TIDMTRIN
RNS Number : 2604B
Trinity Exploration & Production
01 June 2023
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.
1 June 2023
Trinity Exploration & Production plc
("Trinity" or "the Group" or "the Company")
Full Year Results to 31 December 2022
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 2022
("the Period" or "FY 2022").
During 2022 Trinity put in place the foundations for an
ambitious growth programme, developing a series of catalysts to
drive shareholder value that we are now starting to execute in
2023. These include:
-- drilling the Jacobin well targeting the deeper Miocene-age
turbidite play in our onshore blocks;
-- the application for the highly prospective Buenos Ayres block
in the 2022 Onshore Bid Round, the outcome of which is expected
shortly; and
-- revised planning to further exploit the Galeota offshore
block, focused on greater capital efficiency and shorter
development and payback times .
Underlining the resilience of the base business, the Company is
committing to a new Capital Allocation Policy which will include a
modest but sustainable dividend commencing in Q3 2023 with an
intent for that to form part of a broader distribution of operating
cash flow to shareholders, depending on realised oil prices.
Highlights
-- Group net sales for 2022 were 2,975 bopd (2021: 3,006 bopd)
-- Revenues of USD 92.2 million (2021: USD 66.3 million)
-- Profit before tax of USD 2.5 million (2021: USD 3.0 million)
-- Average price per barrel received was USD 84.9/bbl (2021: USD 60.4/bbl)
-- Adjusted EBITDA (before hedge costs) of USD 35.1 million (2021: USD 21.1 million)
-- Adjusted EBITDA of USD 24.7 million (2021: USD 19.8 million)
-- Operating Profit* of USD 19.0 million (2021: USD 9.3 million)
-- Cash generated from continuing operations USD 12.0 million (2021: USD 12.6 million)
-- Cash flow used in investing activities USD 15.6 million (2021: USD 13.9 million)
-- Year-end cash USD 12.1 million (2020: USD 18.3 million)
* Before SPT, Impairments and Exceptional Items
New Capital Allocation Policy
-- The Company aims to distribute 15% of operating cash flow to
shareholders, for each calendar year when the realised oil price is
greater than $50/bbl, and at least 20% of operating cash flow for
periods when the realised price is above $80/bbl
-- Payment of a modest but sustainable dividend and the scope
for additional distributions in the form of share buybacks or
special dividends
-- Expected to include a total dividend (split 1/3 interim, 2/3
final) of 1.5p per share, provided the realised price is at least
$50/bbl
-- It is expected that the maiden interim dividend will be
declared following publication of the 2023 interim results, in Q3
2023, followed by a final dividend declared following publication
of the 2023 preliminary results in Q2 2024
Positioned for Next Growth Phase and progressing catalysts
-- Dynamic strategy for growth is underpinned by a strong
balance sheet and resilient and dependable cash flow
-- Clearly defined, risk-mitigated strategy to drive returns for
shareholders - focus on maximising value from existing assets and
through acquisitions and partnerships
-- Strengthened Management Team
-- Additions of Julian Kennedy, Mark Kingsley and Alistair Green
further strengthening financial/commercial, operational and wider
industry skill sets
-- Creation of Technical Committee
-- Focused on risk-mitigation and assurance of opportunities
which can increase scale and optimise returns
Post Period Highlights
-- Continued momentum into Q1 2023
-- Q1 production levels resilient with sales volumes averaging
2,899 bopd (Q4 2022: 2,961 bopd). Average production in 2023 will
be influenced by the timing and outcome of the drilling campaign
and continued workover and recompletion programme.
-- Average realisation of USD 67.9 /bbl for Q1 2023 (Q4 2022:
USD 75.4/bbl, Q1 2022: USD 83.1/bbl)
-- Cash balance of USD 11.4 million (unaudited) as at 31 March
2023 versus USD 12.1 million as at 31 December 2022 and USD 17.5
million as at 31 March 2022.
-- The Group had drawn borrowings (overdraft) of USD 2.3 million
as at 31 March 2023 (USD 2.7 million as at 31 December 2022 and USD
2.7 million as at 31 March 2022).
-- On 9 January 2023, the Company submitted a bid for the Buenos
Ayres block in the 2022 Onshore and Nearshore Competitive Bid
Round. The results of the Bid Round are expected shortly.
-- On 3 May 2023, the Government of Trinidad and Tobago Ministry
of Energy and Energy Industries ("MEEI") provided confirmation of
the renewal of the PGB Licence for an additional 25 years from the
Effective Date of 18 December 2012. Consequently, the PGB Licence
expires on 17 December 2037. There were no additional liabilities
and commitments arising from the renewed Licence.
-- The Company commenced drilling the Jacobin prospect on 15 May
2023, the first of the nine 'Hummingbird' deeper prospects our 3D
seismic has identified across our Palo Seco acreage .
Jeremy Bridglalsingh, Chief Executive Officer of Trinity,
commented:
"During 2022 Trinity initiated an ambitious growth programme,
seeking to develop a series of catalysts to drive shareholder value
that we are now starting to execute in 2023. We have actioned three
key growth initiatives which we believe have the potential to
deliver meaningful value for shareholders.
Our core business has continued to perform consistently, forming
the basis upon which the capital allocation policy has been
designed. The spudding of Jacobin is an important milestone for the
Company and will help determine our further activities throughout
2023 as we look to harness the potential of the extensive Palo Seco
play which extends into the Buenos Ayres block to the west, which
Trinity applied for in the 2022 Onshore Bid Round. On Galeota we
initiated a revised development plan, including the existing
Trintes producing field as well as appraisal and exploration
opportunities, which we are aiming to finalise by Q4 this year.
2022 was a significant year for Trinity and 2023 has begun to
bear the fruits of this work. I believe we have the right focus to
deliver further progress and I look forward to updating our key
stakeholders as we move through the year. "
Investor Presentation
The Company will host a presentation through the digital
platform Investor Meet Company on 14 June 2023 at 10:00 British
Summer Time. Management will discuss the results and the Company's
growth strategy.
The presentation is open to all existing and potential
shareholders. Questions can be submitted pre-event via the Investor
Meet Company dashboard up until 09.00 the day before the meeting or
at any time during the live presentation.
Investors can sign up to Investor Meet Company for free and add
to meet Trinity Exploration via the following link
https://www.investormeetcompany.com/trinity-exploration-production-plc/register-investor
. Investors who already follow Trinity on the Investor Meet Company
platform will automatically be invited.
Enquiries:
Trinity Exploration & Production plc Via Vigo Consulting
Jeremy Bridglalsingh, Chief Executive Officer
Julian Kennedy, Chief Financial Officer
Nick Clayton, Non- Executive Chairman
SPARK Advisory Partners Limited
(Nominated Adviser and Financial Adviser)
Mark Brady
James Keeshan +44 (0)20 3368 3550
Cenkos Securities PLC (Broker)
Leif Powis +44 (0)20 7397 8900
Neil McDonald +44 (0)131 220 6939
Vigo Consulting Limited trinity@vigoconsulting.com
Finlay Thomson / Patrick d'Ancona +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 ten licences and, across all of the
Group's assets, management's estimate of the Group's 2P reserves as
at the end of 2022 was 17.96 mmbbls. Group 2C contingent resources
are estimated to be 48.88 mmbbls. The Group's overall 2P plus 2C
volumes are therefore 66.84 mmbbls.
Trinity is quoted on AIM, a market operated and regulated by the
London Stock Exchange Plc, under the ticker TRIN.
Competent Person's Statement
All reserves and resources related information contained in this
announcement has been reviewed and approved by Dr. Ryan Ramsook,
Trinity's Executive Manager, Exploration. Dr. Ryan Ramsook also
lectures and is involved in collaborative Geoscience research with
the University of the West Indies and Fellow of the Geological
Society (FGS) of London. He is a Geologist by background with 19+
years' experience.
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.
CHAIRMAN & CEO STATEMENT
Strategic Performance
During 2022 Trinity put in place the foundations for an
ambitious growth programme, developing a series of catalysts to
drive shareholder value that we are now starting to execute in
2023. This important process has involved taking tough decisions
based on identifying the most efficient allocation of capital
across the portfolio. We chose not to pursue several initiatives
which we had previously been exploring, such as the Jubilee field
off the West Coast and NWD deeper play, and instead decided to
focus on three key initiatives which we believe have the potential
to deliver meaningful value for shareholders.
First, the Company has matured its understanding of the deeper
prospectivity across its onshore portfolio using the 3D seismic
which we had acquired to map nine 'Hummingbird' prospects across
its Palo Seco assets. In May 2023 we commenced the first well,
Jacobin, the start of an ambitious, risk-appropriate exploration
programme that we hope will fast-track the monetisation of these
substantial resources. In a success case, this will generate
material growth for our shareholders, further de-risk this
potentially extensive play across our existing acreage and allow us
to quickly evaluate the significant potential in the Buenos Ayres
block offered in the 2022 Onshore and Nearshore Competitive Bid
Round.
Second, during 2022, the Company participated in the 2022
Onshore and Nearshore Competitive Bid Round, bidding for the Buenos
Ayres block, which is located immediately to the west of Trinity's
existing Palo Seco interests, comprising Blocks WD5-6, WD-2 and
PS-4 and, at its closest, is only around 500 metres from the
Company's existing sub-licences. If awarded, Trinity intends to
take advantage of its unique understanding of the stratigraphy in
this area onshore Trinidad, where there are strong analogues to the
Company's existing acreage, to quickly progress from drilling to
production. As an Exploration and Production licence, Buenos Ayres
would benefit from better commercial and fiscal terms than the
Lease Operatorship Agreements; principally, no overriding royalty
payable, instead state-owned Heritage participating as a joint
venture partner with a 15% working interest carried through the
exploration phase.
Third, having paused the Galeota farm-out process, we initiated
an in-depth review of the opportunities across the offshore Galeota
block, including the existing Trintes producing field, to formulate
a revised development plan that offers greater capital efficiency
and shorter development and payback timelines, with the aim of
avoiding significant dilution for existing shareholders. This work
continues in 2023 and we aim to finalise the development option in
order to progress by Q4 this year.
In addition to progressing each of these attractive
opportunities, Trinity has continued to lobby the Trinidadian
Government to take the steps necessary to stimulate activity in the
energy sector. As well as the successfully completed 2022 Onshore
and Nearshore Competitive Bid Round, we welcomed the fiscal changes
that were introduced, particularly changes to Supplemental
Petroleum Tax ("SPT"), announced in September 2022 which took
effect from 1 January 2023. This positive approach from the
Government will provide additional growth opportunities for Trinity
and we continue to engage with Government in a constructive way, as
we believe further reform is necessary to achieve the Government's
aim to stimulate greater activity levels across our sector.
Operating Performance
Trinity delivered a robust operating performance in 2022 which
continues to highlight the strength and resilience of our core
business. We delivered production for the year within guidance, and
we remain on track to progress our growth agenda in 2023.
Group net sales for 2022 were 2,975 bopd (2021: 3,006 bopd).
Trinity managed to substantially mitigate natural production
decline through a programme including 3 new wells, 17 RCPs, 120
Workovers, swabbing across its asset base, including the recently
acquired PS-4, and improved production monitoring using automation
and revised completion strategies.
The Company's investment in technology to automate and remotely
optimise over 50% of its production is proving to be effective,
helping to ensure steady production whilst minimising
non-productive downtime. The Company aims to extend this automation
to an additional 37 onshore wells during 2023, which would result
in the proportion of Group production covered by automation rising
from 50% to approximately 80%.
Three new development wells were drilled and completed during H2
2022. Initial production levels for the three wells were on
prognosis but subsequent performance was below plan and increased
supply chain costs have impaired the economic potential of
conventional drilling. The data acquired through this campaign is
helpful, however, and is currently being used to revise our plans
for future drilling campaigns.
Financial Performance
Our 2022 financial results demonstrate the Company's resilience
despite encountering significant external headwinds. Adjusted
EBITDA for the year was USD 24.7 million (2021: USD 19.8 million)
and cash resources were USD 12.1 million (2021: USD 18.3 million)
at year-end.
Global supply chain pressures and cost inflation saw our
operating breakeven nudge above USD 30.0/bbl (to USD 32.1/ bbl)
(2021: USD 29.2/bbl) for the first time in seven years. This still
represents a relatively low operating cost, which provides a buffer
in times of low oil prices. Nevertheless, we are continuing to
experience inflationary pressures within the supply chain and are
working with our contractors and partners proactively to manage our
cost base and execute our development programme in a cost-effective
manner.
In 2022, in line with previous years, we hedged around 50% of
our production to counteract the impact of low oil prices and the
impact of SPT which, prior to the recent reforms, was at its most
punitive when realised oil prices were between USD 50.01 and USD
55.0 per barrel. The hedging programme, put in place during 2021 to
shield the Company from the possibility of weaker oil prices,
worked against us in 2022 when prices rose sharply in response to
Russia's invasion of Ukraine. This resulted in a cash payment for
hedging of USD 10.4 million for the year (compared to USD 1.3
million in 2021). The Company has elected to remain unhedged moving
into 2023.
Returns to Shareholders
Following the share capital re-organisation undertaken in 2021,
to restore distributable reserves at PLC level, the Board
sanctioned two share buyback programmes in 2022, commencing in
September/October 2022 to repurchase up to USD 2.0 million in
shares. The second share buyback concluded at the end of April
2023. The first and second share buyback acquired 1,432,000 shares,
representing 3.6% of our issued share capital for USD 2.0 million,
terms which the Board believes are accretive to shareholder value.
A third share buyback was announced on 28 April 2023 to return up
to USD 1.0 million to shareholders of the Company.
