TIDMTRIN
RNS Number : 5201M
Trinity Exploration & Production
24 May 2022
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.
Trinity Exploration & Production plc
("Trinity" or "the Group" or "the Company")
Final Results
Continued strong performance with structure in place for dynamic
growth strategy
Trinity, the independent E&P company focused on Trinidad and
Tobago, announces its final results for the year ended 31 December
2021 ("the Period" or "FY 2021").
Trinity delivered another resilient performance in 2021. The
Group is now positioned to leverage its cash and asset base to
drive value and returns - with groundwork laid for near-term
resumption of drilling, comprising a combination of high angle and
horizontal as well as conventional low angle wells. This will be
funded from existing cash resources and is the first phase of an
ambitious growth strategy designed to maximise returns.
Highlights
-- Revenues of USD 66.2 million (2020: USD 44.1 million)
-- Average production of 3,069 bopd (2020: 3,232 bopd)
-- Average price per barrel received increased to USD 60.4/bbl (2020: USD 37.7/bbl)
-- Adjusted EBITDA of USD 19.8 million (2020: USD 12.1 million)
-- Operating Profit* of USD 10.0 million (2020: USD 3.0 million)
-- Sixth consecutive year of sub USD30.0/bbl operating
break-even with industry wide cost pressures increasing
-- Cash generated from continuing operations USD 12.6 million (2020: USD 10.3million)
-- Cash flow used in investing activities USD 13.9 million (2020: USD 6.0 million)
-- Year end cash USD 18.3 million (2020: USD 20.2 million)
-- New 25-year Galeota Licence, Crude Sales Agreement, Joint
Operating Agreement, Conversion to 100% Working Interest
-- Lease Operatorship Agreements renewed for 10 years on attractive terms
-- PS-4 acquisition completed - further enhancing Trinity's contiguous acreage
* Before SPT, PT, Impairments and Exceptional Items
Positioned for Next Growth Phase
-- Dynamic strategy for growth is underpinned by a strong
balance sheet and resilient and dependable cash flow
-- Focus on maximising value from existing assets and through acquisitions and partnerships
-- Clearly defined, risk-mitigated strategy to drive returns for
shareholders through value growth and the potential to return
cash
-- Strengthened Board
o Additions of Derek Hudson and Kaat Van Hecke further
strengthening commercial, operational and wider industry skill
sets
-- Creation of Technical Committee
o Focused on risk-mitigation and assurance of opportunities
which can increase scale and optimise returns
o Resumption of onshore drilling during H2 2022 is the first
phase of this scaling up process
-- Commenced planning for ambitious, risk-appropriate exploration programme
o To test the remaining material prospective onshore resources,
using 3D seismic to map leads with potential to be fast-tracked to
monetisation
o Exploring various options for the Galeota asset
Post Period Highlights
-- Continued momentum into Q1 2022
o Q1 production levels resilient with volumes averaging 3,013
bopd (Q4 2021: 3,103 bopd). 2022 average production will be
influenced by the timing and outcomes of the drilling campaign.
o Cash balance of USD 17.5 million as at 31 March 2022
(unaudited) (USD 18.3 million as at 31 December 2021)
o Average realisation of USD 83.1/bbl for Q1 (Q1 2021: USD
52.3/bbl)
o 2022 average production will be influenced by the timing and
outcomes of the drilling campaign
Analyst Briefing
A briefing for Analysts will be held at 14.00 today both in
person -- with Chairman Nicholas Clayton and Chief Executive
Officer Jeremy Bridglalsingh and via web conference for those who
are unable to attend. Analysts wishing to join should contact
trinityexploration@walbrookpr.com .
Investor Presentation
The Company will be hosting a presentation through the digital
platform Investor Meet Company at 16.00 today. Management will
discuss results and the imminent drilling programme as well as
longer-term opportunities. An updated investor slide deck will be
added to the Company's website later today.
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
Jeremy Bridglalsingh, CEO of Trinity, commented: " We are
delighted with the Company's performance during 2021 and look
forward with confidence. The reinforced technical guidance for the
upcoming drilling programme points towards the potential for this
to be an inflection point for the Company as we commence the next
stage of our growth, and we very much look forward to updating the
market with further developments in due course.
" Our ambition is to double production over the next few years,
and thereby generate sufficient free cash flow both to fund future
growth initiatives and deliver meaningful cash returns for
shareholders, and we believe that we now have the structure in
place to deliver this challenging target ."
Enquiries
For further information please visit www.trinityexploration.com
or contact:
Trinity Exploration & Production plc Via Walbrook
Nick Clayton, Non-Executive Chairman
Jeremy Bridglalsingh, Chief Executive
Officer
SPARK Advisory Partners Limited (Nominated
Adviser and Financial Adviser) +44 (0)20 3368 3550
Mark Brady
James Keeshan
Cenkos Securities PLC (Broker)
Leif Powis +44 (0)20 7397 8900
Neil McDonald +44 (0)131 220 6939
Walbrook PR Limited +44 (0)20 7933 8780
Nick Rome/Tom Cooper trinityexploration@walbrookpr.com
About Trinity ( www.trinityexploration.com)
Trinity is an independent oil production company focused solely
on Trinidad and Tobago. Trinity operates producing and development
assets both onshore and offshore, in the shallow water West and
East Coasts of Trinidad. Trinity's portfolio includes current
production, significant near-term production growth opportunities
from low risk developments and multiple exploration prospects with
the potential to deliver meaningful reserves/resources growth. The
Company operates all of its nine licences and, across all of the
Group's assets, management's estimate of the Group's 2P reserves as
at the end of 2021 was 19.73 mmbbls. Group 2C contingent resources
are estimated to be 47.22 mmbbls. The Group's overall 2P plus 2C
volumes are therefore 66.95 mmbbls.
Trinity is quoted on the AIM market of the London Stock Exchange
under the ticker TRIN.
CHAIRMAN'S STATEMENT
It is a privilege to chair Trinity as we emerge from a period of
significant change during which management refreshed our strategy
and focused the business on clear and deliverable growth
opportunities. Our dynamic strategy for growth is underpinned by a
strong balance sheet and resilient and dependable cash flow from
production - something of a rarity amongst the smaller companies in
our sector - and a testament to our strong business model.
I would like to commend our team which has maintained focus,
momentum and professionalism throughout a challenging year,
allowing us to protect the integrity of existing assets and operate
safely to deliver steady production and cash flow. Importantly,
this core operating model provides the basis from which we can grow
the Company into a leading independent producer of scale both by
maximising value from existing assets and through acquisitions and
partnerships. We have a clearly defined, risk-mitigated strategy in
place and believe that this will drive returns for shareholders
through value growth and the potential to return cash.
At time of publishing, the world is in turmoil and we are deeply
concerned for those most affected by hostilities in the Ukraine.
This global upheaval brings with it a raft of new and different
challenges to an industry already coping with the perfect storm of
restrictions on working practices imposed by the Covid-19 pandemic,
unprecedented volatility in commodity prices and, in our own case,
the shock of the sudden and untimely passing of our founder and
Executive Chairman, Bruce Dingwall, CBE. As such, 2021 proved to be
an extraordinarily difficult year to navigate, but one in which
Trinity proved its resilience and, perhaps as importantly, its
ability to act decisively for the benefit of our stakeholders,
refining and prioritising our extensive opportunity set, with a
view to generating significant growth in value in the relatively
near term.
Board Changes
In the past year we have changed the composition of our Board to
bring Trinity's governance structure more in-line with market
practice, with the role of Chairman becoming a non-executive
position, complimented by the promotion of Jeremy Bridglalsingh to
the position of Chief Executive Officer. Jeremy is a Trinidadian
whose contribution to the Company's strategy and development since
becoming CFO in 2016, and more recently Managing Director in 2019,
cannot be underestimated.
Further, we added depth and breadth to an already strong Board,
welcoming two important new non-executive directors, Derek Hudson
and Kaat Van Hecke, both highly respected and experienced members
of the international energy industry. David Segel stood down from
the board in March 2021, and I would like to place on record my
thanks for his invaluable contribution to our deliberations since
he joined the board following our recapitalisation in 2016.
Technical Committee
Trinity fields an expert sub-surface team whose knowledge of the
geology of Trinidad's hydrocarbon-bearing basins is a core strength
of the Company. To support them and assist the Board by bringing a
global context to analysis of potential new projects, during 2021
we established an external advisory committee of world-class
sub-surface and petroleum engineering experts who will help us to
critique and filter prospects so that we can confidently focus
expertise, energies and investment to fast-track only the most
viable, high-grade opportunities.
The Technical Committee comprises two board members and three
high-quality independent experts and has helped management refine
and prioritise its existing opportunity set to focus on
risk-mitigated prospects capable of being delivered with the
Company's existing financial and operational resources to increase
scale and optimise returns. It has set ambitious but deliverable
growth targets, and the resumption of onshore drilling during the
second half of this year is the first part of this scaling up
process.
Managing risk to deliver growth in production and cash flow
This additional layer of uncompromising, qualitative analysis in
geoscience and petroleum engineering is matched by two of Trinity's
key financial characteristics; capital discipline, with an
increasing focus on risk assessment, and a relentless commitment to
cost management. 2021 saw Trinity turn in its sixth consecutive
year of sub USD 30.0/bbl operating break-even, in fact USD
29.2/bbl, a real achievement in such challenging times and an
excellent discipline to provide a buffer against times of low
market prices. The Company expects an increase on the usual
operating breakeven in FY 2022 to support medium term growth
through increased technical and intellectual capacity and with
industry-wide cost pressures increasing.
Furthermore, Trinity maintains a strong balance sheet, with cash
resources of USD 18.3 million at 31 December 2021 (2020: USD 20.2
million), meaning we have the resources we require to deliver our
near term growth objectives.
These pillars of our business culture will underpin our dynamic
future strategy where we aim to grow our predictable, stable
production and cash-flow allowing us the opportunity to both fund
attractive new growth opportunities and deliver cash returns to
shareholders.
Risk-appropriate investment for future growth
Stable cashflow forms the bedrock of Trinity's financial
strength and positions us well for our next, exciting growth phase.
One of our key operational objectives is to safely and sustainably
build and scale production and we have already commenced planning
for an ambitious, risk-appropriate exploration programme that will
tap into the region's material remaining reserves, using 3D seismic
to map prospects with potential to be fast-tracked to monetisation,
generating material growth for our shareholders whilst
understanding and hopefully ameliorating technical and commercial
risk.
An additional layer of potential comes from the ongoing
farm-down process for our Galeota licence, comprising the producing
Trintes field, the Echo Prospect and potential from the Foxtrot and
Golf accumulations. The Company has engaged with a range of
potential partners and whilst initial feedback has been
encouraging, several participants have indicated their inability to
fully assess the economics of the opportunity without clarity being
considered by the Government of Trinidad and Tobago ("GORTT"). As
these considerations seem to have been delayed, and to ensure that
the Company attains the best possible value proposition for this
highly valued asset, we have made the decision to pause our
farm-down process until the GORTT fiscal reforms have been
concluded.
We continue to explore a variety of options for this asset, with
the aim of maintaining exposure while avoiding the need for
material additional debt or diluting existing shareholders. These
key criteria must be met, together with tax reform in Trinidad,
which has been flagged by the Government, before your Board will
commit to/progress any partnership offers.
We eagerly anticipate T&T's new bidding rounds for
exploration blocks both onshore and near offshore. We will target
licences that provide additional opportunities to expand our
footprint in Trinidad. Concurrent with that, we will continue to
evaluate acquisition opportunities.
Investing in future energy and transition
Unfolding geopolitical events have made it clear that, for many
years to come, 'traditional' energy (i.e. oil & gas) will
remain an essential part of the energy mix. However, the clock is
ticking towards Energy Transition & Net Zero and Trinity's goal
is to be at the forefront of T&T and the wider Caribbean
region's energy transition.
During 2021 we established a new senior executive role of
Innovation, supported by a small but highly qualified team, and
have already instigated several meaningful studies and
ground-breaking collaborations that we believe will challenge
conventional thought and help to develop innovative new approaches
to energy production.
Trinity's ESG programme is designed to build environmental
considerations into the mindsets of our people and the heart of our
business culture such that sustainability becomes one of the
cornerstones of our future vision.
Financial Discipline
Our 2021 results demonstrate your Company's resilience. Adjusted
EBITDA for the year was USD 19.8 million (2020: USD12.1 million)
and cash resources were USD 18.3 million (2020: USD 20.2 million)
at year end despite the absence of new drilling activity. In 2021,
in line with previous years, we hedged around 50% of our production
to counteract the impact of low oil prices and the effects of
Supplemental Petroleum Tax ("SPT"), which is at its most punitive
when realised oil prices are between USD 50.01 and USD 55.0 per
barrel. The adoption of a similar policy for 2022 has significantly
reduced the immediate benefit of high oil prices on our
profitability and cashflow, especially in the first half of the
year. However, we expect the impact will decrease in H2 2022, as a
lower proportion of our existing production is hedged and our
onshore drilling programme will bring new production onstream.
Financial restructuring
At an appropriate future point it is our goal to make returns to
shareholders either in the form of cash dividends or share
buy-backs. With this in mind, during 2021, your Board undertook a
complex share capital re-organisation to position the distributable
reserves at PLC level that will enable us to return cash to
shareholders as and when appropriate.
Fiscal Reform
Throughout 2021 Trinity continued to leverage its deep and
long-standing relationships with Government, Heritage and the
region's energy participants more broadly to make the case for
positive fiscal reform. We remain confident that the Government
understands the requirement for fiscal reform, despite the
near-term outlook for crude oil prices, in order to stimulate
investment and development of the country's oil and gas resources,
to the benefit of all T&T stakeholders. We understand that the
Government's deliberations on tax reform, specifically in relation
to SPT, are ongoing, and we look forward with keen interest to
receiving positive news on this matter in the near term.
Thanks
I would like to conclude by extending the thanks of the Board to
our Shareholders who have remained supportive and engaged despite a
difficult year. As the frustrating limitations imposed by the
Covid-19 pandemic hopefully subside we look forward to engaging
'in-situ' with shareholders and our broader stakeholder community
with plans for a busy agenda of presentations and events throughout
the coming year. I would also like to extend the sincere thanks of
the Board to our management and employees whose unstinting
dedication has allowed us to successfully and safely navigate the
challenges posed by the Covid-19 pandemic.
We entered 2022 with a refreshed strategy, a strong balance
sheet and a dynamic vision for growth. We believe the time is right
for Trinity and are energised to deliver optimum value on your
behalf.
Nicholas Clayton
Non-Executive Chairman
CHIEF EXECUTIVE OFFICER'S REVIEW OF 2021
The sudden and unexpected passing of our founder and Executive
Chairman, Bruce Dingwall, in August 2021, has accelerated our plans
to focus the business, building on the strong foundations he had
built to take Trinity into a new and dynamic growth phase.
In this context, I am extremely proud to be leading a strongly
bonded, talented team of hard-working individuals who have
consistently brought their top game to bear throughout the year,
enabling Trinity to deliver an applaudably resilient performance in
challenging circumstances.
Growth Strategy
We believe that this is an inflection point for the Company with
the imminent resumption of drilling commencing the next stage of
our growth. During the past year we have re-focused, prioritising
Trinity's existing opportunity set to focus on risk-mitigated
prospects capable of being delivered with the Company's existing
financial and operational resources to increase scale and optimise
returns. In addition, we now have the expertise and processes in
place to mitigate risk and appropriately prioritise the various
opportunities we continue to consider.
