This announcement contains
inside information as stipulated under the UK version of the Market
Abuse Regulation No 596/2014 which is part of English Law by virtue
of the European (Withdrawal) Act 2018, as amended. On
publication of this announcement via a Regulatory Information
Service, this information is considered to be in the public
domain.
23 May 2024
Trinity Exploration &
Production plc
("Trinity" or "the Group" or
"the Company")
Full Year Results to 31
December 2023
Trinity Exploration &
Production plc (AIM: TRIN), the independent E&P company focused
on Trinidad and Tobago, announces its
final results for the year ended 31 December 2023 ("the Period" or
"FY 2023").
2023 was an important year for
Trinity with key developments in our ambitious growth programme
being progressed:
·
The Company drilled the Jacobin well to test
deeper prospectivity in the Lower Cruse Miocene-age turbidite play in our
core onshore Palo Seco acreage. While the well discovered oil
in those deeper horizons, flow rates were disappointing, and
drilling complexities resulted in significant cost
overruns. Management conservatively
decided to write off the entire cost of the well in the year end
accounts. The well has successfully
been completed in the Lower Forest horizon and production is
expected to commence from this zone shortly.
·
In June, the Company was advised by the Ministry
of Energy and Energy Industries ("MEEI") that it had been
successful in its bid for the Buenos Ayres block in the 2022
Onshore and Nearshore Competitive Bid Round, immediately to the
west of our core Palo Seco acreage. Buenos Ayres is undrilled
and offers considerable potential. Finalisation of the awards
of all of the blocks awarded in the bid round are expected
shortly.
·
The ABM-151 well in the Brighton Marine block,
offshore the West Coast of Trinidad, was returned to production on
21 March 2023 following an extensive refurbishment of surface
facilities and the installation of remote surveillance
technology. Between restart and the end of the year the well
flowed at an average rate of 122 bopd, exceeding
expectations.
·
At Galeota, following an extensive
Concept-Screening study completed by Petrofac in Q3 2023, Trinity
identified a revised infrastructure-led development solution which
includes an initial phase of development drilling from existing
platforms. Whilst Trinity believes the revised development solution
will significantly reduce capital requirement prior to first oil
compared to the Echo Field Development Plan, Trinity would need to
secure third party financing to take a final investment decision
and fund the development.
The fire on the Bravo platform in
the Trintes field, represented a significant event for the Company
with valuable lessons learned arising from a comprehensive
investigation with an associated corrective actions register.
A number of safety improvements have been implemented to date,
including those that mitigate the root cause for the fire and
improved fire-fighting capabilities in the event of a similar
incident.
The Company completed a share
buyback programme which commenced on 24 October 2022 and
ended on 27 June 2023, having repurchased 1,549,000
shares on the open market for a total cost of USD 2.1 million and Trinity paid its
first interim dividend of 0.5 pence per ordinary share on 26
October 2023.
James Menzies has decided not to
stand for re-election at this forthcoming Annual General Meeting
which coincides with James taking on greater levels of
responsibility in other roles outside of Trinity. The Board
expresses its thanks to James for his contribution to the Board
since joining in 2017.
On 1 May 2024, the boards of
directors of Trinity and Touchstone
Exploration Inc ("Touchstone")
announced the terms of the recommended all share
offer (the "Acquisition"). The Acquisition is to be effected
by means of a scheme of arrangement under Part 26 of the Companies
Act. Under the terms of the Acquisition, Trinity Shareholders
shall be entitled to receive 1.5 New Touchstone Shares for each
Trinity share. Should the Scheme be approved by
Shareholders and sanctioned by the Court, Trinity has an exciting
future as part of the enlarged Touchstone organisation.
Highlights
·
Group net sales for 2023 were 2,790 bopd (2022:
2,975 bopd)
·
Revenues of USD 69.8 million (2022: USD 92.2
million)
·
Loss before tax of USD (9.5) million (2022:
Profit USD 2.5 million)
·
Average price per barrel received was USD
68.6/bbl (2022: USD 84.9/bbl)
·
Adjusted EBITDA (before hedge costs)
of USD 19.2 million (2022: USD 35.1
million)
·
Adjusted EBITDA of USD 19.2 million (2022: USD
24.7 million)
·
Operating Profit1 of USD 9.6million
(2022: USD 19.0 million)
·
Cash generated from continuing operations USD
13.2 million (2022: USD 12.0 million)
·
Cash flow used in investing activities USD 15.4
million (2022: USD 15.6 million)
·
Year-end cash USD 9.8 million (2022: USD 12.1
million)
Note:
1 Before SPT, Impairments and Exceptional
Items
- Ends -
Enquiries:
Trinity Exploration & Production plc
Jeremy Bridglalsingh, Chief
Executive Officer
Julian Kennedy, Chief Financial
Officer
Nick Clayton, Non- Executive
Chairman
|
Via Vigo Consulting
|
|
|
SPARK Advisory Partners Limited
(Nominated Adviser)
Mark Brady
James Keeshan
|
+44 (0)20 3368 3550
|
|
|
Cavendish Capital Markets Limited (Broker)
Leif Powis
Derrick Lee
Neil McDonald
|
+44 (0)20 7397 8900
+44 (0)131 220 6939
|
|
|
Vigo Consulting Limited
Finlay Thomson
Patrick d'Ancona
|
trinity@vigoconsulting.com
+44 (0)20 7390
0230
|
About Trinity (www.trinityexploration.com)
Trinity is an independent oil
production company focused solely on Trinidad and Tobago. Trinity
operates producing and development assets both onshore and
offshore, in the shallow water West and East Coasts of
Trinidad. Trinity's portfolio includes current production,
significant near-term production growth opportunities from low-risk
developments and multiple exploration prospects with the potential
to deliver meaningful reserves/resources growth. The Company
operates all of its licences and, across all of the Group's assets,
management's estimate of the Group's 2P reserves as at the end of
2023 was 12.91 mmstb. Group 2C contingent resources are
estimated to be 38.68 mmstb. The Group's overall 2P plus 2C
volumes are therefore 51.58 mmstb.
Trinity is quoted on AIM, a market
operated and regulated by the London Stock Exchange Plc, under the
ticker TRIN.
Qualified Person's Statement
The technical information
contained in the announcement has been reviewed and approved by
Mark Kingsley, Trinity's Chief Operating Officer. Mark
Kingsley (BSc (Hons) Chemical Engineering, Birmingham University)
has over 35 years of experience in international oil and gas
exploration, development and production and is a Chartered
Engineer.
Disclaimer
This document contains certain
forward-looking statements that are subject to the usual risk
factors and uncertainties associated with the oil exploration and
production business. Whilst the Group believes the
expectation reflected herein to be reasonable in light of the
information available to it at this time, the actual outcome may be
materially different owing to macroeconomic factors either beyond
the Group's control or otherwise within the Group's
control.
Chair & CEO Statement
Dear shareholders,
2023 was an important year for
Trinity with key developments in our ambitious growth programme
being progressed. The Company drilled the Jacobin well in the year
to test deeper prospectivity in the Lower Cruse horizons in our
core Palo Seco acreage. While the well discovered oil in those
deeper horizons, flow rates were disappointing, and drilling
complexities resulted in significant cost overruns. The results
from the well are being incorporated into further understanding the
"Hummingbird" play with independent features still offering future
potential as well as the prospectivity of the exploration block,
Buenos Ayres. In June, the Company was advised by the Ministry of
Energy and Energy Industries ("MEEI") that it had been successful
in its bid for the Buenos Ayres block in the 2022 Onshore and
Nearshore Competitive Bid Round, immediately to the west of our
core Palo Seco acreage. Buenos Ayres is undrilled and offers
considerable potential.
The ABM-151 well in the Brighton
Marine block, offshore the West Coast of Trinidad, was returned to
production on 21 March 2023 following an extensive refurbishment of
surface facilities and the installation of remote surveillance
technology. Between restart and the end of the year the well flowed
at an average rate of 122 bopd, exceeding expectations.
Group net sales for 2023 were 2,790
bopd (2022: 2,975 bopd). Trinity managed to substantially mitigate
natural production decline through a programme including six well
recompletions ("RCPs"), 98 workovers and swabbing across its asset
base. The fire on the Bravo platform in the Trintes field,
represented a significant event for the company with valuable
lessons learned arising from a comprehensive investigation with an
associated corrective actions register. A number of safety
improvements have been implemented to date, including those that
mitigate the root cause for the fire and improved fire-fighting
capabilities in the event of a similar incident.
At Galeota, following an extensive
Concept-Screening study completed by Petrofac in Q3 2023, Trinity
identified a revised infrastructure-led development solution which
includes an initial phase of development drilling from existing
platforms. Whilst Trinity believes the revised development solution
will significantly reduce capital requirement prior to first oil
compared to the Echo Field Development Plan, Trinity would need to
secure third party financing to take a final investment decision
and fund the development.
In parallel to progressing the
Galeota asset development plan project, Trinity assembled a
pipeline of investment projects including brownfield development
opportunities at the West Coast and onshore assets and a portfolio
of exploration prospects across Trinity's Palo Seco assets. Trinity
believes that significant capital investment, both debt and equity,
will be required to realise the potential of the Company's
portfolio.
Our 2023 financial results
demonstrate the Company's resilience. Adjusted EBITDA for the year
was USD 19.2 million (2022: USD 24.7 million) and cash resources
were USD 9.8 million (2022: USD 12.1 million) at year-end. The
Company completed a share buyback programme which commenced on 24
October 2022 and ended on 27 June 2023, having repurchased
1,549,000 shares on the open market for a total cost of USD 2.1
million. These shares are held in treasury and are used to settle
options exercised. Trinity paid its first interim dividend of 0.5
pence per ordinary share on 26 October 2023.
Angus Winther, having joined the
Board in 2017 and completed two full terms as a Non-Executive
Director and Chair of the Audit Committee, retired from the Board
by rotation in June. In August, we welcomed Jon Cooper as an
Independent Non-Executive Director, and the new Chair of the Audit
Committee, and Julian Kennedy as an Executive Director, taking on
the role of Chief Financial Officer, to the Board. James Menzies
has decided not to stand for re-election at this forthcoming Annual
General Meeting which coincides with James taking on greater levels
of responsibility in other roles outside of Trinity. We want to
express our thanks and that of our fellow Directors for his
contribution to the Board since joining in 2017. The management
team was strengthened by the addition in April 2023 of Mark
Kingsley as Chief Operating Officer and in November 2023 of Aida
Shafina Abu Bakar as Executive Manager, Subsurface.
It became clear during 2023 that the
Group would require new capital to fund its portfolio of
development opportunities. In October 2023, the Company engaged a
financial adviser, Houlihan Lokey, to assist in exploring strategic
and financing alternatives for the Company. On 23 November 2023,
Trinity received an unsolicited, conditional non-binding proposal
to acquire the issued and to be issued share capital of Trinity
from Touchstone Exploration Inc ("Touchstone") and following the
execution of a confidentiality agreement, Touchstone was provided
access to due diligence information.
On 1 May 2024, following a period of
due diligence and negotiation, the boards of directors of Trinity
and Touchstone announced the terms of the recommended all share
offer (the "Acquisition"). The Acquisition is to be effected by
means of a scheme of arrangement under Part 26 of the Companies
Act. Under the terms of the Acquisition, Trinity Shareholders shall
be entitled to receive 1.5 New Touchstone Shares for each Trinity
share. Should the Scheme be approved by Shareholders and sanctioned
by the Court, we believe Trinity has an exciting future as part of
the enlarged Touchstone organisation.
During what has been an exciting but
also challenging period, we would like to thank our staff, the
Board and our advisors for their continuing hard work during a
particularly busy time for the Company.
Nicholas
Clayton
Jeremy Bridglalsingh
Non-Executive
Chair
Chief Executive Officer
Operations Review
The Group achieved net sales of
2,790 bopd in 2023 (2022: 2,975 bopd) despite no development
drilling (2022 three development wells) and six RCPs, (2022 17
RCPs) combined with operational challenges in the East Coast Asset.
Investments into production-related activities, such as RCPs, ABM
151 reactivation, production maintenance workovers and swabbing
enabled the Company to deliver annual production decline of 6%,
below the expected natural field decline range of 7% to
10%.
2023 vs 2022 Annual Sales Breakdown
Sales
2022
(Net WI
bopd)
|
|
|
Sales
2023
(Net WI
bopd)
|
|
|
|
Assets
|
Annual
|
Annual
|
H1
|
H2
|
Q1
|
Q2
|
Q3
|
Q4
|
WD13
|
109
|
91
|
92
|
89
|
97
|
88
|
78
|
99
|
WD14
|
100
|
93
|
97
|
88
|
99
|
96
|
87
|
88
|
WD2
|
258
|
208
|
224
|
193
|
241
|
206
|
196
|
191
|
WD5/6
|
1,004
|
941
|
935
|
946
|
940
|
930
|
974
|
918
|
PS4
|
62
|
56
|
54
|
59
|
60
|
48
|
49
|
69
|
FZ2
|
118
|
106
|
110
|
103
|
111
|
109
|
109
|
97
|
TAB
|
4
|
|
|
|
|
|
|
|
Onshore
|
1,655
|
1,495
|
1,512
|
1,478
|
1,548
|
1,477
|
1,493
|
1,462
|
TRINTES
|
1,051
|
943
|
1,011
|
876
|
1,038
|
985
|
843
|
908
|
East Coast
|
1,051
|
943
|
1,011
|
876
|
1,038
|
985
|
843
|
908
|
BRIGHTON
|
158
|
246
|
230
|
263
|
204
|
255
|
268
|
258
|
PGB
|
111
|
107
|
108
|
105
|
110
|
107
|
102
|
107
|
West Coast
|
269
|
353
|
338
|
368
|
314
|
362
|
370
|
365
|
TOTAL
|
2,975
|
2,790
|
2,861
|
2,721
|
2,899
|
2,824
|
2,705
|
2,736
|
Note TAB was relinquished on 29
September 2023
Onshore Assets
Trinity's onshore assets comprise the lease operatorship
("LO") blocks: WD-5/6, WD-2 and PS-4 (together "Palo Seco") and
FZ-2, WD-13, WD-14 (together "Forest Reserve").
Onshore average net sales for 2023
were 1,495 bopd (2022: 1,654 bopd) accounting for approximately 54%
of the Group's total annual sales.
Average sales declined by
approximately 10% between 2022 and 2023 due to wells drilled in H2
2022 accentuating the decline. Trinity successfully completed six
RCPs (2022: 17) and ninety-eight workovers (2022: 87), which
contributed to the maintenance of the industry standard decline of
between 7-10% for brownfields. In WD-2, the asset experienced a
higher-than-expected decline due to increased water production in
one well (PS 570) and declining production in the naturally flowing
well (PS 571).
In 2024, Trinity intends to manage
its base production through further RCP activity, implementation of
recommendations from the re-evaluation of the inactive well hopper,
and swabbing. Trinity's use of automation to optimise production
and costs continues to meet our objectives.
The Jacobin well, 1PS 1524ST3, was
drilled to a total depth of 10,021 ft. Geologically, the well
intersected stacked pay potential across the PS4 block in both the
development and exploration sections of the well. However,
reservoir properties in the exploration section were poorer than
predicted and, as such, post-drill volumes for the exploration
section were below the lower end of the predicted ranges. The rapid
decline in reservoir pressures suggests reservoir boundaries are
much closer than pre-drill estimates.
The total well cost was USD 9.6
million. An impairment assessment was done on this well, triggered
by poorer than expected results and higher costs incurred, the
entire Jacobin costs was written off.
Data acquired from the well will be
incorporated into our regional model to de-risk and re-prioritise
future drilling candidates across our Palo Seco LOs and Buenos
Ayres.
Trinity has embarked on an idle well
study, with the initial phase including technical reviews of circa
250 wells, with field investigations having commenced on the first
30 of these, which as a result has added more wells to the swabbing
program.
East Coast Assets
Current East Coast production is generated from the Alpha,
Bravo and Delta platforms in the Trintes field located in the
Galeota block.
Average net sales for 2023 from the
East Coast were 943 bopd (2022: 1,051 bopd) which accounts for
approximately 34% of Group sales for the year. A total of 22
workovers in 2023 (2022: 23) were conducted across the assets
focusing on optimising and stabilising production from all wells
via a data-driven strategy utilising automation. Chemical injection
initiatives were also deployed to counteract increased solids
deposition in mature wells.
Average sales declined by
approximately 10% between 2022 and 2023 due to two main events: the
Bravo platform fire in April; and the lower performance of the D9
well, the largest producer in the Trintes field.
The Galeota licence has significant
growth potential from undeveloped reserves and resources in the
Trintes field and broader development of the Galeota block,
including exploration potential.
In July 2023, Trinity initiated a
review of the approved Field Development Plan ("FDP") for the TGAL
Echo development to reduce capital expenditure, reduce time to
first oil and improve financial returns; a new development
strategy- concept being created envisaging the use of a mobile
operation and production unit ("MOPU").
Trinity appointed Petrofac to
undertake a Concept- Screening study for the development of further
reserves. This study created a more holistic approach to block
development whereby Phase 1 involved drilling horizontal infill
wells in Trintes to demonstrate that such wells can be successfully
drilled and produced as to date they have not been attempted. Phase
2 then took the learnings from Trintes infill drilling to drill and
produce horizontal wells in the TGAL area from a lightweight
structure tied back to a leased MOPU. This concept replaces CAPEX
with OPEX in the form of lease rate payments and appears - based on
screening cost estimates to date - to improve the overall economics
of the project materially. This work is progressing with the
revision and update of the subsurface studies in 2024.
West Coast Assets
West Coast production is generated from the Point
Ligoure-Guapo Bay-Brighton Marine ("PGB") and Brighton Marine
("BM") licence areas.
West Coast net sales averaged 353
bopd in 2023 (2022: 269 bopd) which accounted for approximately 13%
of the Group's total annual average sales. This was a 31% year on
year increase on the 2022 average. The increase was mainly due to
the successful execution of the ABM 151 reactivation project. After
placing the well on production, ABM 151 produced at a higher
initial rate than expected and maintained a lower decline rate than
predicted. A total of five workovers in 2023 (2022: 10) were
conducted across the assets. There was increased focus on swabbing
both on land as well as the introduction of an additional offshore
swabbing unit which also assisted in increasing production
volumes.
Facilities Management and Infrastructure
In 2023, the Facilities team focused
on asset integrity, welfare initiatives and projects supporting
production.
On Trintes, the Company continued
replacing and installing planks and gratings on offshore platform
production decks and improved key electrical equipment on the
Alpha, Bravo and Delta platforms, for better use of the available
space. Automated Tank controls were also introduced.
The construction of a new 10,000 bbl
sales tank to accommodate production from the Trintes field was
completed in 2023. In 2024 the tank was certified and put into
service.
Remedial work following the Trintes
Bravo generator fire was completed and upgrades to the safety
systems were implemented. This includes upgraded fire suppression
systems, replacement of all six generator units (Q1 2024 completed)
and introduction of emergency escape systems and advanced
fire-fighting training. The automated systems on all of the Trintes
platforms were also upgraded with additional redundancy.
Onshore and West Coast operations
focused on upgrading welfare facilities, electrical systems as well
as oil storage tanks.
The project and maintenance team was
reorganised with the introduction of a dedicated maintenance team.
This team will focus on fabric maintenance and rotating equipment.
In total, the team progressed 22 projects of which 18 were
completed by end of 2023 and four rolled over into 2024.
Facilities Management and
Infrastructure capex in 2023 was USD 4.1 million (2022 USD 4.5
million).
During 2023 a review of the
decommissioning methodology and cost estimates were undertaken.
This led to a reduction in well abandonment cost estimates and the
overall decommissioning provision to USD 44.4 million (2022: 51.9
million).
Reserves and Resources
A comprehensive reserves and
resources review of all assets has been completed by Management and
the technical work underpinning this management estimate was
reviewed by Netherland, Sewell & Associates, Inc which
estimates Trinity's current 2P reserves to be 12.91 mmstb at the
end of 2023, compared to the year-end 2022 reserve estimate of
17.96 mmstb. This represents a 28% year-on-year decrease. The
largest reduction in 2P Reserves at Year-End 2023 is from wells
that were categorised as economic 2P Reserves at Year-End 2022
which have been reclassified to 2C Resources due to individual
opportunities being considered uneconomic at the date of review.
Additional reductions are due to the impact of earlier economic
limit truncations and revisions to the Trintes Infill well
programme.
The 2C Resources at the end of 2023
are estimated at 38.68 mmstb compared to the end of 2022 resource
estimate of 48.88 mmstb. The reduction in 2C Resources is
attributed largely to the East Coast block based on the latest
interpretation and mapping of reprocessed seismic data which
resulted in a view that the field structure is more steeply dipping
than in previous interpretations. The Year-End 2023 total 2C for
East Coast is 31.3 mmstb (compared to 36.8 mmstb previously). While
the 2C Resource estimate for East Coast has been reduced, the
impact on the development and exploration plans for the field is
minimal.
Management considers the reserves
presented in the table below to be its best estimate as at 31
December 2023 of the quantity of reserves that can be recovered
from Trinity's current assets. It includes forecast production,
which is commercially recoverable, either to licence/ relevant
permitted extension end or earlier via the application of the
economic limit test. The subsurface review has defined investment
programmes and constituent drilling targets to commercialise these
reserves as detailed by asset area shown in the table.