The Board believes that consistent returns to shareholders
should be an important driver for capital and operational
discipline whilst not impeding the Company's growth potential and
has accordingly affirmed a new Capital Allocation Policy which will
comprise payment of a modest but sustainable dividend and the scope
for additional distributions in the form of share buybacks or
special dividends. Going forward, the Board intends to aim to
distribute 15% of operating cash flow to shareholders, for each
calendar year when the realised oil price is USD80/bbl and below,
and at least 20% of operating cash flow for each calendar year when
the realised price is above $80/bbl. This is expected to include a
total dividend (split 1/3 interim, 2/3 final) of 1.5p per share,
provided the realised price is at least USD50/bbl. It is expected
that the maiden interim dividend will declared following
publication of the 2023 interim results, in Q3 2023, followed by a
final dividend being declared following publication of the 2023
preliminary results in Q2 2024.
HSSE and ESG performance
HSSE performance remains a high priority for Trinity, and at the
beginning of 2022 an HSSE Improvement Plan was developed to enhance
the existing HSSE Management System. Key elements of this plan
included creating a Steering Committee, chaired by the CEO,
developing a monthly HSSE Scorecard of key leading and lagging
indicators that is disseminated throughout the organisation, the
introduction of an ongoing Critical Safety Rule campaign and more
focus on contractor management and inclusion. The HSSE Team was
instrumental in achieving "STOW" (Safe to Work) recertification for
a further two years with a score of 100%. Unfortunately, we
recorded two Lost Time Incidents in 2022. Since then, we have
bolstered our incident investigation procedure to ensure that
actions and lessons learnt are being implemented throughout the
organisation.
During 2022, we also commenced the quantification of our Scope 1
and 2 emissions across all assets; established the Bruce Dingwall
Memorial Scholarship (in memory of our Founder and former Executive
Chairman) for Caribbean nationals pursuing studies in Geoscience;
and we continued to foster partnerships with our fence line
communities through the sponsorship of awards for excellence in
education to students undertaking the 11+ examinations.
Cyber Incident
In December 2022 Trinity was subject to a ransomware attack,
something that is becoming increasingly commonplace across all
businesses and geographies. We responded quickly and
comprehensively to this external attack on our business. Our
production facilities remained safe and continued to produce. We
suffered a temporary disruption to our administrative systems, but
Trinity's IT team and our external advisers have returned systems
to full capacity incorporating changes and learnings from the
incident and embedding more resilient IT infrastructure,
cybersecurity systems and procedures.
Organisational changes
The Board and management team was restructured and strengthened
in 2021 following the untimely passing of our founder and Executive
Chairman Bruce Dingwall, CBE. During 2022 the management team was
further reinforced by the recruitment of Julian Kennedy (Chief
Financial Officer), Alistair Green (Development Manager) and, more
recently, Mark Kingsley (Chief Operating Officer). We welcome them
all and look forward to driving the business forward with their
assistance. Angus Winther has completed two full terms as a
Director and specifically in the role of the Audit Committee
Chairman. Therefore, he has decided not to stand for reelection at
this forthcoming Annual General Meeting which coincides with Angus
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 conscientious stewardship of the Audit Committee
since he joined the Board in 2017.
Thanks
Your Board is appreciative of the support we continue to receive
from shareholders during what are very demanding and complex times.
On behalf of the Board, we must also thank our employees and
suppliers for their commitment which has allowed Trinity to deliver
its core business in a safe manner while positioning the Company to
hopefully move into a period of growth.
In summary, following significant challenges experienced by
Trinity in 2021, 2022 proved to be a year of consolidation and
focus, resulting in the identification of numerous near-term and
medium-term catalysts to drive growth and value. We will continue
to advance these during 2023, with a view to generating meaningful
returns for shareholders.
Nicholas Clayton Jeremy Bridglalsingh
Non-Executive Chairman Chief Executive Officer
OPERATIONS REVIEW
The Group achieved net sales of 2,975 bopd in 2022 (2021: 3,006
bopd). Investments into production related activities, such as the
three new infill wells, RCPs, workovers and swabbing, together with
greater automation and monitoring of our key wells, enabled the
Company to deliver annual production rate in-line with the prior
year, thereby largely offsetting the expected natural field decline
rate of between 7% and 10%.
ONSHORE ASSETS
Trinity's onshore assets comprise the lease operatorship blocks:
WD-5/6, WD-2 and PS-4 (together "Palo Seco"), FZ-2, WD-13, WD-14
(together "Forest Reserve") and one farmout block, Tabaquite.
The average net sales for 2022 was 1,655 bopd (2021: 1,644 bopd)
which accounts for 56% of our total annual sales. A breakdown of
the sales by block is shown in the table below.
Table 1 : 2022 vs 2021 Onshore Sales breakdown by block
2021 Avg Sales 2022 Avg
Block (bopd) Sales (bopd)
Palo Seco
--------------- --------------
WD-5/6 1,050 1,004
--------------- --------------
WD-2 246 258
--------------- --------------
PS-4* 4 62
--------------- --------------
Forest Reserve
--------------- --------------
FZ-2 122 117
--------------- --------------
WD-13 95 109
--------------- --------------
WD-14 110 100
--------------- --------------
Tabaquite
--------------- --------------
TABAQUITE 17 4
--------------- --------------
Annual Avg. 1,644 1,655
--------------- --------------
Note PS-4* was acquired on 1 Dec 2021 at an average monthly rate
of 52 bopd
Trinity drilled 3 new onshore development wells in 2022 (2021:
nil), completed 17 RCPs (2021: 7), 1 sand control job (2021: 5),
and 86 workovers (2021: 74), which, together with the inclusion of
PS-4 for the full year, resulted in a modest uplift in our onshore
production for the year as a whole.
Table 2 : 2022 Onshore Work Programme Breakdown by Block
Block New Wells Recompletions Workovers SCN
Palo Seco
---------- -------------- ---------- ----
WD-5/6 1 0 38 0
---------- -------------- ---------- ----
WD-2 1 2 3 0
---------- -------------- ---------- ----
PS-4 0 5 17 0
---------- -------------- ---------- ----
Forest Reserve
---------- -------------- ---------- ----
FZ-2 0 7 12 0
---------- -------------- ---------- ----
WD-13 1 1 9 0
---------- -------------- ---------- ----
WD-14 0 2 7 1
---------- -------------- ---------- ----
Tabaquite
---------- -------------- ---------- ----
TABAQUITE 0 0 0 0
---------- -------------- ---------- ----
TOTAL 3 17 86 1
---------- -------------- ---------- ----
In 2023, Trinity intends to manage its base production through
additional automation of wells, further RCP activity, 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 three new wells drilled in 2022 contributed 20 bopd
to the annual average.
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 2022 from the East Coast were 1,051 bopd
(2021: 1,107 bopd) which accounts for 35% of Group sales for the
period. A total of 23 workovers in 2022 (2021: 16) 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.
The Galeota licence has significant growth potential from
undeveloped reserves and resources in the Trintes field and broader
development of the Galeota block.
Having paused the Galeota farm-out process in May 2022, the
Company initiated an in-depth review of the opportunities across
the offshore Galeota block, including the existing Trintes
producing field, to formulate a revised development plan that
offers greater capital efficiency and shorter development and
payback timelines.
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 269 bopd in 2022 (2021: 255 bopd)
which accounted for 9% of the Group's total annual average sales.
This was a 5% year on year increase on the 2021 average. The
increase was achieved through increased swabbing activity via 10
conversions to swab workovers in 2022 (2021: nil) conducted across
the assets. Subsequent to the period end, in March 2023, ABM-151,
was producing at a managed rate of 140 bopd, higher than the
expected range of 60 to 110 bopd, thereby significantly improving
the economics of our West Coast assets in 2023.
Block 2021 Avg Sales 2022 Avg Sales
-----------
(bopd) (bopd)
----------- --------------- ---------------
Brighton 155 158
--------------- ---------------
PGB (70%) 100 111
--------------- ---------------
TOTAL 255 269
--------------- ---------------
Facilities Management and Infrastructure
In 2022, the Facilities team focused on asset integrity, welfare
initiatives and projects supporting production.
On Trintes, the Company replaced gratings on offshore platform
production decks and improved key electrical equipment on the
Alpha, Bravo and Delta platforms, resulting in the repurposing of
floor space allowing for better access and more efficient use of
the work area. Accommodation units were replaced, fuel and water
tanks were upgraded and repositioned for better use of the
available space.
The construction of a new 10,000 bbl storage tank to accommodate
production from the Trintes field was 86% complete at the end of
2022. The project experienced some delays but is now expected to be
fully operational in Q2-2023.
Activities for the Onshore and West Coast operations focused on
upgrading welfare facilities and construction of a new crow's nest
to support the ABM-151 well reactivation.
In total, the team progressed 40 projects of which 32 were
completed by the end of 2022 and 8 rolled over in 2023.
Facilities Management and Infrastructure spend in 2022 was USD
4.0 million (comprising East Coast - USD 2.9 million, West Coast -
USD 0.7 million and Onshore - USD 0.4 million).
Onshore Drilling
Trinity's onshore development drilling campaign during 2022
comprised three wells drilled in the second half of the year (one
well in each of WD-5/6, WD-2 and WD-13) targeting Lower Forest and
Upper Cruse reservoirs. Supply chain challenges and inflationary
pressures significantly increased the cost of drilling and impaired
economics. While we encountered reservoir in all wells broadly on
prognosis, we observed higher than expected depletion in all three
which resulted in stabilised production rates being lower than
predicted. Our intention is to manage the wells' up-hole potential
to maximise the economic recovery. Data acquired from the 2022
drilling campaign and the performance of these wells will be
incorporated into our regional model to de-risk and re-prioritise
future infill development candidates.
Reserves and Resources
A comprehensive reserves and resources review of all assets has
been completed by Management which estimates Trinity's current 2P
reserves to be 17.96 mmstb at the end of 2022, compared to the
year-end 2021 reserve estimate of 19.73 mmstb. This represents a 9%
year-on-year decrease. The overall decrease in reserves of 1.77
mmstb comprise 1.09 mmstb produced in 2022 and revisions, including
re-categorisation of reserves from 2P to 2C of 0.68 mmstb.
Factoring in the 2022 produced volume of 1.09 mmstb, the 2P
year-on-year decline is 3.4%.
(USD/bbl) 2023 2024 2025 2026 2027 2028 2029 2030 2031
Price Strip 82.13 77.09 73.50 70.83 68.78 67.85 68.31 67.50 68.72
Brent Forward Price Deck applied to Reserves Economic Limit
Testing ("ELT") from Britannic Trading LLC as at 3 January 2023
Management considers the reserves presented in the table below
to be its best estimate as at 31 December 2022 of the quantity of
reserves that can be recovered from Trinity's current assets. It
includes forecasted 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 de ned investment programmes and constituent drilling targets
to commercialise these reserves as detailed by asset area shown in
the table:
Unaudited 2022 2P Reserves
Net Oil Reserves 31-Dec-21 Production Revisions 31-Dec-22
mmstb mmstb mmstb mmstb
------------------ ---------- ----------- ---------- ----------
Asset
Onshore 7.26 (0.60) (0.13) 6.53
West Coast 2.70 (0.11) (0.42) 2.17
East Coast 9.77 (0.38) (0.13) 9.26
Total 19.73 (1.09) (0.68) 17.96
------------------- ---------- ----------- ---------- ----------
Note:
- The 2022 produced volume of 1.09 mmstb accounts for 61.6% of
the overall 2P decrease in 2022 compared to 2021 .
- Revisions:
-- Onshore: FZ-2 +0.22 mmstb and WD-14 +0.26 mmstb due to
Economic Limit Testing. Onshore sub-licences decrease (-0.61 mmstb)
due to uneconomic infills.
-- West cost: Reactivation of ABM-151 in March 2023 and revised
IP of 80 bopd; +0.15 mmstb. Reallocation of infill wells from 2P to
2C category (-0. 20 mmstb). PGB base decreased -0.37 mmstb.
-- East coast: Reduced base performance due to decreased well
performance from key producers in Trintes (-0.78 mmstb). Reduced
RCP 2P from 2021 to 2022 mainly due to reduced RCP count (-0.07
mmstb). Reclassification of three conventional infill wells from
the Echo FDP back to Trintes development 2P reserves. +0.72
mmstb.
Management's Estimate of 2C Resources as at 31 December 2022
Net Oil Resources 31-Dec-21 Revisions 31-Dec-22
mmstb mmstb mmstb
------------------- ---------- ---------- ----------
Asset
Onshore 3.82 4.80 8.62
West Coast 3.01 0.44 3.45
East Coast 40.39 (3.58) 36.81
Total 47.22 1.66 48.88
-------------------- ---------- ---------- ----------
Note (*):
Onshore:
-- Recently concluded 3D seismic mapping work across WD-5/6,
WD-2, PS-4 assets has redefined the subsurface structure/model
resulting in the addition of 2C resources +4.80 mmstb in Year End
2022.
West Coast:
-- Reallocation of infill wells from 2P to 2C category across West Coast +0.44 mmstb
East Coast:
-- Year End 2021 most likely case of 12-well development
inclusive of three Trintes infills re-categorised at Year End 2022
as part of Trintes development 2P rather than as Echo 2C (-3.58
mmstb)
Management's Estimate of Reserves and Resources as at 31
December 2022
2022 2P 2021 2P
2022 2P 2022 2C Reserves Reserves
Reserves Resources and 2C Resources and 2C Resources
mmstb mmstb mmstb mmstb
------------ ---------- ----------- ------------------ ------------------
Asset
Onshore 6.53 8.62 15.15 11.08
West Coast 2.17 3.45 5.62 5.71
East Coast 9.26 36.81 46.07 50.16
Total 17.96 48.88 66.84 66.95
------------- ---------- ----------- ------------------ ------------------
Financial Review
KPIs
During 2022 the Group benefitted from higher oil prices and,
combined with the Group's robust cost control structure, resulted
in Adjusted EBITDA (before hedge costs) increasing by 66% to USD
35.1 million (2021: USD 21.1 million). The crude oil hedges in
place muted our upside exposure, although the Group delivered a
resilient operating performance as shown by Adjusted EBITDA (after
hedge costs) increasing by 25% to USD 24.7 million and IFRS
Operating Profit before SPT doubling compared to 2021.
