TIDMTRIN
RNS Number : 7537U
Trinity Exploration & Production
02 April 2019
RNS ANNOUNCEMENT: The information communicated in this
announcement contains inside information for the purposes of
Article 7 of Regulation 596/2014.
Trinity Exploration & Production plc
("Trinity" or "the Group" or "the Company")
Preliminary Results
Trinity, the independent E&P company focused on Trinidad and
Tobago, today announces its unaudited preliminary results for the
12 months ended 31 December 2018.
2018 was a significant year for Trinity with the recommencement
of onshore drilling activities, continuation of our low-cost work
programme and strengthening of our balance sheet. The maintenance
of our high operating margins and increase in production propelled
us to exit the year in a strong financial and operational position
as evidenced by our Q4 2018 production levels being in excess of
3,000 bopd and our Adjusted EBITDA margin for the year exceeding
30%.
Key Performance Indicators
FY 2018 FY 2017 Change (%)
Average realised oil price(1) USD/bbl 59.8 48.6 23
Average net production bopd 2,871 2,519 14
Adjusted EBITDA(2) USD MM 19.2 12.7 51
Adjusted EBITDA(3) USD/bbl 18.3 13.8 33
Adjusted EBITDA margin(4) % 30.7 28.0 10
Adjusted EBITDA after SPT & PT(5) USD MM 12.8 10.6 21
Consolidated operating break-even(6) USD/bbl 29.0 28.4 -2
Cash balance USD MM 10.2 11.8 -14
Cash + working capital surplus (7) USD MM 18.1 0.1 18000
1. Realised price: Actual price received for crude oil sales per
barrel ("bbl"). A discount is normally applied to the West Texas
Intermediate ("WTI") price by The Petroleum Company of Trinidad and
Tobago Limited ("Petrotrin") (1 January 2018 - 30 November 2018)
and Heritage Petroleum Company Limited ("Heritage") (effective 1
December 2018 to present) to derive the realised price received by
Trinity.
2. Adjusted EBITDA (USD MM): Operating Profit before
Supplemental Petroleum Tax ("SPT") and Property Tax ("PT") for the
period, adjusted for Depreciation, Depletion & Amortisation
("DD&A"), non-cash share option expenses and Other Expenses
(derivative hedge instruments)
3. Adjusted EBITDA (USD/bbl): Adjusted EBITDA/Annual
production
4. Adjusted EBITDA Margin (%): Adjusted EBITDA/Revenues
5. Adjusted EBITDA SPT and PT (USD MM): Adjusted EBITDA less
Supplementary Petroleum Taxes and Property Taxes
6. Consolidated operating break-even: The realised price where
Adjusted EBITDA for the entire Group is equal to zero
7. Cash plus working capital surplus: Current assets less
Convertible Loan Notes ("CLN") less Trade and other payables less
Taxation payable less Derivative financial instrument (CLN and
Ministry of Energy and Energy Industries of T&T ("MEEI") is
face value of debt, including accrued interest)
Financial Highlights
-- Revenues increased by 38% to USD 62.6 million (2017: USD: 45.2 million)
-- Adjusted EBITDA increased 51% to USD 19.2 million (2017: USD 12.7 million)
-- Adjusted EBITDA margin of 31% (2017: 28%) or USD 18.3/bbl (2017: USD 13.8/bbl)
-- Adjusted EBITDA after SPT and PT up 21% to USD 12.8 million (2017: USD 10.6 million)
-- Maintained a group operating break-even price below USD 30.0/bbl
-- Cash balance of USD 10.2 million (2017: USD 11.8 million)
impacted by one-off increase in trade receivables of USD 6.7
million relating to the Petrotrin restructuring. Post the
period-end, USD 4.1 million of these outstanding receivables have
been collected and full collection of the remaining USD 2.6 million
is expected by the end of H1 2019
-- Cash plus working capital surplus of USD 18.1 million (2017: USD 0.1 million)
Corporate Highlights
-- Balance sheet significantly strengthened with all outstanding
debt fully repaid following USD 20 million fundraise which also
provided funds for ongoing onshore drilling programme
-- Strengthening of Board, with appointment of Nicholas Clayton as Senior Independent Director
Operational Highlights
-- The Company's total 2P reserves (Onshore and Offshore)
increased to 24.49 million stock tank barrels ("mmstb") (6%
increase vs 2017: 23.21 mmstb)
-- Driven primarily by 26% increase in onshore reserves
following on from a 45% increase in 2017
-- Total 2P reserves and 2C resources of 43.26 mmstb at 31 December 2018 (2017: 47.19 mmstb)
-- Average production of 2,871 bopd (2017: 2,519 bopd),
representing a 14% increase, underpinned by:
o Drilling of eight new onshore wells efficiently and cost
effectively on a turnkey basis
o 17 recompletions ("RCPs") (2017: 37) including first offshore
RCP
o Increase in active offshore wells producing to 31 (2017:
17)
o Base production maintenance through a continuous campaign of
143 workovers ("WO") and reactivations (2017: 97).