2023 2P
Reserves
|
31-Dec-22
|
Production
|
Revisions
|
31-Dec-23
|
Net Oil
Reserves
|
mmstb
|
mmstb
|
mmstb
|
mmstb
|
Asset
|
|
|
|
|
Onshore
|
6.53
|
(0.55)
|
(1.72)
|
4.26
|
West
Coast
|
2.17
|
(0.13)
|
(1.18)
|
0.86
|
East
Coast
|
9.26
|
(0.34)
|
(1.14)
|
7.78
|
Total
|
17.96
|
(1.02)
|
(4.03)
|
12.91
|
2023 2C
Resources
|
|
31-Dec-22
|
Production
|
Revisions
|
31-Dec-23
|
Net Oil
Resources
|
mmstb
|
mmstb
|
mmstb
|
mmstb
|
Asset
|
|
|
|
|
Onshore
|
8.62
|
N/A
|
(4.88)
|
3.74
|
West
Coast
|
3.45
|
N/A
|
0.18
|
3.63
|
East
Coast
|
36.81
|
N/A
|
(5.50)
|
31.31
|
Total
|
48.88
|
N/A
|
(10.20)
|
38.68
|
2023 Reserves and
Resources
|
|
31-Dec-2022
2P
Reserves
and 2C
Resources
|
Production
|
Revisions
|
31-Dec-2023
2P
Reserves
and 2C
Resources
|
|
mmstb
|
mmstb
|
mmstb
|
mmstb
|
Asset
|
|
|
|
|
Onshore
|
15.15
|
(0.55)
|
(6.60)
|
8.00
|
West
Coast
|
5.62
|
(0.13)
|
(1.00)
|
4.49
|
East
Coast
|
46.07
|
(0.34)
|
(6.64)
|
39.09
|
Total
|
66.84
|
(1.02)
|
(14.24)
|
51.58
|
2P Reserves Note:
The 2023 produced volume of 1.02
mmstb accounts for 20% of the overall 2P decrease in 2023 compared
to 2022. Other revisions contributing to the overall decrease
are:
· (0.38) mmstb from PS4 and Tabaquite Revision
· mmstb from Base Revisions
· (0.22) mmstb from RCP Revisions
· (2.34) mmstb from Infill Well Revisions
2C Resources Note:
Revisions contributing to the
overall decrease are:
· (4.90) mmstb from Appraisal Wells Revisions
(Onshore)
· (8.33) mmstb from TGAL Revision and 2.83 mmstb (Trintes) from
re-categorisation and ELT
Financial Review
KPIs
During 2023 the Group saw lower
realised oil prices compared with 2022. A combination of lower oil
price, a six percent reduction in net production and an increase
operating break-even resulted in Adjusted EBITDA (before hedge
costs) decreasing by USD 15.9 million to USD 19.2 million (2022:
USD 35.1 million). The Group delivered a resilient operating
performance as shown by its positive Adjusted EBITDA margin (after
hedge costs) of 28.1% (2022: 26.8%) and IFRS Operating Profit
before SPT of USD 9.6 million (2022: USD 19.0 million) despite a
19% decrease in realised oil price.
A summary of the year-on-year
operational and financial highlights are set out below:
|
|
FY
2023
|
FY
2022
|
Change
%
|
Average realised
oil price1
|
USD/bbl
|
68.6
|
84.9
|
(19)
|
Average net
production2
|
bopd
|
2,790
|
2,975
|
(6)
|
Revenues
|
USD
million
|
69.8
|
92.2
|
(24)
|
Cash
balance
|
USD
million
|
9.8
|
12.1
|
(19)
|
IFRS
Results
|
|
|
|
|
Operating Profit
before SPT
|
USD
million
|
9.6
|
19.0
|
(49)
|
Total
Comprehensive (loss)/income for the year
|
USD
million
|
(6.8)
|
0.1
|
(7,415)
|
Earnings Per Share
- Diluted
|
USD
cents
|
0.0
|
0.0
|
(100)
|
APM
Results
|
|
|
|
|
Adjusted EBITDA
(before hedge costs)3
|
USD
million
|
19.2
|
35.1
|
(45)
|
Adjusted EBITDA
(after hedge costs)4
|
USD
million
|
19.2
|
24.7
|
(22)
|
Adjusted EBITDA
(after hedge costs)5
|
USD/bbl
|
18.9
|
22.7
|
(17)
|
Adjusted EBITDA
margin (after hedge costs)6
|
%
|
27.5
|
26.8
|
3
|
Adjusted EBIDA
after Current Taxes7
|
USD
million
|
12.9
|
12.3
|
5
|
Adjusted EBIDA
after Current Taxes Per Share - Diluted
|
US
cents
|
32.3
|
30.6
|
5
|
Consolidated
operating break-even8
|
USD/bbl
|
38.3
|
32.1
|
19
|
Net cash plus
working capital surplus9
|
USD
million
|
8.6
|
14.2
|
(39)
|
Notes:
1.
Average realised price (USD/bbl): Actual price received for crude
oil sales per barrel ("bbl").
2.
Average net production (bopd): Production sold in barrels per day
in a given year.
3.
Adjusted EBITDA (before hedge) (USD MM): Adjusted EBITDA for the
period, before Derivative expense.
4.
Adjusted EBITDA (USD MM): Operating Profit before Taxes for the
period, adjusted for non-cash DD&A, SOE, ILFA, FX gain/(loss)
and Fair Value Gains/Losses on Derivative Financial
Instruments.
5.
Adjusted EBITDA (USD/bbl): Adjusted EBITDA/Annual sales
volume.
6.
Adjusted EBITDA margin (%): Adjusted EBITDA/Revenues.
7.
Adjusted EBIDA after Current Taxes: Adjusted EBIDA less
Supplemental Petroleum Taxes ("SPT"), Petroleum Profits Tax ("PPT")
and Unemployment Levy ("UL").
8.
Consolidated operating break-even: The realised price/bbl where the
Adjusted EBITDA/bbl for the Group is equal to zero.
9.
Net cash plus working capital surplus: Current Assets less Current
Liabilities (other than Derivative financial asset / liability and
Provision for other liabilities).
See Note 27 to Consolidated
Financial Statements - Adjusted EBITDA for further
details.
2023 Trading Summary
A five-year historical summary of
realised price, sales, operating break-even, Royalties, Production
Costs ("Opex") and General & Administrative ("G&A")
expenditure metrics is set out below.
|
|
2019
|
2020
|
2021
|
2022
|
2023
|
Realised
Price
|
USD/bbl
|
58.1
|
37.7
|
60.4
|
84.
9
|
68.6
|
Sales
|
|
|
|
|
|
|
Onshore
|
bopd
|
1,616
|
1,793
|
1,644
|
1,655
|
1,495
|
West
Coast
|
bopd
|
185
|
245
|
255
|
269
|
353
|
East
Coast
|
bopd
|
1,208
|
1,188
|
1,107
|
1,051
|
943
|
Consolidated
|
bopd
|
3,007
|
3,226
|
3,006
|
2,975
|
2,790
|
Metrics
|
|
|
|
|
|
|
Royalties/bbl -
Onshore
|
USD/bbl
|
22.3
|
11.5
|
22.6
|
35.9
|
26.8
|
Royalties/bbl -
West Coast
|
USD/bbl
|
10.0
|
6.1
|
11.1
|
15.8
|
12.7
|
Royalties/bbl -
East Coast
|
USD/bbl
|
14.1
|
8.3
|
13.0
|
17.9
|
13.3
|
Royalties/bbl -
Consolidated
|
USD/bbl
|
10.7
|
9.9
|
18.1
|
27.7
|
20.5
|
Opex/bbl -
Onshore
|
USD/bbl
|
12.1
|
12.2
|
14.4
|
17.0
|
20.6
|
Opex/bbl - West
Coast
|
USD/bbl
|
26.9
|
20.3
|
26.2
|
30.7
|
30.1
|
Opex/bbl - East
Coast
|
USD/bbl
|
17.1
|
16.5
|
18.3
|
23.2
|
30.1
|
Opex/bbl -
Consolidated
|
USD/bbl
|
14.9
|
14.0
|
16.0
|
17.7
|
22.0
|
G&A/bbl -
Consolidated1
|
USD/bbl
|
5.1
|
4.3
|
6.3
|
6.6
|
7.2
|
Operating
Break-Even2
|
|
|
|
|
|
|
Onshore
|
USD/bbl
|
16.4
|
16.5
|
19.0
|
19.2
|
23.9
|
West
Coast
|
USD/bbl
|
32.4
|
24.6
|
32.2
|
31.8
|
31.8
|
East
Coast
|
USD/bbl
|
21.9
|
21.0
|
23.2
|
24.4
|
31.7
|
Consolidated3
|
USD/bbl
|
26.4
|
20.1
|
29.2
|
32.1
|
38.3
|
Notes
1.
G&A/bbl - Consolidated: Excludes SOE, ILFA, Derivative FV
gain/loss and FX gain/loss.
2.
Operating break-even: The realised price where Adjusted EBITDA
([before hedge]) for the respective asset or the entire Group
(Consolidated) is equal to zero.
3.
Consolidated operating break-even: Includes G&A but excludes
SOE, ILFA, Derivative FV gain/loss and FX gain/loss.
Review of Financial Statements
Trinity and its subsidiaries' ("the
Group") consolidated financial information has been prepared on a
going concern basis, in accordance with International Accounting
Standards ("IAS") as adopted in the United Kingdom. This
consolidated financial information has been prepared under the
historical cost convention, modified for fair values under IFRS.
The Group's accounting policies and details of accounting
judgements and critical accounting estimates are disclosed within
Notes 1 to 3 of the Financial Statements.
Throughout this report, reference is
made to adjusted results and measures. The Board believes that the
selected adjusted measures allow Management and other stakeholders
to better compare the normalised performance of the Group between
the current and prior year, without the effects of one-off or
non-operational items, and better reflects the underlying cash
earnings achieved in the year. In exercising this judgment, the
Board has taken appropriate regard of IAS 1 "Presentation of
financial statements".
In particular, the Alternative
Performance Measure ("APM") measure of Adjusted EBITDA excludes the
impact of Depreciation, Depletion & Amortisation ("DD&A"),
as well as the non-cash impact of Share Option Expense ("SOE"),
Impairment losses on financial assets ("ILFA"), FX gain/loss and
Fair Value Gains/Losses on Derivative Financial Instruments. Each
of these are summarised on the face of the Consolidated Income
Statement as well as being described in Note 21 to the consolidated
financial statements.
Summary of Results for the Year
Lower revenue driven by lower average realised oil price and
sales volume in 2023:
The combined impact of a 19%
decrease in average oil price realisations to USD 68.6/bbl (2022:
USD 84.9/bbl), and a modest 6% decrease in average annual sales
2,790 bopd (2022: 2,975 bopd), resulted in a 24% decrease in
revenues to USD 69.8 million (2022: USD 92.2 million).
Maintained robust operating profits despite inflationary
pressures:
The Group continued to deliver
strong operating profits despite the inflationary pressures on
goods and services. Operating profit before taxes was USD 9.6
million (2022: USD 19.0 million) and consolidated operating
break-even moved up to USD 38.3/bbl (2022: USD 32.1/bbl)
demonstrating the Group's ability to be profitable across a broad
range of oil prices.
Increased capex investment programme to drive
growth:
USD 17.1 million (2022: USD 15.5
million) invested to drive future production growth. This
comprised:
·
USD 9.1 million Exploration and Evaluation
("E&E") asset.
·
USD 5.0 million infrastructure Capex including
facilities (USD 4.1 million) and ICT (USD 0.9 million).
·
USD 1.1 million production capex comprising, 6
RCP's and production equipment (USD 0.2 million) and the ABM-151
reactivation project (USD 0.9 million).
·
USD 1.6 million subsurface costs.
·
USD 0.3 million in Exploration and Evaluation
("E&E") Environmental Impact Assessment (EIA) to the Buenos
Ayres Block.
Refer to Notes to Financial Statements: Note 13 Property,
Plant and Equipment - Additions (USD 6.9 million) and Note 15 -
Intangible Assets - E&E Additions (USD 10.2 million) inclusive
of accruals.
Rebuilding the balance sheet:
The Group's cash balances at year
end were USD 9.8 million (2022: USD 12.1 million), primarily
reflecting positive cash generated from operations of USD 13.2
million, Capex spend of USD (15.4) million and Financing activities
of USD (0.2) million. In aggregate, despite these significant cash
outflows, the Group's net cash plus working capital surplus stood
at USD 8.6 million (2022: USD 14.2 million) and the Group's current
ratio was 1.4x (2022: 2.1x). Elements of spend relating to 2023
activities, principally drilling of the Jacobin well, will be
settled in 2024. The Company is focused on managing its cost base
and activities in 2024 in order to build-back cash on its balance
sheet.
Statement of Comprehensive Income
2023 Financial Highlights
Average realisation of USD 68.6/bbl
(2022: USD 84.9/bbl).
Operating Revenues
Operating revenues down 24% to USD
69.8 million (2022: USD 92.2 million).
Operating expenses
Operating expenses decreased by 18%
in 2023 to USD (60.2) million reflecting a reduction in crude oil
price environment and no hedge costs (2022: USD (73.3) million) and
comprised:
Operating Expenses (excluding non-cash items): USD 50.6
million (2022: (67.6) million):
·
Royalties of USD (20.9) million (2022: USD (30.1)
million), this decrease being driven by lower average realised oil
price and sales production.
·
Opex of USD (22.4) million (2022: USD (19.2)
million), the increase mainly due to inflationary costs on goods
and services seen in increased repairs and maintenance, vessel,
swabbing and workover cost in the year.
·
G&A expenses of USD (7.4) million (2022: USD
(7.2) million), the increase mainly due to comprehensive reserve
review being commenced during the year and build out of the
Management Team net of reduced levies and administrative costs
including professional fees.
·
Derivative expense of nil (2022: Derivative
expense of USD (10.4) million) being the cash impact of derivative
instruments paid out for 2022.
·
Covid 19 expense of nil (2022: USD (0.6) million)
being the costs associated with accommodation, testing and
sanitisation related to our prevention and response.
·
Cash FX loss USD (0.0) million (2022: USD (0.1)
million).
Non-Cash Operating Expenses: USD 9.5 million (2022: USD (5.7)
million):
·
DD&A of USD (8.9) million (2022: USD (7.6)
million).
·
SOE of USD (0.5) million (2022: USD (0.7)
million).
·
ILFA USD (0.1) million (2022: USD 0.0
million).
·
FX loss USD (0.0) million (2022: USD (0.3)
million).
·
Derivative credit of nil (2022: Derivative
expense of USD 2.9 million) being the movement in the FV of
derivative instruments held at the beginning and end of the
financial year.
Operating Profit Before SPT, Impairment, Exceptional Items
and Decommissioning Reduction
The operating profit before SPT,
impairment, exceptional items and decommissioning reduction for the
year amounted to USD 9.6 million (2022: USD 19.0 million) and was
mainly due to lower operating revenues resulting lower oil prices
despite inflationary pressures on cost.
SPT
SPT of USD (5.7) million (2022: USD
(9.0) million) mainly due to lower realised oil prices in relation
to the Group's operations in 2023. Only offshore assets were
subject to SPT in 2023 as the realised oil price throughout the
year was lower than USD 75/bbl.
Operating Profit before Impairment and Exceptional
items
The Group's reported operating
profit before impairment and exceptional items was USD 3.9 million
(2022: USD 10.0 million). Adjusting for non-cash expenses, the
Group's Adjusted EBIDA after Current Taxes was USD 12.9 million
(2022: USD 12.3 million) (further details below).
Impairment charge
Impairment charges taken were USD
(13.5) million (2022: USD (6.1) million) relating to the impairment
of Jacobin E&E well and other E&E costs USD (11.8) million
and property, plant, and equipment USD (1.7) million.
See Note 3(d and e) to Consolidated Financial Statements -
Impairment of Property, Plant and Equipment and Exploration and
Evaluation Assets for further details.
Exceptional items
Exceptional items were USD (0.3)
million cyber incident costs USD (0.2) million (2022: USD (0.2))
and Bravo fire-incident costs USD (0.1) million.
See Note 7 to Consolidated Financial Statements - Exceptional
items for further details.
Decommissioning reduction
In 2023, there was a reduction of
decommissioning provision costs due to revision in decommissioning
well cost estimates and the surrender of Tabaquite Block. This
resulted in a gain of USD 2.5 million.
See Note 3(b) to Consolidated Financial Statements further
details.
Finance Income
Finance income is solely related to
bank interest income received on short term investments with
financial institutions of USD 0.1 million (2022: 0.1
million).
Finance Costs
Finance costs amounted to USD (2.2)
million (2022: USD (1.3) million) and comprised:
·
Unwinding of the discount rate related to the
decommissioning liability USD (2.1) million (2022: USD (1.1)
million).
·
Interest on Leases USD (0.1) million (2022: USD
(0.1) million).
·
Bank overdraft interest USD 0.0 million (2022:
(0.1) million).
See Note 9 to Consolidated Financial Statements - Finance
Costs for further details.
Income Taxation
Income Taxation net credit for 2023
of USD 2.7 million (2022: USD (2.3) million), comprising the
following:
·
Current Taxes:
o Petroleum Profit Tax ("PPT") USD (0.4) million (2022: (2.4)
million).
o Unemployment Levy ("UL") USD (0.2) million (2022: USD (1.0)
million).
·
Increase in Deferred Tax Assets ("DTA")
recognised on available tax losses of USD 3.2 million (2022:
Increase in DTA of USD 1.0 million).
·
Decrease in Deferred Tax Liabilities ("DTL") USD
0.1 million due to accelerated accounting impairments/depreciation
(2022: USD 0.1 million decrease).
See Note 10 to Consolidated Financial Statements - Income
Taxation for further details.
Total Comprehensive (loss)/income
Total Comprehensive loss for the
period was USD (6.8) million (2022: USD 0.1 million
income).
Adjusted EBITDA
Adjusted EBITDA is a non-IFRS
measure used by the Group to measure business performance. It is
calculated as Operating Profit before SPT, Impairment and
Exceptional Items for the year, adjusted for non-cash DD&A,
gain or loss on the sale of assets, SOE, ILFA, FX and FV of
Derivative Instruments.
The Group presents Adjusted EBITDA
after hedge expense at USD 19.2 million and Adjusted EBIDA after
Current Taxes at USD 12.9 million as it is used by Management and
judged to be a better measure of underlying performance.
Statement of Cash Flows
Cash inflow from operating activities
Operating Cash Flow was USD 13.2
million (2022: USD 12.0 million) comprising:
·
Operating cash flow before working capital and
income taxes of USD 13.1 million (2022: USD 15.5
million).
·
Changes in working capital resulted in a net
increase of USD 0.9 million (2022: USD (0.1) million
decrease).
·
Income taxes, PPT and UL paid USD (0.8) million
(2022: USD (3.4) million paid) resulting from lower oil price and
production.
Cash (outflow) from investing activities
Cash outflow from investing
activities was USD (15.4) million (2022: USD (15.6)
million):
·
Expenditure on exploration and evaluation assets
and other intangible assets USD (9.0) million (2022: USD (0.4)
million) which includes costs incurred Jacobin well and
Galeota.
·
Property, plant and equipment for the year
totaling USD (5.9) million (2022: USD (15.0) million).
·
Computer software USD (0.5) million (2022: USD
(0.1) million).
·
Performance bond related to the onshore lease
operatorship assets nil (2022: USD (0.1) million).
Cash (outflow) from financing activities
Cash outflow from financing
activities was USD (0.2) million (2022: USD (2.2)
million):
·
Increase in Bank overdraft drawdown USD 1.3
million to match outstanding VAT refunds filed as at 31 December
2023 (2022: nil).
·
Principal paid on lease liability USD (0.6)
million (2022: (0.5) million).
·
Share buyback of USD (0.6) million (2022:
(1.5)).
·
Dividends paid of USD (0.2) million
·
Interest paid on lease liability USD (0.1)
million (2022: (0.1) million).
·
Net Finance cost of nil (2022: (0.1)
million).
Closing Cash Balance
Trinity's cash balance at 31
December 2023 was USD 9.8 million (31 December 2022: USD 12.1
million).
Net
Cash Plus Working Capital Surplus
(All figures in
USD million)
|
FY 2019
Audited
|
FY 2020
Audited
|
FY 2021
Audited
|
FY 2022
Audited
|
FY 2023
Audited
|
A:
|
Current
Assets
|
|
|
|
|
|
|
Cash and cash
equivalents
|
13.8
|
20.2
|
18.3
|
12.1
|
9.8
|
|
Trade and other
receivables (including taxes)
|
9.4
|
7.2
|
10.8
|
10.7
|
12.2
|
|
Inventories
|
5.2
|
5.3
|
3.8
|
4.6
|
3.9
|
|
Derivative
Financial Instrument
|
0.1
|
0.3
|
-
|
-
|
-
|
|
Total Current
Assets
|
28.5
|
33.0
|
32.9
|
27.4
|
25.9
|
B:
|
Current
Liabilities
|
|
|
|
|
|
|
Trade and other
payables
|
10.4
|
7.8
|
8.8
|
9.9
|
13.0
|
|
Bank
overdraft
|
-
|
2.7
|
2.7
|
2.7
|
4.0
|
|
Lease
liability
|
0.6
|
0.6
|
0.6
|
0.6
|
0.2
|
|
Taxation
payable
|
0.1
|
0.2
|
-
|
-
|
0.1
|
|
Dividend
payable
|
-
|
-
|
-
|
-
|
0.0
|
C:
|
Derivative
Financial Instrument
|
-
|
-
|
2.9
|
-
|
-
|
D:
|
Provision for
other liabilities
|
|
|
0.1
|
0.2
|
0.6
|
|
Total Current
Liabilities
|
11.1
|
11.3
|
15.1
|
13.4
|
17.9
|
(A-B+C+D):
|
Cash plus working
capital surplus
|
17.3
|
21.4
|
20.8
|
14.2
|
8.6
|
Note: Net cash
plus working capital surplus: Current Assets less Current
Liabilities (other than Derivative financial asset/liability and
Provision for other liabilities).
Events since year end
1.
Subsequent to 31 December 2023, the Group received VAT refunds of
USD 0.8 million. As at 22 May 2024, the Group had USD 5.1 million
in VAT refunds recoverable.
2.
On 13 June 2023, Trinity announced its successful bid for the
onshore Buenos Ayres block. Subsequent to 31 December 2023, the
Group is awaiting finalisation of the exploration and production
licence with the MEEI.
3.
Fiscal reforms (Finance Act) - Effective 1 January 2024, SPT rates
for Small Shallow Marine Area Producers were introduced. It becomes
applicable when the weighted average realised crude oil price
exceeds USD 75/bbl, starting at a rate of 18% and goes up to 40%
depending on the price.
A Small Shallow Marine Area
Producer is defined as a person who carries out petroleum
operations in shallow marine areas under a licence, sub-licence or
contract and produces less than 4,000 barrels of crude oil per
day.
4.
On 1 May 2024, the board of directors of each of Touchstone and
Trinity announced that they have reached agreement on the terms of
a recommended all share offer pursuant to which Touchstone will
acquire the entire issued and to be issued ordinary share capital
of Trinity (the "Acquisition"). The Acquisition is to be effected
by means of a scheme of arrangement under Part 26 of the Companies
Act. Under the terms of the Acquisition, Trinity Shareholders shall
be entitled to receive 1.5 New Touchstone Shares for each Trinity
share. Further information on the transaction can be found on our
website at https://trinityexploration.com/.