A summary of the year-on-year operational and financial
highlights are set out below:
FY 2022 FY 2021 Change
%
Average realised oil price(1) USD/bbl 84.9 60.4 41
Average net production (2) bopd 2,975 3,006 (1)
Revenues USD million 92.2 66.3 39
Cash balance USD million 12.1 18.3 (34)
IFRS Results
Operating Profit before SPT USD million 19.0 9.3 104
Total Comprehensive income for
the year USD million 0.1 7.7 (99)
Earnings Per Share - Diluted USD cents 0.0 18.0 (100)
APM Results
Adjusted EBITDA (before hedge
costs)(3) USD million 35.1 21.1 66
Adjusted EBITDA (after hedge
costs)(4) USD million 24.7 19.8 25
Adjusted EBITDA (after hedge
costs)(5) USD/bbl 22.7 18.0 26
Adjusted EBITDA margin (after
hedge costs)(6) % 26.8 29.9 (10)
Adjusted EBIDA after Current
Taxes(7) USD million 12.3 14.8 (17)
Adjusted EBIDA after Current
Taxes Per Share - Diluted US cents 30.6 35.0 (13)
Consolidated operating break-even(8) USD/bbl 32.1 29.2 10
Net cash plus working capital
surplus(9) USD million 14.2 20.8 (32)
Notes:
1. Average realised price (USD/bbl): Actual price received for
crude oil sales per barrel ("bbl").
2. Average net sales (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).
Note (*): See Note 26 to Consolidated Financial Statements -
Adjusted EBITDA for further details.
Adjusted EBITDA Calculation
Adjusted EBITDA is an Alternative Performance Measure guideline
("APM") used by the Group to measure business performance. The
Group presents Adjusted EBITDA metrics as they are used by
Management to assess the Group's underlying operational and
financial performance.
2022 2021
USD MM USD MM Change
%
========================================= ========== ======== =======
Operating Profit Before SPT, Impairment
and Exceptional Items 19.0 9.3 104
Add back realised hedge costs 10.4 1.3 697
DD&A 7.6 7.4 3
Share Option Expense 0.6 0.6 0.0
Impairment Losses on Financial Assets 0.0 (0.7) (100)
FX loss/(gain) 0.4 0.0 2,857
FV gain/(loss) on derivative financial
instruments (2.9) 3.2 (191)
----------------------------------------- ---------- -------- -------
Adjusted EBITDA (before hedge) 35.1 21.1 66
Deduct realised hedge costs (10.4) (1.3) 697
Adjusted EBITDA (APM Result) 24.7 19.8 25
========================================= ========== ======== =======
Current Taxes:
========================================= ========== ======== =======
SPT (9.0) (5.1) 77
PPT and UL (3.4) (1.4) 143
Adjusted EBIDA after Current Taxes (APM
Result) 12.3 13.3 (17)
========================================= ========== ======== =======
Refer to Glossary for abbreviations.
2022 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.
2018 (1) 2019 2020 2021 2022
84.
Realised Price USD/bbl 59.8 58.1 37.7 60.4 9
------------------------- --------- --------- ------ ------ ------ ------
Sales
Onshore bopd 1,563 1,616 1,793 1,644 1,655
West Coast bopd 198 185 245 255 269
East Coast bopd 1,110 1,208 1,188 1,107 1,051
Consolidated bopd 2,871 3,007 3,226 3,006 2,975
------------------------- --------- --------- ------ ------ ------ ------
Metrics
Royalties/bbl -
Onshore USD/bbl 24.2 22.3 11.5 22.6 35.9
Royalties/bbl -
West Coast USD/bbl 10.0 10.0 6.1 11.1 15.8
Royalties/bbl -
East Coast USD/bbl 14.5 14.1 8.3 13.0 17.9
Royalties/bbl -
Consolidated USD/bbl 19.1 10.7 9.9 18.1 27.7
Opex/bbl - Onshore USD/bbl 11.7 12.1 12.2 14.4 17.0
Opex/bbl - West
Coast USD/bbl 22.1 26.9 20.3 26.2 30.7
Opex/bbl - East
Coast USD/bbl 20.1 17.1 16.5 18.3 23.2
Opex/bbl - Consolidated USD/bbl 16.8 14.9 14.0 16.0 17.7
------------------------- --------- --------- ------ ------ ------ ------
G&A/bbl - Consolidated
(2) USD/bbl 5.0 5.1 4.3 6.3 6.6
------------------------- --------- --------- ------ ------ ------ ------
Operating Break-Even
(3)
Onshore USD/bbl 16.1 16.4 16.5 19.0 19.2
West Coast USD/bbl 26.8 32.4 24.6 32.2 31.8
East Coast USD/bbl 25.9 21.9 21.0 23.2 24.4
Consolidated (4) USD/bbl 29.0 26.4 20.1 29.2 32.1
------------------------- --------- --------- ------ ------ ------ ------
Notes
1. Metrics for 2018 and prior are pre-IFRS 16 adoption effective
1 January 2019 which impacted the Operating Break-Even Levels and
Opex/bbl & G&A/bbl Metrics for historical comparative
purposes. Full details of the impact were set out in the 2019
annual report and accounts.
2. G&A/bbl - Consolidated: Excludes SOE, ILFA, Derivative FV gain/loss and FX gain/loss.
3. Operating break-even: The realised price where Adjusted
EBITDA ([before hedge]) for the respective asset or the entire
Group (Consolidated) is equal to zero.
4. 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 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 believe 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 International Accounting Standards ("IAS") 1 "Presentation of
financial statements".
In particular, the 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
Higher revenue driven by higher average realised oil price in
2022:
The positive impact of a 41% increase in average oil price
realisations to USD 84.9/bbl (2021: USD 60.4/bbl), and a modest 1%
decrease in average annual sales to 2,975 bopd (2021: 3,006 bopd),
resulted in a 39% increase in revenues to USD 92.2 million (2021:
USD 66.3 million).
Maintained robust operating profits despite inflationary
pressures:
The Group continued to deliver strong operating margins despite
the inflationary pressures on goods and services. Operating profit
before taxes was USD 19.0 million (2021: USD 9.3 million). The
Adjusted EBITDA margin (pre-hedge costs) increased to 38.1% (2021:
31.9%), with consolidated operating break-even moving up to USD
32.1 (2021: USD 29.2) demonstrating the Group's ability to be
profitable across a broad range of oil prices. The 25% increase in
Adjusted EBITDA (after hedge costs) to USD 24.7 million (2021: USD
19.8 million) is a direct result of the increased realised oil
price and strong operational performance.
Increased capex investment programme to drive growth:
USD 15.5 million (2021: USD 13.6 million) invested to drive
future production growth. This comprised:
-- USD 8.4 million Production capex comprising three onshore
wells drilled (USD 5.8 million), 17 RCP's (USD 1.5 million) and
ABM-151 reactivation project (USD 1.1 million).
-- USD 4.8 million Infrastructure Capex including facilities, operations and ICT.
-- USD 1.7 million Subsurface and time-writing costs.
-- USD 0.3 million in Exploration and Evaluation ("E&E") relating to Onshore and West Coast.
-- USD 0.3 million Exploration and Evaluation ("E&E") assets relating to Galeota.
Refer to Notes to Financial Statements: Note 13 Property, Plant
and Equipment - Additions (USD 15.1 million) and Note 15 -
Intangible Assets - E&E Additions (USD 0.5 million) inclusive
of accruals.
Continued financial strength:
The Group's cash balances at year end were USD 12.1 million
(2021: USD 18.3 million ) , primarily reflecting positive cash
generated from operations of USD 12.0 million (after derivative
payments and taxes), Capex spend of USD (15.6) million and
Financing activities of USD (2.2) million (which included effecting
our first share buyback). In aggregate, despite these significant
cash outflows, the Group's net cash plus working capital surplus
stood at USD 14.2 million (2021: USD 20.8 million) and our current
ratio was a healthy 2.1x (2021: 2.2x).
Statement of Comprehensive Income
2022 Financial Highlights
Average realisation of USD 84.9/bbl (2021: USD 60.4/bbl).
Operating Revenues
Operating revenues up 39% to USD 92.2 million (2021: USD 66.3
million).
Operating expenses
Operating expenses increased by 29% in 2022 to USD (73.3)
million reflecting operating in a higher crude oil price
environment (2021: USD (56.9) million) and comprised:
Operating Expenses (excluding non-cash items): USD (67.6)
million (2021: (46.4) million):
-- Royalties of USD (30.1) million (2021: USD (19.8) million),
this increase being driven by the higher average realised oil
price.
-- Opex of USD (19.2) million (2021: USD (17.6) million), the
increase mainly due to impact of inflationary pressures on goods
and services as well as increased repairs and maintenance,
workovers and fuel in the year.
-- G&A expenses of USD (7.2) million (2021: USD (7.0)
million), the increase mainly due to recruitment and replacement of
key personnel to support the businesses growth strategy, increased
levies, business travel, and administrative costs including
professional fees.
-- Derivative expense of USD (10.4) million (2021: Derivative
expense of USD (1.3) million) being the cash impact of derivative
instruments paid out for 2022.
-- Covid 19 expense of USD (0.6) million (2021: USD (0.7)
million) being the costs associated with accommodation, testing and
sanitisation related to our prevention and response.
-- Cash FX loss USD (0.1) million (2021: USD 0.0 million)
Non-Cash Operating Expenses: USD (5.7) million (2021: USD (10.5)
million):
-- DD&A of USD (7.6) million (2021: USD (7.4) million).
-- Derivative credit of USD 2.9 million (2021: Derivative
expense of USD (3.2) million) being the movement in the FV of
derivative instruments held at the beginning and end of the
financial year.
-- SOE of USD (0.7) million (2021: USD (0.6) million).
-- ILFA reversal USD 0.0 million (2021: USD 0.7 million).
-- FX loss USD (0.3) million (2021: USD 0.0 million).
Operating Profit Before SPT, Impairment and Exceptional
Items
The operating profit before SPT, impairment and exceptional
items for the year amounted to USD 19.0 million (2021: USD 9.3
million) and was mainly due to higher operating revenues resulting
from higher oil prices despite inflationary pressures on cost.
SPT and PT
SPT and PT of USD (9.0) million (2021: USD (3.6) million) and
comprised:
-- SPT of USD (9.0) million (2021: USD (5.1) million) mainly due
to the higher realised oil prices in relation to the Group's
operations in 2022. Both onshore and offshore assets were subject
to SPT in 2022 as the realised oil price throughout the year was
higher than USD 75/bbl.
-- PT nil (2021: USD 1.5 million net reversal), as no Notice of
Assessment has been received in relation to this tax.
Operating Profit before Impairment and Exceptional items
The Group's reported operating profit before impairment and
exceptional items was USD 10.0 million (2021: USD 5.8 million).
Adjusting for non-cash expenses, the Group's Adjusted EBIDA after
Current Taxes was USD 12.3 million (2021: USD 14.8 million)
(further details below).
Impairment charge
Impairment charges taken were USD (6.1) million (2021: USD (1.3)
million) relating to the Impairment of property, plant, and
equipment USD (5.8) million and Inventory (0.3) million.
See Note 3(d) to Consolidated Financial Statements - Impairment
of Property, Plant and Equipment for further details.
Exceptional items
Exceptional items were USD (0.2) million relating to the cyber
incident costs in December 2022 (2021 : USD (0.1) million relating
to fees for corporate restructuring advice).
See Note 7 to Consolidated Financial Statements - Exceptional
items for 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 (2021: 0.1 million).
Finance Costs
Finance costs amounted to USD (1.3) million (2021: USD (1.5)
million) and comprised:
-- Unwinding of the discount rate related to the decommissioning
liability USD (1.1) million (2021: USD (1.2) million).
-- Bank overdraft interest USD (0.1) million (2021: (0.2) million).
-- Interest on Leases USD (0.1) million (2021: USD (0.1) million).
See Note 9 to Consolidated Financial Statements - Finance Costs
for further details.
Income Taxation
Income Taxation charge for 2022 of USD (2.3) million (2021: USD
4.7 million credit), comprising the following:
-- Current Taxes comprising
o Petroleum Profit Tax ("PPT") USD (2.4) million (2021: (1.0)
million).
o Unemployment Levy ("UL") USD (1.0) million (2021: USD (0.4)
million).
-- Increase in Deferred Tax Assets ("DTA") recognised on
available tax losses of USD 1.0 million (2021: Increase in DTA of
USD 5.5 million).
-- Decrease in Deferred Tax Liabilities ("DTL") USD 0.1 million due to accelerated accounting impairments/depreciation (2021: USD 0.6 million decrease).
See Note 10 to Consolidated Financial Statements - Income
Taxation for further details.
Total Comprehensive Income
Total Comprehensive Income for the period was USD 0.09 million
(2021: USD 7.7 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, SOE, ILFA, FX and FV of Derivative
Instruments.
The Group presents Adjusted EBITDA after hedge expense at USD
24.7 million and Adjusted EBIDA after Current Taxes at USD 12.3
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 12.0 million (2021: USD 12.6
million) comprising:
-- Operating cash flow before working capital and income taxes
of USD 15.5 million (2021: USD 16.1 million).
-- Changes in working capital resulted in a net decrease of USD
(0.1) million (2021: USD (1.8) million decrease).
-- Income taxes, PPT and UL paid USD (3.4) million (2021: USD
(1.7) million paid) resulting from the higher oil price.
Cash (outflow) from investing activities
Cash outflow from investing activities was USD (15.6) million
(2021: USD (13.8) million):
-- Property, plant and equipment for the year totaling USD
(15.0) million (2021: USD (10.0) million).
