Trinity Exploration - Full Year Results to 31 December 2022
01/06/2023 07:00
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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
(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 (mailto:trinity@vigoconsulting.com)
Jeremy Bridglalsingh, Chief Executive Officer
Julian Kennedy, Chief Financial Officer
Nick Clayton, Non- Executive Chairman
SPARK Advisory Partners Limited +44 (0)20 3368 3550
(Nominated Adviser and Financial Adviser)
Mark Brady
James Keeshan
Cenkos Securities PLC (Broker) +44 (0)20 7397 8900
Leif Powis +44 (0)131 220 6939
Neil McDonald
Vigo Consulting Limited trinity@vigoconsulting.com (mailto:trinity@vigoconsulting.com)
Finlay Thomson / Patrick d'Ancona +44 (0)20 7390 0230
About Trinity (www.trinityexploration.com (http://www.trinityexploration.com)
)
Trinity is an independent oil production company focused solely on Trinidad
and Tobago. Trinity operates producing and development assets both onshore
and offshore, in the shallow water West and East Coasts of Trinidad.
Trinity's portfolio includes current production, significant near-term
production growth opportunities from low-risk developments and multiple
exploration prospects with the potential to deliver meaningful
reserves/resources growth. The Company operates all of its 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 (bopd) 2022 Avg Sales (bopd)
Block
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 defined 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 Reserves 2022 2C Resources 2022 2P Reserves and 2C Resources 2021 2P Reserves 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
Realised Price USD/bbl 59.8 58.1 37.7 60.4 84. 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 Instrument -- 2.9 -- --
D: Provision for other liabilities 0.2 0.1 -- --
Total Current Liabilities 13.4 15.1 11.3 11.1
(A-B+C+D): Cash plus working capital 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 4 92,232 66,257
sales
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 18,971 9,350
Taxes ("PT")
SPT (9,012) (5,074)
PT net reversal - 1,516
(9,012) (3,558)
9,959 5,792
Operating Profit before Impairment and Exceptional items
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
13,296 3,991
Total Liabilities
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 Capital Share Premium Share Based Payment Reserve Reverse Acquisition Reserve Merger Treasury Translation Reserve Retained Earnings Total Equity
Reserves Shares
Year ended 31 December 2021 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
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 Capital Share Premium Share Based Payment Reserve Merger Reserves Treasury Shares Retained Earnings/ Accumulated Losses Total 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 (2,883) 3,149
instruments
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:
Foreign 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 (13)
items
(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 "£") currencies. The following exchange rates have
been used in the preparation of these financial statements:
2022 2021
$ £ $ £
Average rate TTD= $/£ 6.754 8.357 6.765 9.006
Closing rate TTD= $/£ 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 year 1 to 2 years 2 to 5 years Total
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 2021 $'000 $'000 $'000 $'000
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 1 year Total
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 2021 $'000 $'000
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 of Financial Position: Consolidated Statement 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: 16 16
The audit of Company's subsidiaries
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 2022 31 December 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 2022 31 December 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 2022 31 December 2021
$'000 $'000
Impairment of Inventory 334 1,220
Impairment of property, plant and equipment 5,558 96
Other impairment of property, plant and equipment 158 --
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 4,836 3,441
countries
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 the year $'000 Weighted Average Number of Shares Earnings 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 of Incorporation Nature of Business % Shares held by the Group
Bayfield Energy Limited c/o Pinsent Masons LLP, 1 Park Row, Leeds, LS1 5AB, UK Holding Company 99.99998 %
Trinity Exploration & Production (UK) Limited 13 Queen's Road, Aberdeen, Holding Company 100 %
AB15 4YL, UK
Trinity Exploration and Production Services (UK) Limited c/o Pinsent Masons LLP, 1 Park Row, Leeds, LS1 5AB, UK Service Company 100 %
Bayfield Energy do Brasil Ltda Av. Presidente Vargas 509, Rio de Janeiro, 20071-003, Brazil Dormant 100 %
Trinity Exploration & Production (Barbados) Limited Ground Floor, One Welches, Welches, Holding Company 100 %
St. Thomas BB22025, Barbados
Trinity Exploration and Production (Trinidad and Tobago) Limited 3(rd) Floor Southern Supplies Limited Building, 40 -44 Sutton Street, San Holding Company 100 %
Fernando, Trinidad & Tobago ("Trinidad address")
Trinity Exploration and Production (Galeota) Limited Trinidad address Oil and Gas 100 %
Oilbelt Services Limited Trinidad address Oil and Gas 100 %
Trinity Exploration and Production Services Limited Trinidad address Service Company 100 %
Trinity Midstream Limited Trinidad address Oil and Gas 100 %