This rigorous approach has resulted in the Company de-selecting
some options, a signal of the important contribution of our
Technical Committee's mentorship and guidance. The level of
commercial and operational input their experience brings is now
enabling us to shape our decision-making process by adding quality
reviews alongside technical risk assurance of the options we are
pursuing.
Whilst we are focused on expanding our portfolio we will not put
undue pressure on the Company's cash and operational resources. We
are now positioned to activate our refined strategy with a view to
driving value. Our ambition is to double production over the next
few years, and thereby generate sufficient free cash flow both to
fund future growth initiatives and deliver meaningful cash returns
for shareholders. And we believe we now have the operational and
financial resources we need to deliver this challenging target.
Financial Performance
Following a difficult year in 2020, when commodity prices dipped
dramatically and Trinity's average price received was USD 37.7/bbl,
we welcomed the market's recovery and the subsequent uplift in our
realised price for 2021 to USD 60.4/bbl. The combined effects of
this uplift and our relentless pursuit of cost efficiencies
delivered an adjusted EBITDA of USD 19.8 million (2020: USD 12.1
million) and ending cash of USD 18.3 million after meaningful capex
invested of USD 13.9 million (2020: USD 6.0 million)
Our hedging policy has historically been designed to provide
protection from low commodity prices and to ameliorate the impact
of realised prices in the USD 50-55/bbl range where SPT in Trinidad
is most punitive. In the context of the recent extraordinary and
unpredictable uplift in commodity prices, magnified by Russia's
invasion of Ukraine in March 2022, we are not alone in finding that
our hedges have blunted the otherwise positive impact these higher
prices would have had on our operating cashflow. We expect the
impact will decrease in H2 2022, as a lower proportion of our
existing production is hedged and our onshore drilling programme
will bring new production onstream. Going forward, we expect that
growing our onshore production, further driving down our operating
break-even, and the expected reform of the SPT regime will
significantly reduce our future hedging requirements.
HSSE
My first priority is the health and safety of our workforce and
contractors as well as minimising the environmental impact
associated with our operations. However, while our leading
indicators continue on a favourable trajectory, we incurred three
Lost Time Incidents ("LTIs") during 2021. This has prompted us to
place even greater emphasis on HSE throughout the organisation,
from the Boardroom to the well head. We have created an HSE
Steering Committee, and have also appointed an HSSE champion at
Board level, Kaat Van Hecke, to oversee this function and highlight
its critical importance to us as a company. This has begun to
inject greater rigour into our HSE oversight, with a prime focus on
creating Trinity's Safety Rules to underpin our safe systems of
work.
I am delighted to chair the HSE Steering Committee and the
energy and enthusiasm of those involved is helping to drive
improvements in the effectiveness of our HSE function. This will
further strengthen our operations, motivate our team and
demonstrate to our partners and regulatory stakeholders our
competency as an operator.
OPERATIONS IN 2021
Reducing Volatility
During 2021, having taken a commercial decision not to
recommence drilling activity, we opted to underpin our base
production via a programme of seven recompletions, 96 workovers and
increasing the volume under surveillance via Supervisory Control
And Data Acquisition ("SCADA") to 50% of total production. The
impact of these activities, allowing us to increase the
predictability of our production profile and mitigate natural
reservoir decline for the second consecutive year, has been
significant. Despite the absence of drilling, production for the
year reached the upper quartile of our guidance (2,900-3100 bopd),
averaging 3,069 bopd, slightly lower than 2020's 3,232 bopd.
In particular, our strategic decision to invest in technology to
automate and optimise our wells has proved to be highly effective.
The operation of 31 Tier 1 onshore wells, over half of all
Trinity's production, is now automated, helping to ensure steady,
low-cost production whilst minimising non-productive downtime. As a
result, 2021 saw Trinity deliver its sixth consecutive year of
sub-USD 30.0/bbl operating break-even, a real achievement in such
challenging times and an effective buffer against times of low
market prices. Shareholders will see a small upward shift in our
breakeven to low USD30's in 2022 as we increase the intellectual
resource to achieve our medium term vision of scaling up Trinity,
but our relentless focus on optimising production and reducing cost
continues.
Trinity is already one of T&T's top five crude oil
producers, giving us a deep historical knowledge of the region's
hydrocarbon basins and strong working relationships with our
partners and regulatory stakeholder. The benefit of this unique
skillset came to the fore during 2021 when our Field Development
Plan ("FDP") for Galeota attained full Ministry approval within
just three months, an unusually short timeframe and testament to
the quality of our technical rationale. This was aided by the
timely acquisition of the full suite of Certificates of
Environmental Clearances for Galeota's Echo project from the
Environmental Management Authority.
In line with our strategy to refine and prioritise the range of
growth options at our disposal, our sub-surface team, supported by
world class external consultants, continued their study of the 37
km2 of 3D seismic acquired during 2021 from Heritage Petroleum
Company Limited ("Heritage"). This activity was significantly
complemented by gaining access to the entire 287 km2 3D seismic
data made available via our participation in the NWD process.
The Technical Team continues to work hard to accelerate its
interpretation and integration of this data to enable Trinity to
develop a regional geological framework with a view to identifying
new play concepts, deeper, largely undrilled reservoirs, and the
best locations for drilling into the key productive Forest and
Upper Cruze horizons, being the dominant producing reservoirs
onshore Southern Trinidad.
Our principal objective is to improve our drilling returns by
developing a mix of lower risk, conventional wells, with
technically more challenging but potentially higher return, high
angle, horizontal and deeper wells. These more complex wells have
the potential to increase the ratio of barrels recovered to the
capital invested, and thereby provide stronger economics.
Growth through acquisition and collaboration
The Company is in robust financial health, and is conservatively
financed compared with many of our peers, where operating
break-evens are higher and finances more constrained. We are
therefore well placed to take advantage of commercial opportunities
as and when they arise. A prime example of this was our acquisition
of the PS-4 Block Lease Operatorship Sub-Licence, onshore Trinidad,
which was finalised in December 2021. We moved quickly to secure
this synergistic asset, adjacent to our core WD5/6 and WD2
producing assets, funding this acquisition out of existing cash
resources.
To progress some of the exciting opportunities in the T&T
region Trinity continues to develop excellent working relationships
with potential partners, both Heritage (the state-owned oil
company) and larger international operators.
Reviewing opportunities for growth, we consistently apply
rigorous technical and financial metrics to balance risk with
reward. In this context, having carefully appraised the NWD
exploration play in Trinidad's Southern Basin with partner
Capricorn Energy PLC, the Board decided not to participate further
with this process as neither we nor our partner Capricorn Energy
were comfortable with the technical and operational risks
associated with the deeper Cretaceous leads that were
identified.
GALEOTA
Our Galeota prospect offers a broad range of opportunities to
add value for Trinity
- The Trintes field, currently producing at 1,107 bopd, in which
the significant 2P reserve potential has not been fully
exploited,
- The Echo Prospect, which has an approved FDP, with potential peak production of 7,000 bopd
- The Foxtrot and Golf appraisal prospects with combined peak production of 7,000 bopd
- Significant tax losses of circa USD164 million
A crucial milestone
In July 2021 our negotiations with the Ministry of Energy and
Energy Industries ("MEEI") and state oil company Heritage were
rewarded with the award of new and improved commercial terms
including
- A new 25-year licence commencing 14 July 2021, covering an area of 19,280 acres
- A significant reduction in minimum work obligations and performance guarantees
- A new Crude Oil Sales Agreement ("COSA") provides greater pricing clarity
- An improved Joint Operating Agreement ("JOA") more aligned with international standards
One of the outcomes of this development is that Management's
estimate of the net 2P plus 2C reserves increased to 50.16 mmbbls
(previously 27.60 mmbbls). An additional benefit is the conversion
of Heritage's 35% working interest to an Overriding Royalty ("ORR")
whereby the Company now benefits from holding a 100% Working
Interest over the entire block, enabling Trinity to apply the bulk
of its tax losses across the entire Galeota Licence area.
These improved terms provide Trinity and prospective funding
partners with more attractive commercial terms and the requisite
visibility to bring on new low carbon development projects such as
Echo, incentivising maximum resource extraction at a time of high
oil prices and a transition towards lower carbon intensity energy
supplied.
The Galeota farm-down process got underway in December 2021,
hosted by Stellar Energy Advisers, and whilst initial feedback has
been encouraging, participants were unable to fully assess the
economic opportunities at Galeota without clarity on expected SPT
reform. On this basis the Company has decided to pause the Galeota
farm down process pending SPT reform. This will enable the Company
to seek the best value proposition for Galeota. In keeping with our
prudent commercial strategy, Trinity is working hard to achieve the
most capital efficient outcome, balancing acceptable and
proportionate levels of investment with a desire to maintain a
significant share in the project and thus our ability to deliver
significant upside for shareholders.
Sub Licence Renewals
We were delighted that Heritage reconfirmed their trust in
Trinity's skills and commitment by extending five of the Company's
six Lease Operatorship Agreements ("LOAs") for an additional 10
years, effective 1 January 2021, on improved commercial terms. This
will allow Trinity to plan and commit to future work programmes
across its onshore assets with greater confidence.
New Exploration Licences
In response to the recent announcement made by the T&T
Government of its intention to conduct new onshore, shallow water
and deep offshore bidding rounds, Trinity has registered
non-binding interest in six onshore blocks. Details of the shallow
water blocks have not yet been released. We anticipate that further
details will become available following announcements relating to
fiscal reform, which we consider to be essential to the success of
the bid rounds.
Fiscal Reform
We remain optimistic about the prospects for imminent, and
necessary, reform of T&T's fiscal regime, specifically SPT
which significantly discourages investment and stifles activity in
the sector. This is, in our view, essential if Trinidad is to
attract the necessary investment to maximise the value of its world
class hydrocarbon deposits within the Net Zero time frame. We
continue to work with the MEEI and wider Government with the goal
of delivering a positive outcome.
Our ESG Activities
In 2021 a structured and focused approach has been initiated
towards our ESG Programme as we position Trinity on a trajectory to
deliver a sustainable future for your Company. The measurement and
reporting of environmental performance is an emerging science and
Trinity is taking the important steps to understand what is
required and to ensure that what we measure and report is
transparent, provable and, most importantly contributes positively
to sustainable operations in years to come.
In Q4 2021 we appointed an expert external advisory team to help
us refine our ESG strategy and develop a clear process by which ESG
becomes embedded across the business. They have hosted several
well-attended workshops including both office and field-based
staff, tailor-made to explain the regulation framework in the
context of our own operations and provide ongoing guidance on the
necessary changes to our work methods to ensure that the data we
report is reliable. Internally, an ESG Committee was established
and a new senior post of Executive Manager, Innovation was created
along with an Innovation Team.
With regard to the Social element of ESG, our HR and Business
Administration Teams have been pro-active in enhancing our
healthcare provision, devising wellness programmes and ramping up
our community engagement to provide much needed support for school
children and families. In collaboration with the University of West
Indies ("UWI") a scholarship fund in our recently deceased Bruce
Dingwall's name has been established.
Our Chairman has already alluded to changes made to our Board to
upgrade our governance model and we are delighted to have welcomed
two new members, one of whom, Kaat Van Hecke, brings specific
expertise and focus on HSSE matters.
Renewables
Momentum in energy efficiency and transition to renewable energy
is picking up. We believe that in the medium term there may be
renewable power opportunities with the potential to be accretive to
shareholder value. For that reason, Trinity is building a strong
network of partners to ensure that our Company is part of the
vanguard leading T&T's commercialisation of emerging renewable
technology.
We are delighted to continue to develop these important
relationships, helping to explore and develop new projects with the
National Gas Company ("NGC") and the UWI. The scope of their
mission is to enable energy transition not only in T&T, but
potentially in the wider Caribbean and Latin America. We have no
doubt that a number of innovative projects will come out of this
important collaboration which is already bearing fruit with:
-- Commencement of T&T's inaugural Solar irradiance study
adjacent to Trinity's Galeota field office, with plans for a
further Wind Resource Assessment
-- Installation of a solar power system for the WD5/6 field office
In summary, 2022 marks the start of a planned growth phase for
Trinity; a robust operating platform, a refreshed Board, further
complemented by the formation of a world-class technical advisory
committee, a refined strategy and a healthy balance sheet all put
Trinity in an ideal position to accelerate growth and generate
meaningful returns for shareholders.
Jeremy Bridglalsingh
Chief Executive Officer
OPERATIONS REVIEW
In the face of a year dominated by lockdown and Covid-19
restrictions, a decision was made to desist from any new drilling
within our portfolio, meaning that Group production for 2021
aligned with natural reservoir decline of 7%. As we weathered the
pandemic we were forced to adapt our operating plans to achieve the
budgeted level of production and with production growing by 4% from
Q3 to Q4 we exited 2021 at 3,143 bopd. This has provided us with a
stable platform entering 2022.
Current onshore production is from Lease Operatorship Blocks:
WD-5/6, WD-2, FZ-2, WD-14, WD-13, PS-4 and Farmout Block,
Tabaquite.
Average 2021 net sales from the onshore assets was 1,644 bopd
(2020: 1,793 bopd), which accounted for 55% of total annual average
sales. The projections for the year anticipated this decline since
no drilling was planned. The team's multi-faceted approach to
production delivery included recompletions ("RCPs"), work-overs
("WOs"), reactivations, sand exclusions, an expanded swab portfolio
and production optimisation initiatives to maintain production
delivery.
Trinity executed 7 RCPs Onshore during the year (2020: 16) as
well as 74 WOs (2020: 92), and 5 sand control jobs (2020:2).
Overall, we aim to minimise the need for well interventions, and
reduce the frequency of WOs, as we target an increasingly
predictable and sustainable production base. Timely execution of
WOs when they are required is an essential component of our
strategy, in returning base wells to production as quickly as
possible. Our sand control measures focused on high frequency wells
impacted by formation entry. As described below, the combination of
surveillance and automation further assisted in our ability to
improve our response to our Tier 1 ( > 25 bopd) wells on which
they were installed in WD-5/6.
Natural annual field decline of 7-10% can be significantly
mitigated via the execution of RCPs and, in spite of a slow
approval process (within Heritage and the Government) due to
Covid-19, our campaign delivered substantially all of the intended
production targeted from the RCP programme.
In 2022, the team intends to explore further cost-effective
means of production maintenance through the expansion of the active
well stock via RCPs, reactivations and swabbing.
Automation continues to enhance efficiency
Trinity's use of automation to optimise our production uptime
took a significant step forward in 2021, with the execution of the
automation of 31 Top Tier wells that covers 85% of the Block
production in WD-5/6, which has delivered some preliminary
results:
-- 11 WOs have been avoided during the period due to remote
surveillance by the SCADA monitoring team
-- Real time data collection through the SCADA system is
facilitating faster responses to changing well conditions and
optimised real time production. Speed ramp up and pump stroke
optimization in real time netted > 3000 bbls increased
production.
-- Reduction in Man Hours required for production and monitoring.
-- Carbon footprint has been reduced by having less frequent wellsite visits and fewer WOs.
Further works are being progressed to building internal
competency and leveraging more cost-effective automation that can
be deployed on lower producing wells.
East Coast Assets
Current East Coast production is generated from the Alpha, Bravo
and Delta platforms in the Trintes Field which resides within the
Galeota Block.