Consolidated Statement of Comprehensive
Income
For the year ended 31 December
2023
(Expressed in United States Dollars)
|
Note
|
2023
$'000
|
2022
$'000
|
Revenues
|
|
|
|
Crude oil sales
|
4
|
69,819
|
92,232
|
Other income
|
|
7
|
7
|
|
|
69,826
|
92,239
|
Operating Expenses
|
|
|
|
Royalties
|
|
(20,864)
|
(30,091)
|
Production costs
|
|
(22,402)
|
(19,242)
|
General & Administrative
("G&A") expenses
|
|
(7,375)
|
(7,181)
|
Covid-19 expenses*
|
|
-
|
(579)
|
Depreciation, Depletion &
Amortisation ("DD&A")
|
13-15
|
(8,935)
|
(7,617)
|
Share Option Expense ("SOE")
|
|
(528)
|
(647)
|
Foreign exchange ("FX")
loss
|
|
(65)
|
(394)
|
Impairment losses on financial
assets ("ILFA")/ net reversal
|
|
(64)
|
46
|
Derivative expenses
|
6
|
-
|
(10,446)
|
Fair value income derivative
instruments
|
6
|
-
|
2,883
|
|
|
(60,233)
|
(73,268)
|
Operating Profit before Supplemental Petroleum Taxes
("SPT")
|
|
9,593
|
18,971
|
SPT
|
|
(5,697)
|
(9,012)
|
Operating Profit before Impairment, Exceptional items
and Decommissioning reduction
|
|
3,896
|
9,959
|
Impairment
|
8
|
(13,462)
|
(6,050)
|
Exceptional items
|
7
|
(307)
|
(161)
|
Decommissioning reduction
|
7
|
2,508
|
-
|
Operating (Loss)/Profit
|
|
(7,365)
|
3,748
|
Finance income
|
9
|
50
|
48
|
Finance costs
|
9
|
(2,214)
|
(1,339)
|
(Loss)/Profit Before Income Taxation
|
|
(9,529)
|
2,457
|
Income taxation credit/(charge)
|
10
|
2,725
|
(2,344)
|
(Loss)/Profit for the year
|
|
(6,804)
|
113
|
Other Comprehensive Income/(Expense)
|
|
|
|
Items that may be subsequently reclassified to profit or
loss
|
|
|
|
Exchange differences on
translation of foreign operations
|
|
1
|
(20)
|
Total Comprehensive (Loss)/Income for the year
|
|
(6,803)
|
93
|
Earnings per share (expressed in dollars per share)
|
|
|
|
Basic
|
11
|
0.0
|
0.0
|
Diluted
|
11
|
0.0
|
0.0
|
*
Covid-19 expenses have been reclassified as Operating
Expenses.
Consolidated Statement of Financial
Position
at 31 December 2023
(Expressed in United States Dollars)
|
Note
|
2023
$'000
|
2022
$'000
|
ASSETS
|
|
|
|
Non-current Assets
|
|
|
|
Property, plant and equipment
|
13
|
35,188
|
44,987
|
Right-of-Use ("ROU") assets
|
14
|
312
|
838
|
Intangible assets
|
15
|
31,399
|
33,537
|
Abandonment fund
|
16
|
4,962
|
4,511
|
Performance bond
|
17
|
606
|
602
|
Deferred tax assets ("DTA")
|
18
|
15,703
|
12,465
|
|
|
88,170
|
96,940
|
Current Assets
|
|
|
|
Inventories
|
19
|
3,916
|
4,615
|
Trade and other receivables
|
20
|
11,709
|
10,560
|
Taxation recoverable
|
|
509
|
231
|
Cash and cash equivalents
|
22
|
9,819
|
12,131
|
|
|
25,953
|
27,537
|
Total Assets
|
|
114,123
|
124,477
|
EQUITY AND LIABILITIES
|
|
|
|
Capital and Reserves Attributable to Equity Holders
|
|
|
|
Share capital
|
23
|
399
|
399
|
Share based payment reserve
|
25
|
2,812
|
2,990
|
Reverse acquisition reserve
|
26
|
(89,268)
|
(89,268)
|
Translation reserve
|
|
(1,666)
|
(1,667)
|
Treasury shares
|
24
|
(1,553)
|
(1,522)
|
Retained earnings
|
|
138,321
|
145,199
|
Total Equity
|
|
49,045
|
56,131
|
Non-current Liabilities
|
|
|
|
Lease liability
|
14
|
137
|
341
|
Deferred tax liabilities
("DTL")
|
18
|
1,862
|
1,940
|
Provision for other liabilities
|
28
|
45,076
|
52,460
|
Employee benefits
|
|
31
|
23
|
|
|
47,106
|
54,764
|
Current Liabilities
|
|
|
|
Trade and other payables
|
29
|
13,094
|
10,045
|
Bank overdraft
|
30
|
4,000
|
2,700
|
Lease liability
|
14
|
208
|
584
|
Provision for other liabilities
|
28
|
622
|
249
|
Dividend payable
|
21
|
5
|
-
|
Taxation payable
|
|
43
|
4
|
|
|
17,972
|
13,582
|
Total Liabilities
|
|
65,078
|
68,346
|
Total Equity and Liabilities
|
|
114,123
|
124,477
|
The financial statements were
authorised for issue by the Board of Directors on 22 May 2024 and
were signed on its behalf by:
Jeremy Bridglalsingh
Director
22 May 2024
Company Statement of Financial Position
at 31 December 2023
(Expressed in United States Dollars)
|
Note
|
2023
$'000
|
2022
$'000
|
ASSETS
|
|
|
|
Non-current Assets
|
|
|
|
Investment in subsidiaries
|
12
|
61,342
|
60,864
|
Current Assets
|
|
|
|
Trade and other receivables
|
20
|
259
|
233
|
Intercompany
|
20
|
4,567
|
2,830
|
Cash and cash equivalents
|
22
|
1,194
|
2,102
|
|
|
6,020
|
5,165
|
Total Assets
|
|
67,362
|
66,029
|
EQUITY AND LIABILITIES
|
|
|
|
Capital and Reserves Attributable to Equity Holders
|
|
|
|
Share capital
|
23
|
399
|
399
|
Share based payment reserve
|
|
3,596
|
3,775
|
Merger reserves
|
|
6,552
|
6,552
|
Treasury shares
|
24
|
(1,553)
|
(1,522)
|
Retained earnings
|
|
41,635
|
43,529
|
Total Equity
|
|
50,629
|
52,733
|
Current Liabilities
|
|
|
|
Trade and other payables
|
29
|
678
|
565
|
Intercompany
|
31
|
16,050
|
12,731
|
Dividend payable
|
|
5
|
-
|
|
|
16,733
|
13,296
|
Total Liabilities
|
|
16,733
|
13,296
|
Total Equity and Liabilities
|
|
67,362
|
66,029
|
The Company has elected to take the
exemption under section 408 of the Companies Act 2006, to not
present the Statement of comprehensive income. The net loss for the
parent company was $1.9 million (2022: $9.4 million).
The financial statements were
authorised for issue by the Board of Directors on 22 May 2024 and
were signed on its behalf by:
Jeremy Bridglalsingh
Director
22 May 2024
Trinity Exploration & Production
plc
Registered Number:
07535869
Consolidated Statement of Changes in Equity
for the year ended 31 December
2023
Year ended 31
December 2022
|
Share
Capital
$'000
|
Share Based Payment Reserve
$'000
|
Reverse Acquisition
Reserve
$'000
|
Treasury Shares
$'000
|
Translation Reserve
$'000
|
Retained Earnings
$'000
|
Total
Equity
$'000
|
At 1
January 2022
|
389
|
3,784
|
(89,268)
|
-
|
(1,650)
|
143,666
|
56,921
|
Issue of shares
|
10
|
-
|
-
|
-
|
-
|
-
|
10
|
LTIPs lapsed (Note 25)
|
-
|
(1,416)
|
-
|
-
|
-
|
1,416
|
-
|
Share based payment expense (Note
25)
|
-
|
622
|
-
|
-
|
-
|
-
|
622
|
Treasury shares acquired (Note
24)
|
-
|
-
|
-
|
(1,522)
|
-
|
-
|
(1,522)
|
Translation adjustment
|
-
|
-
|
-
|
-
|
3
|
4
|
7
|
Profit for the year
|
-
|
-
|
-
|
-
|
-
|
113
|
113
|
Other comprehensive
income/
(expense)
|
|
|
|
|
|
|
|
Exchange differences on
translation of foreign operations
|
-
|
-
|
-
|
-
|
(20)
|
-
|
(20)
|
Total comprehensive
income for
the year
|
-
|
-
|
-
|
-
|
(20)
|
113
|
93
|
At 31 December 2022
|
399
|
2,990
|
(89,268)
|
(1,522)
|
(1,667)
|
145,199
|
56,131
|
Year ended 31
December 2023
|
|
|
|
|
|
|
|
At 1
January 2023
|
399
|
2,990
|
(89,268)
|
(1,522)
|
(1,667)
|
145,199
|
56,131
|
Share options exercised/lapsed
|
-
|
(698)
|
-
|
-
|
-
|
698
|
-
|
Share based payment expense (Note
25)
|
-
|
520
|
-
|
-
|
-
|
-
|
520
|
Treasury shares acquired
|
-
|
-
|
-
|
(566)
|
-
|
-
|
(566)
|
Treasury shares issued
|
-
|
-
|
-
|
535
|
-
|
(535)
|
-
|
Dividends
|
|
|
|
|
|
(236)
|
(236)
|
Translation adjustment
|
-
|
-
|
-
|
-
|
-
|
(1)
|
(1)
|
Loss for the year
|
-
|
-
|
-
|
-
|
-
|
(6,804)
|
(6,804)
|
Other comprehensive
income/
(expense)
|
|
|
|
|
|
|
|
Exchange differences on
translation of foreign operations
|
-
|
-
|
-
|
-
|
1
|
-
|
1
|
Total comprehensive loss for the year
|
-
|
-
|
-
|
-
|
1
|
(6,804)
|
(6,803)
|
At 31 December 2023
|
399
|
2,812
|
(89,268)
|
(1,553)
|
(1,666)
|
138,321
|
49,045
|
Company Statement of Changes in Equity
for the year 31 December
2023
Year ended 31
December 2022
|
Share
Capital
$'000
|
Share Based Payment Reserve
$'000
|
Merger Reserves
$'000
|
Treasury Shares
$'000
|
Retained Earnings
$'000
|
Total
Equity
$'000
|
At 1
January 2022
|
389
|
4,569
|
6,552
|
-
|
51,526
|
63,036
|
Issue of shares
|
10
|
-
|
-
|
-
|
-
|
10
|
Share based payment charge (Note
25)
|
-
|
622
|
-
|
-
|
-
|
622
|
Share options exercised/lapsed
(Note 25)
|
-
|
(1,416)
|
-
|
-
|
1,416
|
-
|
Treasury shares (Note 24)
|
-
|
-
|
-
|
(1,522)
|
-
|
(1,522)
|
Total comprehensive loss for the
year
|
-
|
-
|
-
|
-
|
(9,413)
|
(9,413)
|
At 31 December 2022
|
399
|
3,775
|
6,552
|
(1,522)
|
43,529
|
52,733
|
Year ended 31
December 2023
|
|
|
|
|
|
|
At 1
January 2022
|
399
|
3,775
|
6,552
|
(1,522)
|
43,529
|
52,733
|
Share options exercised
|
-
|
(698)
|
-
|
-
|
698
|
-
|
Share based payment expense (Note
25)
|
-
|
519
|
-
|
-
|
-
|
519
|
Treasury shares acquired (Note
24)
|
-
|
-
|
-
|
(566)
|
-
|
(566)
|
Treasury shares issued (Note
24)
|
-
|
-
|
-
|
535
|
(535)
|
-
|
Dividends
|
-
|
-
|
-
|
-
|
(236)
|
(236)
|
Total comprehensive loss for the
year
|
-
|
-
|
-
|
-
|
(1,821)
|
(1,821)
|
At 31 December 2023
|
399
|
3,596
|
6,552
|
(1,553)
|
41,635
|
50,629
|
Consolidated Statement of Cash Flows
for the year 31 December
2023
(Expressed in United States
Dollars)
|
Note
|
2023
$'000
|
2022
$'000
|
Operating Activities
|
|
|
|
(Loss)/Profit before taxation
|
|
(9,529)
|
2,457
|
Adjustments for:
|
|
|
|
Foreign exchange ("FX")
loss
|
|
65
|
394
|
Finance cost - loans and
interest
|
9
|
137
|
229
|
Finance income
|
9
|
(50)
|
(48)
|
Finance cost - decommissioning
provision
|
28
|
2,077
|
1,110
|
Share-based payment expense
|
|
528
|
647
|
DD&A
|
13-15
|
8,935
|
7,617
|
Loss on disposal
|
|
15
|
-
|
Impairment/ (net reversal) of
financial assets
|
|
64
|
(46)
|
Inventory impairment
|
|
-
|
334
|
Impairment of exploration and
evaluation assets
|
|
11,766
|
-
|
Impairment of property, plant and
equipment
|
13
|
1,542
|
5,558
|
Fair value gain on derivative
financial instruments
|
|
-
|
(2,883)
|
Other impairments
|
13
|
147
|
158
|
Net release of decommissioning
costs
|
|
(2,508)
|
-
|
|
|
13,189
|
15,527
|
Changes In Working Capital
|
|
|
|
Inventories
|
19
|
699
|
(1,129)
|
Trade and other receivables
|
16,20
|
(1,664)
|
(376)
|
Trade and other payables
|
28,29
|
1,822
|
1,353
|
|
|
857
|
(152)
|
Income taxation paid
|
|
(831)
|
(3,390)
|
Net Cash
Inflow from Operating Activities
|
|
13,215
|
11,985
|
Investing Activities
|
|
|
|
Purchase of exploration and
evaluation ("E&E") assets and investment in research &
development
|
15
|
(8,972)
|
(388)
|
Purchase of computer software
|
15
|
(492)
|
(102)
|
Purchase of property, plant and
equipment
|
13
|
(5,917)
|
(15,016)
|
Performance bond
|
|
-
|
(130)
|
Net Cash
Outflow from Investing Activities
|
|
(15,381)
|
(15,636)
|
Financing Activities
|
|
|
|
Finance income
|
|
50
|
48
|
Finance cost
|
|
(50)
|
(94)
|
Proceeds from the issue of
shares
|
|
0
|
10
|
Principal paid on lease
liability
|
|
(589)
|
(536)
|
Interest paid on lease
liability
|
|
(86)
|
(135)
|
Dividends paid
|
|
(231)
|
-
|
Acquisition of treasury
shares
|
|
(566)
|
(1,522)
|
Bank overdraft
|
|
1,300
|
-
|
Net Cash Outflow from Financing Activities
|
|
(172)
|
(2,229)
|
Decrease in Cash and Cash Equivalents
|
|
(2,338)
|
(5,880)
|
Cash and Cash Equivalents
|
|
|
|
At beginning of year
|
|
12,131
|
18,312
|
Effects of foreign exchange rates
differences on cash
|
|
26
|
(301)
|
Decrease in Cash and Cash
equivalents
|
|
(2,338)
|
(5,880)
|
Company Statement of Cash Flows
for the year 31 December
2023
At end of year
|
22
|
9,819
|
12,131
|
(Expressed in United States
Dollars)
|
Note
|
2023
$'000
|
2022
$'000
|
Operating Activities
|
|
|
|
Loss before taxation
|
|
(1,821)
|
(9,413)
|
Adjustments for:
|
|
|
|
Foreign exchange ("FX")
loss
|
|
(22)
|
306
|
Finance income
|
|
(164)
|
(156)
|
Share based payment charge
|
|
41
|
107
|
Impairment loss/ (net reversal) on
financial assets
|
|
129
|
(14)
|
Fair value loss on derivative
financial instruments
|
|
-
|
(2,883)
|
|
|
(1,837)
|
(12,053)
|
Changes In Working Capital
|
|
|
|
Trade and other receivables
|
|
(1,893)
|
521
|
Trade and other payables
|
|
3,432
|
12,188
|
|
|
1,539
|
12,709
|
Taxation Paid
|
|
-
|
-
|
Net Cash (Outflow)/ Inflow from Operating Activities
|
|
(298)
|
656
|
Financing Activities
|
|
|
|
Finance income
|
|
164
|
156
|
Issue of shares
|
|
0
|
10
|
Dividends paid
|
|
(231)
|
-
|
Treasury shares
|
|
(566)
|
(1,522)
|
Net Cash Outflow from Financing Activities
|
|
(633)
|
(1,356)
|
Decrease In Cash and Cash Equivalents
|
|
(931)
|
(700)
|
Cash and Cash Equivalents
|
|
|
|
At beginning of year
|
|
2,102
|
3,108
|
Effects of foreign exchange rates
differences on cash
|
|
23
|
(306)
|
Decrease Cash and Cash
equivalents
|
|
(931)
|
(700)
|
At End of Year
|
22
|
1,194
|
2,102
|
​
Notes to the Consolidated Financial
Statements
31 December 2023
1. Background and Summary of significant
accounting policies
The principal accounting policies
applied in the preparation of this consolidated financial
information are set out below. These policies have been
consistently applied to all the years presented, unless otherwise
stated. The financial statements are for Trinity Exploration &
Production plc ("Trinity" or "the Company" or "Parent") and its
subsidiaries (together "the Group").
Background
Trinity is an independent energy
company limited by shares and listed on the Alternative Investment
Market ("AIM") market of the London Stock Exchange ("LSE"). The
Company is incorporated and domiciled in England and the address of
the registered office is c/o Pinsent Masons LLP 1 Park Row, Leeds
LS1 5AB, United Kingdom ("UK"). The Group is involved in the
exploration, development and production of oil reserves in Trinidad
& Tobago ("T&T").
Basis of preparation
The Group's and Company's financial
statements have been prepared and approved by the Board of
Directors ("Board") in accordance with international accounting
standards as adopted in the United Kingdom.
The preparation of the consolidated
financial statements in compliance with IFRS requires the use of
certain critical accounting estimates. It also requires the Board
and Executive Management Team ("EMT") (together "Management") to
exercise its judgement in the process of applying the Group's
accounting policies. The areas involving a higher degree of
judgement or complexity, or areas where assumptions and estimates
are significant to the consolidated financial information, are
disclosed in Note 3: Critical Accounting Estimates and
Assumptions.
The Company has taken advantage of
the exemption in Section 408 of the Companies Act 2006 not to
present its own income statement or Statement of Comprehensive
Income. The loss for the Company for the year was $1.9 million
(2022: $9.4 million loss).
Basis of measurement
The consolidated financial
statements have been prepared under the historical cost convention,
except certain financial assets and liabilities (including
derivative financial instruments) - which are measured at fair
value through the Consolidated Statement of Comprehensive Income.
Accounting policies have been applied consistently, other than
where a new accounting policy has been adopted.
Going Concern
The Board adopted the going concern
basis in preparing these consolidated financial
statements.
In making their going concern
assessment, the Board have considered the Group's current financial
position, budget and cash flow forecast. The going concern
assessment has considered the current operating environment and the
potential impact of the volatility of the oil price.
The Group started 2024 with a stable
operating and financial position; 2023 average production of 2,790
barrels of oil per day ("bopd"), (2022 2,975 bopd), and cash and
short-term investments of $9.8 million as at 31 December 2023
(2022: $12.1 million). The Group's base case going concern
assessment is based upon management's best estimate of forward
commodity price curves and uses production in line with approved
asset plans. The base case forecast was prepared with consideration
of the following:
·
Future oil prices are assumed to be in line with
the forward curve prevailing as at 2 April 2024. The forward price
curve applied in the cash flow forecast starts at a realised price
of $75.3/bbl in April 2024, fluctuating each month down to
$69.7/bbl in December 2024 through to $65.5/bbl in December
2025.
·
Average forecast production for the years to
December 2023 and December 2024 are in line with the Group's asset
development plans, with production being maintained by RCPs, WOs
and swabbing activities;
·
No SPT is assumed to be incurred on both onshore
and offshore assets in 2024 or 2025, as the forecast realised price
is below $75.0/bbl;
·
Trinity continuing to progress various growth and
business development opportunities; and
·
No derivative instruments being put in place for
2024.
·
No drawdown of working capital overdraft
facility
Management considers this is a
reasonable base scenario, reflecting a prudent outlook for the
future oil price, production profile and costs. The cash flow
forecast showed that the Group will remain in a strong financial
position for at least the next twelve months, and as such being
able to meet its liabilities as they fall due.
Management has considered a separate
stressed scenario including:
·
the effect of reductions in Brent oil prices at
$60.0/bbl being sustained across the forecast period, noting that
the base case pricing is in line with market prices; and
·
the compounded impact of a reduction in
production by 10%.
The stressed case cash flow forecast
allows for the impact of mitigating actions that are within the
Group's control which include:
·
Reducing non-core and discretionary opex and
administrative costs across the forecast period.
·
Reducing discretionary capital expenditure and
capital returns over the forecast period.
All reasonably plausible forecasts
demonstrate that the Group's cash balances are maintained under
such scenarios and as such are sufficient to meet the Group's
obligations as they fall due.
As a result, at the date of approval
of the financial statements, the Board have a reasonable
expectation that the Group has sufficient and adequate resources to
continue in existence for at least twelve months post approval of
these financial statements and is poised for continued growth. For
this reason, the Board have concluded it is appropriate to continue
to adopt the going concern basis of accounting in the preparation
of the consolidated and company financial statements.
The directors of Trinity Exploration
& Production Plc have received a letter of support from Trinity
Exploration and Production Services Limited confirming that they
will not recall related party balances and any loan to the Company
for a period of not less than twelve months from the date of
signing of Company's statutory accounts unless the Company can
repay the related party balances and loan.
Changes in accounting policies
(a) New
standards, interpretations and amendments adopted from 1 January
2023:
The following amendments are
effective for the period beginning 1 January 2023:
·
IFRS 17 Insurance Contracts
·
Disclosure of Accounting Policies (Amendments to
IAS 1 Presentation of Financial Statements and IFRS Practice
Statement 2 Making Materiality Judgements); Definition of
Accounting Estimates (Amendments to IAS 8 Accounting Policies,
Changes in Accounting Estimates and Errors); Deferred Tax related
to Assets and Liabilities arising from a Single Transaction
(Amendments to IAS 12 Income Taxes); and
·
International Tax Reform - Pillar Two Model Rules
(Amendment to IAS 12 Income Taxes) (effective immediately upon the
issue of the amendments and retrospectively).
These amendments to various IFRS
Accounting Standards are mandatorily effective for reporting
periods beginning on or after 1 January 2023. There is no impact to
the 2023 accounts.
(b) New
standards, interpretations and amendments not yet
effective
There are a number of standards,
amendments to standards, and interpretations which have been issued
by the IASB that are effective in future accounting periods that
the Group has decided not to adopt early.
The following amendments are
effective for the period beginning 1 January 2024:
·
Liability in a Sale and Leaseback (Amendments to
IFRS 16 Leases);
·
Classification of Liabilities as Current or
Non-Current (Amendments to IAS 1 Presentation of Financial
Statements);
·
Non-current Liabilities with Covenants
(Amendments to IAS 1 Presentation of Financial Statements);
and
·
Supplier Finance Arrangements (Amendments to IAS
7 Statement of Cash Flows and IFRS 7 Financial Instruments:
Disclosures)
The following amendments are
effective for the period beginning 1 January 2025:
·
Lack of Exchangeability (Amendments to IAS 21 The
Effects of Changes in Foreign Exchange Rates)
The Group is currently assessing the
impact of these new accounting standards and amendments. The Group
does not believe that the amendments to IAS 1 will have a
significant impact on the classification of its liabilities, as the
conversion feature in its convertible debt instruments is
classified as an equity instrument and therefore, does not affect
the classification of its convertible debt as a non-current
liability. The Group does not expect any other standards issued by
the IASB, but are yet to be effective, to have a material impact on
the Group.