Trinity Exploration and Production (Erin 1) Limited Trinidad address Oil and Gas 100 %
Trinity Exploration and Production (Erin 2) Limited Trinidad address Oil and Gas 100 %
Trinity Exploration and Production (Forest 1) Limited Trinidad address Oil and Gas 100 %
Trinity Exploration and Production (Forest 2) Limited Trinidad address Oil and Gas 100 %
Trinity Exploration and Production (Forest 3) Limited Trinidad address Oil and Gas 100 %
Trinity Renewable Resources Limited Trinidad address Oil and Gas 100 %
Trinity Exploration and Production plc Employee Benefit Trust c/o Pinsent Masons LLP Employee Benefit Trust 100 %
1 Park Row, Leeds,
LS1 5AB, UK
13 Property, Plant and Equipment
Plant & Equipment Leasehold & Buildings Oil & Gas 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)
(601) (188) (6,101) -- (6,890)
DD&A charge for year
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
Plant & Equipment Leasehold & Buildings Oil & Gas 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 2022 31 December 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:
2021
2022
$'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 assets Computer software Research and Development Total
Year ended 31 December 2022 $'000 $'000 $'000 $'000
Opening net book amount at 1 January 2022 30,217 496 46 30,759
Additions 235 102 183 520
Transfers (Note 3(h)) 2,451 -- -- 2,451
Amortisation charge for year -- (193) -- (193)
Closing net book amount at 31 December 2022 229 33,537
32,903 405
At 31 December 2022
Cost 32,903 979 229 34,111
Accumulated amortisation -- (574) -- (574)
32,903 405 229 33,537
Closing net book amount
Exploration and Evaluation assets Computer software Research 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
3,175 355 46 3,576
Additions
Amortisation charge for year -- (166) -- (166)
30,217 30,759
Closing net book amount at 31 December 2021 496 46
· 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 and supplies Total
$'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 $'000 2021
$'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 2022 As at 31 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 December 2022 $'000 As at 31 December 2021 $'000
Opening balance (2,883) 266
Opening derivative instrument realised 2,883 (266)
Derivative expense (loss in fair value) -- (2,883)
-- (2,883)
Closing balance
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 of shares Ordinary shares Share premium Total
$'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 shares Cost Total
$'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 Date Exercise price per Share Options Number of Options Exercise price per Share Options Number of Share Options
2012-2015 2022 -- GBP8.60 168,554
2013-2016 2023 28,954 GBP12.00 28,954
28,954 197,508
The inputs into the Black-Scholes model for options granted in prior periods
were as follows:
Grant date 29 May 2013 14 February 2013
Share price GBP 11.90 GBP 12.00
Average Exercise price GBP 12.00 GBP 8.90
Expected volatility 55% 78%
Risk-free rates 4.5% 4.5%
Expected dividend yields 0% 0%
Vesting period 3 years 3 years
LTIP
LTIP awards are designed to provide long-term incentives for the Executive
Directors and other members of the EMT to deliver long-term shareholder
returns. Under the plan, participants are granted options which only vest if
certain performance standards are met. Participation in the plan is at the
Board's discretion and no individual has a contractual right to participate in
the plan or to receive any guaranteed benefits.
2017 One Off Award
One Off LTIP awards were granted in August 2017 over 2,541,600 ordinary shares
and in June 2020 over a further 142,296 ordinary shares (the "2017 One Off
Award"). The 2017 One Off Award vested in full on 30 June 2022, subject to
meeting performance targets relating to the following:
• In respect of 70% of the award, the Company's share price growth
from the 2017 placing price of 49.8 pence per share. If the three-month
volume-weighted price ("VWAP") at the testing date is 350 pence or more per
share, this part of the award will vest in full. If the VWAP at the testing
date is 49.8 pence per share or less, this part of the award will not vest at
all. If the VWAP at the testing date is between 49.8 pence and 350 pence per
share, this part of the award will vest on a pro-rated straight-line basis;
• In respect of 20% of the award, repayment of the amount due to
the BIR in accordance with the terms of the Creditors Proposal approved in
2017. The final payment occurred in 2018; and
• In respect of 10% of the award, redemption of all the
Convertible Loan Notes ("CLN") issued in January 2017 before the second
anniversary of their issue. All of the CLNs were redeemed in 2018.
The total fair value of the 2017 One Off Award was $2.6 million and was
expensed over the vesting period with the full charge pro-rated over the
period up to 30 June 2022. However, the 2017 One Off Award could vest in
full or in part on 30 June 2020 or 2021 with the appropriate charge being
taken over that vesting period. The fair value at grant date was independently
determined using an adjusted form of the Black Scholes Model which includes a
Monte Carlo simulation model that takes into account the exercise price, the
term of the option, the share price at grant date and expected price
volatility of the underlying share, the expected dividend yield, the risk-free
interest rate for the term of the option and the correlations and volatilities
of the peer group companies.