Average 2021 net sales from the East Coast were 1,107 bopd
(2020: 1,188) accounting for 37% of the Group's total sales broadly
in line with 2020. To achieve this, the team conducted 15
restorative WOs (2020: 16) including 1 well reactivation to
underpin production (2020: 4 well reactivations) and 2 electrical
submersible pump ("ESP") WOs were conducted (2020: 1 ESP WO), with
continuous emphasis being placed on optimisation and stabilisation
of all wells via a data driven strategy utilising automation. An
enhanced chemical injection strategy was executed to counteract
increased solids deposition in the mature wells.
Again, our ongoing approach of digitalising the Trintes field to
provide reliable and informative essential data in relation to the
wells, thereby pre-empting potential issues and problems, allowed
us to stabilise production. The result is an ongoing reduction in
the production fluctuations in the field brought about by
proactively predicting possible failures and effectively developing
mitigation plans. These production focused operations were coupled
with the team's ongoing efforts to maintain the integrity of our
mature offshore assets. This process is ongoing and is expected to
further improve the team's ability to execute essential workplans
safely.
Galeota Asset Development (Trinity: 100% WI)
The TGAL discovery area (proposed Echo hub) lies in the Galeota
Licence and sits within a separate Fault Block (mapped as Fault
Block 6), an updip panel located to the northeast of the Trintes
Field, con rmed as being oil bearing in six major stacked reservoir
horizons by the TGAL-1 exploration well with an internal best
estimate STOIIP of 187.5 mmstb. Trinity received FDP approval for
the Echo Development from the Ministry of Energy and Energy
Industries ("MEEI") in November 2021. The approved FDP proposed a
conservative eight well configuration. Both the MEEI and reserve
auditor, NSAI, have indicated that the current approved FDP Case
leaves considerable upside potential for recoverable hydrocarbons
with an increased number of well slots. On this basis, Trinity has
considered a variety of development cases to maximise the
recoverable hydrocarbons from the Echo Development. Trinity's
preferred development case (Most Likely Case) consists of an Echo
twelve well configuration. This aligns with MEEI's FDP and NSAI
2021 CPR recommendations and strategy to accelerate the development
and production of its remaining oil and gas reserves in the time
available during the energy transition.
The Most Likely Case, a 12 well configuration may be adopted and
will not only target TGAL but also additional proven oil and
reservoir sands from the adjacent Trintes fault blocks FB4 and FB5;
targeting recoverable resources of 25.2 mmbbls with peak annualised
production of 6,977 bopd, approximately one year after first
oil.
Works on various pre-FEED studies to improve the topside and
other aspects of the facilities design was completed in 2021. In
addition, subsurface model building to support dynamic reservoir
simulation for forecasting production performance and cumulative
estimated ultimate recoverable (EUR) volumes were completed in
2021. The Environmental Impact Assessment ("EIA") is a key item on
the critical path to Final Investment Decision ("FID") which was
submitted in February 2021 and represented a signi cant milestone.
The Certificate of Environmental Clearance was granted in February
2022. Other key milestones achieved in 2021 included the conversion
of the working interest in the Galeota block from 65% to 100% and
attaining FDP approval from MEEI
In Q4 2021, the Company commenced a formal marketing process for
a farm-down of the GAD Project and has appointed Stellar Energy
Advisors as its advisor for the divestment.
There is potential for the GAD Project, which encompasses the
Trintes Field's current production, the Echo Field Development and
the Foxtrot and Golf appraisal areas, to significantly change the
scale of Trinity's operations. As previously announced, the
combined 2P reserves and 2C/2U resources from these fields exceeds
50 mmbbls, with dynamic modelling indicating peak annualised
production of circa 7,000 bopd from Echo alone. An Independent
Competent Person's Report on these assets was completed in Q4 2021
by Netherland, Sewell & Associates, Inc., which offers
significant support to Trinity's own internal volumetric assessment
of the Galeota Block.
The Company has engaged with a range of potential partners as
part of the Galeota farm down process. Whilst initial feedback has
been encouraging, a number of participants have informed the
Company that they are unable to fully assess the economics of the
opportunity at Galeota without clarity on the expected reforms to
Supplemental Petroleum Tax ("SPT"), which are currently being
considered by the Government of Trinidad and Tobago ("GORTT") and
which were initially expected to have been confirmed sooner than
now appears likely.
Pending SPT reform, which management still expects to happen,
the Company has decided to pause the Galeota farm down process.
This will enable the Company to seek the best value proposition for
Galeota when the GORTT's fiscal reforms have been confirmed.
West Coast Assets
West coast production is generated from the Point Ligoure-Guapo
Bay- Brighton Marine ("PGB") and Brighton Marine ("BM") elds.
Average 2021 net sales from the West coast was 255 bopd (2020:
245 bopd) which accounted for 8% of the Group's total annual
average sales and a 4% increase from 2020 average. This increase
was achieved by continuing infrastructural initiatives coupled with
the production enhancing project to arrest the decline from the
West Coast assets.
The team remains focused on exploring opportunities to optimise
production from all offshore platforms in this asset. No RCPs
(2020: 0) were conducted, however two WOs were completed in the PGB
asset for the period.
BM asset sales experienced a 17% increase to 155 bopd (2020: 133
bopd). This was achieved by the team implementing a number of
rigless production enhancing initiatives. No WOs or RCPs were
conducted during this period (2020: 2 RCPs and 1 WO).
The team remains focused on improving asset integrity on its
offshore platforms to create a safer working environment and ensure
production is maintained. We continue to evaluate additional
initiatives to extend the operations horizon by increased WO, RCP
and swabbing activity.
Facilities Management and Infrastructure
In 2021, the Facilities team paid particular attention to
upgrading production and the welfare infrastructure on its East
Coast Trintes Field and addressed key integrity challenges in
relation to the West Coast Brighton Marine Field. These marine
installations require a higher level of maintenance due to the
harsher East/West Coast offshore environment. The internal team was
supplemented by the recruitment of highly experienced contractors,
mechanics and electricians, to ensure a higher level of operational
reliability and uptime on the assets at lower cost.
In 2021, the Team focused on structural and operational
reliability, as such, we progressed 36 projects of which 23 were
completed and 13 rolled over in 2022.
One key activity is the construction of the new 10,000 bbls
storge tank to service the Trintes field. This experienced some
delays as a result of inclement weather and Covid-19 related
issues. However, the works have resumed, with an anticipated
completion during Q3 2022. This tank will bring additional storage
capacity and operational exibility to the Trintes operations
ensuring tank certi cation compliance without any disruption to
production.
Facilities Management and Infrastructure spend in 2021 totaled
USD 3.2mm.
Re s er ve s an d R e s ou r c es
A comp r ehensi ve management review of all assets has been
concluded and has estimated Trinity current 2P reserves to be 19.73
mmstb at the end of 2021, compared to the year-end 2020 reserve
estimate of 19.55 mmstb. This represents a 0.9% year-on-year
increase. The overall increase in reserves of 0.18 mmstb results
from a combination of both negative and positive influences on oil
volumes across all assets. However, a Reserves Replacement Ratio
(RRR) of 100% was achieved in 2021 with production of 1.10 mmstb
fully replaced together with updated well numbers and decline curve
analysis on planned in ll and producing wells Onshore and Offshore
the West and East Coast.
Brent Forward Price Deck applied to Reserves Economic Limit
Testing ("ELT") as at 3 January 2022
WTI Forward Price Deck applied to Reserves Economic
Limit Testing ("ELT") from Britannic Trading LLC as
at 3 January 2022
(USD/bbl) 2022 2023 2024 2025 2026 2027 2028 2029
Price
Strip 76.48 71.76 68.91 67.09 65.97 65.25 65.65 65.65
Management considers the reserves presented in the table below
represent the best estimate as at 31 December 2021 of the quantity
of reserves that will actually be recovered from our current
assets. It represents production which is commercially recoverable,
either to licence/relevant permitted extension end or earlier via
the application of the economic limit test. The subsurface review
has de ned investment programmes and constituent drilling targets
to commercialise these reserves as detailed by asset area shown in
the table:
Unaudited 2021 2P Reserves
Net Oil Production 31 December Production Revisions 31 December
2020 mmstb mmstb mmstb 2021 mmstb
Onshore 5.44 (0.60) 2.42 7.26
East Coast 11.66 (0.40) (1.48) 9.77
West Coast 2.45 (0.09) 0.33 2.70
Total 19.55 (1.09) 1.27 19.73
N o t e (*):
-
East Coast 2P reserves decreased due to a reclassification of
three Trintes infill wells to horizontal well targets for Echo
(-1.89MMstb) which was partially offset by the impact of wells
optimisation and maintenance and economic limit testing
improvements (+0.4 MMstb)
Onshore and West Coast 2P reserve changes primarily reflect
ongoing well optimisation across all assets to arrest decline from
our base wells and, for the Onshore, the acquisition of PS4 adding
2P reserves of 0.67MMstb
The planned 2022 onshore drilling campaign, comprising a
combination of high angle and horizontal wells, conventional wells
and more materially, stratigraphically untested deeper reservoirs
within the fields have utilised improved performance prediction
methods (ie dynamic simulation, inflow equations etc) and decline
curve analysis for assurance in forecast predictions.
Management's best estimate of 2C resources as at 31 December
2021 is 47.22 mmstb (2020: 23.25 mmstb). The positive movement of
23.97 mmstb in 2C resources primarily re ects our increased working
interest in Galeota, now 100% compared to 65% at YE 2020 following
the successful revision of the license terms.
Management's Estimate of 2C Resources as at 31 December 2021
Asset 31 December 2020 Revisions mmstb 31 December 2021
mmstb mmstb
Onshore 4.01 (0.19) 3.82
East Coast 15.94 24.45 40.39
West Coast 3.30 (0.29) 3.01
Total 23.25 23.97 47.22
Note (*):
-- East Coast:
o Working interest in Galeota is now 100% compared to 65% used
in YE 2020
o Year End 2020 ECHO FDP conservative 8 well development vs.
Year End 2021 most likely Case of 12-well development inclusive of
re-categorization of three Trintes infills now being carried as 2C
at ECHO
o Additional contingent resources for the shallower TGAL G, H,
and M Reservoirs, which are not targeted for initial TGAL (Echo)
development, but forms part of phased future development plans.
-- Onshore:
o Base Production Optimisation Operations to recategorize some
2C to 2P
o Improved Well Decline Analysis on planned 2P infills to
capture more 2C;
-- West Coast:
o Recently concluded subsurface work across the Point Ligoure
sub-licence asset has re-defined the subsurface structure resulting
in a downward revision of 2C resources
o Base Production Optimisation Operations to recategorize some
2C to 2P in particular execution of ABM151 RCP in Brighton
Management's Estimate of Reserves and Resources as at 31
December 2021
Asset 2021 2P Reserves 2021 2C Reserves 2021 2P and 2020 2P and
mmstb mmstb 2C Reserves 2C Reserves
mmstb mmstb
Onshore 7,26 3.82 11.08 9.45
East Coast 9.77 40.39 50.16 27.60
West Coast 2.7 3.01 5.71 5.75
Total 19.73 47.22 66.95 42.80
Financial Review
Strong financial performance underpinned by robust operational
cashflows. The recovery in crude oil prices, combined with our
continued financial discipline, meant we were able to generate
solid results and invest in short to medium term growth
initiatives.
KPIs
The Group's robust performance resulted in it being profitable
at both an operating and total comprehensive income level in 2021,
despite the backdrop of the ongoing Covid-19 pandemic.
A summary of the year-on-year operational and financial
highlights are set out below:
FY 2021 FY 2020 Change %
Average realised oil price(1) USD/bbl 60.4 37.7 60
Average net sales(2) bopd 3,006 3,226 (7)
Revenues USD million 66.2 44.1 50
Cash balance USD million 18.3 20.2 (9)
IFRS Results
Operating Profit before SPT & PT USD million 10.0 3.0 233
Total Comprehensive income/(loss) for the year USD million 7.7 (2.8) 375
Earnings Per Share - Diluted USD cents 18.0 (7.0) 357
APM Results
Adjusted EBITDA(3) USD million 19.8 12.1 64
Adjusted EBITDA(4) USD/bbl 18.0 10.3 75
Adjusted EBITDA margin(5) % 29.9 27.4 2.5
Adjusted EBITDA after Current Taxes(6) USD million 14.8 10.6 40
Adjusted EBITDA after Current Taxes Per Share - Diluted US cents 35.0 25.0 39
Consolidated operating break-even(7) USD/bbl 29.2 20.1 45
Net cash plus working capital surplus(8) USD million 20.8 21.4 (3)
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 (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 less Covid-19 expenses.
4. Adjusted EBITDA (USD/bbl): Adjusted EBITDA/Annual sales.
5. Adjusted EBITDA margin (%): Adjusted EBITDA/Revenues.
6. Adjusted EBITDA after Current Taxes: Adjusted EBITDA less
Supplemental Petroleum Taxes ("SPT"), Property Taxes ("PT"),
Petroleum Profits Tax ("PPT") and Unemployment Levy ("UL").
7. Consolidated operating break-even: The realised price/bbl
where the Adjusted EBITDA/bbl for the Group is equal to zero.
8. 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 to Consolidated Financial Statements -
Adjusted EBITDA for further details
Adjusted EBITDA Calculation
Adjusted EBITDA is an Alternative Performance Measure ("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.
2021 2020 Change %
USD MM USD MM
Operating Profit Before SPT, PT, Covid-19 expenses, Impairment and Exceptional Items (IFRS
Result) 10.0 3.0 238
DD& A 7.4 8.2 (9)
SOE 0.6 1.0 (35)
ILFA (0.7) 0.2 (399)
FX loss/(gain) 0.0 (0.0) 0
FV Derivative Instruments 3.2 (0.3) 1,284
Covid-19 expenses (0.7) - 100
Adjusted EBITDA (APM Result) 19.8 12.1 64
Current Taxes:
SPT and PT (3.6) (0.4) 839
PPT and UL (1.4) (1.1) 20
Adjusted EBITDA after Current Taxes (APM Result) 14.8 10.6 40
2021 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.
Details 2017(1) 2018(1) 2019 2020 2021
Realised Price USD/bbl 48.6 59.8 58.1 37.7 60.4
Sales
Onshore bopd 1,347 1,563 1,616 1,793 1,644
West Coast bopd 212 198 185 245 255
East Coast bopd 961 1,110 1,208 1,188 1,107
Consolidated bopd 2,519 2,871 3,007 3,226 3,006
Metrics
Royalties/bbl -
Onshore USD/bbl 18.5 24.2 22.3 11.5 22.6
Royalties /bbl
- West Coast USD/bbl 7.5 10.0 10.0 6.1 11.1
Royalties /bbl
- East Coast USD/bbl 11.7 14.5 14.1 8.3 13.0
Royalties /bbl
- Consolidated USD/bbl 22.2 19.1 18.3 9.9 18.1
Opex/bbl - Onshore USD/bbl 11.1 11.7 12.1 12.2 14.4
Opex/bbl - West
Coast USD/bbl 22.1 22.1 26.9 20.3 26.2
Opex/bbl - East
Coast USD/bbl 18.9 20.1 17.1 16.5 18.3
G&A/bbl - Consolidated(2) USD/bbl 4.4 5.0 5.1 4.3 6.3
Operating Break-Even(3)
2017(4) 2018(4) 2019 2020 2021
Onshore USD/bbl 16.6 16.1 16.4 16.5 19.0
West Coast USD/bbl 26.6 26.8 32.4 24.6 32.2
East Coast USD/bbl 24.9 25.9 21.9 21.0 23.2
Consolidated(4) USD/bbl 28.4 29.0 26.4 20.1 29.2
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 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 Note 1 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 have 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 1 to the consolidated
financial statements.