Basis of consolidation
The Consolidated Financial
Statements comprise the financial statements of the subsidiaries
listed in Note 12. The financial information incorporates the
financial information of the Group made up to 31 December each
year. Control is achieved where the Company has the power to govern
the financial and operating policies of an entity so as to obtain
benefits from its activities. The results of subsidiaries acquired
or disposed of during the year are included in the Consolidated
Statement of Comprehensive Income from the effective date of
acquisition and up to the effective date of disposal, as
appropriate.
The acquisition method of accounting
is used to account for the acquisition of subsidiaries by the
Group. The cost of an acquisition is measured as the fair value of
the assets given, equity instruments issued and liabilities
incurred or assumed at the date of exchange. Identifiable assets
acquired and liabilities and contingent liabilities assumed in a
business combination are measured initially at their fair values at
the acquisition date, irrespective of the extent of any
non-controlling interest. If the cost of acquisition is less than
the fair value of the net assets of the subsidiary acquired, the
difference is recognised directly in the Statement of Comprehensive
Income. Costs related to an acquisition are expensed as
incurred.
Uniform accounting policies have
been adopted across the Group. All intra-group transactions,
balances, income and expenses are eliminated on
consolidation.
Share-based payments
The Group operates a number of
equity-settled, share-based compensation plans comprised of
Long-Term Incentive Plans ("LTIPs") as consideration for services
rendered by the Group's employees. The fair value of the services
received in exchange for the grant of share-based payments is
recognised as an expense. The total amount to be expensed is
determined by reference to the fair value of the options or LTIP
awards granted:
·
including any market performance conditions (for
example, an entity's share price);
·
excluding the impact of any service and
non-market performance vesting conditions; and
·
including the impact of any non-vesting
conditions.
Non-market performance and service
conditions are included in assumptions about the number of
share-based payments that are expected to vest. The total expense
is recognised over the vesting period, which is the period over
which all of the specified vesting conditions are to be
satisfied.
At the end of each reporting period,
the Group revises its estimates of the number of options or LTIP
awards that are expected to vest based on the non-market vesting
conditions. It recognises the impact of the revision to original
estimates, if any, in the Consolidated Statement of Comprehensive
Income, with a corresponding adjustment to equity. When the options
are exercised, the Group issues new shares or utilises shares held
in Treasury. The proceeds received net of any directly attributable
transaction costs are credited to share capital (nominal value) and
share premium.
The grant by the Company of options
and LTIPs over its equity instruments to the employees of
subsidiary undertakings in the Group is treated as a capital
contribution. The fair value of employee services received,
measured by reference to the grant date fair value, is recognised
over the vesting period as an increase to investment in subsidiary
undertakings, with a corresponding credit to equity.
Employee Benefit Trust
The Group established the Trinity
Exploration and Production plc Employee Benefit Trust, which is
consolidated in accordance with the principles in Note 1 - Basis of
consolidation. When the options are exercised, the trust transfers
the appropriate amount of shares to the employee. The proceeds
received, net of any directly attributable transaction costs, are
credited directly to equity.
Cash-settled share-based payments
The Group operates a cash-settled
share-based plan comprised of reference shares as consideration for
services rendered by the Group's employees.
Cash-settled share-based payments
result in the recognition of a liability, which is an obligation to
make a payment in cash or other assets, based on the price of the
underlying equity instrument. At each reporting date, and
ultimately at the settlement date, the fair value of the recognised
liability is remeasured. Remeasurement applies to the recognised
portion of the liability through to vesting date. The full amount
is remeasured from vesting date to settlement date. The cumulative
net cost and amounts recognised in profit or loss that will
ultimately be recognised in respect of the transaction will be
equal to the amount paid to settle the liability.
Foreign currency translation
(a)
Functional and presentation currency
Company:
|
The functional and presentation
currency of the Company is United States Dollars ("USD" or
"$").
|
Group:
|
The functional currencies of the
Group operating entities are Trinidad & Tobago Dollars ("TTD")
and United States dollars as these are the currencies of the
primary economic environment in which the entities operate. The
presentation currency is USD which better reflects the Group's
business activities and improves the ability of users of the
consolidated financial statements to compare financial results with
others in the international Oil and Gas industry. The Consolidated
Statement of Financial Position is translated at the closing rate
and Consolidated Statement of Comprehensive Income is translated at
the average rate from both USD and Great British Pound ("GBP" or
"£") currencies. The following exchange rates have been used in the
preparation of these financial statements:
|
|
|
2023
|
|
2022
|
|
$
|
£
|
$
|
£
|
Average rate TTD = $/£
|
6.750
|
8.397
|
6.754
|
8.357
|
Closing rate TTD = $/£
|
6.716
|
8.550
|
6.742
|
8.146
|
(b)
Transactions and balances
Foreign currency transactions are
translated into the functional currency using the exchange rates at
the dates of the transactions. FX gains/losses resulting from the
settlement of such transactions and from the translation of
monetary assets and liabilities denominated in foreign currencies
at year end exchange rates are generally recognised in the
consolidated Statement of Comprehensive Income. They are deferred
in equity if they relate to qualifying cash flow hedges and
qualifying net investment hedges or are attributable to part of the
net investment in a foreign operation.
Non-monetary items that are measured
at fair value in a foreign currency are translated using the
exchange rates at the date when the fair value was determined.
Translation differences on assets and liabilities carried at fair
value are reported as part of the fair value gain or loss. For
example, translation differences on non-monetary assets and
liabilities such as equities held at fair value through profit or
loss are recognised in the consolidated Statement of Comprehensive
Income as part of the fair value gain or loss and translation
differences on non-monetary assets.
(c)
Group Companies
The results and financial position
of foreign operations (none of which has the currency of a
hyperinflationary economy) that have a functional currency
different from the presentation currency are translated into the
presentation currency as follows:
·
assets and liabilities for each Statement of
Financial Position presented are translated at the closing rate at
the date of that Consolidated Statement of Financial
Position
·
income and expenses for each Statement of
Comprehensive Income are translated at average exchange rates
(unless this is not a reasonable approximation of the cumulative
effect of the rates prevailing on the transaction dates, in which
case income and expenses are translated at the dates of the
transactions), and
·
all resulting exchange differences are recognised
in other comprehensive income.
On consolidation, exchange
differences arising from the translation of any net investment in
foreign entities, and of borrowings and other financial instruments
designated as hedges of such investments, are recognised in other
comprehensive income. When a foreign operation is sold or any
borrowings forming part of the net investment are repaid, the
associated exchange differences are reclassified to profit or loss,
as part of the gain or loss on sale.
(d)
Translation differences
Differences arising from
retranslation of the financial statements at the year-end are
recognised in the Translation reserve through "Other comprehensive
income".
Intangible assets
(a)
Exploration and Evaluation ("E&E") assets
i)
Capitalisation
E&E assets are initially
classified as intangible assets. Such costs include those directly
associated with an exploration area. Upon discovery of commercial
reserves capitalisation is recognised within Property, Plant and
Equipment.
Oil and natural gas E&E
expenditures are accounted for using the successful efforts method
of accounting. Under this method, costs are accumulated on a
prospect-by-prospect basis and capitalised upon discovery of
commercially viable mineral reserves. If the commercial viability
is not achieved or achievable, such costs are charged to
expense.
Costs incurred in the E&E of
assets includes:
·
Licence and
property acquisition costs
Exploration and property leasehold
acquisition costs are capitalised within E&E assets.
·
E&E
expenditure
Costs directly associated with an
exploration well are capitalised until the determination of
reserves is evaluated. Such costs include topographical,
geological, geochemical, and geophysical studies, exploratory
drilling costs, trenching, sampling and activities in relation to
evaluating the technical feasibility and commercial viability of
extracting mineral resources. Capitalisation is made within
property, plant and equipment or intangible assets according to its
nature, although a majority of such expenditure is capitalised as
an intangible asset. If commercial reserves are found, the costs
continue to be carried as an asset. If commercial reserves are not
found, E&E expenditures are written off as a dry hole when that
determination is made.
Once commercial reserves are
found, E&E assets are tested for impairment and transferred to
development tangible and intangible assets as applicable. No
depreciation and/or amortisation are charged during the E&E
phase.
Where development costs have been
capitalised and Management has determined a strategic change to
focus on E&E activities in an asset, these costs are
transferred from development costs to E&E assets in the period
the strategic change was made. An Impairment assessment is
performed prior to the transfer in accordance with IFRS 6
impairment guidance noted below.
ii)
Impairment
E&E assets are tested for
impairment (in accordance with the criteria set out in IFRS 6:
Exploration for and Evaluation of Mineral Resources) whenever facts
and circumstances indicate impairment. An impairment loss is
recognised for the amount by which the E&E assets' carrying
amount exceed their recoverable amount. The recoverable amount is
the higher of the E&Es assets' Fair Value Less Costs of
Disposal ("FVLCD") and their Value In Use ("VIU"). For the purposes
of assessing impairment, the E&E assets subject to testing are
grouped with existing Cash Generating Units ("CGU") of related
production fields located in the same geographical region. The
geographical region is the same as that used for reserves reporting
purposes.
The following indicators are
evaluated to determine whether these assets should be tested for
impairment:
·
The period for which the Group has the right to
explore in the specific area has lapsed.
·
Whether substantive expenditure on further
E&E in the specific area is budgeted or planned.
·
Whether E&E in the specific area have not led
to the discovery of commercially viable quantities and the Company
has decided to discontinue such activities in the specific area;
and/or
·
Whether sufficient data exists to indicate that,
although a development in the specific area is likely to proceed,
the carrying amount of the E&E asset is unlikely to be
recovered in full from successful development or by
sale.
(b)
Computer software
Computer software is initially
recognised at cost once it is purchased. Internally generated
software is capitalised once it is proven technological
feasibility, probable future benefits, intent and ability to use
the software, resources to complete the software, and ability to
measure cost. It is amortised over its four-year useful life, based
on pattern of benefits (straight-line is the default) and charge
recognised under DD&A.
Property, plant and equipment
(a) Oil
& Gas Assets
i)
Development and Producing Assets - Capitalisation
Development expenditures are costs
incurred to obtain access to proven reserves and to provide
facilities for extracting, treating, gathering and storing the oil
and gas. These costs include transfers from E&Es subsequent to
finding commercially viable reserves, development drilling and new
reserve type, infrastructure costs and development Geological and
Geophysical ("G&G") costs. Acquisitions of oil and gas
properties are accounted for under the acquisition method where the
transaction meets the definition of a business
combination.
Transactions involving the
purchases of an individual field interest, or a group of field
interests, that do not meet the definition of a business (and
therefore do not apply business combination accounting) are treated
as asset purchases, irrespective of whether the specific
transactions involve the transfer of the field interests directly,
or the transfer of an incorporated entity. Accordingly, the
consideration is allocated to the assets and liabilities purchased
on a relative fair value basis.
Proceeds on disposal are applied
to the carrying amount of the specific asset or development and
production assets disposed of. Any excess is recorded as a gain on
disposal in the Consolidated Statement of Comprehensive Income and
any shortfall between the proceeds and the carrying amount is
recorded as a loss on disposal in the Consolidated Statement of
Comprehensive Income.
Development expenditure on the
construction, installation or completion of infrastructure
facilities such as platforms, pipelines and the drilling of
development commercially proven wells is capitalised according to
its nature. When development is completed on a specific field it is
transferred to Production Assets. No depreciation and/or
amortisation are charged during the development phase.
Expenditure on G&G surveys
used to locate and identify properties with the potential to
produce commercial quantities of oil and gas as well as to
determine the optimal location for development wells are
capitalised.
ii)
Development and Producing Assets - Impairment
An impairment test is performed
whenever events and circumstances arising during the development or
production phase indicate that the carrying value of a development
or production asset may exceed its recoverable amount. Impairment
triggers include but are not limited to, declining long term market
prices for oil and gas, significant downward reserve revisions,
increased regulations or fiscal changes, market capitalisation
being below net assets, deteriorating local conditions such that it
become unsafe to continue operations) and obsolescence.
The carrying value is compared
against the expected recoverable amount. The recoverable amount is
the higher of an asset's FVLCD and the VIU. For the purposes of
assessing impairment, assets are grouped at the lowest levels (its
CGU) for which there are separately identifiable cash flows. The
CGU applied for impairment test purposes is generally the field.
These fields are the same as that used for reserves reporting
purposes.
iii)
Producing Assets - DD&A
The provision for DD&A of
developed and producing Oil & Gas Assets are calculated using
the unit-of-production method. Oil & Gas Assets are depreciated
generally on a field-by-field basis using the unit-of-production
method which is the ratio of oil and gas production in the period
to the estimated quantities of commercial reserves at the end of
the period plus the production in the period. Costs used in the
unit of production calculation comprise the net book value of
capitalised costs plus the estimated future development costs.
Changes in the estimates of commercial reserves or future
development costs are dealt with prospectively.
iv)
Decommissioning asset and provisions
Provision for decommissioning is
recognised in accordance with the contractual obligations at the
commencement of oil and gas production. The amount recognised is
the net present value of the estimated cost of decommissioning at
the end of the economic producing lives of the wells and the end of
the useful lives of refinery and storage units. Such costs include
removal of equipment and restoration of land or seabed. The
unwinding of the discount on the provision is included in the
Consolidated Statement of Comprehensive Income within finance
costs.
A corresponding asset is also
created at an amount equal to the provision. This is subsequently
depleted as part of the capital costs of the production assets. Any
change in the present value of the estimated expenditure or
discount rates are reflected as an adjustment to the provision and
the asset and dealt with prospectively.
Decommissioning provisions are
updated at each balance sheet date for changes in the estimates of
the amount or timing of future cash flows and changes in the
discount rate. Changes to provisions that relate to the removal of
an asset are added to or deducted from the carrying amount of the
related asset in the current period. However, the adjustments to
the asset are restricted. The asset cannot decrease below zero and
cannot increase above its recoverable amount:
·
if the decrease in provision exceeds the carrying
amount of the asset, the excess is recognised immediately in profit
or loss;
·
adjustments that result in an addition to the
cost of the asset are assessed to determine if the new carrying
amount is fully recoverable or not. An impairment test is required
if there is an indication that the asset may not be fully
recoverable.
(b)
Non-Oil & Gas Assets
All property, plant and equipment
are recorded at historical cost less accumulated depreciation and
any impairment losses. Historical cost includes the original
purchase price of the asset and expenditure that is directly
attributable to bringing the asset to its working condition for its
intended use. Subsequent costs are included in the asset's carrying
amount or recognised as a separate asset, as appropriate, only when
it is probable that future economic benefits associated with the
item will flow to the Group and the cost of the item can be
measured reliably.
The provision for depreciation with
respect to operations other than oil and gas producing activities
is computed using the straight-line method based on estimated
useful lives as follows:
Leasehold and buildings
|
20
years
|
Plant and equipment
|
4
years
|
Other
|
4
years
|
The assets' residual values and
useful lives are reviewed and adjusted if appropriate at each
Statement of Financial Position date. An asset's carrying amount is
written down immediately to its recoverable amount if the asset's
carrying amount is greater than its estimated recoverable amount.
Gains and losses on disposals are determined by comparing proceeds
with carrying amounts and are included in the Consolidated
Statement of Comprehensive Income.
Repairs and maintenance are charged
to the Consolidated Statement of Comprehensive Income during the
financial period in which they are incurred. The cost of major
renovations is included in the carrying amount of the asset when it
is probable that future economic benefits in excess of the
originally assessed standard of performance of the existing assets
will flow to the Group. Major renovations such as leasehold
improvements are depreciated over the remaining useful life of the
related asset.
Impairment of non-financial assets
At each reporting date, assets that
are subject to amortisation are reviewed for impairment whenever
events or changes in circumstances indicate that the carrying
amount may not be recoverable. An impairment loss is recognised for
the amount by which the asset's carrying amount exceeds its
recoverable amount. The recoverable amount is the higher of an
asset's FVLCD and VIU. For the purposes of assessing impairment,
assets are grouped at the lowest levels for which there are
separately identifiable cash flows (CGUs). Non-financial assets
that suffered impairment are reviewed for possible reversal of the
impairment at each reporting date.
Inventories
Crude oil is stated at the lower of
cost and net realisable value. Cost is determined by the average
cost method. Net realisable value is the estimated selling price in
the ordinary course of business, less applicable variable selling
expenses. Materials and supplies used mainly in drilling wells,
RCPs and WOs are stated at lower of cost and net realisable value.
Cost is determined using the weighted average cost
method.
Cash and Cash equivalents
For the purpose of presentation in
the Consolidated Statement of Cash Flows, Cash and Cash equivalents
includes cash on hand, deposits held at call with financial
institutions, other short-term, highly liquid investments with
original maturities of three months or less that are readily
convertible to known amounts of cash and which are subject to an
insignificant risk of changes in value.
Trade receivables
Trade receivables are amounts due
from customers for crude oil sold in the ordinary course of
business. They are generally due for settlement within thirty days
and therefore are all classified as current. Trade receivables are
recognised initially at the amount of consideration that is
unconditional unless they contain significant financing components,
when they are recognised at fair value.
The Group applies the simplified
approach to determine impairment of trade receivables. The
simplified approach requires expected lifetime losses to be
recognised from initial recognition of the receivables. This
involves determining the expected loss rates using a provision
matrix that is based on the historical default rates observed over
the expected life of the receivable and adjusted forward-looking
estimates. This is then applied to the gross carrying amount of the
receivable to arrive at the loss allowance for the
period.
Trade payables
Trade payables are recognised
initially at fair value and subsequently measured at amortised cost
using the effective interest method.
Impairment of Financial Assets
The financial assets within the
Group are subject to the Expected Credit Losses ("ECL") model. The
Group applies the ECL model to trade receivables for sales of
inventory and from the provision of consulting services as well as
Intercompany receivables. While Cash and Cash equivalents are also
subject to the impairment requirements of IFRS 9, the identified
impairment loss was immaterial.
(i)
Trade receivables
The Group applies the IFRS 9
simplified approach to measuring ECL which uses a lifetime expected
loss allowance for all trade receivables.
Financial assets recognition of
impairment provisions under IFRS 9 is based on the ECL model. The
ECL model is applicable to financial assets classified at amortised
cost and contract assets under IFRS 15: Revenue from Contracts with
Customers. The measurement of ECL reflects an unbiased and
probability weighted amount that is available without undue cost or
effort at the reporting date, about past events, current conditions
and forecasts of future economic conditions. The Group applied the
simplified approach to determine impairment of its trade and other
receivables. The simplified approach requires expected lifetime
losses to be recognised from initial recognition of the
receivables. This involves determining the expected loss rates
using a provision matrix that is based on the Group's historical
default rates observed over the expected life of the receivables
and adjusted forward looking estimates. This is then applied to the
gross carrying amount of the receivables to arrive at the loss
allowance for the period.
(ii)
Intercompany receivables
The Company applies IFRS 9 through
the recognition of ECL for intercompany positions. Intercompany
positions eliminate in the consolidated financial statements. In
measurement of the ECL, IFRS 9 notes that the maximum period over
which expected impairment losses is measured is the longest
contractual period where the Company is exposed to credit risk. The
three-stage general impairment model was used, Probability of
Default ("PD") x Loss Given Default ("LGD") x Exposure at Default
("EAD"). Measurement of the ECL at a probability-weighted amount
that reflects the possibility of a credit loss occurs, and the
possibility that no credit loss occurs and even if the possibility
of a credit loss occurring is low.
Income tax
The income tax expense or credit for
the period is the tax payable on the current period's taxable
income based on the applicable income tax rate for each
jurisdiction adjusted by changes in DTA and DTL attributable to
temporary differences and to unused tax losses.
The current income tax charge is
calculated on the basis of the tax laws enacted or substantively
enacted at the end of the reporting period in the countries where
the Company's subsidiaries and associates operate and generate
taxable income. Management periodically evaluates positions taken
in tax returns with respect to situations in which applicable tax
regulation is subject to interpretation. It establishes provisions
where appropriate on the basis of amounts expected to be paid to
the tax authorities.
Deferred income tax is provided in
full, using the liability method, on temporary differences arising
between the tax bases of assets and liabilities and their carrying
amounts in the consolidated financial statements. However, DTLs are
not recognised if they arise from the initial recognition of
goodwill. Deferred income tax is also not accounted for if it
arises from initial recognition of an asset or liability in a
transaction other than a business combination that at the time of
the transaction affects neither accounting nor taxable profit/loss.
Deferred income tax is determined using tax rates (and laws) that
have been enacted or substantially enacted by the end of the
reporting period and are expected to apply when the related
deferred income tax asset is realised or the deferred income tax
liability is settled.
DTA are recognised only if it is
probable that future taxable amounts will be available to utilise
those temporary differences and losses.
DTL and DTA are not recognised for
temporary differences between the carrying amount and tax bases of
investments in foreign operations where the Company is able to
control the timing of the reversal of the temporary differences and
it is probable that the differences will not reverse in the
foreseeable future.
DTA and DTL are offset when there is
a legally enforceable right to offset current tax assets and
liabilities and when the deferred tax balances relate to the same
taxation authority. Current tax assets and tax liabilities are
offset where the entity has a legally enforceable right to offset
and intends either to settle on a net basis, or to realise the
asset and settle the liability simultaneously.
Current and deferred tax is
recognised in profit or loss, except to the extent that it relates
to items recognised in other comprehensive income or directly in
equity. In this case, the tax is also recognised in other
comprehensive income or directly in equity,
respectively.
Property Tax ("PT")
From 2018 until 2020, PT had been
recognised initially at fair value and subsequently measured at
amortised cost using the effective interest method. Assessments
were based on the Annual Rental Value ("ARV") of property. The
Annual Taxable Value ("ATV") is the ARV subject to deductions and
allowances in respect of voids and loss of rent multiplied by the
respective PT rate. The PT rates applicable to the Group were
industrial with building rates at 6% and industrial without
building rates at 3%.
The Finance Act 2023 amendment
waives PT accrued for past years up to 31 December 2023, and so no
liability is now being recognised. Refer to note 3 (f).
Revenue recognition
IFRS 15 Revenue from Contracts with
Customers requires that revenue is recognised by performance
obligation, as or when each performance obligation is satisfied,
and that variable elements of pricing are recognised and to the
extent that it is not highly probable they will be
reversed.
The Group has evaluated its customer
contract with the Heritage Petroleum Company Limited ("Heritage"),
to identify the performance obligations, the timing of the revenue
recognition and the treatment of variable elements of pricing.
Sales revenue represents the sales value of the Group's oil sold in
the year.