-- Expenditure on exploration and evaluation assets and other
intangible assets USD (0.4) million (2021: USD (3.2) million) as
the Group continued to invest in Galeota.
-- Computer software USD (0.1) million (2021: USD (0.4) million).
-- Performance bond related to the onshore lease operatorship
assets USD (0.1) million (2021: USD (0.3) million)
Cash outflow from financing activities
Cash outflow from financing activities was USD (2.2) million
(2021: USD (0.6) million):
-- Share buyback of USD (1.5) million (2021: nil).
-- Principal paid on lease liability USD (0.5) million (2021: (0.4) million).
-- Interest paid on lease liability USD (0.1) million (2021: (0.1) million).
-- Net Finance cost of USD (0.1) million (2021: (0.1) million).
Closing Cash Balance
Trinity's cash balance at 31 December 2022 was USD 12.1 million
(31 December 2021: USD 18.3 million).
Net Cash Plus Working Capital Surplus
FY 2022 FY 2021 FY 2020 FY 2019
(All figures in USD million) Audited Audited Audited Audited
--------------------------------- -------- -------- -------- --------
A: Current Assets
--------------------------------- -------- -------- -------- --------
Cash and cash equivalents 12.1 18.3 20.2 13.8
---------------------------------------------- -------- -------- -------- --------
Trade and other receivables 10.7 10.8 7.2 9.4
---------------------------------------------- -------- -------- -------- --------
Inventories 4.6 3.8 5.3 5.2
---------------------------------------------- -------- -------- -------- --------
Derivative Financial
Instrument -- -- 0.3 0.1
---------------------------------------------- -------- -------- -------- --------
Total Current Assets 27.4 32.9 33.0 28.5
---------------------------------------------- -------- -------- -------- --------
B: Current Liabilities
--------------------------------- -------- -------- -------- --------
Trade and other payables 9.9 8.8 7.8 10.4
---------------------------------------------- -------- -------- -------- --------
Bank overdraft 2.7 2.7 2.7 -
---------------------------------------------- -------- -------- -------- --------
Lease liability 0.6 0.6 0.6 0.6
---------------------------------------------- -------- -------- -------- --------
Taxation payable -- -- 0.2 0.1
---------------------------------------------- -------- -------- -------- --------
C: Derivative Financial -- 2.9 -- --
Instrument
--------------------------------- -------- -------- -------- --------
D: Provision for other liabilities 0.2 0.1 -- --
--------------------------------- -------- -------- -------- --------
Total Current Liabilities 13.4 15.1 11.3 11.1
---------------------------------------------- -------- -------- -------- --------
Cash plus working capital
(A-B+C+D): surplus 14.2 20.8 21.4 17.3
--------------------------------- -------- -------- -------- --------
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 2022, the Group has received
further VAT refunds of USD 2.6 million as at 31 May 2023. On 10 May
2023, the Government of Trinidad and Tobago announced that it
intends to settle outstanding VAT refunds via interest bearing
bonds in order to meet VAT arrears of those registrants who are
owed in excess of USD 0.03 million in VAT refunds. At the end of
May 2023, the Group had USD 2.0 million in VAT refunds recoverable
in VAT bonds.
2. On 31 December 2022, the FZ-2 Lease Operating Agreement
("LOA") expired. Trinity obtained an interim renewal of the LOA to
31 March 2023 and obtained a further extension to 30 June 2023 to
execute the LOA for the period 1 January 2023 to 30 September
2031.
3. On 29 March 2023, the Group provided six-months' notice to
Heritage to terminate the sub-licence Farm-Out agreement for the
Tabaquite block. The new sub-licencee requirements proposed to the
Group makes this licence uneconomic to operate.
4. Cyber incident - The Group was the subject of a sophisticated
cyber incident in December 2022 and immediately took precautionary
measures to protect its IT infrastructure. The Group engaged with
external specialists to investigate the nature and extent of the
incident and implement its systems recovery plan. Trinity moved
quickly to notify relevant regulators and law enforcement agencies.
Trinity's production facilities continued to operate safely
throughout. In 2023, the Group continues to execute its recovery
plan. Trinity's IT team and its external advisers continue to
support the business in returning its administrative systems to
full capacity incorporating learnings from the incident and
embedding more resilient IT infrastructure, cyber security systems
and procedures.
5. Trintes Field Incident - On the evening of 10 April 2023, a
fire occurred in one of the two generators on the Trintes Bravo
platform. Production across the field was halted and the fire was
contained. Production restarted from Alpha and Delta platforms on
11 April 2023. Four operators, all Trinity staff, were on Bravo at
the time of the incident and, having suffered minor injuries , all
have now recovered and resumed work. Following approval from the
Ministry of Energy and Energy Industries, received on 17 April
2023, the Company successfully restored oil production from all
previously producing wells on the Bravo platform on 18 April 2023.
Production from the field is in-line with pre-incident levels at
approximately 1,010 bopd.
6. Share buyback - As at 31 December 2022, the second tranche of
the share buyback programme was still ongoing with 400,000 shares
having been repurchased to 31 December 2022 utilising USD 0.5
million of the USD 1.0 million second tranche. On 26 April 2023,
the second tranche of the share buyback programme was completed and
a third tranche was announced on 28 April 2023 for up to a further
USD 1.0 million. This tranche will be funded from the Group's
existing cash resources and will, unless terminated at an earlier
date, expire at the conclusion of the 2023 AGM, or 30 June 2023,
whichever is earlier.
7. Renewal of PGB Exploration and Production Licence - On 3 May
2023, the MEEI provided confirmation of the renewal of the PGB
Licence for an additional 25 years from the Effective Date of 18
December 2012. Consequently, the PGB Licence expires on 17 December
2037. There were no additional liabilities and commitments arising
from the renewed Licence.
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2022
(Expressed in United States Dollars)
Note 2022 2021
$'000 $'000
Revenues
Crude oil sales 4 92,232 66,257
Other income 7 1
-------------------- -----------------
92,239 66,258
Operating Expenses
Royalties (30,091) (19,828)
Production costs (19,242) (17,625)
General & Administrative ("G&A") expenses (7,181) (7,030)
Covid-19 expenses* (579) (669)
Depreciation, Depletion & Amortisation ("DD&A") 13-15 (7,617) (7,428)
Share Option Expense ("SOE") (647) (626)
Foreign exchange ("FX") loss (394) (14)
Net reversal of Impairment losses on financial
assets ("ILFA") 46 754
Derivative expenses 6 (10,446) (1,293)
Fair value income/(expense) derivative instruments 6 2,883 (3,149)
(73,268) (56,908)
-------------------- -----------------
Operating Profit before Supplemental Petroleum
Taxes ("SPT") & Property Taxes ("PT") 18,971 9,350
SPT (9,012) (5,074)
PT net reversal - 1,516
-------------------- -----------------
(9,012) (3,558)
Operating Profit before Impairment and Exceptional
items 9,959 5,792
Impairment 8 (6,050) (1,316)
Exceptional items 7 (161) (113)
-------------------- -----------------
Operating Profit 3,748 4,363
Finance income 9 48 94
Finance costs 9 (1,339) (1,475)
Profit Before Income Taxation 2,457 2,982
Income taxation (charge)/ credit 10 (2,344) 4,744
-------------------- -----------------
Profit for the year 113 7,726
Other Comprehensive Income/(Expense)
Items that may be subsequently reclassified
to profit or loss
Exchange differences on translation of foreign
operations (20) -
-------------------- -----------------
Total Comprehensive Income for the year 93 7,726
==================== =================
Earnings per share (expressed in dollars
per share)
Basic 11 0.00 0.20
Diluted 11 0.00 0.18
* Covid-19 expenses have been reclassified as Operating
Expenses
Consolidated Statement of Financial Position
at 31 December 2022
(Expressed in United States Dollars)
Note 2022 2021
ASSETS $'000 $'000
Non-current Assets
Property, plant and equipment 13 44,987 49,507
Right-of-Use ("ROU") assets 14 838 616
Intangible assets 15 33,537 30,759
Abandonment fund 16 4,511 4,021
Performance bond 17 602 473
Deferred Tax Assets ("DTA") 18 12,465 11,530
96,940 96,906
---------- --------------
Current Assets
Inventories 19 4,615 3,820
Trade and other receivables 20 10,678 10,747
Cash and cash equivalents 22 12,131 18,312
---------- --------------
27,424 32,879
---------- --------------
Total Assets 124,364 129,785
========== ==============
Equity and liabilities
Capital and Reserves Attributable to
Equity Holders
Share capital 23 399 389
Share based payment reserve 25 2,990 3,784
Reverse acquisition reserve 26 (89,268) (89,268)
Translation reserve (1,667) (1,650)
Treasury shares 24 (1,522) --
Retained earnings 145,199 143,666
---------- --------------
Total Equity 56,131 56,921
---------- --------------
Non-current Liabilities
Lease liability 14 341 97
Deferred Tax Liabilities ("DTL") 18 1,940 2,025
Provision for other liabilities 28 52,460 55,690
Employee benefits 23 --
54,764 57,812
---------- --------------
Current Liabilities
Trade and other payables 29 9,932 8,814
Bank overdraft 30 2,700 2,700
Lease liability 14 584 609
Provision for other liabilities 28 249 46
Derivative financial liabilities 21 -- 2,883
Taxation Payable 4 --
13,469 15,052
---------- --------------
Total Liabilities 68,233 72,864
---------- --------------
Total Equity and Liabilities 124,364 129,785
========== ==============
Company Statement of Financial Position
at 31 December 2022
(Expressed in United States Dollars)
Note 2022 2021
ASSETS $'000 $'000
Non-current Assets
Investment in subsidiaries 12 60,864 60,347
=========== =========
Current Assets
Trade and other receivables 20 233 200
Intercompany 20 2,830 3,372
Cash and cash equivalents 22 2,102 3,108
----------- ---------
5,165 6,680
----------- ---------
Total Assets 66,029 67,027
=========== =========
Equity and liabilities
Capital and Reserves Attributable to
Equity Holders
Share capital 23 399 389
Share based payment reserve 3,775 4,569
Merger reserves 6,552 6,552
Treasury shares 24 (1,522) --
Retained earnings 43,529 51,526
----------- ---------
Total Equity 52,733 63,036
----------- ---------
Current Liabilities
Trade and other payables 29 565 327
Intercompany 31 12,731 781
Derivative financial liabilities 21 -- 2,883
13,296 3,991
----------- ---------
Total Liabilities 13,296 3,991
----------- ---------
Total Equity and Liabilities 66,029 67,027
=========== =========
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 $9.4
million (2021: $6.4 million).
Consolidated Statement of Changes in Equity
for the year ended 31 December 2022
(Expressed in United States Dollars)
Share Share Share Reverse Merger Treasury Translation Retained Total
Capital Premium Based Acquisition Reserves Shares Reserve Earnings Equity
Payment Reserve
Reserve
Year ended 31 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
December 2021
At 1 January
2021 97,692 139,879 14,764 (89,268) 75,467 -- (1,650) (188,332) 48,552
Capital
reorganisation (97,303) (139,879) (11,485) -- (75,467) -- -- 324,134 --
LTIPs
exercised(1) -- -- -- -- -- -- -- 47 47
Share based
payment
expense
(Note 25) -- -- 505 -- -- -- -- 91 596
Profit for the
year -- -- -- -- -- -- -- 7,726 7,726
--------- ---------- --------- ------------ --------- --------- ------------ ---------- --------
Total
comprehensive
income
for the year -- -- -- -- -- -- -- 7,726 7,726
--------- ---------- --------- ------------ --------- --------- ------------ ---------- --------
At 31 December
2021 389 -- 3,784 (89,268) -- -- (1,650) 143,666 56,921
========= ========== ========= ============ ========= ========= ============ ========== ========
Year ended 31
December 2022
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
(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
========= ========== ========= ============ ========= ========= ============ ========== ========
(1) - As described in the notes to the consolidated financial
statements, in 2020 the Company issued 4,745,057 ordinary shares
(pre share consolidation) to certain
employees on exercise of LTIPs at less than the nominal value in
contravention of S580 of the Companies Act 2006. In 2021, on
becoming aware of the issue,
the Company sought remedial advice and corrected this.
Company Statement of Changes in Equity
for the year 31 December 2022
(Expressed in United States Dollars)
Share Retained
Based Earnings/
Share Share Payment Merger Treasury Accumulated Total
Capital Premium Reserve Reserves Shares Losses Equity
$'000 $'000 $'000 $'000 $'000 $'000 $'000
Year ended 31 December
2021
At 1 January 2021 97,692 139,879 4,064 56,652 -- (229,422) 68,865
Capital Reorganisation (97,303) (139,879) -- (50,100) -- 287,282 --
Share based payment charge
(Note 25) -- -- 505 -- -- -- 505
LTIPs exercised(1) -- -- -- -- -- 47 47
Total comprehensive loss
for the year -- -- -- -- -- (6,381) (6,381)
-------------- ---------- --------- ---------- --------- ------------- ---------
At 31 December 2021 389 -- 4,569 6,552 -- 51,526 63, 036
============== ========== ========= ========== ========= ============= =========
Year ended 31 December
2022
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
LTIPs 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
============== ========== ========= ========== ========= ============= =========
(1) - As described in the notes to the consolidated financial
statements, in 2020 the Company issued 4,745,057 ordinary shares
(pre share consolidation) to certain employees on exercise of LTIPs
at less than the nominal value in contravention of S580 of the
Companies Act 2006. In 2021, on becoming aware of the issue the
Company sought remedial advice and corrected this.