Summary of Results for the Year
Revenue increased due to the material higher average realised
oil price in 2021: The positive impact of a 60% increase in average
oil price realisations to USD 60.4/bbl (2020: USD 37.7/bbl), was
partially offset by a 7% decrease in average annual sales to 3,006
bopd (2020: 3,226 bopd), resulting in a 50% increase in revenues to
USD 66.2 million (2020: USD 44.1 million).
Continued financial discipline on costs and preserving strong
operating margins: The Group continued to deliver strong operating
margins despite an increase in costs incurred in dealing with the
pandemic. The Adjusted EBITDA margin increased to 30% (2020: 27%),
with consolidated operating break-even maintained at below USD 30
(2021: USD 29.2/bbl, 2020: USD 20.1/bbl) demonstrating the Group's
ability to be profitable across a broad range of oil prices. The
64% increase in Adjusted EBITDA to USD 19.8 million (2020: USD 12.1
million) is a direct result of the increased realised oil price and
strong operational performance.
Increased capex investment programme to drive growth in the
short to medium term:
USD 13.9 million (2020: USD 5.3 million) invested acquiring a
new onshore lease operatorship (PS 4, onshore), acquiring 3D
Seismic data covering Trinity's onshore acreage, exploration and
evaluation spend on the Galeota Asset Development, continuing
investment in the Group's Infrastructure, Subsurface, Drilling
planning and execution of 11 RCPs.
Capex invested comprised:
-- USD 3.8 million acquisition of PS-4 Lease Operatorship
-- USD 3.2 million Exploration and Evaluation ("E&E") assets
relating to the Galeota Asset Development
-- USD 3.2 million Infrastructure Capex
-- USD 1.1 million acquisition of 3D Seismic Data
-- USD 1.1 million Subsurface time-writing costs
-- USD 0.8 million 11 RCPs
-- USD 0.4 million in computer software and research and development
-- USD 0.2 million renewal of Galeota block licences
-- USD 0.1 million Drilling planning (no New Wells drilled).
Refer to Notes to Financial Statements: Note on Property, Plant
and Equipment - Additions (USD 10.3 million) and Note on Intangible
Assets - E&E Additions (USD 3.6 million) inclusive of
accruals.
Continued financial strength: The Group's cash balances at year
end reduced marginally by 9% to USD 18.3 million (2019: USD 20.2
million), primarily reflecting a strong operating performance
offset increased taxes and derivative expenses and a material
increase in capital spending. In aggregate, despite these
significant cash outflows, the Group's net cash plus working
capital surplus stood at USD 20.8 million, a modest 3% decrease
(2020: USD 21.4 million).
Statement of Comprehensive Income
2021 Financial Highlights
Average realisation of USD 60.4/bbl (2020: USD 37.7/bbl)
Operating Revenues
Operating revenues up 50% to USD 66.2 million (2020: USD 44.1
million).
Operating expenses
Operating expenses increased by 37% in 2021 to USD (56.2)
million reflecting a return to a cost structure similar to that
which prevailed in 2019 (2020: USD (41.1) million) and
comprised:
Operating Expenses (excluding non-cash items): USD (45.7)
million (2020: (31.9) million):
-- Royalties of USD (19.9) million (2020: USD (11.7) million),
this increase being driven mainly due to higher average realised
oil price.
-- Opex of USD (17.6) million (2020: USD (16.5) million) mainly
due to a recovery in crude oil prices from lows in 2020 which had a
commensurate impact on supply chain prices as well as increased
workover and swabbing activity in the year.
-- G&A expenses of USD (7.0) million (2020: USD (5.1)
million) mainly due to an increase in new hires, employee bonuses,
a one off director payment to the estate of Bruce Dingwall, an
increase in professional services provided for the 2021 reserves
audit and increased levies.
-- Derivative expense of USD (1.2) million (2020: Derivative
income of USD 1.3 million) being the cash impact of derivative
instruments.
Non-Cash Operating Expenses: USD (10.5) million (2020: USD (9.1)
million):
-- DD&A of USD (7.4) million (2020: USD (8.2) million).
-- Fair Value of Derivatives: Expense of USD (3.2) million
(2020: Derivative income of USD 0.3 million) being the FV impact of
derivative instruments
-- SOE of USD (0.6) million (2020: USD (1.0) million).
-- ILFA reversal/(charge) USD 0.7 million (2020: USD (0.3) million).
Operating Profit Before Supplemental Petroleum Taxes ("SPT") and
Property Tax ("PT), Covid-19 expenses, Impairment and Exceptional
Items
The operating profit before SPT, PT, Covid-19 expenses,
impairment and exceptional items for the year amounted to USD 10.0
million (2020: USD 3.0 million) and was mainly due to higher
operating revenues resulting from the higher oil prices.
SPT & PT
SPT & PT were net USD (3.6) million (2020: USD (0.4)
million) and comprised:
-- SPT of USD (5.1) million (2020: USD 0.2 million) mainly due
to the higher realised oil prices in relation to the Group's
offshore operations in 2021. There was no SPT payable in respect of
the Group's onshore operations during the year.
-- Reversal of PT charge of USD 1.5 million (2020: USD (0.5)
million). 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 the 31 March in each year. As none have
been received for the years 2018 to 2020, it is highly unlikely the
tax will be required to be paid for these years and there is also
no method to determine a reliable estimate for the liability. As
such, the Company has made a reversal of the liability for periods
2018-2020 and not recognised any liability for 2021.
Operating Profit before Covid expenses, Impairment and
Exceptional items
The Group's reported operating profit before Covid-19 expenses,
impairment and exceptional items was USD 6.5 million (2020: USD 2.6
million). Adjusting for non-cash expenses, the Group's Adjusted
EBITDA after Current Taxes was USD 14.8 million (2020: USD 10.6
million) (further details below).
Covid-19 expenses
Covid-19 expenses incurred by the Group for 2021 was USD (0.7)
million. This was triggered when the Covid-19 impact to the country
was at its highest and the Company sought to protect its workforce
by early detection through Covid-19 testing USD (0.3) million,
Offshore employee isolation prior to offshore rostering USD (0.3)
million and heightened sanitisation efforts across the assets USD
(0.1) million. Covid-19 expense of USD (0.1) million was previously
recognised in 2020 in General and Administration expense relating
to sanitation.
See Note 7 to Consolidated Financial Statements - Exceptional
items and Covid-19 expenses for further details
Impairments charge
Impairment charges taken were USD (1.3) million (2020: USD (1.2)
million) relating to the Impairment of property, plant, and
equipment USD (0.1) million and Inventory (1.2) million.
See Note 3(d) to Consolidated Financial Statements - Impairment
of Property, Plant and Equipment for further details
Exceptional items
Exceptional items were USD (0.1) million (2020: USD (0.04)
million) mainly related to fees for corporate restructuring
advice.
See Note 7 to Consolidated Financial Statements - Exceptional
items and Covid-19 expenses 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 (2020: 0.1 million).
Finance Costs
Finance costs amounted to USD (1.5) million (2020: USD (1.4)
million) and comprised the:
-- Unwinding of the decommissioning liability USD (1.2) million (2020: USD (1.2) million).
-- Bank overdraft USD (0.2) million (2020: (0.1) million).
-- Interest on Leases USD (0.1) million (2020: (0.1) million).
See Note 9 to Consolidated Financial Statements - Finance Costs
for further details
Income Taxation
Income Taxation Credit for 2021 of USD 4.7 million (2020: USD
(2.9) million expense), comprise the following:
-- Increase in Deferred Tax Assets ("DTA") recognised on
available tax losses of USD 5.5 million credit resulting from
higher oil prices (2020: Reduction in DTA of USD 3.4 million
expense).
-- Decrease in Deferred Tax Liabilities ("DTL") USD 0.6 million due to accelerated accounting impairments/depreciation (2020: USD 1.6 million decrease).
-- Unemployment Levy ("UL") USD (0.4) million (2020: USD (0.3) million).
-- Petroleum Profit Tax ("PPT") charge USD (1.0) million (2020: (0.8) million).
See Note 10 to Consolidated Financial Statements - Income
Taxation for further details
Total Comprehensive Income/(Loss)
Total Comprehensive Income for the period was USD 7.7 million
(2020: USD (2.8) million loss).
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, Covid-19 expenses, 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 at USD 19.8 million and
Adjusted EBITDA after Current Taxes at USD 14.8 million as it is
used by Management and judged to be a better measure of underlying
performance.
Statement of CashFlows
Cash inflow from operating activities
Operating Cash Flow ("OCF") was USD 12.6 million (2020: USD 10.3
million):
-- Operating activities 2021 generated an operating cash flow
before working capital and income taxes of USD 16.1 million (2020:
USD USD 11.9 million)
-- Changes in working capital resulted in a net decrease of USD
(1.8) million (2020: USD 0.6 million decrease), primarily as a
result of the increase in trade receivables compared to the 2020
year end.
-- Income taxes PPT and UL paid USD (1.7) million (2020: USD
(1.0) million paid) resulting from higher oil price.
Cash (outflow) from investing activities
Cash outflow from investing activities was USD (13.9) million
(2020: USD (6.0) million):
-- Acquisition of PS 4, onshore 3D seismic, and property, plant
and equipment for the year totalling USD (10.0) million (2020: USD
(5.0) million)
-- Expenditure on exploration and evaluation assets and other
intangible assets USD (3.6) million (2020: USD (1.0) million) as
the Group continued to invest in Galeota asset.
-- Performance bond increase in renewal of Onshore Lease
Operatorship Assets USD (0.3) million (2020: nil)
Cash (outflow)/inflow from financing activities
Cash outflow from financing activities was USD (0.6) million
(2020: USD 2.2 million inflow):
-- Principal paid on lease liability USD (0.4) million (2020: (0.4) million)
-- Interest paid on lease liability USD (0.1) million (2020: (0.1) million)
-- Finance cost of USD (0.1) million (2020: (0.0) million).
-- No further drawdown on of CIBC working capital Facility (2020: USD 2.7 million drawdown).
Closing Cash Balance
Trinity's cash balance at 31 December 2021 was USD 18.3 million
(31 December 2020: USD 20.2 million).
Net Cash Plus Working Capital Surplus
All figures in USD million FY 2021 FY 2020 FY 2019
USD MM USD MM USD MM
Audited Audited Audited
A: Current Assets
Cash and cash equivalents 18.3 20.2 13.8
Trade and other receivables 10.8 7.2 9.4
Inventories 3.8 5.3 5.2
Total Current Assets 32.9 32.7 28.4
B: Liabilities
Trade and other payables 8.8 7.8 10.4
Bank overdraft 2.7 2.7 -
Lease liability 0.6 0.6 0.6
Taxation payable 0.0 0.2 0.1
Total Current Liabilities 12.1 11.3 11.1
(A-B): Net Cash plus working capital surplus 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).
Reconciliation between Adjusted EBITDA after Current Taxes and
Cash Inflow from Operating Activities
Adjusted EBITDA after Current
Taxes 14.8
Changes in working capital (1.9)
Add back current tax 1.4
Income taxation paid (1.7)
Cash inflow from Operating
Activities 12.6
Events since Year End
1. Hedging
The Company implemented crude oil derivatives over the Group's
monthly production in 2021 and 2022.
The derivative protection currently in effect for 2022 is as
follows:
Type of Index Sell Buy Sell Buy Production Effective Expiry Execution Premium
Derivatives Put Put Call Call Date Date Date USD MM
USD/ bbl USD/ bbl USD/ bbl USD/ bbl Monthly
Barrels
3-Way Cost ICE
Collar Brent 50.00 60.00 66.90 - 10,000 1-Jan-22 30-Jun-22 04-Mar-21
3-Way Cost ICE
Collar Brent 50.00 60.00 74.40 - 12,500 1-Jan-22 31-Dec-22 02-Jun-21
4-Way Cost ICE
Collar Brent 59.00 68.00 72.00 82.00 15,000 1-Jan-22 30-Jun-22 05-Jul-21
3-Way Cost ICE
Collar Brent 40.00 50.00 80.50 - 15,000 1-Jan-22 31-Dec-22 27-Aug-21
Put Spread ICE
Option Brent 40.00 50.00 - - 15,000 1-Jul-22 31-Dec-22 14-Jan-22 0.15
2. On 24 February 2022, Russian forces invaded Ukraine, causing
wide-ranging economic sanctions to be applied against the Russian
regime by the US, EU and other major economies. The event caused
both Brent and WTI oil prices to soar, peaking well above USD 100
per bbl in March 2022. The increased oil prices has positively
impacted the Group's crude oil revenue but negatively impacted
derivative expenses. Overall, whilst there has been no significant
adverse impact to the Group, management continues to closely
monitor the event's impact as it unfolds.
3. In 2021 Trinity engaged with a range of potential partners as
part of the Galeota farm down process. The Company on 3 May 2022
indicated, whilst initial feedback has been encouraging, a number
of participants have informed the Company that they are unable to
fully assess the economics of the opportunity at Galeota without
clarity on the expected reforms to Supplemental Petroleum Tax
("SPT"), which are currently being considered by the Government of
Trinidad and Tobago ("GORTT") and which were initially expected to
have been confirmed sooner than now appears likely. Pending SPT
reform, which management still expects to happen, the Company has
decided to pause the Galeota farm down process. This will enable
the Company to seek the best value proposition for Galeota when the
GORTT's fiscal reforms have been confirmed.
In the interim, the Company will continue to refine its plans
for Galeota. In particular, it will advance preparations for
exploiting the 9.77mmbls of 2P reserves remaining in the Trintes
field.
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2021
(Expressed in United States Dollars)
Note 2021 2020
$'000 $'000
Revenues
Crude oil sales 66,257 44,074
Other income 1 4
66,258 44,078
Operating Expenses
Royalties (19,828) (11,746)
Production costs (17,625) (16,458)
Depreciation, Depletion & Amortisation ("DD&A") 13-15 (7,428) (8,174)
General & Administrative ("G&A") expenses (7,030) (5,095)
Net reversal/ (Impairment losses) on financial
assets ("ILFA") 754 (252)
Share Option Expense ("SOE") (626) (963)
Foreign exchange ("FX") (loss)/gain (14) 7
Derivative (expense)/income (realised) 6 (1,293) 1,302
Fair value (expense)/income derivative instruments
(unrealised) 6 (3,149) 266
(56,239) (41,113)
Operating Profit before Supplemental Petroleum
Taxes ("SPT") & Property Taxes ("PT") 10,019 2,965
SPT (5,074) 153
PT net reversal/(charge) 1,516 (532)
Operating Profit before Covid expenses,
Impairment and Exceptional items 6,461 2,586
Covid-19 expenses 7 (669) --
Impairment 8 (1,316) (1,218)
Exceptional items 7 (113) 43
Operating Profit 4,363 1,411
Finance income 9 94 108
Finance costs 9 (1,475) (1,416)
Profit Before Income Taxation 2,982 103
Income taxation credit/(charge) 10 4,744 (2,938)
Profit/(Loss) for the year 7,726 (2,835)
Other Comprehensive Income/(Expense)
Items that may be subsequently reclassified
to profit or loss
Currency translation -- (1)
Total Comprehensive Income/(Loss) for the
year 7,726 (2,836)
Earnings per share (expressed in dollars
per share)
Basic* 11 0.20 (0.07)
Diluted* 11 0.18 (0.07)
* See note 23 regarding restatements as a result of the share
capital reorganisation.
