'000 $'000 $'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 2022 2023 2022
$'000 $'000 $'000 $'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 2022 2023 2022
number number number 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/.
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