-- Resulted in exit production rate in excess of 3,000 bopd (Q4 2018: 3,205 bopd)
-- Contingent upon the prevailing oil price environment, and
subsequent investment, net average production for 2019 is expected
to be in the range of 3,000 - 3,300 bopd
2018 was a significant year for Trinity with the recommencement
of onshore drilling activities, continuation of our low-cost work
programme and strengthening of our balance sheet. The maintenance
of our high operating margins and increase in production propelled
us to exit the year in a strong financial and operational position
as evidenced by our Q4 2018 production levels being in excess of
3,000 bopd and our Adjusted EBITDA margin for the year exceeding
30%.
The Fundraise which we completed in July 2018 means that we are
fully funded and debt free. Equally importantly, the sustained
generation of strong operating cash flows and a consolidated
operating break-even below USD 30.0/bbl provides significant
downside protection in the event of a decline in the oil price.
We continue to focus on delivering our planned work programme,
with our fully funded drilling operations providing near-term
production upside, targeting year-on-year production growth of at
least 10%. Added to this, as the development effort continues to
mature on our TGAL Area development plan, the Company is
increasingly excited the project. The TGAL development has the
potential to achieve a step change in production and value for the
Company as we target our medium-term production goal of 7,500 bopd.
Furthermore, we believe there are a number of inorganic growth
opportunities that the Company could pursue, and we are well placed
to take advantage of any suitable opportunities that may arise.
The broader environment in T&T remains extremely promising.
Whilst there have been some one-off challenges in the transition
from Petrotrin to Heritage, we are confident that our locally led
business model is well suited to the future based on our incumbent
position and strong relationships on the ground in T&T.
With average realisations being above USD 50.0/bbl for 2018, the
regressive Supplemental Petroleum Tax ("SPT") impacted cash
conversion levels. SPT in its current structure is a global anomaly
and disadvantages oil producers when compared to gas producers.
Trinity, alongside other crude oil producers in T&T, continue
to lobby for its reform as was promised by the current Government.
We believe that reform would re-calibrate the economics for all
crude oil operators in the region while potentially opening up new
investment opportunities.
Alongside working towards a more equitable fiscal environment
for oil producers, Trinity continues to strive to optimise the
economic returns from its asset base; with a determined focus on
subsurface analysis, using the best data available and adopting new
technological approaches to include high angle or horizontal
drilling.
Given the strength of our ongoing work programme and visibility
afforded by our balance sheet, we face the future with a growing
confidence. We anticipate further strategic opportunities arising
in 2019 and are committed to delivering value for all our
stakeholders and with our local model, we are ideally positioned to
take advantage of such changes.
Bruce Dingwall, CBE, Executive Chairman of Trinity,
commented:
"2018 was a significant year for Trinity with the recommencement
of onshore drilling activities, continuation of our low-cost work
programme and strengthening of our balance sheet. We face the
future with a growing confidence, ideally positioned to take
advantage of strategic opportunities arising in 2019 for the
benefit of all our stakeholders."
All figures for the financial year 2018 are unaudited. The Board
of Directors ("The Board") currently expects to publish its annual
report and accounts for the year to 31 December 2018 before the end
of April 2019, with the Annual General Meeting ("AGM") expected to
take place during May 2019.
Enquiries
For further information please visit www.trinityexploration.com
or contact:
Trinity Exploration & Production plc +44 (0)131 240 3860
Bruce Dingwall CBE, Executive Chairman
Jeremy Bridglalsingh, Chief Financial Officer
Tracy Mackenzie, Corporate Development
Manager
SPARK Advisory Partners Limited (Nominated
Adviser and Financial Adviser) +44 (0)20 3368 3550
Mark Brady
Miriam Greenwood
Andrew Emmott
Cenkos Securities PLC (Broker)
Joe Nally (Corporate Broking)
Neil McDonald
Beth McKiernan
Derrick Lee +44 (0)20 7397 8900
Pete Lynch +44 (0)131 220 6939
Whitman Howard Limited (Equity Adviser) +44 (0)20 7659 1234
Nick Lovering
Hugh Rich
Walbrook PR Limited +44 (0)20 7933 8780
Nick Rome trinityexploration@walbrookpr.com
About Trinity (www.trinityexploration.com)
Trinity is an independent oil and gas exploration and 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 2P reserves as at the end of 2018 was 24.5 mmbbls.