Consolidated Statement of Cash Flows
at 31 December 2022
(Expressed in United States Dollars)
Note 2022 2021
$'000
$'000
Operating Activities
Profit before taxation 2,457 2,982
Adjustments for:
Foreign exchange ("FX") loss/(gain) 394 (39)
Finance cost - loans and interest 9 229 254
Finance income 9 (48) (94)
Finance cost - decommissioning provision 28 1,110 1,222
Share-based payment expense 647 626
DD&A 13-15 7,617 7,428
Net reversal of impairment on financial
assets (46) (754)
Inventory impairment 334 1,220
Impairment of property, plant and equipment 8 5,558 96
Fair value (gain)/ loss on derivative
financial
instruments (2,883) 3,149
Other non-cash items 158 47
--------- ---------
15,527 16,137
Changes In Working Capital
(Decrease)/increase in inventories 19 (1,129) 228
Decrease in trade and other receivables 16,20,21 (376) (3,019)
Increase in trade and other payables 21,28,29 1,353 909
--------- ---------
(152) (1,882)
Income taxation paid (3,390) (1,700)
--------- ---------
Net Cash Inflow from Operating Activities 11,985 12,555
--------- ---------
Investing Activities
Purchase of Exploration and Evaluation
("E&E") assets 15 (388) (3,262)
Purchase of computer software and investment
in research & development 15 (102) (401)
Purchase of property, plant and equipment 13 (15,016) (9,957)
Performance Bond (130) (220)
--------- ---------
Net Cash Outflow from Investing Activities (15,636) (13,840)
--------- ---------
Financing Activities
Finance income 48 94
Finance cost (94) (153)
Proceeds from the issue of shares 10 --
Principal paid on lease liability (536) (480)
Interest paid on lease liability (135) (101)
Acquisition of treasury shares (1,522) --
--------- ---------
Net Cash Outflow from Financing Activities (2,229) (640)
--------- ---------
Decrease in Cash and Cash Equivalents (5,880) (1,925)
========= =========
Cash and Cash Equivalents
At beginning of year 18,312 20,237
Effects of foreign exchange rates differences
on cash (301) 19
Decrease in Cash and Cash equivalents (5,880) (1,944)
--------- ---------
At end of year 22 12,131 18,312
--------- ---------
Company Statement of Cash Flows
for the year ended 31 December 2022
(Expressed in United States Dollars)
Note 2022 2021
$'000 $'000
Operating Activities
Loss before taxation (9,413) (6,381)
Adjustments for:
For eign exchange ("FX") loss 306 28
Finance income (156) (152)
Share based payment charge 107 178
Net reversal of impairment loss on
financial assets (14) (28)
Fair value loss on derivative financial
instruments (2,883) 3,149
Other non-cash items (13)
(12,053) (3,219)
Changes In Working Capital
Increase in trade and other receivables 521 1,537
Increase in trade and other payables 12,188 354
----------------------- --------
12,709 1,891
----------------------- --------
Taxation Paid -- --
----------------------- --------
Net Cash Inflow/(Outflow) from Operating
Activities 656 (1,328)
----------------------- --------
Financing Activities
Finance income 156 147
Issue of shares 10 --
Treasury Shares (1,522) --
Net Cash (Outflow)/Inflow from Financing
Activities (1,356) 147
----------------------- --------
Decrease In Cash and Cash Equivalents (700) (1,181)
======================= ========
Cash and Cash Equivalents
At beginning of year 3,108 4,317
Effects of foreign exchange rates differences
on cash (306) (28)
Decrease Cash and Cash equivalents (700) (1,181)
At End of Year 22 2,102 3,108
======================= ========
Notes to the Consolidated Financial Statements
31 December 2022
(Expressed in United States Dollars)
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 $9.4 million (2021: $6.4 million loss) driven mainly
by the derivative expenses incurred in 2022.
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 the
Financial Statements.
In making their going concern assessment, the Board have
considered the Group's current financial position, budget and cash
flow forecast. The going concern assessment has considered the
current operating environment and the potential impact of the
volatility of the oil price.
The Group started 2023 with a stable operating and financial
position; 2022 average production of 2,975 barrels of oil per day
("bopd"), (2021 3,006 bopd), and cash and short-term investments of
$12.1 million as at 31 December 2022 (2021: $18.3 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 3 May 2023. The forward price curve applied
in the cash flow forecast starts at a realised price of $67.3/bbl
in May 2023, fluctuating each month down to $64.8/bbl in December
2023 through to $62.0/bbl in December 2024.
-- 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;
-- Whilst the estimated full cost of drilling the deeper Jacobin
well is included, a prudent assumption is utilised in the forecast
whereby production from Jacobin is assumed to be no greater than
that of an onshore conventional well.
-- No SPT is assumed to be incurred on the onshore assets in
2023 or 2024 , 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 2023.
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.
Changes in accounting policies
(a) New standards, interpretations and amendments adopted from 1
January 2022:
The following amendments are effective for the period beginning
1 January 2022:
-- Onerous Contracts - Cost of Fulfilling a Contract (Amendments to IAS 37).
-- Property, Plant and Equipment: Proceeds before Intended Use (Amendments to IAS 16).
-- Annual Improvements to IFRS Standards 2018-2020 (Amendments
to IFRS 1, IFRS 9, IFRS 16 and IAS 41).
The application of these standards has had no impact on the
disclosures, or the amounts recognised in the Group's consolidated
financial statements.
(b) New standards, interpretations and amendments not yet
effective
There are a number of standards, amendments to standards, and
interpretations which have been issued by the IASB that are
effective in future accounting periods that the Group has decided
not to adopt early.
The following amendments will become effective for the period
beginning 1 January 2023:
-- IFRS 17 Insurance Contracts (effective 1 January 2023)
-- IAS 1 Presentation of Financial Statements and IFRS Practice
Statement 2 (Amendment - Disclosure of Accounting Policies)
-- IAS 8 Accounting policies, Changes in Accounting Estimates
and Errors (Amendment - Definition of Accounting Estimates)
-- IAS 12 Income Taxes (Amendment - Deferred Tax related to
Assets and Liabilities arising from a Single Transaction)
While no formal assessment has been performed, the Group does
not expect any other standards issued by the IASB, but not yet
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 Share Options and Long-Term
Incentive Plans ("LTIPs") as consideration for services rendered by
the Group's employees. The fair value of the services received in
exchange for the grant of share-based payments is recognised as an
expense. The total amount to be expensed is determined by reference
to the fair value of the options or LTIP awards granted:
-- including any market performance conditions (for example, an entity's share price);
-- excluding the impact of any service and non-market performance vesting conditions; and
-- including the impact of any non-vesting conditions.
Non-market performance and service conditions are included in
assumptions about the number of share-based payments that are
expected to vest. The total expense is recognised over the vesting
period, which is the period over which all of the specified vesting
conditions are to be satisfied.
At the end of each reporting period, the Group revises its
estimates of the number of options or LTIP awards that are expected
to vest based on the non-market vesting conditions. It recognises
the impact of the revision to original estimates, if any, in the
Consolidated Statement of Comprehensive Income, with a
corresponding adjustment to equity. When the options are exercised,
the Group issues new shares. The proceeds received net of any
directly attributable transaction costs are credited to share
capital (nominal value) and share premium.
The grant by the Company of options and LTIPs over its equity
instruments to the employees of subsidiary undertakings in the
Group is treated as a capital contribution. The fair value of
employee services received, measured by reference to the grant date
fair value, is recognised over the vesting period as an increase to
investment in subsidiary undertakings, with a corresponding credit
to equity.
Employee Benefit Trust
On 15 November 2021, 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 "GBP") currencies. The
following exchange rates have been used in the preparation of these
financial statements:
2022 2021
-------------------- --------------------
$ GBP $ GBP
Average rate TTD= $/GBP 6.754 8.357 6.765 9.006
Closing rate TTD= $/GBP 6.742 8.146 6.763 9.151
(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
Provision for decommissioning is recognised in accordance with
the contractual obligations at the commencement of oil and gas
production. The amount recognised is the net present value of the
estimated cost of decommissioning at the end of the economic
producing lives of the wells and the end of the useful lives of
refinery and storage units. Such costs include removal of equipment
and restoration of land or seabed. The unwinding of the discount on
the provision is included in the Consolidated Statement of
Comprehensive Income within finance costs.
A corresponding asset is also created at an amount equal to the
provision. This is subsequently depleted as part of the capital
costs of the production assets. Any change in the present value of
the estimated expenditure or discount rates are reflected as an
adjustment to the provision and the asset and dealt with
prospectively.
(b) Non-Oil & Gas Assets
All property, plant and equipment are recorded at historical
cost less accumulated depreciation and any impairment losses.
Historical cost includes the original purchase price of the asset
and expenditure that is directly attributable to bringing the asset
to its working condition for its intended use. Subsequent costs are
included in the asset's carrying amount or recognised as a separate
asset, as appropriate, only when it is probable that future
economic benefits associated with the item will flow to the Group
and the cost of the item can be measured reliably.
The provision for depreciation with respect to operations other
than oil and gas producing activities is computed using the
straight-line method based on estimated useful lives as
follows:
Leasehold and buildings 20 years
Plant and equipment 4 years
Other 4 years
The assets' residual values and useful lives are reviewed and
adjusted if appropriate at each Statement of Financial Position
date. An asset's carrying amount is written down immediately to its
recoverable amount if the asset's carrying amount is greater than
its estimated recoverable amount. Gains and losses on disposals are
determined by comparing proceeds with carrying amounts and are
included in the Consolidated Statement of Comprehensive Income.
Repairs and maintenance are charged to the Consolidated
Statement of Comprehensive Income during the financial period in
which they are incurred. The cost of major renovations is included
in the carrying amount of the asset when it is probable that future
economic benefits in excess of the originally assessed standard of
performance of the existing assets will flow to the Group. Major
renovations such as leasehold improvements are depreciated over the
remaining useful life of the related asset.
Impairment of non-financial assets
At each reporting date, assets that are subject to amortisation
are reviewed for impairment whenever events or changes in
circumstances indicate that the carrying amount may not be
recoverable. An impairment loss is recognised for the amount by
which the asset's carrying amount exceeds its recoverable amount.
The recoverable amount is the higher of an asset's FVLCD and VIU.
For the purposes of assessing impairment, assets are grouped at the
lowest levels for which there are separately identifiable cash
flows (CGUs). Non-financial assets that suffered impairment are
reviewed for possible reversal of the impairment at each reporting
date.
Inventories
Crude oil is stated at the lower of cost and net realisable
value. Cost is determined by the average cost method. Net
realisable value is the estimated selling price in the ordinary
course of business, less applicable variable selling expenses.
Materials and supplies used mainly in drilling wells, RCPs and WOs
are stated at lower of cost and net realisable value. Cost is
determined using the weighted average cost method.
Cash and Cash equivalents
For the purpose of presentation in the Consolidated Statement of
Cash Flows, Cash and Cash equivalents includes cash on hand,
deposits held at call with financial institutions, other
short-term, highly liquid investments with original maturities of
three months or less that are readily convertible to known amounts
of cash and which are subject to an insignificant risk of changes
in value.
Trade receivables
Trade receivables are amounts due from customers for crude oil
sold in the ordinary course of business. They are generally due for
settlement within thirty days and therefore are all classified as
current. Trade receivables are recognised initially at the amount
of consideration that is unconditional unless they contain
significant financing components, when they are recognised at fair
value.
The Group applies the simplified approach to determine
impairment of trade receivables. The simplified approach requires
expected lifetime losses to be recognised from initial recognition
of the receivables. This involves determining the expected loss
rates using a provision matrix that is based on the historical
default rates observed over the expected life of the receivable and
adjusted forward-looking estimates. This is then applied to the
gross carrying amount of the receivable to arrive at the 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%.
PT accrued for past years is now considered unlikely to be
charged and paid, 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.
In 2022 the Group revised its estimates due to additional
vehicles and copier assets included in lease agreements and the
extension of staff house leases in December 2022. As a result,
there was a revision to the carrying amount of the lease liability
to reflect the payments to being made over the revised term, which
was discounted using the same incremental rate. Equivalent
adjustment is made to the carrying value of the right-of-use asset,
with the revised carrying amount being amortised over the remaining
(revised) lease term.
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% (2021:
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% (2021: 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.
2022 2021
$'000 $'000
Profit/(loss) for the year and Equity
10% strengthening of the US Dollar/
(2021: 10%) (269) (247)
10% weakening of the US Dollar/ (2021:
10%) 269 247
======================= =================
(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% (2021: 20%) increase and decrease in
realised oil prices. 20% (2021: 20%) is the sensitivity rate that
best represents Management's assessment of the possible change in
the oil prices that may affect the Group. A positive number below
indicates an increase in revenue, while there would be an equal and
opposite impact on revenue if there is a decrease in prices by
20%.
2022 2021
$'000 $'000
Revenue
20% increase in price/ (2021: 20%) 18,931 13,168
20% decrease in price/ (2021: 20%) (18,931) (13,168)
=============== ===============
The Group implemented hedge options during the financial year,
the purpose of which is to offer protection in the event of oil
prices declining significantly.
(iii) Cash flow and fair value interest rate risk
The Group's main interest rate risk arises from borrowings which
expose the Group to cash flow interest rate risk. The Group manages
risk by limiting the exposure to floating interest rates and
maintaining a balance between floating and fixed contract
rates.
At 31 December 2022, there were no loan commitments to attract
interest rates on foreign currency-denominated borrowings, (2021:
nil). During 2022 there was a bank overdraft facility which
incurred $0.1 million interest (2021: $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 (2021: $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 (2021: $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 $12.1 million (2021: $18.3
million).
Management monitors rolling forecasts of the Group's Cash and
Cash equivalents on the basis of expected cash flows. This is
carried out at the Group level in accordance with practice and
limits set by the Group, refer to the disclosures in Note 1:
Background and accounting policies - Going Concern for more
information regarding the factors considered by the Company in
managing liquidity risk.
The table below analyses the Group's and Company's financial
liabilities into relevant maturity groupings based on their
contractual maturities for:
(a) All non-derivative financial liabilities, and
(b) Net and gross settled derivative financial instruments for
which the contractual maturities are essential for an understanding
of the timing of the cash flows.