Revenue associated with the sale of
crude oil is measured based on the consideration specified in
contracts with customers.
Revenue is recognised when control
is transferred from the Group to its customer and the Group has the
present right to payment. The transfer of control of crude oil
coincides with title passing to the customer and the customer
taking physical possession. Typically, payment for the sale of the
oil is received by the end of the month following the month in
which the sale is recognised.
Prices are based on prices
determined by Heritage, with agreed contractual adjustments for
quality. Revenue is measured at the fair value of the consideration
received or receivable, and represents amounts receivable for oil
and gas products in the normal course of business.
Provisions
Provisions are recognised when the
Group has a present legal or constructive obligation as a result of
past events, where it is probable that an outflow of resources will
be required to settle the obligation, and a reliable estimate of
the amount of the obligation can be made. Provisions are not
recognised for future operating losses. Where there are a number of
similar obligations, the likelihood that an outflow will be
required in settlement is determined by considering the class of
obligations as a whole. A provision is recognised even if the
likelihood of an outflow with respect to any one item included in
the same class of obligations may be small.
Provisions are measured at the
present value of the expenditures expected to be required to settle
the obligation using a pre-tax rate that reflects current market
assessments of the time value of money and the risks specific to
the obligation. The increase in the provision due to passage of
time is recognised as a finance cost.
Leases
All leases are accounted for by
recognising a right-of-use asset and a lease liability except
for:
·
Leases of low value assets; and
·
Leases with a duration of 12 months or
less.
Lease liabilities were measured at
the present value of the contractual payments due to the lessor
over the lease term, with the discount rate determined by reference
to the group's incremental borrowing rate. The lease payments are
discounted using the Group's incremental borrowing rate, being the
rate that the Group would have to pay to borrow the funds necessary
to obtain an asset of similar value to the ROU asset in a similar
economic environment with similar terms, security and conditions.
To determine the incremental borrowing rate, Trinity received an
indicative third-party lending rate from Central Bank of Trinidad
and Tobago.
Right of use assets were initially
measured at the amount of the lease liability. Subsequent to
initial measurement lease liabilities increase as a result of
interest charged at a constant rate on the balance outstanding and
are reduced for lease payments made. Right-of-use assets are
amortised on a straight-line basis over the remaining term of the
lease.
The lease term can be described as
the non-cancellable period of the lease plus periods covered by an
option to extend or an option to terminate if the lessee is
reasonably certain to exercise the extension option or not exercise
the termination option.
Share capital
Ordinary shares are classified as
equity. The nominal value of any shares issued is recognised in
share capital with the excess above the nominal amount paid being
shown within share premium.
Incremental costs directly
attributable to the issue of new ordinary shares are shown in
equity. Where, on issuing shares, share premium has been
recognised, the expenses of issuing those shares and any commission
paid on the issue of those shares have been written off against the
share premium account.
Treasury Shares
Where any Group company purchases
the Company's equity instruments, for example as the result of a
share buy- back or a share-based payment plan, the consideration
paid is deducted from equity attributable to the owners of the
Company as treasury shares until the shares are cancelled or
reissued. Where such ordinary shares are subsequently reissued, any
consideration received is included in equity attributable to the
owners of the Company. Shares held by the Company are disclosed as
treasury shares and deducted from equity.
Derivative financial Instruments and hedging
activities
Derivatives are initially recognised
at fair value on the date a derivative contract is entered into and
are subsequently re-measured to their fair value at the end of each
reporting period. The accounting for subsequent changes in fair
value depends on whether the derivative is designated as a hedging
instrument, and if so, the nature of the item being hedged. The
Group has not applied hedge accounting and all oil price derivative
financial instruments (categorised as Derivative Income/(Expenses))
are measured at fair value through profit and loss.
Financial assets at fair value
through profit or loss are classified in this category if acquired
principally for the purpose of selling in the short term.
Derivatives are also categorised as held for trading unless they
are designated as hedges. Assets in this category are classified as
current assets if expected to be settled within twelve months,
otherwise they are classified as non-current. Financial assets are
derecognised when the rights to the cash flows expire, risks and
rewards are transferred or control of the asset is
transferred.
A financial liability is removed
from the Statement of Financial Position only when it is
extinguished; that is, when the obligation specified in the
contract is discharged, cancelled or expired.
Investments
Investments are shown at cost less
provision for any impairment in value. The Company performs
impairment reviews in respect of investments whenever events or
changes in circumstances indicate that the carrying amount of the
investment may not be recoverable. An impairment loss is recognised
when the higher of the investment's net realisable value and fair
value less cost of disposal is less than the carrying
amount.
Exceptional Items
Exceptional items are disclosed
separately in the consolidated financial statements where it is
necessary to do so to provide further understanding of the
financial performance of the Group. They are distinct from routine
operations which are material items of income or expense that have
been shown separately due to the non-recurring nature and in the
significance of their nature or amount.
2. Financial Risk Management
Financial risk factors
The Group's activities expose it to
a variety of financial risks. The Group's overall Risk Management
program seeks to minimise potential adverse effects on the Group's
financial performance.
Management is responsible for Group
Risk Management and for identifying and evaluating financial
risks.
(a)
Market risk
(i)
Foreign currency ("FX") risk
The Group is exposed to FX risk
primarily with respect to the United States dollar. FX risk arises
from future commercial transactions and recognised assets and
liabilities which are denominated in a currency that is not the
entity's functional currency.
Foreign currency sensitivity
The Group is mainly exposed to the
currency fluctuations of the US dollar. The sensitivity analysis
principally arises on FX gain/loss on translation of the USD
denominated receivables. The following table details the Group's
sensitivity to a 10% (2022: 10%) increase and decrease in the
functional currency (TT Dollar) of the main operating subsidiary
against the US Dollar with all other variables held constant. 10%
(2022: 10%) is the sensitivity rate that best represents
Management's assessment of the possible change in the foreign
exchange rates affecting the Group. A positive number below
indicates an increase in profit and equity when the US dollar
weakens against the functional currency. For a strengthening of the
US Dollar against the functional currency, there would be an equal
and opposite impact on the profit and equity, and the balances
below would be negative.
|
2023
$'000
|
2022
$'000
|
Profit/(loss) for the year and
Equity
|
|
|
10% strengthening of the US
Dollar/ (2022: 10%)
|
(253)
|
(269)
|
10% weakening of the US Dollar/
(2022: 10%)
|
253
|
269
|
(ii)
Price risk
The Group is exposed to commodity
price risk regarding its sales of crude oil which is an
internationally traded commodity.
Price risk sensitivity
The Group is a price taker and is
mainly exposed to the risk relating to price fluctuations. The
following table details the Group's sensitivity to a 20% (2022:
20%) increase and decrease in realised oil prices. 20% (2022: 20%)
is the sensitivity rate that best represents Management's
assessment of the possible change in the oil prices that may affect
the Group. The positive number below indicates an increase in
revenue, while there would be an equal and opposite impact on
revenue if there is a decrease in prices by 20%.
|
2023
$'000
|
2022
$'000
|
Revenue
|
|
|
20% increase in price/ (2022:
20%)
|
13,885
|
18,931
|
20% decrease in price/(2022:
20%)
|
(13,885)
|
(18,931)
|
The Group did not implement any
hedge options during the financial year.
(iii)
Cash flow and fair value interest rate risk
The Group's main interest rate
risk arises from borrowings which expose the Group to cash flow
interest rate risk. The Group manages risk by limiting the exposure
to floating interest rates and maintaining a balance between
floating and fixed contract rates.
At 31 December 2023, there were no
loan commitments to attract interest rates on foreign
currency-denominated borrowings, (2022: nil). During 2023 there was
a bank overdraft facility which incurred $0.1 million interest
(2022: $0.1 million).
(b)
Credit risk
Credit risk arises from Cash and
Cash equivalents, deposits with banks and financial institutions,
as well as credit exposures to customers, including outstanding
receivables. For banks and financial institutions, Management
determines the placement of funds based on its judgement and
experience to minimise risk.
All sales are made to a state-owned
entity, Heritage.
The Group applies an IFRS 9
simplified model for measuring the ECL which uses a lifetime
expected loss allowance and are measured on the days past due
criterion. Having reviewed past payments combined with the credit
profile of its existing trade debtors in order to assess the
potential for impairment, Management made the decision in keeping
with the standard to calculate a provision for long outstanding
receivables associated with the Petrotrin outstanding ORR incentive
receipts. The ECL for those sales were assessed at the end of the
year and was immaterial. A provision matrix was applied to
determine the historical and forward-looking loss rates which was
used to ultimately calculate an ECL allowance, which resulted in a
provision being made of $0.01 million.
For Heritage sales, the ECL was
immaterial as all sales payments were made during the stipulated
time frame. However, ECL was also calculated on Joint interest
billings outstanding, which resulted in a provision of $0.1 million
(2022: $0.1 million). Similar to sales, a provision matrix was
applied to determine the historical and forward-looking loss rates
which was used to ultimately calculate an ECL allowance.
The Company also assessed impairment
through the three-stage approach to derive at the ECL. Through
assessing impairment via this method, a provision amount of $0.1
million (2022: $0.1 million) was calculated.
(c)
Liquidity risk
Prudent liquidity risk management
implies maintaining sufficient cash and short-term funds and the
availability of funding through an adequate amount of committed
credit facilities. Management monitors rolling forecasts of the
Group's liquidity and Cash and Cash equivalents on the basis of
expected cash flow. At the end of the year the Group held cash at
bank of $9.8 million (2022: $12.1 million).
Management monitors rolling
forecasts of the Group's Cash and Cash equivalents on the basis of
expected cash flows. This is carried out at the Group level in
accordance with practice and limits set by the Group, refer to the
disclosures in Note 1: Background and accounting policies - Going
Concern for more information regarding the factors considered by
the Company in managing liquidity risk.
The table below analyses the Group's
and Company's financial liabilities into relevant maturity
groupings based on their contractual maturities for:
(a) All
non-derivative financial liabilities, and
(b) Net
and gross settled derivative financial instruments for which the
contractual maturities are essential for an understanding of the
timing of the cash flows.
The following table sets out the
contractual maturities (representing undiscounted contractual
cash-flows) of financial liabilities.
Group
At 31 December 2023
|
Less than
1
year
$'000
|
1 to 2 years
$'000
|
2 to 5 years
$'000
|
Total
$'000
|
Non-derivatives
|
|
|
|
|
Trade and other payables
|
13,094
|
-
|
-
|
13,094
|
Lease liabilities
|
208
|
137
|
-
|
345
|
Bank overdraft
|
4,000
|
-
|
-
|
4,000
|
|
17,302
|
137
|
-
|
17,439
|
At 31 December 2022
|
$'000
|
$'000
|
$'000
|
$'000
|
Non-derivatives
|
|
|
|
|
Trade and other payables
|
10,045
|
-
|
-
|
10,045
|
Lease liabilities
|
584
|
204
|
137
|
925
|
Bank overdraft
|
2,700
|
-
|
-
|
2,700
|
|
13,329
|
204
|
137
|
13,670
|
Company
At 31 December 2023
|
Less than
1
year
$'000
|
Total
$'000
|
Non-derivatives
|
|
|
Trade and other payables
|
678
|
678
|
Intercompany
|
16,050
|
16,050
|
|
16,728
|
16,728
|
At 31 December 2022
|
$'000
|
$'000
|
Non-derivatives
|
|
|
Trade and other payables
|
565
|
565
|
Intercompany
|
12,731
|
12,731
|
|
13,296
|
13,296
|
(d)
Capital risk
The Group's objectives when
managing capital are to safeguard the Group's ability to continue
as a going concern in order to provide returns for shareholders and
benefits for other stakeholders and to maintain an optimal capital
structure to reduce the cost of capital. In order to maintain or
adjust the capital structure, the Group may adjust the amount of
dividends paid to shareholders, issue new shares or sell assets to
reduce debt.
Consistent with others in the
industry, the Group monitors capital on the basis of the gearing
ratio. This ratio is calculated as Net Cash/(Debt) divided by Total
Capital. Net Cash/(Debt) is calculated as total borrowings less
Cash and Cash equivalents. Borrowing relates to the overdraft
facility where all covenants (current ratio not less than 1.25:1)
were met. Total capital is calculated as 'equity' as shown in the
Consolidated Statement Of Financial position plus Net
Cash/(Debt).
|
2023
$'000
|
2022
$'000
|
Net cash
|
5,819
|
9,431
|
Total equity
|
(49,045)
|
(56,131)
|
Total capital
|
(43,226)
|
(46,700)
|
Gearing ratio
|
(13.5)%
|
(20.2)%
|
(e)
Fair value estimation
The Group and Company have
classified financial instruments into the three levels prescribed
under the accounting standards.
·
Level 1: The fair value of financial instruments
traded in active markets (such as publicly traded derivatives, and
equity securities) is based on quoted market prices at the end of
the reporting period. The quoted market price used for financial
assets held by the Group is the current bid price. These
instruments are included in level 1.
·
Level 2: The fair value of financial instruments
that are not traded in an active market (for example, over-the-
counter derivatives) is determined using valuation techniques which
maximise the use of observable market data and rely as little as
possible on entity-specific estimates. If all significant inputs
required to fair value an instrument are observable, the instrument
is included in level 2.
·
Level 3: If one or more of the significant inputs
is not based on observable market data, the instrument is included
in level 3. This is the case for unlisted equity
securities.
3. Critical Accounting Estimates and
Judgements
The preparation of the
consolidated financial statements requires the use of accounting
estimates which, by definition, seldom equal the actual results.
Management also exercise judgement in applying the Group's and the
Company's accounting policies. The estimates and assumptions that
have a significant risk of causing a material adjustment to the
carrying amounts of assets and liabilities within the next
financial year are discussed below:
(a) Recoverability of DTA
DTA mainly arise from tax losses
and are recognised only to the extent it is considered probable
that those assets will be recoverable. This involves an assessment
of when those DTA are likely to reverse, and a judgement as to
whether or not there will be sufficient taxable profits available
to offset the tax assets when they do reverse. This requires
assumptions regarding future profitability on key estimates of
future cost, production volumes, price and is therefore inherently
uncertain. To the extent assumptions regarding future profitability
change, there can be an increase or decrease in the level of DTA
recognised which can result in a charge or credit during the period
in which the change occurs. The Group has concluded that the DTA
recognised will be recoverable using approved business plans and
budgets for the specific subsidiaries in which the DTA arose. See
note 18.
(b) Provision for decommissioning
costs
This provision is significantly
affected by changes in technology, laws and regulations which may
affect the actual cost and timing of decommissioning to be incurred
at a future date:
Decommissioning Cost estimates and
reversals:
In 2023 there was a refresh of the
well abandonment cost methodology which resulted in cost reductions
for both onshore and offshore well abandonment costs. The change
resulted in a significant decrease ($6.6 million) in well
abandonment cost estimates. In addition, during 2023 the Tabaquite
licence was relinquished resulting in a $3.0 million release of
decommissioning liability. There was no material change to the
platform abandonment methodology. The total reduction in
decommissioning liability was $9.6 million.
The reduction in decommissioning
liability resulted in a reduction in the related decommissioning
asset ($ 9.6 million - refer to Note 13) and a net impact to the
statement of comprehensive income where decommissioning assets were
fully utilised ($2.5 million - refer to Note 7).
Decommissioning rates:
The estimate is also impacted by
the discount rates used in the provisioning calculations. The
discount rates used are the Group's risk-free rate and the core
inflation rate applicable. The provision has been estimated using a
rate based on maturity and a core inflation rate. See Note 28:
Provision for other liabilities
|
Bands
(years)
|
2023
|
2022
|
Risk free rates
|
6-11
|
3.84%
|
3.96%
|
|
12-18
|
3.98%
|
4.04%
|
|
19-21
|
4.22%
|
4.14%
|
|
22-23
|
4.22%
|
4.09%
|
Inflation rate
|
|
3.20%
|
3.20%
|
The following table details the
Group's sensitivity to a 1% (2022: 1%) increase and decrease in
discount and inflation rates. 1% (2022: 1%) is the sensitivity rate
that best represents Management's assessment of the possible change
in the rates that may affect the Group. A positive number below
indicates an increase in provisions and finance costs, while a
negative number indicates a decrease in provisions and finance
costs. The impact in 2023 of a 1% change in these variables is as
follows:
|
Consolidated Statement of Financial
Position:
Obligation
2023
$'000
|
Consolidated Statement of
Comprehensive Income/Expense
2023
$'000
|
Discount rate
|
|
|
1% increase in assumed
rate
|
(6,310)
|
106
|
1% decrease in assumed
rate
|
7,595
|
(273)
|
Inflation rate
|
|
|
1% increase in assumed
rate
|
7,592
|
343
|
1% decrease in assumed
rate
|
(6,419)
|
(346)
|
(c)
Estimation of reserves
All reserve estimates involve some
degree of uncertainty, which depends chiefly on the amount of
reliable geological and engineering data available at the time of
the estimate. Generally, reserve estimates are revised as
additional data becomes available. The Group's reserve estimates
are also evaluated when required by independent external reserve
evaluators. The Group estimated its own commercial reserves, guided
by international Petroleum Resource Management System (PRMS)
application guidelines, based on technical information compiled by
appropriately qualified persons relating to the geological and
technical data on the size, depth, shape and grade of the
hydrocarbon body and suitable production techniques and recovery
rates.
The key assumptions used in the
estimation of reserves are as follows:
·
Technical production profiles for the various
assets onshore and offshore held by the Group.
·
Economic assumptions such as forecast period,
discount rate, crude price, operating cost, capital expenditure and
fiscal structure.
As the economic assumptions used
may change, and as additional geological information is obtained
during the operation of a field, estimates of recoverable reserves
may also change. Such changes may impact the Group's reported
financial position and results, which include:
·
The carrying value of E&E assets, oil and gas
properties, property and plant and equipment, may be affected due
to changes in estimated future cash flows. See notes 13 and
15.
·
Depreciation and amortisation charges in the
Statement of Comprehensive Income are depreciated on a unit of
production basis at a rate calculated by reference to proved and
probable ("2P") reserve estimates and incorporating the estimated
future cost of developing and extracting those reserves. There may
be changes where such charges are determined using the unit of
production method, or where the useful life of the related assets
change. See notes 13 and 15.
·
Provisions for decommissioning may change - where
changes to the reserve estimates affect expectations about when
such activities will occur and the associated cost of these
activities. See note 28.
·
The recognition and carrying value of DTA may
change due to changes in the judgements regarding the existence of
such assets and in estimates of the likely recovery of such assets.
See note 18.
(d) Impairment of Property, Plant and
Equipment
Management performs impairment
assessments on the Group's property, plant and equipment once there
are indicators of impairment. Triggers for impairment relate to
changes in the key factors that impact on impairment which are
production, oil price, capital expenditures and operating
expenditures. In order to test for impairment, the higher of FVLCD
and VIU calculations are prepared and an estimate of the timing and
amount of cash flows expected respectively to arise from the CGU. A
CGU represents an individual field or asset held by the Group.
During 2023 an impairment charge of $1.5 million was recognised on
the Group's property, plant and equipment (2022: $5.6 million) see
Note 8. The impairment charge resulted in the carrying amount of
the respective CGUs being written down to their recoverable
amount.
Oil & Gas Assets $1.5 million
(2022: $5.6 million) impairment
Management has carried out an
impairment test on the Oil & Gas Assets classified as property,
plant and equipment. This test compares the carrying value of the
assets at the reporting date with the recoverable amount for each
CGU. The recoverable amount is the higher of the FVLCD and VIU. The
FVLCD is the amount that a market participant would pay for the CGU
less the cost of disposal. The FVLCD approach utilised a discounted
cash flow based on the 2P reserve estimates of the CGUs of the
Group. VIU is the present value of the future cash flows expected
to be derived from an asset or CGU in its current condition. The
period over which Management has projected its cash flow forecast,
ranges between 7-24 year economic lives based on the field economic
life profile. The field economic life profile was derived by using
licence extension data which is permitted in accordance with the
Society of Petroleum Engineers ("SPE") reserves reporting
guidelines outlined in the 2019 Petroleum Resource Management
System ("PRMS"). While there is the risk that licences may not be
renewed upon expiry, Management considers this to be very low based
on historic precedent. For the discounted cash flows to be
calculated, Management has used a production profile based on its
best estimate of proven and probable reserves of each CGU and a
range of assumptions, including an external oil and gas price
profile and a discount rate which, taking into account other
assumptions used in the calculation, Management considers to be
reflective of the risks. The impairment calculation considers the
decommissioning asset and liability used to derive the impairment
charge.
The discounted cash flow approach
assessment involves judgement as to the likely commerciality of the
asset. For the discounted cash flows to be calculated, Management
has used a production profile based on its 2P reserve estimate of
the assets and a range of assumptions (see note 3(c)). Its 2P
reserves which are estimated using standard recognised evaluation
techniques on a fully funded basis; future revenues and estimated
development costs and decommissioning liabilities pertaining to the
CGU's; and a discount rate utilised for the purposes of deriving a
recoverable value.
|
2024
|
2025
|
2026
|
2027
|
2028
|
2029
|
Realised price
|
64.8
|
62.1
|
60.1
|
58.7
|
57.8
|
57.4
|
If the price deck used in the
impairment calculation had been 10% lower than Management's
estimates at 31 December 2023, the Group would have a $4.1 million
increase on impairment of Oil & Gas Assets (2022: $16.1 million
increase). If the price deck used in the impairment calculation had
been 10% higher than Management's estimates at 31 December 2023,
the Group would have a $0.1 million decrease on impairment of the
Oil & Gas Assets (2022: $0.6 million decrease). The valuation
is considered to be a level 3 in the fair value hierarchy due to
unobservable inputs used in the valuation.
For the year ended 31 December
2023, Management's estimate of the Group's cost of capital was
14.4% (2022:15.0%). If the estimated cost of capital used in
determining the post-tax discount rate for the CGU's had been 1%
lower than Management's estimates the Group would have a $0.1
million increase (2022: $0.0 million) change to the impairment
position for 2023 against Oil & Gas Assets within property,
plant and equipment. If the estimated cost of capital had been 1%
higher than Management's estimates the Group would have a $0.1
million decrease to the impairment position for 2023 (2022: $0.0
million increase).
(e) Impairment of intangible E&E
assets
In estimating the recoverability
of exploration assets, Management considers contingent resources
associated with certain evaluation assets as estimated by the
Group's internal experts. Furthermore, Management factors in future
development plans and licence expiries into the assessment.
Exploration assets remain capitalised as long as sufficient
progress is being made in assessing whether petroleum production is
technically feasible and commercially viable. This assessment
requires significant Management judgement, as exploration assets
are subject to regular internal review to confirm the continued
intent to establish the technical feasibility and commercial
viability of a project. At the end of 2023 a review for impairment
triggers was carried out and there were no impairment losses
realised against the carrying values of the Group's E&E
assets.