Consolidated Statement of Financial Position
at 31 December 2021
(Expressed in United States Dollars)
Note 2021 2020
ASSETS $'000 $'000
Non-current Assets
Property, plant and equipment 13 49,507 37,756
Right-of-Use ("ROU") assets 14 616 1,014
Intangible assets 15 30,759 27,349
Abandonment fund 16 4,021 3,490
Performance bond 17 473 253
Deferred Tax Assets ("DTA") 18 11,530 5,997
96,906 75,859
Current Assets
Inventories 19 3,820 5,267
Trade and other receivables 20 10,747 7,239
Derivative financial instruments 21 -- 266
Cash and cash equivalents 22 18,312 20,237
32,879 33,009
Total Assets 129,785 108,868
Equity and liabilities
Capital and Reserves Attributable to Equity
Holders
Share capital 23 389 97,692
Share premium 23 -- 139,879
Share based payment reserve 24 3,784 14,764
Merger reserves 25 -- 75,467
Reverse acquisition reserve 25 (89,268) (89,268)
Translation reserve (1,650) (1,650)
Retained earnings/ (accumulated losses) 143,666 (188,332)
Total Equity 56,921 48,552
Non-current Liabilities
Lease liability 14 97 465
Deferred Tax Liabilities ("DTL") 18 2,025 2,611
Provision for other liabilities 27 55,690 45,405
57,812 48,481
Current Liabilities
Trade and other payables 28 8,814 7,803
Bank overdraft 29 2,700 2,700
Lease liability 14 609 614
Provision for other liabilities 27 46 516
Derivative financial liabilities 21 2,883 --
Taxation payable 31 -- 202
15,052 11,835
Total Liabilities 73,864 60,316
Total Equity and Liabilities 129,785 108,868
Company Statement of Financial Position
at 31 December 2021
(Expressed in United States Dollars)
Note 2021 2020
ASSETS $'000 $'000
Non-current Assets
Investment in subsidiaries 12 60,347 60,021
Current Assets
Trade and other receivables 20 200 424
Intercompany 20 3,372 4,318
Derivative financial instruments 21 -- 266
Cash and cash equivalents 22 3,108 4,317
6,680 9,325
Total Assets 67,027 69,346
Equity and liabilities
Capital and Reserves Attributable to
Equity Holders
Share capital 23 389 97,692
Share premium 23 -- 139,879
Share based payment reserve 4,569 4,064
Merger reserves 6,552 56,652
Retained earnings/ (accumulated losses) 51,526 (229,422)
Total Equity 63,036 68,865
Current Liabilities
Trade and other payables 28 327 481
Intercompany 30 781 --
Derivative financial liabilities 21 2,883 --
3,991 481
Total Liabilities 3,991 481
Total Equity and Liabilities 67,027 69,346
Consolidated Statement of Changes in Equity
for the year ended 31 December 2021
(Expressed in United States Dollars)
Share Share Share Reverse Merger Translation Retained Total
Capital Premium Based Payment Acquisition Reserves Reserve Earnings/ Equity
Reserve Reserve Accumulated
Losses
Year ended 31 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
December 2020
At 1 January 2020 97,692 139,879 14,328 (89,268) 75,467 (1,649) (186,024) 50,425
LTIPs exercised
(Note 23) -- -- (527) -- -- -- 527 --
Share based payment
expense
(Note 24) -- -- 963 -- -- -- -- 963
Translation
difference -- -- -- -- -- (1) -- (1)
Loss for the year -- -- -- -- -- -- (2,835) (2,835)
Total comprehensive
loss
for the year -------- -- -- -- -- (1) (2,835) (2,836)
At 31 December 2020 97,692 139,879 14,764 (89,268) 75,467 (1,650) (188,332) 48,552
Year ended 31
December 2021
At 1 January 2021 97,692 139,879 14,764 (89,268) 75,467 (1,650) (188,332) 48,552
Capital
reorganisation
(Note
23 & 24) (97,303) (139,879) (11,485) -- (75,467) -- 324,134 --
LTIPs exercised (1) -- -- -- -- -- -- 47 47
Share based payment
expense
(Note 24) -- -- 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
(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 2021
(Expressed in United States Dollars)
Share Capital Share Premium Share Based Merger Reserves Retained Total Equity
Payment Reserve Earnings/
Accumulated
Losses
$'000 $'000 $'000 $'000 $'000 $'000
Year ended 31
December 2020
At 1 January 2020 97,692 139,879 3,628 56,652 (229,833) 68,018
LTIPs exercised
(Note 23) -- -- (527) -- 527 --
Share based
payment expense
(Note 24) -- -- 963 -- -- 963
Total
comprehensive
loss for
the year -- -- -- -- (116) (116)
At 31 December
2020 97,692 139,879 4,064 56,652 (229,422) 68,865
Year ended 31
December 2021
At 1 January 2020 97,692 139,879 4,064 56,652 (229,422) 68,865
Capital
Reorganisation
(Note
23 & 24) (97,303) (139,879) -- (50,100) 287,282 --
Share based
payment charge
(Note 24) -- -- 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
(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
for the year ended 31 December 2021
(Expressed in United States Dollars)
Note 2021 2020
$'000 $'000
Operating Activities
Profit before taxation 2,982 103
Adjustments for:
Translation difference (39) 83
Finance cost - loans and interest 9 254 195
Finance income 9 (94) (108)
Finance cost - decommissioning provision 27 1,222 1,221
Share based payment charge 24 626 963
DD&A 13-15 7,428 8,174
Loss on disposal of assets 13 -- 2
Net reversal/ (Impairment loss) on
financial assets (754) 515
Reversal of impairment -- (126)
Inventory impairment 1,220 --
Impairment of property, plant and equipment 13 96 1,121
Fair value loss on derivative financial
instruments 3,149 (266)
Other non-cash items 47 --
16,137 11,877
Changes In Working Capital
Inventories 19 228 (124)
Trade and other receivables 16,20,21 (3,019) 1,556
Trade and other payables 21,27,28 909 (1,985)
(1,882) (553)
Income taxation paid (1,700) (1,028)
Net Cash Inflow from Operating Activities 12,555 10,296
Investing Activities
Purchase of Exploration and Evaluation
("E&E") assets 15 (3,262) (1,062)
Purchase of computer software and
investment in research & development 15 (401) --
Purchase of property, plant and equipment 13 (9,957) (4,979)
Performance bond released (220) --
Net Cash Outflow from Investing Activities (13,840) (6,041)
Financing Activities
Finance income 94 108
Finance cost (153) (55)
Principal paid on lease liability (480) (441)
Interest paid on lease liability (101) (140)
Bank overdraft -- 2,700
Net Cash (Outflow)/Inflow from Financing
Activities (640) 2,172
(Decrease)/Increase in Cash and Cash
Equivalents (1,925) 6,427
Cash and Cash Equivalents
At beginning of year 20,237 13,810
Effects of foreign exchange rates differences
on cash 19 (14)
(Decrease)/increase in Cash and Cash
equivalents (1,944) 6,441
At end of year 22 18,312 20,237
Company Statement of Cash Flows
for the year ended 31 December 2021
(Expressed in United States Dollars)
Note 2021 2020
$'000 $'000
Operating Activities
Loss before taxation (6,381) (116)
Adjustments for:
Finance income (152) (126)
Share based payment charge 178 248
Net reversal of impairment loss on financial (28) --
assets
Fair value loss on derivative financial 3,149 --
instruments
Other non-cash items (13) --
(3,247) 6
Changes In Working Capital
Trade and other receivables 1,537 (1,074)
Trade and other payables 354 (27)
1,891 (1,101)
Taxation Paid -- --
Net Cash Outflow from Operating Activities (1,356) (1,095)
Financing Activities
Finance income 147 126
Net Cash Inflow from Financing Activities 147 126
Decrease In Cash and Cash Equivalents (1,209) (969)
Cash and Cash Equivalents
At beginning of year 4,317 5,286
Decrease Cash and Cash equivalents (1,209) (969)
At End of Year 22 3,108 4,317
Trinity Exploration & Production Plc
Notes to the Consolidated Financial Statements
31 December 2021
(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 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 $6.4 million (2020: $0.1 million loss) driven mainly
by the derivative expenses incurred in 2021.
Basis of measurement
This consolidated financial statements has 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 have 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 for the next twelve months. For the past twelve
months the Group continued to operate with no significant effects
nor interruptions from the presence of the Covid-19 pandemic.
However, the Board have continued to measure the potential impact
of the Covid-19 pandemic on the Group's operational capabilities,
liquidity and financial position over the next twelve-month period
and beyond. The going concern assessment has considered the current
operating environment and the potential impact of the volatility of
the oil price. Oil prices have trended in an upward direction
throughout 2021 and continued to increase in 2022 well over US$100
as at the date of this annual report. Oil prices are forecast to
remain at elevated levels over the next 12 months, which will
continue to positively impact the Group's operations.
The Group started 2022 with a strong operating and financial
position; 2021 average sales of 3,006 barrels of oil per day
("bopd"), (2020 3,226 bopd), and net cash of US$15.6 million (2020:
US$17.5 million) consisting of cash and short term investments of
US$18.3 million (2020: US$20.2 million) and an overdraft facility
of US$2.7 million drawn (2020: US$2.7 million) as at 31 December
2021. In making their going concern assessment, the Board
considered a cash flow forecast based on expected future oil
prices, production volumes and discretionary expenditure reductions
including downside scenarios. The base case forecast was prepared
with consideration of the following:
-- Future oil prices assumed to be in line with the forward
curve prevailing as at January 2022, with an average realised oil
price of US$68.7/bbl in the period to December 2022. The forward
price curve applied in the cash flow forecast starts at US$70.6/bbl
in January 2022, fluctuating each month down to US$65.8/bbl in
December 2022 through to US$63.4/bbl in June 2023
-- Average forecast production for the year to December 2022 of
3,173 bopd and for the six months to June 2023 of 3,133 bopd with
production being maintained by RCPs, WOs and swabbing activities
and no new drilling;
-- No SPT incurred on the onshore assets in 2022, as the SPT
threshold for small onshore operators was increased from US$50 to
US$75.0/bbl for 2022;
-- Trinity continuing to progress various growth and business
development opportunities; and derivative instruments in place to
protect a portion of cashflows against declining oil prices over
the forecast period.
As at the current date, Management considers this is a
reasonable base scenario, reflecting the outlook of the current
production profile and costs. As oil prices have trended upwards
our base scenario will continue to be strengthened. 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 separate stressed scenarios
including:
-- the effect of reductions in oil prices as low as $40.0/bbl
being sustained across the forecast period, noting that the base
case pricing is in line with market prices; and
-- the impact of temporary disruption from localised Covid-19
cases reducing forecast production by 10%, albeit operations have
continued uninterrupted to date and the nature of the operations
reduces the risk of such an eventuality.
All reasonably possible forecasts demonstrate that the Group's
cash balances are maintained under such scenarios and being
sufficient to meet the Group's obligations as they fall due.
Based on the cash flow forecast, when combined with mitigating
actions that are within the Group's control and having considered
the potential impact of Covid-19 pandemic, together with the
Government of Trinidad and Tobago's ("GORTT's") response to date,
the Board currently believe the Group can maintain sufficient
liquidity and a healthy positive cash balance, and remain in
operational existence, for at least the next twelve months.
On 24 February 2022, Russian forces invaded Ukraine, causing
wide-ranging economic sanctions to be applied against the Russian
regime by the US, EU and other major economies. The event caused
both Brent and WTI oil prices to soar, peaking well above US$ 100
per bbl in March 2022. The increased oil prices have impacted the
Group in several ways. These include, positively impacted the
Group's crude oil revenue, negatively impacted derivative expenses,
increased inflationary impacts and some challenges with supply
chain including higher freight costs and delays in receiving
shipments. Overall, whilst there has been no significant adverse
impact to the Group, management continues to closely monitor the
event's impact as it unfolds.
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 as market conditions continue to
improve. 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 2021:
New standards impacting the Group that have been adopted in the
annual financial statements for the year ended 31 December 2021
are:
Covid-19-Related Rent Concessions beyond 30 June 2021
(Amendments to IFRS 16)
On 31 March 2021, the IASB issued another amendment to IFRS 16:
Covid-19-Related Rent Concessions beyond 30 June 2021, which
extended the above practical expedient to reductions in lease
payments that were originally due on or before 30 June 2022. This
amendment is effective for annual periods beginning on or after 1
April 2021 with earlier application permitted.
Interest Rate Benchmark Reform - IBOR 'phase 2' (Amendments to
IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16)
The amendments provide relief to Group in respect of certain
loans whose contractual terms are affected by interest benchmark
reform.
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 2022 (and, in the case of IFRS 17, 1 January
2023):
-- Property, Plant and Equipment: Proceeds before Intended Use (Amendments to IAS 16);
-- Annual Improvements to IFRS Onerous Contracts - Cost of
Fulfilling a Contract (Amendments to IAS 37);
-- Standards 2018-2020 (Amendments to IFRS 1, IFRS 9, IFRS 16 and IAS 41);
-- References to Conceptual Framework (Amendments to IFRS 3).
Disclosure of Accounting Policies (Amendments to IAS 1 and IFRS
Practice Statement 2);
-- Definition of Accounting Estimates (Amendments to IAS 8);
-- Deferred Tax Related to Assets and Liabilities arising from a
Single Transaction (Amendments to IAS
12); and
-- IFRS 17 Insurance Contracts (effective 1 January 2023) - In
June 2020, the IASB issued amendments to IFRS 17, including a
deferral of its effective date to 1 January 2023.
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, trust transfers the
appropriate number of shares to the employee. The proceeds
received, net of any directly attributable transaction costs, are
credited directly to equity.
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 USD as these are the
currencies of the primary economic environment in which the
entities operate. The presentation currency is USD which better
reflects the Group's business activities and improves the ability
of users of the consolidated financial statements to compare
financial results with others in the international Oil and Gas
industry. The Consolidated Statement of Financial Position is
translated at the closing rate and Consolidated Statement of
Comprehensive Income is translated at the average rate from both
USD and Great British Pound ("GBP" or "GBP") currencies. The
following exchange rates have been used in the preparation of these
financial statements:
2021 2020
$ GBP $ GBP
Average rate TTD= $/GBP 6.765 9.006 6.758 8.646
Closing rate TTD= $/GBP 6.763 9.151 6.761 9.213
(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. E&E assets are reclassified from E&E when evaluation
procedures have been completed including technical feasibility and
commercial viability. E&E assets for which commercially viable
reserves have been identified are reclassified to development
assets (refer to E&E expenditure below).
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, however, 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.
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&E 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.
Transactions involving the purchases of an individual field
interest, or a group of field interests, that at a minimum includes
an input and a substantive process that together significantly
contribute to the ability to create output are classified as a
business acquisition. The acquisition method of accounting is used
to account for all business combinations. Alternatively, if these
transactions do not meet this definition of a business combination
they are classified as asset acquisitions. Assets are recognised at
its fair value and subsequently depreciated over its useful life or
reduced using the unit of production method.
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 lost
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. However, 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. 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, DTL 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")
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%.
Where PT accrued for past years is considered unlikely to be
charged and paid, the accrual is reversed in the current year.
Refer to note 3 (f) for further details.
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 2021 the Group revised its estimates due to an addition of
two new leased vehicles in December 2021. As a result, there was a
revision to the carrying amount of the lease liability to reflect
the payments to be 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.
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.