The following table sets out the contractual maturities
(representing undiscounted contractual
cash-flows) of financial liabilities.
Group Less than 1 to 2 years 2 to 5 years Total
1 year
At 31 December
2022
$'000 $'000 $'000 $'000
Non-derivatives
Trade and other
payables 9,932 -- -- 9,932
Bank overdraft 2,700 -- -- 2,700
Lease liabilities 584 204 137 925
13,216 204 137 13,557
========== ============= ============= ===============
At 31 December $'000 $'000 $'000 $'000
2021
Non-derivatives
Trade and other
payables 8,814 -- -- 8,814
Bank overdraft 2,700 -- -- 2,700
Lease liabilities 609 50 47 706
12,123 50 47 12,220
========== ============= ============= ===============
Company Less than Total
1 year
At 31 December
2022
$'000 $'000
Non-derivatives
Trade and other
payables 565 565
Intercompany 12,731 12,731
13,296 13,296
========== ========
At 31 December $'000 $'000
2021
Non-derivatives
Trade and other
payables 327 327
Intercompany 781 781
1,108 1,108
========== ========
(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).
2022 2021
$'000 $'000
--------- ---------
Net cash 9,431 15,612
Total equity (56,131) (56,921)
--------- ---------
Total capital (46,700) (41,309)
Gearing ratio (20.2)% (37.8)%
(e) Fair value estimation
The Group and Company have classified financial instruments into
the three levels prescribed under the accounting standards.
-- Level 1: The fair value of financial instruments traded in
active markets (such as publicly traded derivatives, and equity
securities) is based on quoted market prices at the end of the
reporting period. The quoted market price used for financial assets
held by the Group is the current bid price. These instruments are
included in level 1.
-- Level 2: The fair value of financial instruments that are not
traded in an active market (for example, over-the-counter
derivatives) is determined using valuation techniques which
maximise the use of observable market data and rely as little as
possible on entity-specific estimates. If all significant inputs
required to fair value an instrument are observable, the instrument
is included in level 2.
-- Level 3: If one or more of the significant inputs is not
based on observable market data, the instrument is included in
level 3. This is the case for unlisted equity securities. See Note
21 for details.
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. 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) 2022 2021
Risk free rates 7-12 3.96% 1.80%
-------------- ------ ------
13-18 4.04% 1.96%
-------------- ------ ------
19-21 4.14% 2.20%
-------------- ------ ------
22-23 4.09% 2.20%
-------------- ------ ------
Inflation rate 3.20% 2.40%
-------------- ------ ------
The following table details the Group's sensitivity to a 1%
(2021: 1%) increase and decrease in discount and inflation rates.
1% (2021: 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 2022 of a
1% change in these variables is as follows:
Consolidated Statement Consolidated Statement
of Financial Position: of Comprehensive: Income/Expense
Obligation
2022 2022
$'000 $'000
------------------------ ----------------------------------
Discount rate
1% increase in assumed
rate (7,642) 259
1% decrease in assumed
rate 9,246 (415)
Inflation rate
1% increase in assumed
rate 9,234 222
1% decrease in assumed
rate (7,769) (189)
(c) Estimation of reserves
All reserve estimates involve some degree of uncertainty, which
depends chiefly on the amount of reliable geological and
engineering data available at the time of the estimate. Generally,
reserve estimates are revised as additional data becomes available.
The Group's reserve estimates are also evaluated when required by
independent external reserve evaluators. The last independent
external reserve valuation was done in 2012. Since 2012 up to and
including 2021 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.
As at 31 December 2022 all subsidiaries onshore and offshore 2P
reserve estimates were re-evaluated by the EMT and approved by the
Board.
(d) Impairment of Property, Plant and Equipment
Management performs impairment assessments on the Group's
property, plant and equipment once there are indicators of
impairment . Triggers for impairment 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 2022 an
impairment charge of $5.6 million was recognised on the Group's
property, plant and equipment (2021: $0.1 million) see Note 13. The
impairment charge resulted in the carrying amount of the respective
CGUs being written down to their recoverable amount.
Oil & Gas Assets $5.6 million (2021: $0.1 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.
2023 2024 2025 2026 2027 2028
Realised price 69.8 65.5 62.5 60.2 58.5 57.7
If the price deck used in the impairment calculation had been
10% lower than Management's estimates at 31 December 2021, the
Group would have a $16.1 million increase on impairment of Oil
& Gas Assets (2021: $0.6 million increase). If the price deck
used in the impairment calculation had been 10% higher than
Management's estimates at 31 December 2021, the Group would have a
$0.6 million decrease on impairment of the Oil & Gas Assets
(2021: $0.1 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 2022, Management's estimate of
the Group's cost of capital was 15.0% (2021:13.0%). 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 $0.0 million decrease (2021: $0.0 million)
change to the impairment position for 2022 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 $0.0 million increase to the impairment position for
2022 (2021: $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 2022 a review for impairment triggers was carried out and
there were no impairment losses realised against the carrying
values of the Group's E&E assets.
The Group reviews the carrying values of intangible E&E
assets when there are impairment indicators which would tell
whether an E&E asset has suffered any impairment. The amounts
of intangible E&E assets represent the costs of active projects
the commerciality of which is unevaluated until reserves can be
appraised.
(f) Property tax
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 Amendment to the Act
requires the Board of Inland Revenue to issue a Notice of
Assessment on or before 31 March in each year. To date, none has
been issued for any of the years 2018 to 2021. Based on public
pronouncements the intention was to complete the assessment for
residential properties by 2021, after which other categories can be
assessed. Given the passage of time, it is remote that retroactive
application will be implemented despite waivers being issued by the
Government for periods 2010- 2017 but not for periods 2018-2021.
Whilst there remains some ambiguity within the interpretation of
the law, industry practice within T&T indicates that it is
appropriate to not recognise a PT liability.
The Group has considered whether a contingent liability exists.
However, given the judgement is that the law does not allow for
retroactive application, there is no liability arising from a past
event. A liability will arise when the valuation roll has been
completed and the Notice of Assessment given. 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 2022.
(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.
(h) Transfer of PS-4 development costs to E&E assets
The Group acquired the PS-4 asset on 1 December 2021 for $3.8
million and accounted for the full cost as development capital
expenditure based on the available data when purchased. Subsequent
to acquiring the asset reviewing the seismic acquired, the
subsurface work matured allowing the technical team to demonstrate
that multiple contingent and prospective resource areas exist in
PS-4 and the seismic interpretations in 2022 have identified at
least three exploration/appraisal prospects, one of which is
planned to be drilled in 2023; the 2P and infill wells in this
asset have not been drill due to supply chain costs and
inflationary pressures.
These key developments in 2022 resulted in a strategic change by
Management to focus on E&E activities as the findings confirm
that the PS-4 asset has significant exploration potential.
Management applied judgement based on the specific facts and
circumstances and considered the underlying nature of the asset and
determined it was appropriate to transfer $2.5 million of
development costs to E&E capital expenditure effective 31
December 2022. Judgment was required in determining the date at
which such cost capitalisation commenced considering the timing of
the strategic review being sufficiently concluded. In concluding
that the costs met the cost capitalisation criteria under the
Group's accounting policy for E&E assets, Management considered
the nature of the activities, its objective and contribution to the
E&E activities.
Prior to the strategic change, an impairment assessment was
performed on PS-4 development costs and an impairment was
recognised (refer to 3(d)). No impairment indicators were
identified on the costs transferred to E&E asset.
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
2022 2021
$'000 $'000
------- -------
Operating profit before impairment and exceptional
items is stated after taking the following items
into account:
DD&A (Note 13) 6,890 6,756
Depreciation on ROU (Note 14) 534 505
Amortisation of computer software (Note 15) 193 166
Employee costs (Note 35) 8,317 9,670
Inventory recognised as expense, charged to operating
expenses 174 322
------- -------
Auditors' remuneration
During the year the Group (including its overseas subsidiaries)
obtained the following services from the Company's Auditors as
detailed below:
2022 2021
$'000 $'000
------- -------
* Fees payable to the Company's auditors' and their
affiliated firms for the audit of the parent Company
and consolidated financial statements:
BDO LLP (UK based) * 220 161
BDO Limited (T&T and Barbados based)* 107 84
* Fees payable to the Company's auditors' for other
services:
The audit of Company's subsidiaries 16 16
Audit related assurance services - interim review 29 32
Total assurance and auditors' remuneration 372 293
2022 2021
$'000 $'000
Professional Services:
Tax services -- 1
------- -------
All fees in 2022 are in respect of services provided by BDO LLP
and their affiliated firms. The independence and objectivity of the
external auditors are considered on a regular basis by the Audit
Committee, with particular regard to the level of non-audit fees
incurred. The professional fees relates to tax services rendered
for advice on tax losses.
6 Derivative expenses
The net (loss)/ gain in fair value is recognised in the
Consolidated Statement of Comprehensive Income during the year:
31 December 31 December
2022 2021
$'000 $'000
Derivative expenses (realised) (10,446) (1,293)
Movement in FV of derivative financial
instruments (unreaslised) 2,883 (3,149)
------------ ------------
(7,563) (4,442)
============ ============
7 Exceptional Items:
Items that are material either because of their size, their
nature, or that are non-recurring are considered as exceptional
items and are presented within the line items to which they best
relate. During the current period, exceptional items as detailed
below have been included in the Consolidated Statement of
Comprehensive Income. An analysis of the amounts presented as
exceptional items in these consolidated financial statements are
highlighted below.
31 December 31 December
2022 2021
$'000 $'000
ICT incident costs 161 --
Fees relating to Capital Reorganisation -- 113
Exceptional items 161 113
============== ==============
Exceptional items:
-- Charges relating to ICT incident: $0.2 million charge in
relation to costs incurred in relation to the cyber incident (refer
to Note 36 (4)).
8 Impairment
31 December 31 December
2022 2021
$'000 $'000
Impairment of Inventory 334 1,220
Impairment of property, plant and equipment 5,558 96
Other impairment of property, plant and 158 --
equipment
------------ ------------
Total expense 6,050 1,316
============ ============
-- Impairment of inventory - $0.3 million charge in relation to
inventory impairment. In 2021 $1.2 million on slow moving inventory
items.
-- Impairment of property, plant and equipment - $5.6 million
charge in relation to property, plant and equipment and cash
generating units. In 2021 the impairment of property, plant and
equipment related to charges for impairment losses on cash
generating units (refer to Note 3(d)).
-- Other impairment of property, plant and equipment - $0.1
million charge in other property, plant and equipment relates to
expense incurred on unsuccessful recompletion cost on wells.
9 Finance income and costs
Recognised in the consolidated statement of comprehensive
income
Finance income
2022 2021
$'000 $'000
Interest Income 48 94
================ ===========
Finance costs 2022 2021
$'000 $'000
Decommissioning - Unwinding of discount (Note
28) (1,110) (1,222)
Interest on Leases (Note 14) (135) (101)
Interest and other expenses on overdraft (94) (152)
----------- --------
(1,339) (1,475)
=========== ========
10 Income Taxation
2022 2021
$'000 $'000
Current Taxes
Petroleum profits tax 2,404 982
Unemployment levy 960 393
Deferred Taxes
Current year
Movement in asset due to tax losses recognised
(Note 18) (935) (5,533)
Movement in liability due to accelerated tax
depreciation (Note 18) (85) (586)
Income tax expense/ (credit) 2,344 (4,744)
====== ========
The Group's effective tax rate varies from the statutory rate
for UK companies of 19% (2021:19%) as a result of the differences
shown below:
2022 2021
$'000 $'000
-------- -------------------------------
Profit before taxation 2,457 2,982
Tax calculated at domestic tax rates applicable
to profits in the respective countries 4,836 3,441
Expenses not deductible for tax purposes 13,448 9,037
Impact on tax losses (5,671) (2,595)
Deferred tax on capital allowances in the current
period recognised (9,334) (9,087)
Tax losses previously generated now recognised
in the current period (935) (5,533)
Other reconciling differences -- (7)
-------- ---------------------------------
Tax charge/ (credit) 2,344 (4,744)
======== =================================
Corporate income tax is calculated at 19% (2021: 19%) of the
assessable profit for the year for the UK parent company, 55% for
the operating subsidiaries in Trinidad and Tobago (2021: 55%) and
30% (2021: 30%) for the corporate subsidiaries in Trinidad and
Tobago.
Taxation losses at 31 December 2022 available for set off
against future taxable profits amounts to approximately $227.5
million (2021: $234.6 million), with tax losses recognised of $24.9
million at the end of 2022. These losses do not have an expiry date
and 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 against
75% of the otherwise chargeable profits in a year.
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.
Profit for Weighted Average Earnings
the year $'000 Number of Shares Per Share
'000' $
Year ended 31 December
2022
Basic 113 38,813 0.00
Diluted 113 40,243 0.00
------------------------------ ---------------------- ------------------------ -----------------
Year ended 31 December
2021
Basic 7,726 38,879 0.20
Diluted 7,726 42,260 0.18
------------------------------ ------------ ------------- -----------
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. Share Options of
28,954 are considered potential ordinary shares and have not been
included as the exercise hurdle would not have been met.
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 2022
(See notes 23 and 24).
12 Investment In Subsidiaries
Company
2022 2021
$'000 $'000
---------- ----------
Opening balance 60,347 60,021
Share based payment reserve revision -- (121)
Share based payment 517 447
Closing balance 60,864 60,347
========== ==========
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. In
addition, in 2021 there was a revision to the Share based payment
reserves as it relates to employees that no longer work for the
Group.