The Group reviews the carrying
values of intangible E&E assets when there are impairment
indicators which would tell whether an E&E asset has suffered
any impairment. The amounts of intangible E&E assets represent
the costs of active projects the commerciality of which is
unevaluated until reserves can be appraised.
·
Impairment of
Jacobin Well Cost
Impairment triggers were
identified on this asset as at 31 December 2023. An impairment
assessment was performed resulting in an impairment of $9.6
million.
·
Impairment of
PS 4 E&E costs
In 2022, an E&E asset
(reclassified from Oil and Gas developed asset) was recognised for
costs relating to the PS-4 acquisition costs. At 31 December 2023,
impairment triggers were identified mainly related to the reduction
in 2C resources. An assessment was performed and resulted in the
impairment of $2.1 million.
(f) Property tax
PT is assessed on property owned
by the Group in T&T governed by the Property Tax Act 2009 and
later Property Tax 2018 amendment of T&T. The calculation of
the PT is described in note 1 Background and Summary of significant
accounting policies.
The Property Tax Act and
subsequent Amendments to the Act requires the Board of Inland
Revenue to issue a Notice of Assessment on or before 31 March each
year. The amendment in the Finance Act 2023 waives the tax up to 31
December 2023.
The collection of the tax will be
effective from 2024 for residential properties only, until the
valuation roll has been completed and the Notice of Assessment
given for the other property types. The Group will continue to
monitor developments in the Property tax law and reassess this at
each reporting period. As such, the Group has not recognised any PT
liabilities to 31 December 2023.
(g) Share-based payments
The Company has in place a
share-based compensation plan (the LTIP) for the Executive Director
and the EMT which is designed to provide long-term incentives to
align interests with shareholders. The Company measures the cost of
these equity-settled transactions by reference to the fair value of
the equity instruments at the date at which they are granted. The
fair value of share-based payments is measured using a Monte Carlo
or Black-Scholes option pricing model. The measurement inputs to
this model, including expected volatility, weighted average
expected life of the instruments, expected dividends and risk-free
interest rate, rely on Management judgements. See note 25 for
details.
4. Segment Information
Management has determined the
operating segments which are Onshore, West Coast and East Coast
reported in a manner consistent with the internal reporting
provided to the chief operating decision maker. The chief operating
decision maker is responsible for making strategic decisions
inclusive of allocating resources and assessing performance of the
operating segments. The chief operating decision maker has been
identified as the EMT (which includes the Chief Executive Officer,
Chief Financial Officer, Chief Operations Officer and Chief of
Staff & General Counsel), which makes strategic decisions in
accordance with Board policy.
Management have considered the
requirements of IFRS 8 Operating Segments, in regard to the
determination of operating segments, and concluded that the Group
has only one significant operating segment being the exploration
and development, production and extraction of
hydrocarbons.
All revenue is generated from
crude oil sales in T&T to one customer, Heritage. All revenue
is generated at a point in time. All non-current assets of the
Group are located in T&T.
5. Operating Profit
Before Impairment and Exceptional Items
|
2023
$'000
|
2022
$'000
|
Operating profit before impairment and exceptional items is
stated after taking the following items into
account:
|
DD&A (Note 13)
|
8,168
|
6,890
|
Depreciation on ROU (Note
14)
|
533
|
534
|
Amortisation of computer software
(Note 15)
|
233
|
193
|
Employee costs (Note 35)
|
9,484
|
8,317
|
Inventory recognised as expense,
charged to operating expenses
|
66
|
174
|
Auditors' remuneration
During the year the Group (including
its overseas subsidiaries) obtained the following services from the
Company's Auditors as detailed below:
|
2023
$'000
|
2022
$'000
|
- Fees
payable to the Company's auditors' and their affiliated firms for
the audit of the Parent Company and consolidated financial
statements:
|
BDO LLP (UK based)
|
358
|
220
|
BDO Limited (T&T and Barbados
based)
|
106
|
107
|
- Fees
payable to the Company's auditors' for other services: The audit of
Company's subsidiaries
|
18
|
16
|
Audit related assurance services -
interim review
|
37
|
29
|
Total assurance and auditors' remuneration
|
519
|
372
|
All fees in 2023 are in respect of
services provided by BDO LLP and their affiliated firms. The
independence and objectivity of the external auditors are
considered on a regular basis by the Audit Committee, with
particular regard to the level of non-audit fees incurred. The
professional fees relates to tax services rendered for advice on
tax losses.
6. Derivative expenses
The net (loss)/ gain in fair value
is recognised in the Consolidated Statement of Comprehensive Income
during the year:
|
31
December
2023
$'000
|
31 December
2022
$'000
|
Derivative expenses (realised)
|
-
|
(10,446)
|
Movement in FV of derivative
financial instruments (unrealised)
|
-
|
2,883
|
|
-
|
(7,563)
|
7. Decommissioning
Release/Reduction
Reduction of Decommissioning costs
estimates
|
(114)
|
-
|
Release of Decommissioning
Liablilty- Tabaquite field
|
(2,394)
|
-
|
Decommissioning release/reduction Total
|
(2,508)
|
-
|
·
Reduction of Decommissioning cost estimates $0.1
million
·
Release of Decommissioning cost estimate: $2.4
million in relation to Tabaquite Field surrendered.
See Note 3(b): Critical Accounting Estimates and
Judgement
Exceptional Items:
Items that are material either
because of their size, their nature, or that are non-recurring are
considered as exceptional items and are presented within the line
items to which they best relate. During the current period,
exceptional items as detailed below have been included in the
Consolidated Statement of Comprehensive Income. An analysis of the
amounts presented as exceptional items in these consolidated
financial statements are highlighted below.
|
31
December
2023
$'000
|
31 December
2022
$'000
|
ICT incident costs
|
161
|
161
|
Bravo Fire costs
|
146
|
-
|
Exceptional Items Total
|
307
|
161
|
·
Charges relating to ICT incident: $0.2 million
charge in relation to costs incurred in relation to the cyber
incident
·
Charges relating to Bravo Fire incident: $0.1
million charge in relation to costs incurred for the Bravo Fire in
April 2023
8. Impairment
|
31
December
2023
$'000
|
31 December
2022
$'000
|
Impairment of Inventory
|
-
|
334
|
Impairment of Jacobin Well
Costs
|
9,634
|
-
|
Impairment of PS4 E&E
costs
|
2,132
|
-
|
Impairment of property, plant and
equipment
|
1,549
|
5,558
|
Other impairment of property,
plant and equipment
|
147
|
158
|
Total expense
|
13,462
|
6,050
|
·
Impairment of
inventory - No charge in relation to inventory impairment. In 2022
$0.3 million on moving inventory items.
·
Impairment of
Jacobin Well Costs - $9.6 million charge on Exploration and
Evaluation costs relating to the Jacobin Well (See Note 3(e):
Critical Accounting Estimates and Judgement)
·
Impairment of
E&E assets - $2.1 million charge on PS4 Exploration and
Evaluation costs (See Note 3(e): Critical Accounting Estimates and
Judgement)
·
Impairment of
property, plant and equipment - $1.5 million charge in relation to
property, plant and equipment and cash generating units (See Note
3(d): Critical Accounting Estimates and
Judgement)
·
Other
impairment of property, plant and equipment - $0.1 million charge
in other property, plant equipment costs.
9. Finance income and costs
Recognised in the consolidated
statement of comprehensive income
|
2023
$'000
|
2022
$'000
|
Finance income
|
|
|
Interest Income
|
50
|
48
|
|
2023
$'000
|
2022
$'000
|
Finance costs
|
|
|
Decommissioning - Unwinding of
discount (Note 28)
|
(2,077)
|
(1,110)
|
Interest on Leases (Note
14)
|
(86)
|
(135)
|
Interest and other expenses on
overdraft
|
(51)
|
(94)
|
|
(2,214)
|
(1,339)
|
10. Income Taxation
|
2023
$'000
|
2022
$'000
|
Current Taxes
|
|
|
Petroleum profits tax
|
422
|
2,404
|
Unemployment levy
|
169
|
960
|
Deferred Taxes
|
|
|
Current year
|
|
|
Movement in asset due to tax
losses recognised (Note 18)
|
(3,238)
|
(935)
|
Movement in liability due to
accelerated tax depreciation (Note 18)
|
(78)
|
(85)
|
Income tax (credit)/ expense
|
(2,725)
|
2,344
|
The Group's effective tax rate
varies from the statutory rate for UK companies of 19% (2022:19%)
as a result of the differences shown below:
|
2023
$'000
|
2022
$'000
|
Loss/ (Profit) before taxation
|
(9,529)
|
2,457
|
Tax calculated at domestic tax
rates applicable to profits in the respective countries
|
(3,101)
|
4,836
|
Expenses not deductible for tax
purposes
|
17,005
|
13,448
|
Impact on tax losses
|
(2,327)
|
(5,671)
|
Deferred tax on capital allowances
in the current period recognised
|
(11,064)
|
(9,334)
|
Tax losses previously generated
now recognised in the current period
|
(3,238)
|
(935)
|
Tax (credit)/ charge
|
(2,725)
|
2,344
|
Corporate income tax is calculated
at 19% (2022: 19%) of the assessable profit for the year for the UK
Parent Company, 55% for the operating subsidiaries in Trinidad and
Tobago (2022: 55%) and 30% (2022: 30%) for the corporate
subsidiaries in Trinidad and Tobago.
Taxation losses at 31 December 2023
available for set off against future taxable profits amounts to
approximately
$224.4 million (2022: $227.5
million), with tax losses recognised of $31.4 million at the end of
2023. These losses do not have an expiry date. While Management
have filed Returns, these have not yet been confirmed by the Board
of Inland Revenue ("BIR") or His Majesty's Revenue and Customs
("HMRC"). Tax losses carried forward by companies engaged in
petroleum production business in Trinidad and Tobago are restricted
to set off in a year of in a year of income 75% of the otherwise
chargeable profits.
11. Earnings Per Share
Basic earnings per share is
calculated by dividing the earnings attributable to ordinary
shareholders by the weighted average number of ordinary shares
outstanding during the year. Diluted earnings per share is
calculated using the weighted average number of ordinary shares
adjusted to assume the conversion of all potentially dilutive
ordinary shares.
Year ended 31
December 2023
|
(Loss)/Profit for the year
$'000
|
Weighted Average Number
of
Shares
'000
|
Earnings
Per
Share
$
|
Basic
|
(6,804)
|
38,687
|
0.0
|
Diluted
|
(6,804)
|
38,687
|
0.0
|
Year ended 31
December 2022
|
|
|
|
Basic
|
113
|
39,094
|
0.0
|
Diluted
|
113
|
40,524
|
0.0
|
Impact of dilutive ordinary shares:
Diluted earnings per share is
calculated by adjusting the weighted average number of ordinary
shares outstanding to assume conversion of all dilutive potential
ordinary shares. The awards issued under the Company's LTIP (see
movements in number of LTIPs note 25) are considered potential
ordinary shares.
There was no impact on the weighted
average number of shares outstanding during 2023 as LTIP's were
excluded from the weighted average dilutive share calculation
because their effect would be anti-dilutive and therefore both
basic and diluted earnings per share are the same in
2023.
The basic shares balance was amended
through the net effect of the issuance of new shares (following
exercise of Options) and the repurchase of shares through the share
buyback programme in 2023 (See notes 23 and 24).
12. Investment In Subsidiaries
Company
|
|
2023
$'000
|
2022
$'000
|
Opening balance
|
60,864
|
60,347
|
Share based payment forfeiture
|
(69)
|
-
|
Share based payment
|
547
|
517
|
Closing balance
|
61,342
|
60,864
|
The investment in subsidiaries is
recognised initially at the fair value of the consideration paid.
The Group subsequently measures the investment in subsidiaries at
cost less impairments. Increases in the investment in subsidiaries
relate to capital contributed by the Company to its subsidiary
undertakings.
Listing of Subsidiaries
The Group's subsidiaries at 31
December 2023 are listed below:
Name
|
Registered Address/Country of
Incorporation
|
Nature of Business
|
% Shares held by the Group
|
Bayfield Energy Limited
|
c/o Pinsent Masons LLP,
1 Park Row, Leeds,
LS1 5AB, UK
|
Holding Company
|
99.99998%
|
Trinity Exploration &
Production (UK) Limited
|
13 Queen's Road, Aberdeen,
AB15 4YL, UK
|
Holding Company
|
100%
|
Trinity Exploration and Production
Services (UK) Limited
|
c/o Pinsent Masons LLP,
1 Park Row, Leeds,
LS1 5AB, UK
|
Service Company
|
100%
|
Bayfield Energy do Brasil
Ltda
|
Av. Presidente Vargas 509, Rio de
Janeiro, 20071-003, Brazil
|
Dormant
|
100%
|
Trinity Exploration &
Production (Barbados) Limited
|
Ground Floor, One Welches,
Welches, St. Thomas BB22025, Barbados
|
Holding Company
|
100%
|
Trinity Exploration and Production
(Trinidad and Tobago) Limited
|
3rd Floor Southern Supplies Limited
Building,
40-44 Sutton Street,
San Fernando, Trinidad &
Tobago ("Trinidad address")
|
Holding Company
|
100%
|
Trinity Exploration and Production
(Galeota) Limited
|
Trinidad address
|
Oil and Gas
|
100%
|
Oilbelt Services Limited
|
Trinidad address
|
Oil and Gas
|
100%
|
Trinity Exploration and Production
Services Limited
|
Trinidad address
|
Service Company
|
100%
|
Trinity Midstream Limited
|
Trinidad address
|
Oil and Gas
|
100%
|
Trinity Exploration and Production
(Erin 1) Limited
|
Trinidad address
|
Oil and Gas
|
100%
|
Trinity Exploration and Production
(Erin 2) Limited
|
Trinidad address
|
Oil and Gas
|
100%
|
Trinity Exploration and Production
(Forest 1) Limited
|
Trinidad address
|
Oil and Gas
|
100%
|
Trinity Exploration and Production
(Forest 2) Limited
|
Trinidad address
|
Oil and Gas
|
100%
|
Trinity Exploration and Production
(Forest 3) Limited
|
Trinidad address
|
Oil and Gas
|
100%
|
Trinity Renewable Resources
Limited
|
Trinidad address
|
Oil and Gas
|
100%
|
Trinity Exploration and Production
plc Employee Benefit Trust
|
c/o Pinsent Masons LLP
1 Park Row, Leeds,
LS1 5AB, UK
|
Employee Benefit Trust
|
100%
|
13. Property, Plant and Equipment
Year ended 31
December 2023
|
Plant
& Equipment
$'000
|
Leasehold & Buildings
$'000
|
Oil
& Gas Assets
$'000
|
Total
$'000
|
Opening net book amount at
1 January 2023
|
4,255
|
1,271
|
39,461
|
44,987
|
Additions
|
1,573
|
27
|
5,306
|
6,906
|
Transfers (Note 15)
|
-
|
-
|
319
|
319
|
Disposals
|
(21)
|
-
|
(6)
|
(27)
|
Tabaquite decommissioning asset
relinquishment
|
-
|
-
|
(632)
|
(632)
|
Reduction to decommissioning
estimate (Note 3(b))
|
-
|
-
|
(6,508)
|
(6,508)
|
Impairment charge
|
(36)
|
-
|
(1,653)
|
(1,689)
|
DD&A charge for year
|
(630)
|
(192)
|
(7,346)
|
(8,168)
|
Closing net book amount at 31 December 2023
|
5,141
|
1,106
|
28,941
|
35,188
|
At 31 December 2023
|
|
|
|
|
Cost
|
19,709
|
3,510
|
327,454
|
350,673
|
Accumulated DD&A and
impairment
|
(14,568)
|
(2,404)
|
(298,513)
|
(315,485)
|
Closing net book amount
|
5,141
|
1,106
|
28,941
|
35,188
|
Year ended 31
December 2022
|
Plant
& Equipment
$'000
|
Leasehold & Buildings
$'000
|
Oil
& Gas Assets
$'000
|
Total
$'000
|
Opening net book amount at
1 January 2022
|
2,919
|
1,388
|
45,200
|
49,507
|
Additions
|
1,999
|
71
|
13,062
|
15,132
|
Transfers (Note 3(h))
|
-
|
-
|
(2,451)
|
(2,451)
|
Adjustment to decommissioning
estimate (Note 28)
|
-
|
-
|
(4,595)
|
(4,595)
|
Impairment charge
|
(62)
|
-
|
(5,654)
|
(5,716)
|
DD&A charge for year
|
(601)
|
(188)
|
(6,101)
|
(6,890)
|
Closing net book amount at 31 December 2022
|
4,255
|
1,271
|
39,461
|
44,987
|
At 31 December 2022
|
|
|
|
|
Cost
|
18,193
|
3,483
|
323,497
|
345,173
|
Accumulated DD&A and
impairment
|
(13,938)
|
(2,212)
|
(284,036)
|
(300,186)
|
Closing net book amount
|
4,255
|
1,271
|
39,461
|
44,987
|
1
An impairment loss of $1.7 million (2022: $5.7 million) was
recognised on Oil & Gas Assets (see Note 3 (d)) as a result of
the carrying value being higher than the recoverable amount. The
recoverable amount was determined by assessing its fair value less
costs of disposal.
14. Leases
The Group has recognised ROU assets
and lease liabilities.
(i)
Amounts recognised in the Consolidated Statement of Financial
Position
The Consolidated Statement of
Financial Position shows the following amounts relating to
leases:
|
31
December
2023
$'000
|
31 December
2022
$'000
|
Right-of-use assets
|
|
|
Non-current assets
|
312
|
838
|
Lease Liabilities
|
|
|
Current
|
208
|
584
|
Non-current
|
137
|
341
|
|
345
|
925
|
The ROU assets relate to motor
vehicles, office building, rental house and office equipment leases
that met the recognition criteria of a Lease under IFRS
16.
(ii)
Amounts recognised in the Consolidated Statement of Comprehensive
Income
The Consolidated Statement of
Comprehensive Income shows the following amounts relating to
leases:
|
2023
$'000
|
2022
$'000
|
Depreciation charge of ROU assets
|
|
|
Depreciation
|
(533)
|
(534)
|
Interest expense (including
finance cost)
|
(86)
|
(135)
|
The total cash outflow for leases in
2023 was $0.7 million (2022: $0.7 million)
(iii)
The Group's leasing activities and how these are
accounted.
The Group leases various offices,
equipment, staff housing and vehicles. Rental contracts are
typically made for fixed periods of 6 months to 4 years.
Contracts may contain both lease
and non-lease components. There were no non-lease components
identified and as such the Group allocates the consideration in the
contract to a single lease component based on their relative
stand-alone prices.
Lease terms are negotiated on an
individual basis and contain a wide range of different terms and
conditions. The lease agreements do not impose any covenants other
than the security interests in the leased assets that are held by
the lessor. Leased assets may not be used as security for borrowing
purposes.
15. Intangible Assets
The carrying amounts and changes in
the year are as follows:
Year ended 31
December 2023
|
Exploration
and Evaluation assets
$'000
|
Computer
software
$'000
|
Research
and Development
$'000
|
Total
$'000
|
Opening net book amount at
1 January 2023
|
32,903
|
405
|
229
|
33,537
|
Additions
|
9,421
|
492
|
267
|
10,180
|
Transfers
|
(319)
|
-
|
-
|
(319)
|
Impairment charge
|
(11,766)
|
-
|
-
|
(11,766)
|
Amortisation charge for
year
|
-
|
(233)
|
-
|
(233)
|
Closing net book amount at 31 December 2023
|
30,239
|
664
|
496
|
31,399
|
At 31 December 2023
|
|
|
|
|
Cost
|
30,239
|
1,471
|
496
|
32,206
|
Accumulated amortisation
|
-
|
(807)
|
-
|
(807)
|
Closing net book amount
|
30,239
|
664
|
496
|
31,399
|
Year ended 31
December 2022
|
Exploration and Evaluation
assets
$'000
|
Computer software
$'000
|
Research
and Development
$'000
|
Total
$'000
|
Opening net book amount at
1 January 2022
|
30,217
|
496
|
46
|
30,759
|
Additions
|
235
|
102
|
183
|
520
|
Transfers (Note 3(h))
|
2,451
|
-
|
-
|
2,451
|
Amortisation charge for
year
|
-
|
(193)
|
-
|
(193)
|
Closing net book amount at 31 December 2022
|
32,903
|
405
|
229
|
33,537
|
At 31 December 2022
|
|
|
|
|
Cost
|
32,903
|
979
|
229
|
34,111
|
Accumulated amortisation
|
-
|
(574)
|
-
|
(574)
|
Closing net book amount
|
32,903
|
405
|
229
|
33,537
|
·
E&E assets: Represents the cost for the TGAL
1 exploration well. The Group tests whether E&E assets have
suffered any impairment triggers on an annual basis and there was
an impairment loss of $11,766 (2022: nil). See reference 3 (e)
(impairment of intangible E&E assets).
·
Computer Software: In 2023, costs incurred in
connection with the acquisition of software.
·
Research and Development: In 2023, there were
costs associated for various initiatives in connection with
reducing carbon emissions.
16. Abandonment fund
|
2023
$'000
|
2022
$'000
|
At 1
January
|
4,511
|
4,021
|
Additions
|
451
|
490
|
At 31 December
|
4,962
|
4,511
|
17. Performance
bond
|
2023
$'000
|
2022
$'000
|
At 1
January and 31 December
|
606
|
602
|
The Group's Lease Operatorship
Assets ("LOA") licences were renewed in June 2021. New Performance
Bonds for each of the LOA were put in place totaling $0.47 million
at a bond fee of 1.75% executed with First Citizens Bank Trinidad
and Tobago Limited and effective until 31 December 2030. A
performance bond of $0.13 million for PS-4 block was also executed
with First Citizens Bank Trinidad and Tobago Limited in 2022
effective 31 December 2030 at a bond fee of 1.75%. These funds have
been restricted to fixed deposits for the period of the respective
LOA licences at varying rates of interest.