Royalty expense
Royalty expense is recognized on an accrual basis in accordance
with the substance of the relevant agreement. There are two types
of royalties incurred, government royalties and overriding
royalties in accordance with the various agreements held and are
calculated based on the percentage rate multiplied by the barrels
of oil produced. Government royalties are paid to the Government of
Trinidad and Tobago on a quarterly and monthly basis based on the
terms of the various agreements.
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% (2020:
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% (2020: 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.
2021 2020
$'000 $'000
Profit/(loss) for the year and Equity
10% strengthening of the US Dollar/
(2020: 10%) (247) (168)
10% weakening of the US Dollar/
(2020: 10%) 247 168
(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% (2020: 20%) increase and decrease in
realised oil prices. 20% (2020 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%.
2021 2020
$'000 $'000
Revenue
20% increase in price/ (2020: 20%) 13,168 11,702
20% decrease in price/ (2020: 20%) (13,168) (11,702)
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 2021, there were no loan commitments to attract
interest rates on foreign currency-denominated borrowings, (2020:
nil). During 2021 there was a bank overdraft facility which
incurred $0.1 million interest (2020: $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, experience and the institution's
credit rating to minimise risk. Our financial institutions credit
rating in Trinidad and the UK are BBB- and A+ respectively
(Standards and Poor 2021).
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 the 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 (2020: $0.9 million).
Consequently, there was a net reversal of $0.8 million in the
current period to reflect the decrease in the impairment provision.
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 (2020: $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 $18.3 million (2020: $20.2
million).
Management monitors rolling forecasts of the Group's Cash and
Cash equivalents on the basis of expected cash flows. This is
carried out at the Group level in accordance with practice and
limits set by the Group, refer to the disclosures in Note 1:
Background and accounting policies - Going Concern for more
information regarding the factors considered by the Company in
managing liquidity risk.
The table below analyses the Group's and Company's financial
liabilities into relevant maturity groupings based on their
contractual maturities for:
(a) All non-derivative financial liabilities, and
(b) Net and gross settled derivative financial instruments for
which the contractual maturities are essential for an understanding
of the timing of the cash flows.
The following table sets out the contractual maturities
(representing undiscounted contractual
cash-flows) of financial liabilities.
Group Less than 1 to 2 years 2 to 5 years Total
1 year
At 31 December
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
At 31 December $'000 $'000 $'000 $'000
2020
Non-derivatives
Trade and other
payables 7,803 -- -- 7,803
Bank overdraft 2,700 -- -- 2,700
Lease liabilities 614 442 23 1,079
11,117 442 23 11,582
Company Less than Total
1 year
At 31 December
2021
$'000 $'000
Non-derivatives
Trade and other
payables 327 327
Intercompany 781 781
1,108 1,108
At 31 December $'000 $'000
2020
Non-derivatives
Trade and other
payables 481 481
481 481
(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 Debt/(Net Cash).
2021 2020
$'000 $'000
Net cash (15,612) (17,537)
Total equity 56,921 48,552
Total capital 41,309 31,015
Gearing ratio (37.8)% (56.5)%
(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 to be made by Management which are based on key
estimates of future cost, production volumes and price and are
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 within three
years 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 27: Provision for other
liabilities
Bands (years) 2021 2020
Risk free rates 8-12 1.80% 3.14%
13-18 1.96% 3.17%
19-25 2.20% 2.42%
Inflation rate 2.40% 2.00%
The following table details the Group's sensitivity to a 1%
(2020: 1%) increase and decrease in discount and inflation rates.
1% (2020: 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 2021 of a
1% change in these variables is as follows:
Consolidated Statement Consolidated Statement
of Financial Position: of Comprehensive: Income/Expense
Obligation
2021 2021
$'000 $'000
Discount rate
1% increase in assumed
rate (8,917) 262
1% decrease in assumed
rate 10,963 (412)
Inflation rate
1% increase in assumed
rate 10,813 225
1% decrease in assumed
rate (8,973) (186)
(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 applied 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 27.
-- 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 2021 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 relates 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 2021 an
impairment charge of $0.1 million was recognised on the Group's
property, plant and equipment (2020: $1.1 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 $0.1 million (2020: $1.1 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 9-24 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.
2022 2023 2024 2025 2026 2027
Realised price 65.0 61.0 58.6 57.0 56.1 55.5
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 $0.6 million increase on impairment of Oil &
Gas Assets (2020: $1.0 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 $0.1 million
decrease on impairment of the Oil & Gas Assets (2020: $0.6
million decrease). The valuation is considered to be a level 3 in
the fair value hierarchy due to unobservable inputs used in the
valuation.
For the year ended 31 December 2021, Management's estimate of
the Group's cost of capital was 13% (2020:12%). 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 no change to the impairment position for 2021 (2020:
$0.2 million decrease) 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 no
change to the impairment position for 2021 (2020: $0.2 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 2021 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 reversal of prior period liability
PT is assessed on property owned by the Group in Trinidad and
Tobago governed by the Property Tax Act 2009 and later Property Tax
2018 amendment of Trinidad and Tobago. The calculation of PT is
described in note 1 Background and Summary of significant
accounting policies.
At the end of 2020 PT accrued for the period 2018 to 2020 within
Trade and Other Payables was $1.5 million (2020: $1.0 million). PT
has been accrued using the guidance provided by the legislation
noted above, as the administration arrangements of the PT under the
valuation of land act is not in place and the actual method for
calculating PT is therefore unavailable.
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 2020 (nor for 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
the period 2018-2021. Whilst there remains some ambiguity within
the interpretation of the law, Industry practice within Trinidad
means that it is appropriate to reverse the accrual.
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 agreed reverse the PT accruals previously
recognized ($1.5 million) for 2018 to 2020 and not recognize any PT
liability for the year ended 31 December 2021.
(g) PS-4 Asset Acquisition
The Group completed the acquisition of the Block on 1 December
2021. IFRS 3 Business Combination, requires an assessment to be
performed to determine whether the acquisition should be accounted
for as a business combination or asset acquisition. To be
considered a business acquisition, an acquired set must include an
input and a substantive process that together significantly
contribute to the creation of an output otherwise the acquisition
is considered an asset acquisition. An assessment was performed and
concluded that although the acquisition contains outputs, the vast
majority of its value resides in the proved undeveloped reserves
which does not contain any material input or output. As such, it
was concluded the acquisition did not meet the requirements to be
classified as a business combination and as such the acquisition
was treated as an asset acquisition.
(h) Share based payments
The Company has in place a share-based compensation plan (the
LTIP) for Executive Directors 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 24 for details.
4 Segment Information
Management has determined the operating segments which are
Onshore, West Coast and East Coast which are 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 now comprises the Chief Executive Officer, Finance Director,
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 non-current assets of the Group are located
in T&T.
5 Operating Profit Before Impairment, Covid-19 expenses and Exceptional Items
2021 2020
$'000 $'000
Operating profit before impairment, Covid-19 expenses
and exceptional items is stated after taking the
following items into account:
DD&A (Note 13) 6,756 7,566
Depreciation on ROU (Note 14) 505 502
Amortisation of computer software (Note 15) 166 106
Employee costs (Note 34) 9,707 7,587
Inventory recognised as expense, charged to operating
expenses 322 330
Auditors' remuneration
During the year the Group (including its overseas subsidiaries)
obtained the following services from the Company's Auditors as
detailed below:
2021 2020
$'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) 161 136
BDO Limited (T&T and Barbados based) 84 84
- Fees payable to the Company's auditors' for other
services:
The audit of Company's subsidiaries 16 13
Audit related assurance services - interim review 32 29
Total assurance and auditors' remuneration 293 262
2021 2020
$'000 $'000
Professional services:
Tax advice 1 --
All fees in 2021 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)/income
The net (loss)/ gain in fair value is recognised in the
Consolidated Statement of Comprehensive Income during the year:
31 December 31 December
2021 2020
$'000 $'000
Net derivative (expense)/income (realised) (1,293) 1,302
FV of derivative financial instruments
(unrealised) (3,149) 266
(4,442) 1,568
7 Exceptional Items and Covid-19 expenses
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.
2021 2020
$'000 $'000
Reversal of Impairment on equipment -- (126)
Fees relating to corporate restructuring
advice 113 83
Exceptional Expense/(Income) 113 (43)
Exceptional items 2021:
-- Fees relating to corporate restructuring advice: 0.1 million
charge in relation to professional advice on the capital
reorganisation
2021 2020
Covid-19 expenses: $'000 $'000
Covid-19 expense 669 --
669 --
-- Covid-19 expense: $0.7 million charge in relation to Covid-19
costs incurred by the Group during 2021. Covid-19 expense of $0.1
million was previously recognised in General and Administration
expense in the 2020 comparative.
8 Impairment
31 December 31 December
2021 2020
$'000 $'000
Impairment of Inventory 1,220 --
Impairment of property, plant and equipment 96 1,218
Impairment expense 1,316 1,218
-- Impairment of inventory - $1.2 million charge in relation to
inventory impairment. During the year Management engaged certified
persons to conduct a review of high value slow moving inventory
items which resulted in the above impairment. In 2020 there was no
impairment on inventory items.
-- Impairment of property, plant and equipment - $0.1 million
charge in relation to property, plant and equipment. In 2020 and
2021 the impairment of property, plant and equipment related to
charges for impairment losses on cash generating units (refer to
Note 3(d)).
9 Finance income and costs
Recognised in the Consolidated Statement of Comprehensive
Income
Finance income
2021 2020
$'000 $'000
Interest Income 94 108
Finance costs 2021 2020
$'000 $'000
Decommissioning - Unwinding of discount
(Note 27) (1,222) (1,221)
Interest on Leases (Note 14) (101) (140)
Interest and other expenses on overdraft (152) (55)
(1,475) (1,416)
10 Income Taxation
2021 2020
$'000 $'000
Current tax
Petroleum profits tax 982 817
Unemployment levy 393 333
Deferred Tax
Current year
Movement in asset due to tax losses (recognised)/derecognised
(Note 18) (5,533) 3,365
Movement in liability due to accelerated tax
depreciation (Note 18) (586) (1,577)
Income tax (credit)/ expense (4,744) 2,938
The Group's effective tax rate varies from the statutory rate
for UK companies of 19% (2020:19%) as a result of the differences
shown below:
2021 2020
$'000 $'000
Profit before taxation 2,982 103
Tax calculated at domestic tax rates applicable
to profits in the respective countries 3,441 741
Expenses not deductible for tax purposes 9,037 2,163
Impact on tax losses (2,595) (2,187)
Deferred tax on capital allowances in the
current period recognised (9,087) (1,389)
Tax losses previously generated now recognised
in the current period (5,533) 3,365
Other reconciling differences (7) 245
Tax (credit)/ charge (4,744) (2,938)
Corporate income tax is calculated at 19% (2020: 19%) of the
assessable profit for the year for the UK parent company, 55% for
the operating subsidiaries in Trinidad and Tobago (2020: 55%) and
30% (2020: 30%) for the corporate subsidiaries in Trinidad and
Tobago.
Taxation losses at 31 December 2021 available for set off
against future taxable profits amounts to approximately $234.6
million (2020: $237.2 million), with tax losses generated of $7.4
million (2020: $1.7 million) and tax losses utilised of $10.0
million (2020: $5.2 million) during the year. These losses do not
have an expiry date and have not yet been confirmed by the Board of
Inland Revenue ("BIR") and the Her Majesty's Revenue and Customs
("HMRC"). Tax losses carried forward by companies engaged in the
petroleum production business in Trinidad and Tobago are restricted
to set off in a year of income 75% of the otherwise chargeable
profits.
11 Earnings Per Share
Basic earnings per share is calculated by dividing the earnings
attributable to ordinary Shareholders by the weighted average
number of ordinary shares outstanding during the year. Diluted
earnings per share is calculated using the weighted average number
of ordinary shares adjusted to assume the conversion of all
potentially dilutive ordinary shares.
Profit/(loss) Weighted Average Earnings
$'000 Number Of Shares Per Share
'000' $
Year ended 31 December
2021
Basic 7,726 38,879 0.20
Diluted 7,726 42,260 0.18
Year ended 31 December
2020
Basic* (2,835) 38,623 (0.07)
Diluted* (2,835) 38,623 (0.07)
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 24) are considered potential ordinary shares. Share Options of
1,975,084 are considered potential ordinary shares and have not
been included as the exercise hurdle would not have been met.
*Restatement
Comparative figures have been recalculated to conform with
changes in presentation in the current year. The comparative
figures were recalculated to show the impact on EPS resulting from
the share consolidation which reduced the number of ordinary shares
from 388,794,303 to 38,879,430 (refer to note 23). The impact of
the restatement is summarised below:
Profit/(Loss) Weighted Average Earnings
$'000 Number Of Shares Per Share
'000 $
Year ended 31 December
2020
Basic (restated) (2,835) 38,623 (0.07)
Diluted (restated) (2,835) 38,623 (0.07)
Basic (2,835) 386,233 (0.01)
Diluted (2,835) 386,233 (0.01)
12 Investment In Subsidiaries
Company
2021 2020
$'000 $'000
Opening balance 60,021 59,306
Share based payment reserve revision (121) --
Share based payment 447 715
Closing balance 60,347 60,021
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 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 2021 are listed
below:
Name Registered Address/Country Nature of % Shares
of Incorporation Business held by
the Group
c/o Pinsent Masons LLP,
1 Park Row, Leeds, LS1 99.99998
Bayfield Energy Limited 5AB, UK Holding Company %
Trinity Exploration 13 Queen's Road, Aberdeen,
& Production (UK) Limited AB15 4YL, UK Holding Company 100 %
Trinity Exploration c/o Pinsent Masons LLP,
and Production Services 1 Park Row, Leeds, LS1
(UK) Limited 5AB, UK Service Company 100 %
Av. Presidente Vargas 509,
Bayfield Energy do Rio de Janeiro, 20071-003,
Brasil Ltda Brazil Dormant 100 %
Trinity Exploration Ground Floor, One Welches,
& Production (Barbados) Welches,
Limited St. Thomas BB22025, Barbados Holding Company 100 %
3(rd) Floor Southern Supplies
Limited Building, 40 -44
Trinity Exploration Sutton Street, San Fernando,
and Production (Trinidad Trinidad & Tobago ("Trinidad
and Tobago) Limited address") Holding Company 100 %
Trinity Exploration
and Production (Galeota)
Limited Trinidad address Oil and Gas 100 %
Oilbelt Services Limited Trinidad address Oil and Gas 100 %
Trinity Exploration
and Production Services
Limited Trinidad address Service Company 100 %
Trinity Midstream Limited Trinidad address Oil and Gas 100 %
Trinity Exploration
and Production (Erin
1) Limited Trinidad address Oil and Gas 100 %
Trinity Exploration
and Production (Erin
2) Limited Trinidad address Oil and Gas 100 %
Trinity Exploration
and Production (Forest
1) Limited Trinidad address Oil and Gas 100 %
Trinity Exploration
and Production (Forest
2) Limited Trinidad address Oil and Gas 100 %
Trinity Exploration
and Production (Forest
3) Limited Trinidad address Oil and Gas 100 %
Trinity Renewable Resources
Limited Trinidad address Oil and Gas 100 %
Trinity Exploration c/o Pinsent Masons LLP,
and Production plc 1 Park Row, Leeds, LS1 Employee
Employee Benefit Trust 5AB, UK Benefit Trust 100 %
13 Property, Plant and Equipment
Oil
Plant Leasehold & Gas
& Equipment & Buildings Assets Other Total
Year ended 31 December 2021 $'000 $'000 $'000 $'000 $'000
Opening net book amount at
1 January 2021 2,028 1,481 34,247 -- 37,756
Additions 1,328 74 8,794 -- 10,196
Adjustment to decommissioning
estimate (Note 27) -- -- 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
Oil
Plant Leasehold & Gas
& Equipment & Buildings Assets Other Total
Year ended 31 December 2020 $'000 $'000 $'000 $'000 $'000
Opening net book amount at
1 January 2020 1,141 1,652 39,587 -- 42,380
Disposals -- (2) -- -- (2)
Additions 1,124 (16) 2,983 -- 4,091
Adjustment to decommissioning
estimate (Note 27) -- -- (152) -- (152)
Impairment reversal equipment 126 -- -- -- 126
Impairment charge(1) (116) -- (1,005) -- (1,121)
DD&A charge for year (247) (153) (7,166) -- (7,566)
Closing net book amount at
31 December 2020 2,028 1,481 34,247 -- 37,756
At 31 December 2020
Cost 14,894 3,338 300,857 336 319,425
Accumulated DD&A and impairment (12,866) (1,857) (266,610) (336) (281,669)
Closing net book amount 2,028 1,481 34,247 -- 37,756
1 An impairment loss of $0.1 million (2020: $1.1 million) was
recognised on Oil & Gas Assets (see Note 3 ( d)) as a result of
the carrying value being higher than the recoverable amount. The
recoverable amount was determined by assessing its fair value less
costs of disposal.