Listing of Subsidiaries
The Group's subsidiaries at 31 December 2022 are listed
below:
Name Registered Address/Country Nature of % Shares
of Incorporation Business held by
the Group
c/o Pinsent Masons LLP,
1 Park Row, Leeds, LS1 99.99998
Bayfield Energy Limited 5AB, UK Holding Company %
------------------------------ ----------------- -----------
Trinity Exploration 13 Queen's Road, Aberdeen,
& Production (UK) Limited AB15 4YL, UK Holding Company 100 %
------------------------------ ----------------- -----------
Trinity Exploration c/o Pinsent Masons LLP,
and Production Services 1 Park Row, Leeds, LS1
(UK) Limited 5AB, UK Service Company 100 %
------------------------------ ----------------- -----------
Av. Presidente Vargas 509,
Bayfield Energy do Rio de Janeiro, 20071-003,
Brasil Ltda Brazil Dormant 100 %
------------------------------ ----------------- -----------
Trinity Exploration Ground Floor, One Welches,
& Production (Barbados) Welches,
Limited St. Thomas BB22025, Barbados Holding Company 100 %
------------------------------ ----------------- -----------
3(rd) Floor Southern Supplies
Limited Building, 40 -44
Trinity Exploration Sutton Street, San Fernando,
and Production (Trinidad Trinidad & Tobago ("Trinidad
and Tobago) Limited 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 c/o Pinsent Masons LLP
and Production plc 1 Park Row, Leeds, Employee
Employee Benefit Trust LS1 5AB, UK Benefit Trust 100 %
13 Property, Plant and Equipment
Oil
Plant Leasehold & Gas
& Equipment & Buildings Assets Other Total
Year ended 31 December 2022 $'000 $'000 $'000 $'000 $'000
------------- ------------- ---------- ------ ----------
Opening net book amount at
1 January 2022 2,919 1,388 45,200 -- 49,507
Additions 1,999 71 13,062 -- 15,132
Transfers (Note 3(h)) -- -- (2,451) -- (2,451)
Adjustment to decommissioning
estimate (Note 28) -- -- (4,595) -- (4,595)
Impairment charge(1) (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 3,483 323,161 336 345,173
Accumulated DD&A and impairment (13,938) (2,212) (283,700) (336) (300,186)
Closing net book amount 4,255 1,271 39,461 -- 44,987
Oil
Plant Leasehold & Gas
& Equipment & Buildings Assets Other Total
Year ended 31 December 2021 $'000 $'000 $'000 $'000 $'000
------------- ------------- ---------- ------ ----------
Opening net book amount at
1 January 2021 2,028 1,481 34,247 -- 37,756
Additions 1,328 74 8,794 -- 10,196
Adjustment to decommissioning
estimate (Note 28) -- -- 8,407 -- 8,407
Impairment charge(1) -- -- (96) -- (96)
DD&A charge for year (437) (167) (6,153) -- (6,757)
Translation differences -- -- 1 -- 1
Closing net book amount at
31 December 2021 2,919 1,388 45,200 -- 49,507
============= ============= ========== ====== ==========
At 31 December 2021
Cost 16,222 3,412 318,058 336 338,028
Accumulated DD&A and impairment (13,303) (2,024) (272,858) (336) (288,521)
Closing net book amount 2,919 1,388 45,200 -- 49,507
============= ============= ========== ====== ==========
1 An impairment loss of $5.7 million (2021: $0.1 million) was
recognised on Oil & Gas Assets (see Note 3 ( d)) as a result of
the carrying value being higher than the recoverable amount. The
recoverable amount was determined by assessing its fair value less
costs of disposal.
14 Leases
The Group has recognised ROU assets and lease liabilities.
(i) Amounts recognised in the Consolidated Statement of Financial Position
The Consolidated Statement of Financial Position shows the
following amounts relating to leases:
31 December 31 December
2022 2021
$'000 $'000
Right-of-use assets
Non-current assets 838 616
============== ==============
Lease Liabilities
Current 584 609
Non-current 341 97
925 706
============== ==============
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:
2022 2021
$'000 $'000
Depreciation charge of ROU assets
Depreciation (534) (505)
=============== ========
Interest expense (including finance cost) (135) (101)
=============== ========
The total cash outflow for leases in 2022 was $0.7 million
(2021: $0.6 million)
(iii) The Group's leasing activities and how these are accounted for
The Group leases various offices, equipment, staff housing and
vehicles. Rental contracts are typically made for fixed periods of
6 months to 4 years.
Contracts may contain both lease and non-lease components. There
were no non-lease components identified and as such the Group
allocates the consideration in the contract to a single lease
component based on their relative stand-alone prices.
Lease terms are negotiated on an individual basis and contain a
wide range of different terms and conditions. The lease agreements
do not impose any covenants other than the security interests in
the leased assets that are held by the lessor. Leased assets may
not be used as security for borrowing purposes.
15 Intangible Assets
The carrying amounts and changes in the year are as follows:
Exploration
and Evaluation Computer Research
assets software and Development Total
Year ended 31 December 2022 $'000 $'000 $'000 $'000
Opening net book amount at
1 January 2022 30,217 496 46 30,759
Additions 235 102 183 520
Transfers (Note 3(h)) 2,451 -- -- 2,451
Amortisation charge for year -- (193) -- (193)
Closing net book amount
at 31 December 2022 32,903 405 229 33,537
At 31 December 2022
Cost 32,903 979 229 34,111
Accumulated amortisation -- (574) -- (574)
Closing net book amount 32,903 405 229 33,537
Exploration
and Evaluation Computer Research
assets software and Development Total
Year ended 31 December 2021 $'000 $'000 $'000 $'000
Opening net book amount at
1 January 2021 27,042 307 -- 27,349
Additions 3,175 355 46 3,576
Amortisation charge for year -- (166) -- (166)
Closing net book amount
at 31 December 2021 30,217 496 46 30,759
-- E&E assets: Represents the cost for the TGAL 1
exploration well and transfer of PS-4 Development cost to E&E
costs of USD 2.5 million (refer to Note 3(h)). The Group tests
whether E&E assets have suffered any impairment triggers on an
annual basis and there were no impairment triggers identified
(2021: nil).
-- Computer Software: In 2022, costs incurred in connection with the acquisition of software.
-- Research and Development: In 2022, there were costs
associated for various initiatives in connection with reducing
carbon emissions.
16 Abandonment fund
2022 2021
$'000 $'000
At 1 January 4,021 3,490
Additions 490 531
At 31 December 4,511 4,021
Abandonment funds are restricted cash put aside in escrow for
abandonment and environmental purposes in accordance with
contractual obligations to be used in accordance with the
contract.
17 Performance bond
2022 2021
$'000 $'000
At 1 January and 31 December 602 473
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:
2022 2021
$'000 $'000
DTA:
DTA to be recovered in more than 12 months (7,774) (5,130)
DTA to be recovered in less than 12 months (4,691) (6,400)
DTL:
DTL to be settled in more than 12 months 1,940 2,025
Net DTA (10,525) (9,505)
The movement on the deferred income tax is as follows:
2022 2021
$'000 $'000
At beginning of year (9,505) (3,386)
Movement for the year (935) (6,041)
Unwinding of deferred tax on fair value uplift (85) (78)
Net DTA (10,525) (9,505)
The deferred tax balances are analysed below:
2020 Movement 2021 Movement 2022
$'000 $'000 $'000 $'000 $'000
Acquisition (33,436) -- (33,436) -- (33,436)
Tax losses recognised (39,476) (5,533) (45,009) (935) (45,944)
Tax losses derecognised 66,915 66,915 66,915
(5,997) (5,533) (11,530) (935) (12,465)
2020 Movement 2021 Movement 2022
DTL $'000 $'000 $'000 $'000 $'000
Accelerated tax
depreciation and
non-current asset
impairment (18,867) (508) (19,375) -- (19,375)
Acquisitions 19,580 -- 19,580 -- 19,580
Fair value uplift 1,898 (78) 1,820 (85) 1,735
2,611 (586) 2,025 (85) 1,940
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 $0.9 million
have been recognised (2021: $5.5 million was recognised) based on
estimated future taxable profits. The Group has unrecognised
deferred tax assets amounting to $87.2 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 2022 the Group had gross tax losses
carried forward of $227.5 million (2021: $234.6 million)
represented by corporate tax losses in the UK of $33.2 million
(2021: $23.7 million) and PPT and Corporate tax losses in Trinidad
and Tobago of $194.3 million (2021: $210.9 million). In the UK
corporation tax losses may be carried forward indefinitely.
Similarly, in Trinidad and Tobago PPT and corporate tax losses may
be carried forward indefinitely to reduce the taxes in future
years. As of 1 January 2020, however, PPT losses can only be
utilised to shelter a maximum of 75 percent of PPT per annum.
19 Inventories
Crude oil Materials Total
and supplies
$'000 $'000 $'000
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
At 1 January 2021 67 5,200 5,267
Impairment (see note 8) -- (1,220) (1,220)
Net inventory movement 29 (256) (227)
At 31 December 2021 96 3,724 3,820
(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 a total of $0.3
million of impairment of inventory items (2021: $1.2 million).
20 Trade and Other Receivables
Group Company
2022 2021 2022 2021
$'000
$'000 $'000 $'000
Due within 1 year
Amounts due from related parties
(Note 31 (d)) -- -- 2,830 3,372
Trade receivables 4,643 4,641 -- --
Less: provision for impairment of
trade and intercompany receivables (4) (6) -- --
Trade receivables: net 4,639 4,635 2,830 3,372
Prepayments 969 895 198 175
VAT recoverable 4,544 4,550 29 25
Other receivables 582 767 6 --
Less: provision for Impairment of
other receivables (56) (100) -- --
10,678 10,747 3,063 3,572
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 2022 of $0.1 million (31 December 2021: $0.1 million)
against Other receivables.
VAT recoverable - At 31 December 2022 the VAT recoverable was
$4.5 million. During 2022, the Group generated VAT refunds of $3.1
million and received VAT refunds of $3.2 million.
All trade receivables are with the Group's only customer,
Heritage. Ageing analysis of these trade receivables as at 31
December 2022 is as follows:
2022 2021
$'000 $'000
Up to 30 days 4,544 4,495
>60 days -- --
>180 days 95 140
4,639 4,635
The carrying amount of the Group's trade and other receivables
are denominated in the following currencies:
Group Company
2022 2021 2022 2021
$'000 $'000 $'000 $'000
USD 3,381 3,292 2,873 3,416
GBP 260 169 190 156
TTD 7,037 7,286 -- --
10,678 10,747 3,063 3,572
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
2022 2021 2022 2021
$'000 $'000 $'000 $'000
Trade receivables
Counterparties without external
credit rating:
Existing customers with no defaults
in the past 10,678 10,747 -- --
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
2022, trade receivables of $4.6 million (2021: $4.6 million) were
therefore considered to be fully performing.
At the end of 2022 a total of $0.1 million was outstanding from
Petrotrin (2021: $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 (2021: $0.1 million) was
calculated.
21 Derivative financial instruments
The following table compares the carrying amounts and fair
values of the Group's financial liabilities as at 31 December
2022.
As at 31 December As at 31
2022 December
2021
$'000 $'000
Derivative liability -- 2,883
Total -- 2,883
By 31 December 2022 all crude derivative contracts expired.
The Group considers that the carrying amount of the following
financial assets and financial liabilities are a reasonable
approximation of their fair value:
- Trade receivables
- Trade payables
- Cash and cash equivalents
Fair Value Hierarchy
The level in the fair value hierarchy within which the
derivative financial asset is categorised is determined on the
basis of the lowest level input that is significant to the fair
value measurement.
The derivative financial assets are classified in their entirety
into only one of the three levels.
The fair value hierarchy has the following level:
- Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities
- Level 2 - inputs other than quoted prices included within
Level 1 that are observable for the asset or liability, either
directly (i.e. as prices) or indirectly (i.e. derived from
prices)
- Level 3 - inputs for the asset or liability that are not based
on observable market data (unobservable inputs).
Level 2 recurring fair value measurements:
As at 31 As at 31
December 2022 December 2021
$'000 $'000
Opening balance (2,883) 266
Opening derivative instrument realised 2,883 (266)
Derivative expense (loss in fair value) -- (2,883)
Closing balance -- (2,883)
22 Cash and Cash Equivalents
Group Company
2022 2021 2022 2021
$'000 $'000 $'000 $'000
Short term investment 1,033 2,449 1,033 2,449
Cash and cash equivalents 11,098 15,863 1,069 659
12,131 18,312 2,102 3,108
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 Ordinary Share premium Total
of shares shares $'000
$'000 $'000
As at 1 January 2022 38,879,431 389 -- 389
Shares Issued at Nominal
value 1,005,206 10 -- 10
As at 31 December 2022 39,884,637 399 -- 399
24 Treasury Shares
Treasury shares are shares in the Company that are held by the
Company. In September 2022, the Group announced a share buyback
programme to return up to $1 million to shareholders, which was
completed with 672,000 ordinary shares having been repurchased. The
Group subsequently announced a second tranche of its share buyback
programme to return up to an additional $1 million to shareholders,
and as at 31 December 2022, this programme was still ongoing with
400,000 shares having been repurchased for approximately $0.5m
during 2022.