18. Deferred Income Taxation
Group
The analysis of DTA is as
follows:
|
2023
$'000
|
2022
$'000
|
DTA:
|
|
|
DTA to be recovered in more than
12 months
|
(11,507)
|
(7,774)
|
DTA to be recovered in less than
12 months
|
(4,196)
|
(4,691)
|
DTL:
|
|
|
DTL to be settled in more than 12
months
|
1,862
|
1,940
|
Net DTA
|
(13,841)
|
(10,525)
|
The movement on the deferred income
tax is as follows:
|
2023
$'000
|
2022
$'000
|
At beginning of year
|
(10,525)
|
(9,505)
|
Movement for the year
|
(3,238)
|
(935)
|
Unwinding of deferred tax on fair
value uplift
|
(78)
|
(85)
|
Net DTA
|
(13,841)
|
(10,525)
|
The deferred tax balances are
analysed below:
|
2021
$'000
|
Movement
$'000
|
2022
$'000
|
Movement
$'000
|
2023
$'000
|
Acquisition
|
(33,436)
|
-
|
(33,436)
|
-
|
(33,436)
|
Tax losses recognised
|
(45,009)
|
(935)
|
(45,944)
|
(3,238)
|
(49,182)
|
Tax losses derecognised
|
66,915
|
|
66,915
|
-
|
66,915
|
|
(11,530)
|
(935)
|
(12,465)
|
(3,238)
|
(15,703)
|
|
2021
$'000
|
Movement
$'000
|
2022
$'000
|
Movement
$'000
|
2023
$'000
|
DLT
|
|
|
|
|
|
Accelerated tax depreciation and
non- current asset impairment
|
(19,375)
|
-
|
(19,375)
|
-
|
(19,375)
|
Acquisitions
|
19,580
|
-
|
19,580
|
-
|
19,580
|
Fair value uplift
|
1,820
|
(85)
|
1,735
|
(78)
|
1,657
|
|
2,025
|
(85)
|
1,940
|
(78)
|
1,862
|
DTA are recognised for tax loss
carry-forwards to the extent that the realisation of the related
tax benefit through future taxable profits are probable. Deferred
tax assets of $3.2 million have been recognised (2022: $0.9 million
was recognised) based on estimated future taxable profits. The
Group has unrecognised deferred tax assets amounting to $82.5
million which have no expiry date.
DTL have decreased by $0.1 million
related to unwinding of assets.
·
DTA and DTL can only be offset in the
consolidated statement of financial position if an entity has a
legal right to settle current tax amounts on a net basis and
deferred tax amounts are levied by the same tax authority (as per
IAS 12). The Group has no legal right to offset any DTA and
DTL.
·
Tax losses - At the end of 2023 the Group had
gross tax losses carried forward of $224.4 million (2022: $227.5
million) represented by corporate tax losses in the UK of $34.7
million (2022: $33.2 million) and PPT and Corporate tax losses in
Trinidad and Tobago of $189.7 million (2022: $194.3 million). In
the UK corporation tax losses may be carried forward indefinitely.
Similarly, in Trinidad and Tobago PPT and corporate tax losses may
be carried forward indefinitely to reduce the taxes in future
years. As of 1 January 2020, however, PPT losses can only be
utilised to shelter a maximum of 75 percent of PPT per
annum.
19. Inventories
|
Crude
oil
$'000
|
Materials and
supplies
$'000
|
Total
$'000
|
At 1
January 2023
|
125
|
3,851
|
3,976
|
Net inventory movement
|
25
|
(85)
|
(60)
|
At 31 December 2023
|
150
|
3,766
|
3,916
|
At 1
January 2022
|
96
|
3,724
|
3,820
|
Impairment (see note 8)
|
-
|
(334)
|
(334)
|
Net inventory movement
|
29
|
1,100
|
1,129
|
At 31 December 2022
|
125
|
4,490
|
4,615
|
(i) Assigning costs to inventories
The costs of individual items of
inventory within the category material and supplies are determined
using weighted average costs. The cost assigned for crude oil is
based on the lower of cost and net realisable value. In the current
year there was no impairment of inventory items (2022: $0.3
million).
20. Trade and Other Receivables
|
Group
|
|
Company
|
|
2023
$'000
|
2022
$'000
|
2023
$'000
|
2022
$'000
|
Due within 1 year
|
|
|
|
|
Amounts due from related parties
(Note 31 (d))
|
|
|
4,567
|
2,830
|
Trade receivables
|
4,393
|
4,643
|
-
|
-
|
Less: provision for impairment of
trade and intercompany receivables
|
(26)
|
(4)
|
-
|
-
|
Trade receivables: net
|
4,367
|
4,639
|
4,567
|
2,830
|
Prepayments
|
1,005
|
969
|
158
|
198
|
VAT recoverable
|
6,015
|
4,657
|
101
|
29
|
Other receivables
|
420
|
351
|
-
|
6
|
Less: provision for Impairment of
other receivables
|
(98)
|
(56)
|
-
|
-
|
|
11,709
|
10,560
|
4,826
|
3,063
|
The fair value of trade and other
receivables approximate their carrying amounts.
The Group applies the IFRS 9
simplified model for measuring ECL which uses a lifetime expected
loss allowance and are measured on the days past due
criterion.
Trade receivables - Heritage net
sales receipts have been collected on a timely basis. Since the
Joint Interest Billing ("Jibs") balances are outstanding, an ECL
was calculated at 31 December 2023 of $0.1 million (31 December
2022: $0.1 million) against Other receivables.
VAT recoverable (gross) - As at 31
December 2022 the VAT recoverable amount was $4.7 million. During
the period ending 31 December 2023, the Group generated future
refunds of $5.2 million, refunds received amounted to $3.9
million.
All trade receivables are with the
Group's only customer, Heritage. Ageing analysis of these trade
receivables as at 31 December 2023 is as follows:
|
2023
$'000
|
2022
$'000
|
Up to 30 days
|
4,313
|
4,544
|
>60 days
|
-
|
-
|
>180 days
|
54
|
95
|
|
4,367
|
4,639
|
The carrying amount of the Group's
trade and other receivables are denominated in the following
currencies:
|
Group
|
|
Company
|
|
2023
$'000
|
2022
$'000
|
2023
$'000
|
2022
$'000
|
USD
|
3,378
|
3,381
|
4,724
|
2,873
|
GBP
|
260
|
260
|
102
|
190
|
TTD
|
8,071
|
6,919
|
-
|
-
|
|
11,709
|
10,560
|
4,826
|
3,063
|
The maximum exposure to credit risk
at the reporting date is the value of each class of receivable as
shown above. The Group does not hold any collateral as
security.
The credit quality of the financial
assets that are neither past due nor impaired can be assessed by
reference to historical information about the counterparty default
rates:
|
Group
|
|
Company
|
|
2023
$'000
|
2022
$'000
|
2023
$'000
|
2022
$'000
|
Trade receivables
|
|
|
|
|
Counterparties without external
credit rating:
|
|
|
|
|
Existing customers with no
defaults in the past
|
11,709
|
10,560
|
-
|
-
|
The fair value of trade and other
receivables approximate their carrying amounts.
The Group applies the IFRS 9
simplified model for measuring expected credit losses ("ECL") using
a lifetime expected loss provision for trade and other receivables.
The expected loss rates are based on the Group's historical credit
losses experienced over a period prior to the period end. The
historical loss rates are then adjusted for current and forward-
looking information on key macroeconomic factors affecting the
Group's customer including GDP, foreign exchange rates, WTI crude
oil price and inflation rates. In calculating an ECL, two default
loss rates are established; default loss rate 1 which is calculated
through the ageing profiles of sales, and default loss rate 2 which
is default loss rate 1 adjusted based on forward looking
information.
Having reviewed past payment
performance combined with the credit rating of Heritage (and its
predecessor, Petrotrin), a Provision matrix was completed to
calculate a potential impairment on the receivable balances. Trade
receivables that are less than six months past due are not
considered impaired and at 31 December 2023, trade receivables of
$4.4 million (2022: $4.6 million) were therefore considered to be
fully performing.
At the end of 2023 a total of $0.1
million was outstanding from Petrotrin (2022: $0.1 million). An ECL
of $0.0 million was applied to the outstanding $0.1 million
receivables amount due from Petrotrin.
For other Joint Interest Billing
receivable amounts from Heritage, an ECL of $0.1 million (2022:
$0.1 million) was calculated.
21. Dividend Payable
The Company declared dividends of
US$ 0.2 million (2022: nil) for the six months ended 30 June 2023.
As at 31 December 2023, US$ 0.0 million remains payable to
shareholders.
|
As at
31
December
2023
$'000
|
As at 31 December
2022
$'000
|
Dividend declared
|
236
|
|
Dividend paid
|
(231)
|
-
|
Dividend payable
|
5
|
-
|
22. Cash and Cash Equivalents
|
Group
|
|
Company
|
|
2023
$'000
|
2022
$'000
|
2023
$'000
|
2022
$'000
|
Short term investment
|
245
|
1,033
|
245
|
1,033
|
Cash and cash equivalents
|
9,574
|
11,098
|
949
|
1,069
|
|
9,819
|
12,131
|
1,194
|
2,102
|
Cash and Cash equivalents disclosed
above and in the consolidated statement of cash flows exclude
restricted cash and are available for general use by the
Group.
23. Share Capital and Share Premium
Group
|
Number of
shares
|
Ordinary shares
$'000
|
Share
premium
$'000
|
Total
$'000
|
As at 1
January 2023
|
39,884,637
|
399
|
-
|
399
|
Shares Issued at Nominal
value
|
15,176
|
0
|
-
|
0
|
As at 31 December 2023
|
39,899,813
|
399
|
-
|
399
|
24. Treasury Shares
Treasury shares are shares in the
Company that are held by the Company. From September 2022 to June
2023, three share buyback programmes were executed.
Group and Company
|
Number of shares
|
Cost
$'000
|
Total
$'000
|
As at 1
January 2023
|
1,072,000
|
1,522
|
1,522
|
Share buybacks
|
477,000
|
566
|
566
|
Shares issued out of Treasury
|
(377,313)
|
(535)
|
(535)
|
As at 31 December 2023
|
1,171,687
|
1,553
|
1,553
|
25. Share Based Payment Reserve
The share-based payments reserve is
used to recognise:
·
The grant date fair value of options issued to
employees but not exercised
·
The grant date fair value of share awards issued
to employees
·
The grant date fair value of deferred share
awards granted to employees but not yet vested; and
·
The issue of shares held by the Employee Share
Trust to employees.
During 2023 the Group had in place
share-based payment arrangements for its employees and Executive
Directors, the LTIP. The Share Option Plan referenced below is
fully vested and expensed. The current year charge for share-based
payments are solely in relation to the LTIP arrangements shown
below, with further details of each scheme following:
|
2023
$'000
|
2022
$'000
|
At 1
January
|
2,990
|
3,784
|
Share based payment expense:
|
|
|
Exercised/lapsed options realised
to retained earnings
|
(698)
|
(1,416)
|
LTIP expense
|
520
|
622
|
At 31 December
|
2,812
|
2,990
|
Share Option Plan
Share Options were granted to
Executive Directors and to selected employees. The exercise price
of the granted option was equal to Management's best estimate of
the fair value of the shares at the time of the award of the
options. The Group has no legal or constructive obligation to
repurchase or settle the options in cash. These Share Options were
fully vested in 2015 and 2016 with nil exercised and expiry dates
in 2022 and 2023. The table below gives details:
|
|
|
2022
|
|
2021
|
Grant-Vest
|
Expiry
Date
|
Exercise
price per Share
Options
|
Number of Options
|
Exercise price per Share
Options
|
Number of Share Options
|
2012-2015
|
2022
|
|
-
|
GBP8.60
|
168,554
|
2013-2016
|
2023
|
|
28,954
|
GBP12.00
|
28,954
|
|
|
|
28,954
|
|
197,508
|
The inputs into the Black-Scholes
model for options granted in prior periods were as
follows:
Grant date
|
29 May
2013
|
14
February 2013
|
Share price
|
GBP
11.90
|
GBP
12.00
|
Average Exercise price
|
GBP
12.00
|
GBP
8.90
|
Expected volatility
|
55%
|
78%
|
Risk-free rates
|
4.5%
|
4.5%
|
Expected dividend yields
|
0%
|
0%
|
Vesting period
|
3
years
|
3
years
|
LTIP
LTIP awards are designed to provide
long-term incentives for the Executive Directors and other members
of the EMT to deliver long-term shareholder returns. Under the
plan, participants are granted options which only vest if certain
performance standards are met. Participation in the plan is at the
Board's discretion and no individual has a contractual right to
participate in the plan or to receive any guaranteed
benefits.
2017 One off Award
One Off LTIP awards were granted in
August 2017 over 2,541,600 ordinary shares and in June 2020 over a
further 142,296 ordinary shares (the "2017 One Off Award"). The
2017 One Off Award vested in full on 30 June 2022, subject to
meeting performance targets relating to the following:
·
In respect of 70% of the award, the Company's
share price growth from the 2017 placing price of 49.8 pence per
share. If the three-month volume-weighted price ("VWAP") at the
testing date is 350 pence or more per share, this part of the award
will vest in full. If the VWAP at the testing date is 49.8 pence
per share or less, this part of the award will not vest at all. If
the VWAP at the testing date is between 49.8 pence and 350 pence
per share, this part of the award will vest on a pro-rated
straight-line basis;
·
In respect of 20% of the award, repayment of the
amount due to the BIR in accordance with the terms of the Creditors
Proposal approved in 2017. The final payment occurred in 2018;
and
·
In respect of 10% of the award, redemption of all
the Convertible Loan Notes ("CLN") issued in January 2017 before
the second anniversary of their issue. All of the CLNs were
redeemed in 2018.
The total fair value of the
2017 One Off Award was $2.6 million and was expensed over the
vesting period with the full charge pro-rated over the period up to
30 June 2022. However, the 2017 One Off Award could vest in full or
in part on 30 June 2020 or 2021 with the appropriate charge being
taken over that vesting period. The fair value at grant date was
independently determined using an adjusted form of the Black
Scholes Model which includes a Monte Carlo simulation model that
takes into account the exercise price, the term of the option, the
share price at grant date and expected price volatility of the
underlying share, the expected dividend yield, the risk-free
interest rate for the term of the option and the correlations and
volatilities of the peer group companies.
The model inputs for the 2017 One
Off Award were as follows:
Grant Date
|
24
August 2017
|
30 June
2020
|
Share price at grant date
|
GBP
107.50p
|
GBP
79.00p
|
Exercise price
|
GBP
0.00
|
GBP
0.00
|
Expected volatility
|
73.3%
|
84.9%
|
Risk-free interest rates
|
0.44%
|
(0.07%)
|
Expected dividend yields
|
0%
|
0%
|
Vesting period 1
|
30 June
2020
|
-
|
Vesting period 2
|
30 June
2021
|
-
|
Vesting period 3
|
30 June
2022
|
30 June
2022
|
The final vesting of the 2017 One
Off Award was due to occur on 30 June 2022. However, as the
three-month average VWAP to 30 June 2022 of 130.0p was below that
prevailing at 30 June 2021, the remaining 1,214,744 unvested
options lapsed.
2017 and 2018 LTIP Award
In January 2019 Options over 282,400
ordinary shares and in May 2019 Options over 383,282 ordinary
shares were granted under the LTIP awards in accordance with the
policy announced to the market on 25 August 2017 in respect of the
performance of the Company in the financial years ended 31 December
2017 and 2018 respectively. These awards vested on 1 January 2021
and the May 2019 awards vested on 2 January 2022 subject to meeting
the performance criteria set out in the table below and continued
employment with the Company.
Performance
|
Vesting
|
Below the Median
|
None of the award will
vest
|
Median (50th percentile)
|
30% of the maximum award will
vest
|
Between Median and Upper
Quartile
|
Straight Line basis between these
points
|
Upper Quartile (75%)
|
100% of the maximum award will
vest.
|
Above the Upper Quartile
|
100% of the maximum award will
vest
|
These awards were subject to the
achievement of relative Total Shareholder Return ("TSR")
performance targets measured over a 3-year performance period
ending on 1 January 2021 and 31 December 2021 respectively. The
amounts stated above represent the maximum possible
opportunity.
The total fair value at grant date
of the LTIP awards granted during the period ended 31 December 2019
was $0.9 million and this was expensed over the vesting period with
the full charge pro-rated over the vesting period. The fair value
at grant date was determined using a Monte Carlo simulation model
that takes into account the exercise price, the term of the option,
the share price at grant date and expected price volatility of the
underlying share, the expected dividend yield, the risk-free
interest rate for the term of the option and the correlations and
volatilities of the peer group companies. The model inputs for the
LTIP awards granted during the period ended 31 December 2019
included:
|
2017
LTIP Award
|
2018
LTIP Award
|
Grant Dates
|
2
January 2019
|
9 May
2019
|
Share price at grant dates
|
GBP167.7p
|
GBP146.6p
|
Exercise price
|
GBP0.00
|
GBP0.00
|
Expected volatility
|
113.9%
|
113.9%
|
Risk-free interest rates
|
0.73%
|
0.73%
|
Expected dividend yields
|
0%
|
0%
|
Vesting period
|
1
January 2021
|
2
January 2022
|
2019 LTIP Award
On 25 June 2020 and 30 October 2020
Options over a total of 481,586 ordinary shares were granted under
the LTIP in accordance with the policy announced to the market on
25 August 2017 in respect of the performance of the Company in the
financial year ended 31 December 2019. These LTIP awards vested on
2 January 2023, subject to meeting the performance criteria set out
in the table below and continued employment with the
Company.
Performance
|
Vesting
|
Below the Median
|
None of the award will
vest
|
Median (50th percentile)
|
30% of the maximum award will
vest
|
Between Median and Upper
Quartile
|
Straight Line basis between these
points
|
Upper Quartile (75%)
|
100% of the maximum award will
vest.
|
Above the Upper Quartile
|
100% of the maximum award will
vest
|
These Awards are subject to the
achievement of relative TSR performance targets measured over a
three-year performance period ending on 31 December 2022. The
amounts stated above represent the maximum possible
opportunity.
The total fair value at grant date
of the LTIP awards granted during the period ended 31 December 2020
was $0.4 million and this will be pro-rated and expensed over the
vesting period. The fair value at grant date was determined using a
Monte Carlo simulation model that takes into account the exercise
price, the term of the option, the share price at grant date and
expected price volatility of the underlying share, the expected
dividend yield, the risk-free interest rate for the term of the
option and the correlations and volatilities of the peer group
companies. The model inputs for the LTIP awards granted during the
period ended 31 December 2020 included:
|
2019
LTIP Award
|
2019
LTIP Award
|
Grant Dates
|
25 June
2020
|
30
October 2020
|
Share price at grant dates
|
GBP79.0
|
GBP77.0
|
Exercise price
|
GBP0.00
|
GBP0.00
|
Expected volatility
|
84.9%
|
84.9%
|
Risk-free interest rates
|
(0.07%)
|
(0.07%)
|
Expected dividend yields
|
0%
|
0%
|
Vesting dates
|
2
January 2023
|
2
January 2023
|
2020 LTIP Award
On 13 August 2021, Options over a
total of 325,000 ordinary shares were granted under the LTIP in
accordance with a revised LTIP scheme (the Revised LTIP") in
respect of the performance of the Company in the financial year
ended 31 December 2020. These LTIP awards will vest on 1 January
2024, subject to meeting the performance criteria set and continued
employment in the Company.
The performance targets set for
awards made under the Revised LTIP during the period ended 31
December 2021 will be measured considering both the Company's
absolute TSR performance and the Company's relative TSR performance
over a three-year period, commencing with the current financial
year of the Company (i.e. a measurement period of 1 January 2021 to
31 December 2023). TSR calculations will be determined by reference
to the volume weighted three- month average price prior to the
start and end of the measurement period (with the starting average
price adjusted for the Share Consolidation). The three-month volume
weighted average price at the start of the performance period was
88p (adjusted for the Share Consolidation).
The performance targets provide
that:
·
No portion of a distinct one-half of the LTIP
Award (the "Absolute TSR Part") may vest unless the Company's
compound annual growth rate of TSR over the performance period is
at least 10% p.a., for which 30% of the Absolute TSR Part may vest,
rising on a straight-line basis for full vesting of the Absolute
TSR Part if the Company's compound annual growth rate of TSR over
the performance period equals or exceeds 25% p.a.
·
No portion of the other distinct one-half of the
LTIP Award (the "Relative TSR Part") may vest unless the Company's
TSR over the performance period ranks at least median relative to
the TSR performance within a comparator group of companies, for
which 30% of the Relative TSR Part may vest, rising on a straight
line basis for full vesting of the Relative TSR Part if the
Company's TSR over the performance period ranks upper quartile or
better relative to the TSR performance within a comparator group.
However, an underpin term applies to the Relative TSR Part which
provides that, regardless of relative TSR performance, no vesting
may ordinarily accrue in respect of the Relative TSR Part unless
the Company's compound annual growth rate of TSR over the
performance period is at least 10% per annum.
The total fair value at grant date
of the LTIP awards granted during the period ended 31 December 2021
was $0.7 million and this will be pro-rated and expensed over the
vesting period. The fair value at grant date was determined using a
Monte Carlo simulation model that takes into account the exercise
price, the term of the option, the share price at grant date and
expected price volatility of the underlying share, the expected
dividend yield, the risk-free interest rate for the term of the
option and the correlations and volatilities of the peer group
companies. The model inputs for the LTIP awards granted during the
period ended 31 December 2021 included:
|
2020
LTIP Award
|
Grant Date
|
13
August 2021
|
Share price at grant dates
|
GBP146.00p
|
Exercise price
|
GBP0.00
|
Expected volatility
|
6.3%
|
Risk-free interest rates
|
(0.20%)
|
Expected dividend yields
|
0%
|
Vesting dates
|
1
January 2024
|
2021 LTIP Award
On 6 June 2022, 24 October 2022 and
9 December 2022 Options over a total of 415,000 ordinary shares
were granted in accordance with the Revised LTIP in respect of the
performance of the Company in the financial year ended 31 December
2021. The earliest vesting date for the Award will be 1 January
2025, subject to meeting the performance criteria set and continued
employment in the Company.
The performance targets set for
awards made under the Revised LTIP during the period ended 31
December 2022 will be measured considering both the Company's
absolute TSR performance and the Company's relative TSR performance
over a three-year period, commencing with the current financial
year of the Company (i.e. a measurement period of 1 January 2022 to
31 December 2024). TSR calculations will be determined by reference
to the volume weighted three month average price prior to the start
and end of the measurement period (with the starting average price
adjusted for the Share Consolidation). The three-month volume
weighted average price at the start of the performance period was
£1.38 (adjusted for the Share Consolidation).
The performance targets provide
that:
·
No portion of a distinct one-half of the LTIP
Award (the "Absolute TSR Part") may vest unless the Company's
compound annual growth rate of TSR over the performance period is
at least 10% p.a., for which 30% of the Absolute TSR Part may vest,
rising on a straight line basis for full vesting of the Absolute
TSR Part if the Company's compound annual growth rate of TSR over
the performance period equals or exceeds 20% p.a.
·
No portion of the other distinct one-half of the
LTIP Award (the "Relative TSR Part") may vest unless the Company's
TSR over the performance period ranks at least median relative to
the TSR performance within a comparator group of companies, for
which 30% of the Relative TSR Part may vest, rising on a straight
line basis for full vesting of the Relative TSR Part if the
Company's TSR over the performance period ranks upper quartile or
better relative to the TSR performance within a comparator group.
However, an underpin term applies to the Relative TSR Part which
provides that, regardless of relative TSR performance, no vesting
may ordinarily accrue in respect of the Relative TSR Part unless
the Company's compound annual growth rate of TSR over the
performance period is at least 10% per annum.