14 Leases
The Group has recognised ROU assets and lease liabilities.
(i) Amounts recognised in the Consolidated Statement of Financial Position
The Consolidated Statement of Financial Position shows the
following amounts relating to leases:
31 December 31 December
2021 2020
$'000 $'000
Right-of-use assets
Non-current assets 616 1,014
Lease Liabilities
Current 609 614
Non-current 97 465
706 1,079
The ROU assets relate to motor vehicles, office building, rental
property 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 2020
$'000 $'000
Depreciation charge of ROU assets
Included in DD&A - ROU Depreciation (505) (502)
Interest expense (including finance cost) (101) (140)
The total cash outflow for leases in 2021 was $0.6 million
(2020: $0.6 million)
(iii) The Group's leasing activities and how these are accounted for
The Group leases various offices, equipment, staff housing and
vehicles. Rental contracts are typically made for fixed periods of
6 months to 4 years.
Contracts may contain both lease and non-lease components. There
were no non-lease components identified and as such the Group
allocates the consideration in the contract to a single lease
component based on their relative stand-alone prices.
Lease terms are negotiated on an individual basis and contain a
wide range of different terms and conditions. The lease agreements
do not impose any covenants other than the security interests in
the leased assets that are held by the lessor. Leased assets may
not be used as security for borrowing purposes.
15 Intangible Assets
The carrying amounts and changes in the year are as follows:
Exploration
and Evaluation Computer Research
assets software and Development Total
Year ended 31 December
2021 $'000 $'000 $'000 $'000
Opening net book amount
at
1 January 2021 27,042 307 -- 27,349
Additions 3,175 355 46 3,576
Amortisation charge for
year -- (166) -- (166)
Closing net book
amount
at 31 December 2021 30,217 496 46 30,759
At 31 December 2021
Cost 30,217 877 46 31,140
Accumulated
amortisation -- (381) -- (381)
Closing net book
amount 30,217 496 46 30,759
Exploration
and Evaluation Computer Research
assets software and Development Total
Year ended 31 December
2020 $'000 $'000 $'000 $'000
Opening net book amount
at
1 January 2020 25,987 268 -- 26,255
Additions 1,055 145 -- 1,200
Amortisation charge for
year -- (106) -- (106)
Closing net book
amount
at 31 December 2020 27,042 307 -- 27,349
At 31 December 2020
Cost 27,042 520 -- 27,562
Accumulated
amortisation -- (213) -- (213)
Closing net book
amount 27,042 307 -- 27,349
-- E&E assets: Represents the cost of the TGAL 1 exploration
well and further Galeota E&E costs. The Group tests whether
E&E assets have suffered any impairment triggers on an annual
basis and there were no impairment triggers identified in 2021
(2020: nil).
In November 2021, the Group received approval for the Field
Development Plan (FDP) for the Galeota Asset Development (GAD) from
the MEEI. This approval confirmed the technical feasibility of the
asset. To date, the Group is in the process of determining a
funding plan to achieve commercial viability. As such, the Galeota
E&E asset continues to be classified as an E&E asset until
both the technical feasibility and commercial viability
requirements are met.
Computer Software: In 2021, costs incurred in connection with
the acquisition of software.
Research and Development: In 2021, costs incurred in connection
with various initiatives reducing carbon emissions.
16 Abandonment fund
2021 2020
$'000 $'000
At 1 January 3,490 3,378
Additions 531 112
At 31 December 4,021 3,490
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
2021 2020
$'000 $'000
At 1 January and 31 December 473 253
In June 2021 the Group's Lease Operatorship Assets ("LOA")
licences were renewed with Heritage for ten years effective 1
January 2021 with the exception of the Fyzabad (FZ-2) licence which
was extended for two years effective 1 January 2021. New
Performance Bonds for each of the LOA were put in place totalling
$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. 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:
2021 2020
$'000 $'000
DTA:
-DTA to be recovered in more than 12 months (5,130) (4,447)
-DTA to be recovered in less than 12 months (6,400) (1,550)
DTL:
-DTL to be settled in more than 12 months 2,025 2,611
Net DTA (9,505) (3,386)
The movement on the deferred income tax is as follows:
2021 2020
$'000 $'000
At beginning of year (3,386) (5,174)
Movement for the year (6,041) 1,879
Unwinding of deferred tax on fair value uplift (78) (91)
Net DTA (9,505) (3,386)
The deferred tax balances are analysed below:
2019 Movement 2020 Movement 2021
$'000 $'000 $'000 $'000 $'000
DTA
Acquisition (33,436) -- (33,436) -- (33,436)
Tax losses recognised (39,476) -- (39,476) -- (39,476)
Tax losses derecognised 63,550 3,365 66,915 (5,533) 61,382
(9,362) 3,365 (5,997) (5,533) (11,530)
2019 Movement 2020 Movement 2021
DTL $'000 $'000 $'000 $'000 $'000
Accelerated tax
depreciation and
non-current asset
impairment (17,380) (1,487) (18,867) (508) (19,375)
Acquisitions 19,580 -- 19,580 -- 19,580
Fair value uplift 1,988 (90) 1,898 (78) 1,820
4,188 (1,577) 2,611 (586) 2,025
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. A DTA of $5.5 million have been
recognised during 2021 (2020: $3.4 million was derecognised) based
on future taxable profits. The Group has unrecognised deferred tax
assets amounting to $94.3 million which have no expiry date.
DTL have decreased by $0.6 million as the temporary difference
between the accounting values of property, plant and equipment and
intangible assets and tax values decreased compared to 2020 year
end
- 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).
- Tax losses - At the end of 2021 the Group had gross tax losses
carried forward of $234.6 million (2020: $237.2 million)
represented by corporate tax losses in the UK of $23.7 million
(2020: $16.6 million) and PPT and Corporate tax losses in Trinidad
and Tobago of $210.9 million (2020: $220.6 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. However, as of 1 January 2020, PPT losses can only be
utilised to shelter a maximum of 75 percent of PPT per annum.
19 Inventories
Crude oil Materials Total
and supplies
$'000 $'000 $'000
At 1 January 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
At 1 January 2020 89 5,054 5,143
Impairment -- -- --
Net inventory movement (22) 146 124
At 31 December 2020 67 5,200 5,267
(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 $1.2
million of impairment of inventory items.
20 Trade and Other Receivables
Group Company
2021 2020 2021 2020
$'000 $'000 $'000 $'000
Due within 1 year
Amounts due from related parties
(Note 30 (d)) -- -- 3,372 4,418
Trade receivables 4,641 3,357 -- --
Less: provision for impairment of
trade and intercompany receivables (6) (6) -- (100)
Trade receivables - net 4,635 3,351 3,372 4,318
Prepayments 895 862 175 149
VAT recoverable 4,550 2,467 25 125
Other receivables 767 1,413 -- 150
Less: provision for Impairment of
other receivables (100) (854) -- --
10,747 7,239 3,572 4,742
All trade receivables are with the Group's only customer,
Heritage. Ageing analysis of these trade receivables as at 31
December 2021 is as follows:
2021 2020
$'000 $'000
Up to 30 days 4,495 3,211
>60 days -- --
>180 days 140 140
4,635 3,351
The carrying amount of the Group's trade and other receivables
are denominated in the following currencies:
Group Company
2021 2020 2021 2020
$'000 $'000 $'000 $'000
USD 3,292 4,567 3,416 4,589
GBP 169 191 156 252
TTD 7,286 2,481 -- --
10,747 7,239 3,572 4,841
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
2021 2020 2021 2020
$'000 $'000 $'000 $'000
Trade receivables
Counterparties without external
credit rating:
Existing customers with no defaults
in the past 10,747 7,239 -- --
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, crude oil prices 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
2021, trade receivables of $4.6 million (2020: $3.4 million) were
therefore considered to be fully performing.
At the end of 2021 a total of $0.1 million was outstanding from
Petrotrin (2020: $0.1 million). An ECL of $0.0 million was applied
to the outstanding $0.1 million receivables amount due from
Petrotrin.
In June 2021 Trinity renewed its Galeota Block Joint Operating
Agreement (JOA) with Heritage. In addition, Heritage and Trinity
formed a new agreement to convert Heritage's participating interest
in the Galeota Block into an Overriding Royalty with Trinity now
having 100% interest in the Galeota Block. Previously, Trinity
invested 100% of the funds in capital expenditure towards the
Galeota Asset Development and rebilled Heritage's share (via Joint
Interest Billings (JIBs)). As at 14 July 2021 all JIBs receivable
relating to the Galeota Block was reclassified as capital
expenditure. The total amounts converted from JIBs to E&E
expenditure as at 14 July 2021 was $2.2 million which consisted of
JIBs receivable of $1.4 million (2020: $1 million) and reversal of
ECL $0.8 million (2020 ECL: $0.8 million).
For other Joint Interest Billing receivable amounts from
Heritage, an ECL of $0.1 million (2020: $0.9 million) was
calculated.
21 Derivative financial instruments
Derivative financial assets
The following table compares the carrying amounts and fair
values of the Group's financial assets and financial liabilities as
at 31 December 2021.
-
As at 31 As at 31
December December
2021 2020
$'000 $'000
Derivative asset -- 266
Total -- 266
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
2021
$'000
Opening balance 266
Opening derivative instrument realised (266)
Closing balance --
Derivative financial liabilities
As at 31 As at 31
December December
2021 2020
$'000 $'000
Derivative liabilities 2,883 --
Total 2,883 --
On 31 December 2021 the crude derivative contracts were valued
using a Mark to Market report. The report provides estimated
forward looking values on the existing crude derivatives held at 31
December 2021.
22 Cash and Cash Equivalents
Group Company
2021 2020 2021 2020
$'000 $'000 $'000 $'000
Short term investment 2,449 4,055 2,449 4,055
Cash and cash equivalents 15,863 16,182 659 262
18,312 20,237 3,108 4,317
Cash and Cash equivalents disclosed above and in the
Consolidated Statement of Cash Flows exclude restricted cash and
are available for general use by the Group.
23 Share Capital and Share Premium
Group
Number Ordinary Share premium Total
of shares shares $'000
$'000 $'000
As at 1 January 2021 483,594,288 97,692 139,879 237,571
Share reduction and cancellation (444,714,857) -- -- --
of deferred shares
Capital reduction -- (97,308) (139,879) (237,187)
2020 Share Issue - Nominal
value (1) -- 5 -- 5
As at 31 December 2021 38,879,431 389 -- 389
During 2021 the Company undertook a Capital Reorganisation to
enable the Company to pay dividends, or effect share buybacks, when
it is considered prudent to do so. This process comprised:
1. a Consolidation of every 10 Existing Ordinary Shares into one Consolidated Ordinary Share
2. an immediate Sub-Division of each of those Consolidated
Ordinary Shares into one New Ordinary Share and one New Deferred
Share; and
3. a Capital Reduction by way of both the cancellation of the
Existing Deferred Shares and the New Deferred Shares and the
cancellation of the Company's Share Premium Account.
-- On 18 June 2021 the Share Consolidation and Sub-Division
reduced the high number of existing Ordinary Shares in issue and
the Sub-Division retained the nominal value of $0.01 each per New
Ordinary Share, which is same as the previous nominal value of each
of the existing Ordinary Shares.
-- On 14 July 2021 the Capital Reduction effectively cancelled
the entire Share Premium Account of the Company as well as the
Existing Deferred Shares and new Deferred Shares created following
the Share Consolidation and Sub-Division.
-- The Capital Reorganisation was completed on 14 July 2021
subsequent to the UK Court approval of the Capital Reduction.
-- Following the Capital Reduction, the issued ordinary share
capital of the Company stood at 38,879,431 ordinary shares of $0.01
each, with no Ordinary Shares held in treasury. The total number of
voting rights in the Company also remains at 38,879,431.
(1) - In 2020, 4,745,057 shares (pre-consolidation) were issued
at nil value to certain employees who exercised options that vested
in respect to one off LTIP awards made in 2017. In 2021 the nominal
value of these shares, being US$0.05 million, were paid to the
Company and as part of the Capital Reduction, $0.05 million was
transferred to retained earnings and the remaining US$0.0 million
was treated as share capital.
24 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 2021 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:
2021 2020
$'000 $'000
At 1 January 14,764 14,328
Capital Reduction (11,485)
Share based payment expense:
LTIP exercised -- (527)
LTIP expense 505 963
At 31 December 3,784 14,764
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 expire in 2022 and 2023. The table below gives
details:
2021 2020
Grant-Vest Expiry Exercise Number Exercise Number
Date price per of Options price per of Share
Share Option Share Option Options
2012-2015 2022 GBP 8.60 168,554 GBP8.60 168,554
2013-2016 2023 GBP 12.00 28,954 GBP12.00 28,954
197,508 197,508
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
EMT to deliver long-term shareholder returns. Under the plan,
participants are granted options which only vest if certain
performance conditions 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. The
Options are exercisable at nil cost by the participants.
2017 LTIPs
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 LTIP Awards"). The 2017 LTIP awards, which
ordinarily vest on 30 June 2022, partially vested on 30 June 2020
and 30 June 2021, 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 LTIP Award is $2.6 million and
will be expensed over the vesting period with the full charge
pro-rated over the period up to 30 June 2022. However, LTIP Award
may vest in full or in part on 30 June 2020 or 2021 with the
appropriate charge being taken over the vesting period. The fair
value at grant date is 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 LTIP Awards granted in 2017 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
2019 LTIPs
In January 2019 Options over 282,400 ordinary shares and in May
2019 Options over 383,282 ordinary shares were granted under the
LTIP in accordance with the policy announced to the market on 25
August 2017. The January 2019 LTIP awards vested on 1 January 2021,
while the May 2019 awards will vest on 2 January 2022 subject to
meeting the performance criteria set out in the table below and
continued employment with the Company.