Group 2C contingent resources are estimated to be 18.8 mmbbls. The
Group's overall 2P plus 2C volumes are therefore 43.3 mmbbls.
Trinity is quoted on the AIM market of the London Stock Exchange
under the ticker TRIN.
Executive Chairman's Statement
Strategy
Trinity's aim is to position itself as the leading independent
producer in T&T on market. To achieve this, our strategy is
simple; to retain the integrity of the core producing proved and
probable ("2P") reserves base, to continue to grow production
safely, to efficiently deliver profitable returns and to prudently
convert our significant contingent ("2C") resources to 2P reserves
and future inventory.
Delivering production growth whilst sustaining a low operating
break-even
Trinity's focus in recent years has been on preserving the
integrity of our producing asset base whilst improving operational
practices and efficiencies to materially re-base costs. 2018 was
the first year since 2013 that Trinity undertook new onshore
drilling, with two new wells in H1 and six new wells in H2. The
resulting production growth, and improved crude oil prices, had a
positive impact on our revenues in 2018. As we progress into 2019,
the financial impact of higher base production and new production
growth from our continuing drilling programme should become even
more apparent.
Average production volumes grew in aggregate by 14% to 2,871
bopd in 2018 (2017: 2,519 bopd). With increased activity levels
during H2 2018 there was a 15% quarter on quarter increase in
average production volumes to 3,205 bopd for Q4 2018 (Q3 2018:
2,734 bopd). The increase in annualised production was underpinned
by a combination of eight new onshore development wells coming on
stream during 2018, an increase in active offshore wells producing
from 17 to 31 and the continuation of the Group's low-cost ongoing
work programme of RCPs, WOs, reactivations and swabbing. The 2018
work programme included a total of 17 RCPs (2017: 37), and 143 WOs
and reactivations (2017: 97). On the East Coast, the first offshore
RCP on the Trintes field was undertaken by Trinity since assuming
operatorship in 2013. It was successfully completed during Q4 2018
and put on production at a rate ahead of management's
expectations.
Financial Performance
The result of the 14% growth in production volumes and 23%
improvement in oil prices was a 38% increase in revenues to USD
62.6 million (2017: USD 45.2 million). This resulted in a strong
operating performance with a 51% increase in Adjusted EBITDA to USD
19.2 million (2017: USD 12.7 million) which is the equivalent of
USD 18.3/bbl (2017: USD 13.8/bbl) and US 5.4 cents per share
(diluted) (2017: US 3.2 cents) representing a 69% year-on-year
increase.
However, bottom-line profitability and cash conversion was
negatively affected by the application of SPT which is a regressive
tax on net revenues when realised oil prices are above USD 50.0/bbl
(2018 average realisations of USD 59.8/bbl vs 2017 of USD
48.6/bbl). The like-for-like comparison of Adjusted EBITDA after
SPT and PT was USD 12.8 million (USD 12.2/bbl) for 2018, a 21%
increase versus USD 10.6 million (USD 11.6/bbl) for 2017, which
equated to a 33% year-on-year increase in Adjusted EBITDA after
Taxes of US 3.6 cents per share (diluted) (2017: 2.7 cents).
Operating Cash Flow ("OCF") for 2018 was USD 12.1 million (2017:
USD 8.7million). Net OCF after changes in working capital movements
and income taxes was USD 5.2 million (2017: USD 9.6 million). The
reduction is mainly a function of a USD 4.4 million year-on-year
increase in cash taxes paid (largely related to SPT) and an
increase in trade receivables totalling USD 6.7 million. The
increase in trade receivables was due to delayed revenue receipts
of USD 6.7 million as a result of the Petrotrin restructuring (see
details below). Post the year end, USD 4.1 million of the
outstanding receivables from Petrotrin have been collected and full
collection of the remaining USD 2.6 million is expected to occur by
the end of H1 2019. Stripping out the increase in receivables, the
like for like OCF after changes in working capital would have been
USD 11.8 million versus USD 9.6 million for 2017.