Group and Company
Number of Cost Total
shares $'000 $'000
Share buyback - 1st tranche 672,000 994 994
Share buyback - 2nd tranche 400,000 528 528
As at 31 December 2022 1,072,000 1,522 1,522
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 2022 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:
2022 2021
$'000 $'000
At 1 January 3,784 14,764
Capital Reduction -- (11,485)
Share based payment expense:
Lapsed options released to retained earnings (1,416) --
LTIP expense 622 505
At 31 December 2,990 3,784
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 Exercise Number Exercise Number
Date price per of Options price per of Share
Share Options Share Options 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 Awards
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 2 January 2022
respectively, 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 (50(th) 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 2018 LTIP
Award Award
Grant Dates 2 January 9 May 2019
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 2 January
2021 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 (50(th) 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 GBP1.38 (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
Movements in the number of LTIPs outstanding and their related
weighted average exercise prices are as follows:
2022 Average Number 2021 Average Number of
exercise of Options exercise price Options
price per per Share Option
Share Option
At 1 January GBP 0.00 3,381,299 GBP 0.00 3,156,299
Forfeited/Lapsed GBP 0.00 (1,360,733) GBP 0.00 (100,000)
Granted(1) GBP 0.00 415,000 GBP 0.00 325,000
Exercised(2) GBP 0.00 (1,005,206) GBP 0.00 --
At 31 December GBP 0.00 1,430,360 GBP 0.00 3,381,299
(1 Weighted average fair value of LTIPs granted GBP 1.38)
(2 Weighted average share price at the date of exercise GBP
1.00)
LTIPs outstanding at the end of the year have the following
expiry date and exercise prices:
Expiry Exercise
Grant-Vest date price 2022 2021
24/8/2017 - 30/6/2022 24/08/2027 GBP 0.00 167,037 2,103,032
2/1/2019 - 1/1/2021 1/1/2024 GBP 0.00 50,858 252,510
9/5/2019 - 2/1/2021 2/1/2025 GBP 0.00 90,879 319,171
25/6/2020 - 2/1/2023 2/1/2026 GBP 0.00 381,586 381,586
13/8/2021 - 31/12/2023 2/1/2027 GBP 0.00 325,000 325,000
6/6/2022 - 1/1/2025 1/1/2027 GBP 0.00 415,000 -
26 Merger and Reverse Acquisition Reserves
Reverse Acquisition Merger Reserve Total
Reserve
$'000 $'000 $'000
At 1 January 2022 (89,268) -- (89,268)
Capital re-organisation/reduction -- -- --
Translation differences -- -- --
At 31 December 2022 (89,268) -- (89,268)
At 1 January 2021 (89,268) 75,467 (13,801)
Capital re-organisation/reduction -- (75,467) (75,467)
Translation differences -- -- --
At 31 December 2021 (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:
2022 2021
$'000 $'000
Operating Profit Before SPT, Impairment
and Exceptional Items 18,971 9,350
DD&A (note 13 - 15) 7,617 7,428
ILFA (note 20) (46) (754)
SOE (note 24) 647 626
FX (loss)/gain 394 14
Movement in FV of Derivative Financial
Instruments (note 6) (2,883) 3,149
Adjusted EBITDA 24,700 19,813
$'000 $'000
Weighted average ordinary shares outstanding
- basic 38,813 38,879
Weighted average ordinary shares outstanding
- diluted 40,243 41,969
$ $
Adjusted EBITDA per share - basic (note
11) 0.64 0.51
Adjusted EBITDA per share - diluted
(note 11) 0.61 0.47
Adjusted EBITDA after Current Taxes
(the impact of SPT and PPT/UL) is calculated
as follows:
2022 2021
$'000 $'000
Adjusted EBITDA 24,700 19,813
PT -- 1,516
SPT (9,012) (5,074)
PPT/UL (3,365) (1,375)
Adjusted EBIDA After Current Taxes 12,323 14,880
'000 '000
Weighted average ordinary shares outstanding
- basic 38,813 38,879
Weighted average ordinary shares outstanding
- diluted 40,243 41,969
$ $
Adjusted EBIDA After Current Taxes per
share - basic 0.32 0.38
Adjusted EBIDA After Current Taxes per
share - diluted 0.31 0.35
28 Provision for Other Liabilities
(a) Non-current: Decommissioning Closure of Total
provision pits
$'000 $'000 $'000
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
Year ended 31 December 2021
Opening amount as at 1 January
2021 45,405 470 45,875
Unwinding of discount (Note
9) 1,222 -- 1,222
Revision to estimates (Note
13) 8,407 -- 8,407
Decommissioning contribution 195 -- 195
Translation differences (9) -- (9)
Closing balance at 31 December
2021 55,220 470 55,690
Decommissioning cost
The Group operates oil fields and this cost represents an
estimate of the amounts required for abandonment of the Group's
wells, platforms, gathering station and pipeline infrastructures.
The amounts are calculated based on the provisions of existing
contractual agreements with Heritage and MEEI. Furthermore,
liabilities for decommissioning costs are recognised when the Group
has an obligation to dismantle and remove a facility or an item of
plant and to restore the site on which it is located, and when a
reasonable estimate of that liability can be made. An obligation
for decommissioning may also crystallise during the period of
operation of a facility through a change in legislation or through
a decision to terminate operations.
The amount recognised is the present value of the estimated
future expenditure determined in accordance with local conditions
and requirements. A corresponding item of property, plant and
equipment of an amount equivalent to the provision is also created.
This is subsequently depreciated as part of the capital costs of
the facility or item of plant. Any change in the present value of
the estimated expenditure is reflected as an adjustment to the
provision and the corresponding property, plant and equipment. Some
of the key assumptions made in the present value decommissioning
calculation include the following:
a. Core inflation rate - 3.20% (2021: 2.40%)
b. Risk free rate - 3.96% - 4.14% (2021: 1.80% - 2.20%)
c. Estimated market value/decommissioning cost
d. Estimated life of each asset
See Note 3(b): Critical Accounting Estimates and Assumptions for
the rates used and sensitivity analysis.
Closure of Pits
Closure of pits relate to the remedy and closure of pits
associated with drilling new onshore wells . It is an environmental
regulatory requirement set by the Environmental Management
Authority ("EMA") that all open drill pits for onshore drilling
must be closed after sufficient testing has deemed it safe to close
the pit.
(b) Current : Litigation Total
claims Other provisions
$'000 $'000 $'000
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
Year ended 31 December 2021
Opening amount as at 1 January
2021 46 -- 46
Closing balance at 31 December
2021 46 -- 46
Litigation claims
There was an increase in the provisions for $0.1 million to
reflect the best estimate of litigation claims as at 31 December
2022.
Other provisions
There was a provision of $0.1 million arising from the ICT
downtime due to the cyber incident arising in December 2022 (Note
36 (4)).
29 Trade and Other Payables
Group Company
Current 2022 2021 2022 2021
$'000 $'000 $'000 $'000
Trade payables 2,605 2,274 136 88
Accruals 4,661 4,486 429 239
Other payables 500 492 -- --
SPT 2,166 1,562 -- --
9,932 8,814 565 327
30 Bank overdraft
31 December 31 December
2022 2021
$'000 $'000
Bank Overdraft 2,700 2,700
2,700 2,700
An on-demand operating (overdraft) line of $5.0 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 6.75%. 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 $5.0 million of which $2.7
million was drawn as at 31 December 2022.
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
2022 2021
$'000 $'000
Company subsidiaries:
Trinity Exploration and Production Services
Limited 10,510 856
Trinity Exploration & Production (UK) Limited -- 8
Trinity Exploration and Production (Galeota)
Limited -- 659
Bayfield Energy Limited 80 19
Oilbelt Services Limited -- 1,659
Trinity Exploration and Production (Trinidad
and Tobago) Limited 1,800 393
Trinity Exploration and Production Services
Limited (UK) Limited 1,100 30
Transfer of funds -- 73
13,490 3,697
(b) Transfer of funds to related parties
Company
2022 2021
$'000 $'000
Company subsidiaries:
Trinity Exploration and Production Services
Limited -- (70)
Bayfield Energy Limited -- (100)
Trinity Exploration and Production Services
Limited (UK) Limited (1,265) (2,063)
(1,265) (2,233)
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
2022 2021
$'000 $'000
Salaries and short-term employee benefits 876 1,337
Post-employment benefits 30 27
Share-based payment expense 279 305
1,185 1,669
(d) Year-end balances arising from transfer to and from related
parties
Company
2022 2021
$'000 $'000
Receivables from related parties:
Trinity Exploration & Production (UK) Limited 40 28
Trinity Exploration and Production (Galeota)
Limited 2 --
Bayfield Energy Limited 122 192
Trinity Exploration and Production (Trinidad
and Tobago) Limited -- 22
Trinity Exploration and Production Services
(UK) Limited 2,652 3,129
Employee Benefit Trust (See note 1) -- 73
Total intercompany receivables 2,816 3,443
Reversal of provision for impairment/ (provision
for impairment) 14 (71)
Closing intercompany receivables (Note 20) 2,830 3,372
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 (2021: 0.1
million).
Company
2022 2021
$'000 $'000
Payables to related parties:
Trinity Exploration and Production Services
Limited 10,683 167
Trinity Exploration and Production Services
(UK) Limited -- 7
Trinity Exploration and Production (Galeota)
Limited -- 112
Trinity Exploration and Production (Trinidad
& Tobago) Ltd 1,779 --
Oilbelt Services Limited 269 495
Total intercompany payables 12,731 781
32 Taxation Payable
2022 2021
$'000 $'000
Taxation payable
PPT 4 --
UL -- --
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 2022 and 2021, the Group held the following
financial assets at amortised cost:
Group Company
2022 2021 2022 2021
$'000 $'000 $'000 $'000
Trade and other receivables - current
(*) 5,165 5,302 6 200
Abandonment fund - non current 4,511 4,021 -- --
Intercompany -- -- 2,830 3,372
Cash and cash equivalents 12,131 18,312 2,102 3,108
21,807 27,635 4,938 6,680
Note (*): Excludes prepayments and VAT recoverable
At 31 December 2022 and 2021, the Group held the following
financial liabilities at amortised cost:
Group Company
2022 2021 2022 2021
$'000 $'000 $'000 $'000
Accounts payable and accruals 9,932 8,814 565 327
Intercompany -- -- 12,731 781
Bank overdraft 2,700 2,700 -- --
12,632 11,514 13,296 1,108
At 31 December 2022 and 2021, the Group held the following
financial liabilities at fair value through profit or loss:
Group Company
2022 2021 2022 2021
$'000 $'000 $'000 $'000
Derivative financial liability -- 2,883 -- 2,883
-- 2,883 -- 2,883
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) The West Coast Point Ligoure, Guapo Bay and Brighton Marine
Outer ("PGB") licences and the Farm-Out Agreement for the Tabaquite
Block (held by Coastline International Inc.) was expired as at 31
December 2022. Subsequent to the year-end the PGB licence was
renewed to 17 December 2037 (Note 36 (7)). There were no additional
liabilities and commitments arising from the renewed agreement.
ii) 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
c lause 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 c lause 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.
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
Employee costs for the Group during 2022 2021 2022 2021
the year
$'000 $'000 $'000 $'000
Wages and salaries 7,245 8,625 483 1,170
Other pension costs 425 372 -- --
Share based payment expense 647 673 107 94
8,317 9,670 590 1,264
Average monthly number of people 2022 2021 2022 2021
(including Executive and Non-Executive number number number number
Directors') employed by the Group
Executive and Non-Executive Directors 6 6 6 6
Administrative staff 102 95 -- --
Operational staff 168 144 -- --
276 245 6 6
36 Events after the Reporting Period
1. Subsequent to 31 December 2022, the Group has received
further VAT refunds of $2.6 million as at 31 May 2023. On 10 May
2023, the Government of Trinidad and Tobago announced that it
intends to settle outstanding VAT refunds via interest bearing
bonds in order to meet VAT arrears of those registrants who are
owed in excess of $0.03 million in VAT refunds. At the end of May
2023, the Group had $ 2.0 million in VAT refunds recoverable in VAT
bonds.
2. On 31 December 2022, the FZ-2 Lease Operating Agreement (LOA)
expired. Trinity obtained an interim renewal of the LOA to 31 March
2023 and obtained a further extension to 30 June 2023 to execute
the LOA for the period 1 January 2023 to 30 September 2031.
3. On 29 March 2023, the Group provided six-months' notice to
Heritage to terminate the sub-licence Farm-Out agreement for the
Tabaquite block. The new sub-licencee requirements proposed to the
Group makes this licence uneconomic to operate.
4. Cyber incident - The Group was the subject of a sophisticated
cyber incident in December 2022 and immediately took precautionary
measures to protect its IT infrastructure. The Group engaged with
external specialists to investigate the nature and extent of the
incident and implement its systems recovery plan. Trinity moved
quickly to notify relevant regulators and law enforcement agencies.
Trinity's production facilities continued to operate safely
throughout. In 2023, the Group continues to execute its recovery
plan. Trinity's IT team and its external advisers continue to
support the business in returning its administrative systems to
full capacity incorporating learnings from the incident and
embedding more resilient IT infrastructure, cyber security systems
and procedures.
5. Trintes Field Incident - On the evening of 10 April 2023, a
fire occurred in one of the two generators on the Trintes Bravo
platform. Production across the field was halted and the fire was
contained. Production restarted from Alpha and Delta platforms on
11 April 2023. Four operators, all Trinity staff, were on Bravo at
the time of the incident and, having suffered minor injuries, all
are now recovered and resume work. Following approval from the
Ministry of Energy and Energy Industries, received on 17 April
2023, the Company successfully restored oil production from all
previously producing wells on the Bravo platform on 18 April 2023.
Production from the field is in-line with pre-incident levels at
approximately 1,010 bopd.
6. Share buyback - As at 31 December 2022, the second tranche of
the share buyback programme was still ongoing with 400,000 shares
repurchased to 31 December 2022 utilising $0.5 million of the $1
million tranche. On 26 April 2023, the second tranche of the share
buyback programme was completed and a third tranche was announced
on 28 April 2023 for up to a further $1 million. This tranche will
be funded from the Group's existing cash resources and will, unless
terminated at an earlier date, expire at the conclusion of the 2023
AGM, or 30 June 2023, whichever is earlier.
7. Renewal of PGB Exploration and Production Licence - On 3 May
2023, the MEEI provided confirmation of the renewal of the PGB
Licence for an additional 25 years from the Effective Date of 18
December 2012. Consequently, the PGB Licence expires on 17 December
2037. There were no additional liabilities and commitments arising
from the renewed Licence.
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