Performance targets January 2019 LTIPs May 2019 LTIPs
Below the Median None of the award will None of the award will
vest vest
Median (50th percentile) 30% of the maximum 30% of the maximum
award will vest award will vest
Between Median and Straight-Line basis Straight-Line basis
Upper Quartile between these points between these points
Upper Quartile (75%) 100% of the maximum 100% of the maximum
and above award will vest award will vest
The 2019 LTIP Awards are 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 2019 LTIP awards was
$0.9 million and this will be 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
2019 LTIP awards granted during the period ended 31 December 2019
were as follows:
January 2019 May 2019
LTIPs LTIPs
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
2020 LTIPs
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 to
members of the EMT in respect of the performance of the Company in
the financial year ended 31 December 2019. These LTIP awards will
vest on 2 January 2023, subject to meeting the performance criteria
set out in the table below and continued employment in 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
The LTIP Awards are subject to the achievement of relative Total
Shareholder Return ("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 2020 LTIP awards 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 2020 LTIP awards granted during
the period were as follows:
June 2020 LTIPs October 2020
LTIPs
Grant Dates 25 June 2020 30 October 2020
Share price at grant dates GBP79.00p GBP77.00p
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
2021 LTIPs
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") to members of the EMT 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 the 2021 Annual LTIP Awards will
be measured considering both the Company's absolute TSR performance
and the Company's relative TSR performance over a three-year
period, commencing 1 January 2021. 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 for the 2021 Annual LTIP Award was 88p (adjusted
for the Share Consolidation).
The performance targets provide that:
No portion of a distinct one-half of the 2021 Annual LTIP Award
(the "Absolute TSR Part") may vest unless the Company's compound
annual growth rate of TSR over the performance period is at least
10% p.a., for which 30% of the Absolute TSR Part may vest, rising
on a straight line basis for full vesting of the Absolute TSR Part
if the Company's compound annual growth rate of TSR over the
performance period equals or exceeds 25% p.a.
No portion of the other distinct one-half of the 2021 Annual
LTIP Award (the "Relative TSR Part") may vest unless the Company's
TSR over the performance period ranks at least median relative to
the TSR performance within a comparator group of companies, for
which 30% of the Relative TSR Part may vest, rising on a straight
line basis for full vesting of the Relative TSR Part if the
Company's TSR over the performance period ranks upper quartile or
better relative to the TSR performance within a comparator
group.
However, an underpin term applies to the Relative TSR Part which
provides that, regardless of relative TSR performance, no vesting
may ordinarily accrue in respect of the Relative TSR Part unless
the Company's compound annual growth rate of TSR over the
performance period is at least 10% per annum.
The total fair value at grant date of the 2020 LTIP awards 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 2021 LTIP awards granted during
the period were as follows:
August 2021 LTIPs
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
Movements in the number of LTIPs outstanding and their related
weighted average exercise prices are as follows:
2021 Average Number 2020 Average Number of
exercise of Options exercise price Options
price per per Share Option
Share Option
At 1 January GBP 0.00 3,156,299 GBP 0.00 3,178,982
Forfeited GBP 0.00 (100,000) GBP 0.00 (172,059)
Granted(1) GBP 0.00 325,000 GBP 0.00 623,882
Exercised(2) GBP 0.00 -- GBP 0.00 (474,506)
At 31 December GBP 0.00 3,381,299 GBP 0.00 3,156,299
(1 Weighted average fair value of LTIPs granted GBP 0.70)
(2 Weighted average share price at the date of exercise GBP
0.80)
LTIPs outstanding at the end of the year have the following
expiry date and exercise prices:
Expiry Exercise
Grant-Vest date price 2021 2020
24/8/2017 - 30/6/2022 24/8/2027 GBP 0.00 2,103,032 2,103,032
2/1/2019 - 1/1/2021 1/1/2023 GBP 0.00 252,510 252,510
9/5/2019 - 2/1/2022 2/1/2024 GBP 0.00 319,171 319,171
25/6/2020 - 2/1/2023 2/1/2025 GBP 0.00 381,586 481,586
13/8/2021 - 31/12/2023 2/1/2025 GBP 0.00 325,000 --
25 Merger and Reverse Acquisition Reserves
Reverse Acquisition Merger Reserve Total
Reserve
$'000 $'000 $'000
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)
At 1 January 2020 (89,268) 75,467 (13,801)
At 31 December 2020 (89,268) 75,467 (13,801)
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.
26 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 FV Derivative
Instruments.
The Group presents Adjusted EBITDA as it is used in assessing
the Group's growth and operational performance 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:
2021 2020
$'000 $'000
Operating Profit Before SPT, PT,
Impairment and Exceptional Items
and Covid-19 expense 10,019 2,965
Covid-19 expense (669) --
DD&A (note 13 - 15) 7,428 8,174
ILFA (note 20) (754) 252
SOE (note 24) 626 963
FX (loss)/gain 14 (7)
FV Derivative Instruments (note
6) 3,149 (266)
Adjusted EBITDA 19,813 12,081
$'000 $'000
Weighted average ordinary shares
outstanding - basic 38,879 38,623
Weighted average ordinary shares
outstanding - diluted 41,969 41,780
$ $
Adjusted EBITDA per share - basic
(note 11) 0.51 0.31
Adjusted EBITDA per share - diluted
(note 11) 0.47 0.29
Adjusted EBITDA after current taxes
(the impact of SPT, PT and PPT/UL)
is calculated as follows:
2021 2020
$'000 $'000
Adjusted EBITDA 19,813 12,081
SPT (5,074) 153
PT 1,516 (532)
PPT/UL (1,375) (1,143)
Adjusted EBITDA After Current Taxes 14,880 10,559
'000 '000
Weighted average ordinary shares
outstanding - basic 38,879 38,623
Weighted average ordinary shares
outstanding - diluted 41,969 41,780
$ $
Adjusted EBITDA After Current Taxes
per share - basic 0.38 0.27
Adjusted EBITDA After Current Taxes
per share - diluted 0.35 0.25
*Restatement 2020 balance
Comparative figures have been recalculated to conform with
changes in presentation in the current year. The comparative
figures were recalculated to show the impact on the Adjusted EBITDA
per share resulting from the 10:1 share consolidation which reduced
the number of ordinary shares from 388,794,303 to 38,879,430 (see
note 23). The impact of the restatement is summarised below:
31 December 31 December
2020 2020
$ $
Restated Prior period
Adjusted EBITDA
Adjusted EBITDA per share - basic 0.31 0.03
Adjusted EBITDA per share - diluted 0.29 0.03
Adjusted EBITDA after Current Taxes
Adjusted EBITDA after Current Taxes
per share - basic 0.27 0.03
Adjusted EBITDA after Current Taxes
per share - diluted 0.25 0.03
27 Provision for Other Liabilities
(a) Non-current: Decommissioning Closure Total
provision of pits(1)
$'000 $'000 $'000
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
Year ended 31 December 2020
Opening amount as at 1 January
2020 44,330 -- 44,330
Unwinding of discount (Note
9) 1,221 -- 1,221
Revision to estimates (152) -- (152)
Translation differences 6 6
Closing balance at 31 December
2020 45,405 -- 45,405
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 stations 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 - 2.40% (2020: 2.00%)
b. Risk free rate - 1.80% - 2.20% (2020: 2.42% - 3.17%)
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.
(1) There was a change in estimate whereby the Closure of pits
provision was reclassified from current to non-current liabilities
for the period to 31 December 2021 as management obtained new
information in the current period estimating that the liability may
extend beyond 12 months.
(b) Current:
Litigation
claims
$'000
Opening and Closing balance
2021 46
Opening and Closing balance
at 2020 46
Litigation claims
In 2021 there was a litigation settlement for $0.0 million and
increase in the provisions for $0.0 million.
Closure of Pits
In 2020 there was a decrease in the provision of $0.0 million
relating to the revision to 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. Testing
period can last up to or over a year depending on the testing
criteria.
28 Trade and Other Payables
Group Company
Current 2021 2020 2021 2020
$'000 $'000 $'000 $'000
Trade payables 2,274 2,024 88 130
Accruals 4,486 3,793 239 351
Other payables 492 471 -- --
SPT & PT 1,562 1,515 -- --
8,814 7,803 327 481
29 Bank overdraft
31 December 31 December
2021 2020
$'000 $'000
Bank Overdraft 2,700 2,700
2,700 2,700
In 2020, an on-demand operating (overdraft) line of $2.7 million
was established 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 4.05% per
annum, effective rate 4.95%, floor rate of 3.95%. 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.
On 2 April 2020 the Company drew down the $2.7 million in full.
For the year ended 31 December 2021, the credit limit was increased
to $5 million but no further amounts were drawn.
30 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
2021 2020
$'000 $'000
Company subsidiaries:
Trinity Exploration and Production Services 856 --
Trinity Exploration & Production (UK) Limited 8 10
Trinity Exploration and Production (Galeota)
Limited 659 26
Bayfield Energy Limited 19 61
Oilbelt Services Limited 1,659 170
Trinity Exploration and Production (Trinidad 393 --
and Tobago) Limited
Galeota Oilfield Services Limited -- 3
Trinity Exploration and Production Services
Limited (UK) Limited 30 899
Transfer of funds 73 --
3,697 1,169
(b) Transfer of funds to related parties
Company
2021 2020
$'000 $'000
Company subsidiaries:
Trinity Exploration and Production Services (70) (473)
Bayfield Energy Limited (100) --
Trinity Exploration and Production Services (2,063) ---
Limited (UK) Limited
(2,233) (473)
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
2021 2020
$'000 $'000
Salaries and short-term employee benefits 1,337 1,219
Post-employment benefits 27 26
Share-based payment expense 305 469
1,669 1,714
(d) Year-end balances arising from transfer to and from related
parties
Company
2021 2020
$'000 $'000
Receivables from related parties:
Trinity Exploration and Production Services
Limited -- 408
Trinity Exploration & Production (UK) Limited 28 28
Trinity Exploration and Production (Galeota)
Limited -- 159
Bayfield Energy Limited 192 104
Oilbelt Services Limited -- 1,029
Galeota Oilfield Services Limited -- 4
Trinity Exploration and Production (Trinidad
and Tobago) Limited 22 414
Trinity Exploration and Production Services
(UK) Limited 3,129 2,272
Employee Benefit Trust (See note 1) 73 --
Total intercompany receivables (Note 20) 3,443 4,418
Less: provision for impairment of intercompany
receivables (71) (100)
Closing intercompany receivables (Note 20) 3,372 4,318
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 (2020: 0.1
million).
Company
2021 2020
$'000 $'000
Payables to related parties:
Trinity Exploration and Production Services
Limited 167 --
Trinity Exploration and Production Services
(UK) Limited 7
Trinity Exploration and Production (Galeota)
Limited 112 --
Oilbelt Services Limited 495 --
Total intercompany payables 781 --
31 Taxation Payable
2021 2020
$'000 $'000
Taxation payable
PPT -- 144
UL -- 58
-- 202
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.
32 Financial Instruments by Category
At 31 December 2021 and 2020, the Group held the following
financial assets at amortised cost:
Group Company
2021 2020 2021 2020
$'000 $'000 $'000 $'000
Trade and other receivables - current
(*) 5,302 3,910 200 424
Abandonment fund - non current 4,021 3,490 -- --
Intercompany -- -- 3,372 4,318
Cash and cash equivalents 18,312 20,237 3,108 4,317
27,635 27,637 6,680 9,059
Note (*): Excludes prepayments and VAT recoverable
At 31 December 2021 and 2020, the Group held the following
financial liabilities at amortised cost:
Group Company
2021 2020 2021 2020
$'000 $'000 $'000 $'000
Accounts payable and accruals 8,814 7,803 327 481
Intercompany -- -- 781 --
Bank overdraft 2,700 2,700 -- --
11,514 10,503 1,108 481
At 31 December 2021 and 2020, the Group held the following
financial asset at fair value through profit or loss:
Group Company
2021 2020 2021 2020
$'000 $'000 $'000 $'000
Derivative financial asset -- 266 -- 266
-- 266 -- 266
Group Company
2021 2020 2021 2020
$'000 $'000 $'000 $'000
Derivative financial liability 2,883 -- 2,883 --
2,883 -- 2,883 --
33 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 27: 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.) have expired. There
may be additional liabilities and commitments arising when new
agreements are finalised, but these cannot be presently quantified
until new agreements are available.
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. The PGB licence has expired.
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 condensed consolidated
financial statements.
iv) On 1 December 2021, Trinity acquired the PS-4 Block Lease
Operatorship Sub-Licence. As part of the lease agreement, a
Performance Bond of $0.13 million is required to be executed with
Heritage. At 31 December 2021, the Performance Bond was not
finalised and is expected to be completed subsequent to the
year-end.
34 Employee Costs
Group Company
Employee costs for the Group during the 2021 2020 2021 2020
year
$'000 $'000 $'000 $'000
Wages and salaries 8,625 6,266 1,170 910
Other pension costs 372 358 -- --
Share based payment expense (Note 22) 673 963 94 248
9,670 7,587 1,264 1,158
Average monthly number of people 2021 2020 2021 2020
(including Executive and Non-Executive number number number number
Directors') employed by the Group
Executive and Non-Executive Directors 6 6 6 6
Administrative staff 95 85 -- --
Operational staff 144 131 -- --
245 222 6 6
35 Events after the Reporting Year
1. The Company implemented crude derivatives over the Group's
monthly production in 2021 and 2022. The derivative protection
currently in effect for 2022 is as follows:
Type of Index Sell Buy Sell Buy Production Effective Expiry Execution Premium
Derivatives Put Put Call Call Date Date Date USD MM
US$/bbl US$/bbl US$/bbl US$/bbl Monthly
Barrels
3-Way Cost
Collar ICE Brent 50.00 60.00 66.90 - 10,000 1-Jan-22 30-Jun-22 04-Mar-21
3-Way Cost
Collar ICE Brent 50.00 60.00 74.40 - 12,500 1-Jan-22 31-Dec-22 02-Jun-21
4-Way Cost
Collar ICE Brent 59.00 68.00 72.00 82.00 15,000 1-Jan-22 30-Jun-22 05-Jul-21
3-Way Cost
Collar ICE Brent 40.00 50.00 80.50 - 15,000 1-Jan-22 31-Dec-22 27-Aug-21
Put Spread
Option ICE Brent 40.00 50.00 - - 15,000 1-Jul-22 31-Dec-22 14-Jan-22 0.15
2. On 24 February 2022, Russian forces invaded Ukraine, causing
wide-ranging sanctions to be applied against the Russian regime by
the US, EU and other major economies. The event caused both Brent
and WTI oil prices to soar, peaking well above $100 per bbl into
March 2022. The impact of increased oil prices has mainly
positively impacted the Group's crude oil revenue but negatively
impacted derivative expenses. Overall, whilst there has been no
significant adverse impact to the Group, Management continues to
closely monitor the event's impact as it unfolds.
3. In 2021 Trinity engaged with a range of potential partners as
part of the Galeota farm down process. The Company on 3 May 2022
indicated, whilst initial feedback has been encouraging, a number
of participants have informed the Company that they are unable to
fully assess the economics of the opportunity at Galeota without
clarity on the expected reforms to Supplemental Petroleum Tax
("SPT"), which are currently being considered by the Government of
Trinidad and Tobago ("GORTT") and which were initially expected to
have been confirmed sooner than now appears likely. Pending SPT
reform, which management still expects to happen, the Company has
decided to pause the Galeota farm down process. This will enable
the Company to seek the best value proposition for Galeota when the
GORTT's fiscal reforms have been confirmed.
In the interim, the Company will continue to refine its plans
for Galeota. In particular, it will advance preparations for
exploiting the 9.77mmstb of 2P reserves remaining in the Trintes
field.
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