The Group's cash balances at the year-end stood at USD 10.2
million (2017: USD 11.8 million). The lower cash balance is as a
result of capital expenditures of USD 12.5 million (2017: USD 3.1
million) and the repayment of all outstanding debts to Board of
Inland Revenue of T&T ("BIR") and Ministry of Energy and Energy
Industries of T&T ("MEEI") (together "T&T State Creditors")
and Convertible Loan Notes ("CLN") holders (USD 5.8 million and USD
7.2 million respectively). However, importantly, the Company is now
debt free, with no dilutive CLN overhang, and has the financial
flexibility required to grow by the most effective means. In
aggregate, the resultant cash plus working capital surplus (cash
plus net operating working capital) stood at an impressive USD 18.1
million (2017: USD 0.1 million)
Reserve base continues to grow
Management's estimate of the Company's total 2P reserves
(Onshore and Offshore) increased by 6% to 24.49 million stock tank
barrels ("mmstb") (2017: 23.21 mmstb), despite total production of
1.04 mmstb. This increase is testament to the quality of our
onshore and offshore producing assets and the benefits of the
return to robust subsurface evaluation to identify additional
infill drilling, RCP and WO candidates. Onshore reserves grew
significantly by 26%, following on from a 45% increase in 2017 as
the subsurface team continued to add locations to the onshore
drilling inventory.
2C resources decreased by 22% to 18.77 mmstb (2017: 23.98
mmstb). The movement in 2C resources primarily reflects moving some
5.98 mmstb (net) of TGAL resources to 3C until a formal development
solution is finalised. This follows the high grading of a first
phase development stage targeting 10.41 mmstb (net) with more
robust overall economics. In aggregate, total 2P reserves and 2C
resources amounted to 43.26 mmstb at 31 December 2018 (2017: 47.19
mmstb).
Corporate
Funded and Debt Free
In July 2018 the Company raised gross proceeds of USD 20.0
million through a Fundraising exercise comprising a placing and an
open offer. Of this, USD 6.4 million comprised a non-cash rollover
by holders of 88% of the CLNs electing to convert the value of
their CLNs into new ordinary shares at the issue price. This
enabled the full and final repayment of all outstanding debts to
the T&T State Creditors as well as redemption of the remaining
CLNs which were outstanding. The Fundraise has enabled the Company
to accelerate its onshore drilling programme and production, with a
planned 8-10 wells per year going forward subject to a conducive
landscape and economic environment.
East Coast Asset Development
In November 2018 the Company, as operator of the Galeota
licence, submitted the first phase of its revised Field Development
Plan ("FDP") for the TGAL Area to the MEEI. Work is now ongoing on
pre- Front End Engineering Design ("FEED") studies and
environmental approvals as we move towards a Final Investment
Decision ("FID") during H1 2020.
This FDP is the first phase of a potential wider development
strategy moving across the Galeota anticline to fully develop the
reserves potential from the large volumes of oil in place (c. 700
mmbbls). The first phase currently contemplates the installation of
a low cost, 10 well conductor supported platform, the installation
of a new generation thermoplastic composite subsea export pipeline,
the laying of a subsea power cable to provide power to the offshore
facilities, and the drilling of horizontal production wells. The
development of these assets would underpin our medium-term group
onshore and offshore production target of over 7,500 bopd.
Petrotrin Restructuring and Heritage Update
On 28 August 2018 Petrotrin announced its intention to
discontinue refining operations to focus on its upstream
exploration and production activities following a restructuring. To
that end the new national oil company, Heritage began trading on 1
December 2018. Whilst the transition has been relatively seamless
with regards to production, supply and distribution, there have
been delays in the timing of payments for October and November oil
production from Petrotrin. As a result, Trinity's receivables
increased by USD 6.7 million at the year end. To date, USD 4.1
million of the USD 6.7 million delayed revenues have been collected
and under Heritage's stewardship since December 2018 all payments
have been received according to the agreed payment terms. The
management of both Petrotrin and Heritage have been in close
contact with Trinity's management team and have provided the
requisite comfort that all outstanding revenues will be received in
full during H1 2019.
Trinity currently accounts for approximately 5% of all crude oil
production in T&T and we are optimistic of our ability to
deliver continued production growth in the short-term. Having
established a locally driven, efficient and low-cost operating
model, Trinity will work alongside Heritage wherever possible to
help facilitate efficiency drives and production growth in T&T
with the resultant economic benefits for all citizens and
stakeholders.
Overview
This time last year our aim was to stabilise base production,
build well inventory and execute a limited investment programme
whilst maintaining controls on operating costs and Health, Safety,
Security and Environment ("HSSE"). The Company managed to deliver
on that initial programme resulting in a significant improvement in
our operational performance and a successful year in terms of our
key performance indicators ("KPIs").