The total fair value at grant date
of the LTIP awards granted in the period ended 31 December 2022 was
$0.6 million and this will be pro-rated and expensed over the
vesting period. The fair value at grant date was determined using a
Monte Carlo simulation model that takes into account the exercise
price, the term of the option, the share price at grant date and
expected price volatility of the underlying share, the expected
dividend yield, the risk-free interest rate for the term of the
option and the correlations and volatilities of the peer group
companies. The model inputs for the LTIP awards granted during the
period ended 31 December 2022 included:
|
2021
LTIP Award
|
Grant Date
|
Jun/Oct/Dec 2022
|
Share price at grant dates
|
GBP135p/120p/108p
|
Exercise price
|
GBP0.00
|
Expected volatility
|
79%
|
Risk-free interest rates
|
1.83%/3.59%/3.28%
|
Expected dividend yields
|
0%
|
Vesting dates
|
1
January 2025
|
2022 LTIP Award
On 22 August 2023, the Company
announces that 565,000 options have been granted under the LTIP in
respect of the Company's performance in the year to 31 December
2022 (the "2022 LTIP Award"), including 100,000 options granted to
Jeremy Bridglalsingh, Chief Executive Officer, 175,000 options
granted to Julian Kennedy, Chief Financial Officer, (CFO) (of which
100,000 are one-off options granted on joining the Board), and
100,000 one-off options granted to the new Chief Operating Officer,
(COO) who joined earlier this year. The 2022 Annual LTIP Award
represents 1.42% of the Company's current issued share capital.
Excluding the one-off options issued to the CFO and COO concerning
their appointments, the 2022 Annual LTIP Award represents 0.91 per
cent of the current issued share capital of the Company.
The performance targets set for
awards made under the 2022 Annual LTIP Award will be measured
considering both the Company's absolute TSR performance and the
Company's relative TSR performance over a three-year period,
commencing with the current financial year of the Company (i.e. a
measurement period of 1 January 2023 to 31 December 2025). TSR
calculations will be determined by reference to the three-month
average closing price prior to the start and end of the measurement
period. The three-month average closing price at the start of the
performance period for the 2022 Annual LTIP Award was
£1.15.
The performance targets provide
that:
·
No portion of a distinct one-half of the 2022
Annual LTIP Award (the "Absolute TSR Part") may vest unless the
Company's compound annual growth rate of TSR over the performance
period is at least 10% p.a., for which 30% of the Absolute TSR Part
may vest, rising on a straight line basis for full vesting of the
Absolute TSR Part if the Company's compound annual growth rate of
TSR over the performance period equals or exceeds 20%
p.a.
·
No portion of the other distinct one-half of the
2022 Annual LTIP Award (the "Relative TSR Part") may vest unless
the Company's TSR over the performance period ranks at least median
relative to the TSR performance within a comparator group of
companies, for which 30% of the Relative TSR Part may vest, rising
on a straight line basis for full vesting of the Relative TSR Part
if the Company's TSR over the performance period ranks upper
quartile or better relative to the TSR performance within a
comparator group. However, an underpin term applies to the Relative
TSR Part which provides that, regardless of relative TSR
performance, no vesting may ordinarily accrue in respect of the
Relative TSR Part unless the Company's compound annual growth rate
of TSR over the performance period is at least 10% per
annum.
The total fair value at grant date
of the LTIP awards granted in the period ended 31 December 2023 was
$0.8 million and this will be pro-rated and expensed over the
vesting period. The fair value at grant date was determined using a
Monte Carlo simulation model that takes into account the exercise
price, the term of the option, the share price at grant date and
expected price volatility of the underlying share, the expected
dividend yield, the risk-free interest rate for the term of the
option and the correlations and volatilities of the peer group
companies. The model inputs for the LTIP awards granted during the
period ended 31 December 2023 included:
|
2022
LTIP Award
|
Grant Date
|
August
2023
|
Share price at grant dates
|
GBP
90p
|
Exercise price
|
GBP0.00
|
Expected volatility
|
52%
|
Risk-free interest rates
|
5.01%
|
Expected dividend yields
|
0%
|
Vesting dates
|
1
January 2026
|
Movements in the number of LTIPs
outstanding and their related weighted average exercise prices are
as follows:
|
2023 Average exercise price
per Share Option
|
Number of Options
|
2022
Average exercise price per Share
Option
|
Number of Options
|
At 1
January
|
GBP
0.00
|
1,430,360
|
GBP
0.00
|
3,381,299
|
Forfeited/Lapsed
|
GBP
0.00
|
(231,930)
|
GBP
0.00
|
(1,360,733)
|
Granted1
|
GBP
0.00
|
565,000
|
GBP
0.00
|
415,000
|
Exercised
|
GBP
0.00
|
(463,608)
|
GBP
0.00
|
(1,005,206)
|
At 31 December
|
GBP
0.00
|
1,299,822
|
GBP
0.00
|
1,430,360
|
1 Weighted average fair value of
LTIPs granted GBP 1.15
LTIPs outstanding at the end of the
year have the following expiry date and exercise prices:
Grant-Vest
|
Expiry
date
|
Exercise price
|
2023
|
2022
|
24/8/2017 - 30/6/2022
|
24/08/2027
|
GBP
0.00
|
-
|
167,037
|
2/1/2019 - 1/1/2021
|
1/1/2024
|
GBP
0.00
|
-
|
50,858
|
9/5/2019 - 2/1/2021
|
2/1/2025
|
GBP
0.00
|
-
|
90,879
|
25/6/2020 - 2/1/2023
|
2/1/2026
|
GBP
0.00
|
94,822
|
381,586
|
13/8/2021 - 31/12/2023
|
2/1/2027
|
GBP
0.00
|
275,000
|
325,000
|
6/6/2022 - 1/1/2025
|
1/1/2027
|
GBP
0.00
|
365,000
|
415,000
|
22/8/2023 - 1/1/2026
|
1/1/2028
|
GBP
0.00
|
565,000
|
-
|
26. Merger and Reverse Acquisition Reserves
|
Reverse Acquisition
Reserve
$'000
|
Merger Reserve
$'000
|
Total
$'000
|
At 1
January 2023
|
(89,268)
|
-
|
(89,268)
|
Capital re-organisation/reduction
|
-
|
-
|
-
|
Translation differences
|
-
|
-
|
-
|
At 31 December 2023
|
(89,268)
|
-
|
(89,268)
|
At 1
January 2022
|
(89,268)
|
-
|
(89,268)
|
Capital re-organisation/reduction
|
-
|
-
|
-
|
Translation differences
|
-
|
-
|
-
|
At 31 December 2022
|
(89,268)
|
-
|
(89,268)
|
The issue of shares by the Company
as part of the reverse acquisition (February 2013) met the criteria
for merger relief such that no share premium was recorded. As
allowed under the UK Companies Act 2006 and required by IAS 27
('Consolidated and separate financial statements'), a merger
reserve equal to the difference between the fair value of the
shares acquired by the Company and the aggregation of the nominal
value of the shares issued by the Company has been
recorded.
27. Adjusted EBITDA
Adjusted EBITDA is a non-IFRS
measure used by the Group to measure business performance. It is
calculated as Operating Profit before SPT, PT, Impairment and
Exceptional Items for the period, adjusted for DD&A, ILFA, SOE,
FX Gain/(Loss) and the movement in the FV of Derivative Financial
Instruments.
The Group presents Adjusted EBITDA
as it is used in assessing the Group's growth and operational
efficiencies as it illustrates the underlying performance of the
Group's business by excluding items not considered by Management to
reflect the underlying operations of the Group.
Adjusted EBITDA is calculated as
follows:
|
2023
$'000
|
2022
$'000
|
Operating Profit Before SPT,
Impairment and Exceptional Items
|
9,593
|
18,971
|
DD&A (note 13 - 15)
|
8,935
|
7,617
|
ILFA (Note 20)
|
64
|
(46)
|
SOE (Note 24)
|
528
|
647
|
FX (loss)/gain
|
65
|
394
|
Loss on disposal
|
15
|
-
|
Movement in FV of Derivative
Financial Instruments (Note 6)
|
-
|
(2,883)
|
Adjusted EBITDA
|
19,200
|
24,700
|
|
'000
|
'000
|
Weighted average ordinary shares
outstanding - basic
|
38,867
|
39,094
|
Weighted average ordinary shares
outstanding - diluted
|
39,987
|
40,524
|
|
$
|
$
|
Adjusted EBITDA per share -
basic
|
0.50
|
0.64
|
Adjusted EBITDA per share -
diluted
|
0.48
|
0.61
|
Adjusted EBIDA after Current
Taxes (the impact of SPT and
PPT/UL) is calculated as follows:
|
2023
$'000
|
2022
$'000
|
Adjusted EBITDA
|
19,200
|
24,700
|
SPT
|
(5,697)
|
(9,012)
|
PT
|
(591)
|
(3,365)
|
Adjusted EBIDA After Current Taxes
|
12,912
|
12,323
|
|
'000
|
'000
|
Weighted average ordinary shares
outstanding - basic
|
38,687
|
39,094
|
Weighted average ordinary shares
outstanding - diluted
|
39,987
|
40,524
|
|
$
|
$
|
Adjusted EBIDA After Current Taxes
per share - basic
|
0.33
|
0.32
|
Adjusted EBIDA After Current Taxes
per share - diluted
|
0.32
|
0.31
|
28. Provision for Other Liabilities
(a)
Non-current:
Year ended 31
December 2022
|
Decommissioning
provision
$'000
|
Closure of pits
$'000
|
Total
$'000
|
Opening amount as at
1 January 2023
|
51,857
|
603
|
52,460
|
Unwinding of discount (Note
9)
|
2,077
|
-
|
2,077
|
Revision to estimates (Note
13)
|
(9,638)
|
-
|
(9,638)
|
Additions
|
-
|
40
|
40
|
Translation differences
|
137
|
-
|
137
|
Closing balance at 31 December 2023
|
44,433
|
643
|
45,076
|
Year ended 31
December 2022
|
|
|
|
Opening amount as at
1 January 2022
|
55,220
|
470
|
55,690
|
Unwinding of discount (Note
9)
|
1,110
|
-
|
1,110
|
Revision to estimates (Note
13)
|
(4,595)
|
-
|
(4,595)
|
Additions
|
-
|
138
|
138
|
Translation differences
|
122
|
(5)
|
117
|
Closing balance at 31 December 2022
|
51,857
|
603
|
52,460
|
Decommissioning provision
The Group operates oil fields and
this cost represents an estimate of the amounts required for
abandonment of the Group's wells, platforms, gathering station and
pipeline infrastructures. The amounts are calculated based on the
provisions of existing contractual agreements with Heritage and
MEEI. Furthermore, liabilities for decommissioning costs are
recognised when the Group has an obligation to dismantle and remove
a facility or an item of plant and to restore the site on which it
is located, and when a reasonable estimate of that liability can be
made. An obligation for decommissioning may also crystallise during
the period of operation of a facility through a change in
legislation or through a decision to terminate
operations.
The amount recognised is the present
value of the estimated future expenditure determined in accordance
with local conditions and requirements. A corresponding item of
property, plant and equipment of an amount equivalent to the
provision is also created. This is subsequently depreciated as part
of the capital costs of the facility or item of plant. Any change
in the present value of the estimated expenditure is reflected as
an adjustment to the provision and the corresponding property,
plant and equipment. Some of the key assumptions made in the
present value decommissioning calculation include the
following:
a.
Core inflation rate - 3.20% (2022: 3.20%)
b.
Risk free rate - 3.84% - 4.22% (2022: 3.96% - 4.14%)
c.
Estimated market value/decommissioning cost
d.
Estimated life of each asset
See Note 3(b): Critical Accounting Estimates and Assumptions
for the rates used and sensitivity analysis.
Closure of Pits
Closure of pits relate to the remedy
and closure of pits associated with drilling new onshore wells. It
is an environmental regulatory requirement set by the Environmental
Management Authority ("EMA") that all open drill pits for onshore
drilling must be closed after sufficient testing has deemed it safe
to close the pit.
(b)
Current:
Year ended 31
December 2023
|
Litigation claims
$'000
|
Other provisions
$'000
|
Total
$'000
|
Opening amount as at
1 January 2022
|
137
|
112
|
249
|
Payments
|
(15)
|
(112)
|
(127)
|
Additions
|
-
|
500
|
500
|
Closing balance at 31 December 2023
|
122
|
500
|
622
|
Year ended 31
December 2022
|
|
|
|
Opening amount as at
1 January 2021
|
46
|
-
|
46
|
Additions
|
91
|
112
|
203
|
Closing balance at 31 December 2022
|
137
|
112
|
249
|
Litigation claims
Other provisions
There was a provision of $0.5
million in relation to drilling costs for the Jacobin
well.
29. Trade and Other Payables
|
Group
|
|
Company
|
Current
|
2023
$'000
|
2022
$'000
|
2023
$'000
|
2022
$'000
|
Trade payables
|
3,154
|
2,605
|
256
|
136
|
Accruals
|
5,747
|
4,661
|
422
|
429
|
VAT payable
|
245
|
113
|
|
|
Other payables
|
2,560
|
500
|
-
|
-
|
SPT
|
1,388
|
2,166
|
-
|
-
|
|
13,094
|
10,045
|
678
|
565
|
30. Bank overdraft
|
31
December
2023
$'000
|
31 December
2022
$'000
|
Bank Overdraft
|
4,000
|
2,700
|
|
4,000
|
2,700
|
An on-demand operating (overdraft)
line of $8.0 million exists with FirstCaribbean International Bank
(Trinidad & Tobago) Limited ("CIBC"). Details of the overdraft
facility:
·
Description: Demand revolving credit.
·
Interest Rate: United States dollar prime rate
minus 6.50% per annum, effective rate 7.75%. Interest is payable
monthly.
·
Repayment: Upon demand at CIBC's
discretion.
·
Debenture: Floating charge debenture giving the
lender a first ranking floating charge over inventory and trade
receivables only.
·
Covenant: Current Ratio not less than
1.25:1.
The credit limit on the facility is
$8.0 million of which $4.0 million was drawn as at 31 December
2023.
31. Related Party
Transactions
Group
The following transactions were
carried out with the Group's subsidiaries and related parties.
These transactions comprise sales and purchases of goods and
services and funding provided in the ordinary course of business
during the year. The following are the major transactions and
balances with related parties:
(a)
Transfers of funds from related parties
Company
|
|
2023
$'000
|
2022
$'000
|
Company subsidiaries:
|
|
|
Trinity Exploration and Production
Services Limited
|
4,600
|
10,510
|
Bayfield Energy Limited
|
1
|
80
|
Trinity Exploration and Production
(Trinidad and Tobago) Limited
|
-
|
1,800
|
Trinity Exploration and Production
Services Limited (UK) Limited
|
35
|
1,100
|
|
4.636
|
13,490
|
(b)
Transfer of funds to related parties
Company
|
|
2023
$'000
|
2022
$'000
|
Company subsidiaries:
|
|
|
Trinity Exploration and Production
Services Limited
|
(1,000)
|
-
|
Bayfield Energy Limited
|
(75)
|
-
|
Trinity Exploration and Production
Services Limited (UK) Limited
|
(2,079)
|
(1,265)
|
|
(3,154)
|
(1,265)
|
Related party transactions comprise
of the transfer of funds to and from related parties which are
payable on demand. Positive balances indicate increase in funds
transferred to the entities, while negative balances indicate
repayment to entities.
(c)
Key Management and Directors' compensation: Key Management includes
Board (Executive & Non- Executive). The compensation paid or
payable to Key Management for employee services is shown
below:
Group
|
|
2023
$'000
|
2022
$'000
|
Salaries and short-term employee
benefits
|
857
|
876
|
Post-employment benefits
|
40
|
30
|
Share-based payment expense
|
196
|
279
|
|
1,093
|
1,185
|
(d)
Year-end balances arising from transfer to and from related
parties
Company
|
|
2023
$'000
|
2022
$'000
|
Receivables from related parties:
|
|
|
Trinity Exploration &
Production (UK) Limited
|
80
|
40
|
Trinity Exploration and Production
(Galeota) Limited
|
15
|
2
|
Bayfield Energy Limited
|
204
|
122
|
Trinity Exploration and Production
Services (UK) Limited
|
4,384
|
2,652
|
Total intercompany receivables
|
4,683
|
2,816
|
(Provision for
impairment)/Reversal of provision for impairment
|
(116)
|
14
|
Closing intercompany receivables (Note 20)
|
4,567
|
2,830
|
Company
·
The receivables from related parties arise mainly
from inter-group recharges. The receivables are unsecured and bear
no interest. An ECL provision was calculated $0.1 million (2022:
0.1 million).
Company
|
|
2023
$'000
|
2022
$'000
|
Payables to related parties:
|
|
|
Trinity Exploration and Production
Services Limited
|
14,135
|
10,683
|
Trinity Exploration and Production
(Trinidad & Tobago) Ltd
|
1,779
|
1,779
|
Oilbelt Services Limited
|
136
|
269
|
Total intercompany payables
|
16,050
|
12,731
|
32. Taxation Payable
|
2023
$'000
|
2022
$'000
|
Taxation payable
|
|
|
PPT
|
31
|
4
|
UL
|
12
|
-
|
|
43
|
4
|
Trinidad and Tobago statutory
petroleum profit tax ("PPT") and unemployment levy ("UL") are a
combined rate of 55% of taxable income. PPT has a tax charge of
50%, while UL has a tax charge of 5% on taxable profits.
33. Financial Instruments by Category
At 31 December 2023 and 2022, the
Group held the following financial assets at amortised
cost:
|
Group
|
|
Company
|
|
2023
$'000
|
2022
$'000
|
2023
$'000
|
2022
$'000
|
Trade and other receivables -
current*
|
5,199
|
5,165
|
-
|
6
|
Abandonment fund - non
current
|
4,962
|
4,511
|
-
|
-
|
Intercompany
|
-
|
-
|
4,567
|
2,830
|
Cash and cash equivalents
|
9,819
|
12,131
|
1,194
|
2,102
|
|
19,980
|
21,807
|
5,761
|
4,938
|
Note (*): Excludes prepayments and
VAT recoverable
At 31 December 2023 and 2022, the
Group held the following financial liabilities at amortised
cost:
|
Group
|
|
Company
|
|
2023
$'000
|
2022
$'000
|
2023
$'000
|
2022
$'000
|
Accounts payable and accruals
|
8,901
|
9,932
|
677
|
565
|
Intercompany
|
-
|
-
|
16,050
|
12,731
|
Bank overdraft
|
4,000
|
2,700
|
-
|
-
|
|
12,901
|
12,632
|
16,727
|
13,296
|
At 31 December 2023 and 2022, the
Group held no financial liabilities at fair value through profit or
loss.
34. Commitments and
Contingencies
a)
Commitments
There are commitments for
decommissioning costs of the wells and facilities under the Group's
agreements with Heritage, which have been provided for as described
in Note 28: Provision for other liabilities.
b)
Contingent Liabilities
i)
Parent Company Guarantee:
a)
PGB - A Letter of Guarantee has been established in substance over
the PGB Block where a subsidiary of Trinity is obliged to carry out
a Minimum Work Programme to the value of $8.4 million. A clause
within the Letter of Guarantee implies that the Guarantor may
reduce the Guarantee Sum available for payment to the MEEI under
the Letter of Guarantee on an obligation by obligation basis
provided PGB delivers to the Guarantor a certificate duly issued
and signed by the MEEI.
b)
Galeota - A Letter of Guarantee has been established in substance
over the Galeota Block where a subsidiary of Trinity is obliged to
carry out a Minimum Work Programme to the value of $0.9 million. A
clause within the Letter of Guarantee implies that the Guarantor
may reduce the Guarantee Sum available for payment to the MEEI
under the Letter of Guarantee on an obligation by obligation basis
provided the subsidiary of Trinity delivers to the Guarantor a
certificate duly issued and signed by the Minister of the MEEI. The
Letter of Guarantee was effective from 14 July 2021 until the
earlier of performance of Minimum Work Programme or the Guarantor
has paid the Guarantee amount.
ii)
Jacobin drilling disputed cost: There is a disputed drilling cost
of $2.4 million with a supplier in relation to the Jacobin well,
where Management has included a provision for $0.5 million which it
believes is appropriate based on external advice obtained. $1.9
million is disclosed as a contingent liability.
iii)
The Group is party to various claims and actions. Management has
considered the matters and where appropriate has obtained external
legal advice. No material additional liabilities are expected to
arise in connection with these matters, other than those already
provided for in these consolidated financial statements.
35. Employee Costs
|
Group
|
|
Company
|
|
2023
$'000
|
2022
$'000
|
2023
$'000
|
2022
$'000
|
Employee costs for the Group during the year
|
|
|
|
|
Wages and salaries
|
8,489
|
7,245
|
432
|
483
|
Other pension costs
|
467
|
425
|
70
|
-
|
Share based payment expense
|
528
|
647
|
41
|
107
|
|
9,484
|
8,317
|
543
|
590
|
Average monthly number of people
(including Executive and
Non-Executive Directors') employed by the Group
|
2023
number
|
2022
number
|
2023
number
|
2022
number
|
Executive and Non-Executive
Directors
|
5
|
6
|
6
|
6
|
Administrative staff
|
107
|
102
|
-
|
-
|
Operational staff
|
170
|
168
|
-
|
-
|
|
282
|
276
|
6
|
6
|
36.
Events after the Reporting Period
1. Subsequent to
31 December 2023, the Group received VAT refunds of USD 0.8
million. As at 22 May 2024, the Group had USD 5.1 million in VAT
refunds recoverable.
2. On 13 June
2023, Trinity announced its successful bid for the onshore Buenos
Ayres block. Subsequent to 31 December 2023, the Group is awaiting
finalisation of the exploration and production licence with the
MEEI.
3. Fiscal
reforms (Finance Act) - Effective 1 January 2024, SPT rates for
Small Shallow Marine Area Producers were introduced. It becomes
applicable when the weighted average realised crude oil price
exceeds US$75/bbl, starting at a rate of 18% and goes up to 40%
depending on the price.
A Small Shallow Marine Area
Producer is defined as a person who carries out petroleum
operations in shallow marine areas under a licence, sub-licence or
contract and produces less than 4,000 barrels of crude oil per
day.
4. On 1 May
2024, the board of directors of each of Touchstone and Trinity
announced that they have reached an agreement on the terms of a
recommended all share offer pursuant to which Touchstone will
acquire the entire issued and to be issued ordinary share capital
of Trinity (the "Acquisition"). The Acquisition is to be effected
by means of a scheme of arrangement under Part 26 of the Companies
Act. Under the terms of the Acquisition, Trinity Shareholders shall
be entitled to receive 1.5 New Touchstone Shares. Further
information on the transaction can be found on our website at
https://trinityexploration.com/.