The model inputs for the 2017 One Off Award were as follows:
Grant Date 24 August 2017 30 June 2020
Share price at grant date GBP 107.50p GBP 79.00p
Exercise price GBP 0.00 GBP 0.00
Expected volatility 73.3% 84.9%
Risk-free interest rates 0.44% (0.07%)
Expected dividend yields 0% 0%
Vesting period 1 30 June 2020 --
Vesting period 2 30 June 2021 --
Vesting period 3 30 June 2022 30 June 2022
The final vesting of the 2017 One Off Award was due to occur on 30 June
2022. However, as the three-month average VWAP to 30 June 2022 of 130.0p
was below that prevailing at 30 June 2021, the remaining 1,214,744 unvested
options lapsed.
2017 and 2018 LTIP 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 Award 2018 LTIP Award
Grant Dates 2 January 2019 9 May 2019
Share price at grant dates GBP167.7p GBP146.6p
Exercise price GBP0.00 GBP0.00
Expected volatility 113.9% 113.9%
Risk-free interest rates 0.73% 0.73%
Expected dividend yields 0% 0%
Vesting period 1 January 2021 2 January 2022
2019 LTIP Award
On 25 June 2020 and 30 October 2020 Options over a total of 481,586 ordinary
shares were granted under the LTIP in accordance with the policy announced to
the market on 25 August 2017 in respect of the performance of the Company in
the financial year ended 31 December 2019. These LTIP awards vested on 2
January 2023, subject to meeting the performance criteria set out in the table
below and continued employment with the Company.
Performance Vesting
Below the Median None of the award will vest
Median (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 £1.38 (adjusted for the Share Consolidation).
The performance targets provide that:
· No portion of a distinct one-half of the LTIP Award (the
"Absolute TSR Part") may vest unless the Company's compound annual growth rate
of TSR over the performance period is at least 10% p.a., for which 30% of the
Absolute TSR Part may vest, rising on a straight line basis for full vesting
of the Absolute TSR Part if the Company's compound annual growth rate of TSR
over the performance period equals or exceeds 20% p.a.
· No portion of the other distinct one-half of the LTIP Award (the
"Relative TSR Part") may vest unless the Company's TSR over the performance
period ranks at least median relative to the TSR performance within a
comparator group of companies, for which 30% of the Relative TSR Part may
vest, rising on a straight line basis for full vesting of the Relative TSR
Part if the Company's TSR over the performance period ranks upper quartile or
better relative to the TSR performance within a comparator group. However,
an underpin term applies to the Relative TSR Part which provides that,
regardless of relative TSR performance, no vesting may ordinarily accrue in
respect of the Relative TSR Part unless the Company's compound annual growth
rate of TSR over the performance period is at least 10% per annum.
The total fair value at grant date of the LTIP awards granted in the period
ended 31 December 2022 was $0.6 million and this will be pro-rated and
expensed over the vesting period. The fair value at grant date was determined
using a Monte Carlo simulation model that takes into account the exercise
price, the term of the option, the share price at grant date and expected
price volatility of the underlying share, the expected dividend yield, the
risk-free interest rate for the term of the option and the correlations and
volatilities of the peer group companies. The model inputs for the LTIP awards
granted during the period ended 31 December 2022 included:
2021 LTIP Award
Grant Date Jun/Oct/Dec 2022
Share price at grant dates GBP135p/120p/108p
Exercise price GBP0.00
Expected volatility 79%
Risk-free interest rates 1.83%/3.59%/3.28%
Expected dividend yields 0%
Vesting dates 1 January 2025
Movements in the number of LTIPs outstanding and their related weighted
average exercise prices are as follows:
2022 Average exercise price per Share Option Number of Options 2021 Average exercise price per Share Option Number of Options
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:
Grant-Vest Expiry date Exercise 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 Reserve Merger Reserve Total
$'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
24,700 19,813
Adjusted EBITDA
$'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 provision Closure of pits Total
$'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 claims Other provisions Total
$'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 -- --
9,932 565 327
8,814
30 Bank overdraft
31 December 31 December 2021
2022
$'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 clause within the Letter of
Guarantee implies that the Guarantor may reduce the Guarantee Sum available
for payment to the MEEI under the Letter of Guarantee on an obligation by
obligation basis provided PGB delivers to the Guarantor a certificate duly
issued and signed by the MEEI.
b) Galeota - A Letter of Guarantee has been established in substance over
the Galeota Block where a subsidiary of Trinity is obliged to carry out a
Minimum Work Programme to the value of $0.9 million. A clause within the
Letter of Guarantee implies that the Guarantor may reduce the Guarantee Sum
available for payment to the MEEI under the Letter of Guarantee on an
obligation by obligation basis provided the subsidiary of Trinity delivers to
the Guarantor a certificate duly issued and signed by the Minister of the
MEEI. The Letter of Guarantee was effective from 14 July 2021 until the
earlier of performance of Minimum Work Programme or the Guarantor has paid the
Guarantee amount.
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 the year 2022 2021 2022 2021
$'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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