During 2018, we continued to prioritise HSSE and the well-being
of our people, promoting safe behaviours among all stakeholders
whilst undertaking a step-change in activity levels. The
dedication, hard work and expertise to deliver this growth on a
portfolio of 1,094 wells with 216 active wells at the end of 2018
(2017:182) across nine licences and multiple reservoirs has
required a huge effort from those involved. As such, we remain
extremely thankful to our employees and the continued support of
the supply chain, with whom we look forward to working alongside as
we continue to build on, and strengthen relationships with all of
our stakeholders.
We are ideally placed to continue to grow organically but also
very well positioned to make the most of the significant number of
other development opportunities that may arise locally. Whilst we
work with the Petrotrin restructuring and transition changes with
Heritage, we are assured that our locally led business model is
well suited to the future based on our strong relationships on the
ground in T&T.
Good governance remains at the core and we remain committed to
delivering our strategy in a responsible and transparent manner. In
November 2018, the Company expanded its Board with the appointment
of Nicholas Clayton as a Senior Independent Director. The breadth
and depth of his sector specific advisory experience will provide
the Board with additional perspective and, combined with our
existing Board members, strengthens our collective industry, merger
and acquisitions ("M&A") and capital markets expertise as we
continue to grow and develop Trinity's business.
Plans for 2019 and beyond
We are ideally placed to continue to grow organically but also
very well positioned to make the most of the significant number of
other development opportunities that may arise locally. Whilst we
look forward to working with Heritage going forward, we are assured
that our locally led business model is well suited to the future
based on our strong relationships on the ground in T&T.
The Company's successful drilling programme completed during Q4
means that it fulfilled stated >10% per annum ("p.a.")
production growth target for 2018 and, subject to the scheduling of
the drilling programme, Trinity is targeting similar growth in
2019. The fully funded onshore drilling programme will continue,
but given recent oil price volatility, the timing and scale of the
programme will be determined with a view to optimising capital
allocation.
We see a number of options for further value creation across
Trinity's asset base both organically and from wider portfolio
management. Our programme of phased and risk mitigated development
activities through infill development wells onshore, routine RCPs,
WOs, reactivations and swabbing on the current well stock has
succeeded in arresting decline and provided for a step-change in
base production on which to further grow.
The Company intends to build on base production to reach a
targeted annual average production range of 3,000 - 3,300 bopd for
2019. The absolute level of growth from production will be
determined by oil price and activity levels which will be set with
a view to optimising profitability and cash flows, and not just
top-line production growth.
The Company's strengthened balance sheet and low operating
break-even provides financial resilience to low oil prices and
gives confidence that the Company's growth and investment plans can
be optimised according to the prevailing macro and fiscal
environment.
On behalf of the Board, I must thank all our staff and suppliers
in T&T for their diligence, commitment and support which has
allowed Trinity to focus on growth whilst maintaining a safe
working environment. The Board would additionally like to take this
opportunity to thank existing shareholders and other stakeholders,
notably Petrotrin, Heritage, BIR, and the MEEI, for their support
and to welcome new shareholders as we move forward debt free and
strongly positioned to add value from future opportunities in the
changing environment in T&T.
2018 was a notable year for Trinity and the Board is confident
that the quality and low cost nature of our underlying assets will
deliver sustainable cash generation throughout oil price cycles and
excellent returns for shareholders from the execution of our
strategy in 2019 and beyond.
KEY PERFORMANCE INDICATORS
The Group's performance was profitable at an operating level
throughout 2018 with a 51% increase in Adjusted EBITDA of USD 19.2
million (2017: USD 12.7 million), year-end cash balance of USD 10.2
million (2017: USD 11.8 million) and a cash plus working capital
surplus of USD 18.1 million (2017: USD 0.1 million).
A summary of the year-on-year operational and financial
highlights are set out below:
FY 2018 FY 2017 Change (%)
Average realised oil price(1) USD/bbl 59.8 48.6 23
Average net production bopd 2,871 2,519 14
Annual production(2) mmbbls 1.05 0.92 14
Revenues USD MM 62.6 45.2 38
Adjusted EBITDA(3) USD MM 19.2 12.7 51
Adjusted EBITDA(4) USD/bbl 18.3 13.8 33
Adjusted EBITDA margin(5) % 30.7 28.0 10
Adjusted EBITDA Per Share - Diluted(6) US cents 5.4 3.2 69
Adjusted EBITDA after SPT and PT(7) USD MM 12.8 10.6 21
Adjusted EBITDA after SPT and PT(8) USD/bbl 12.2 11.6 6
Adjusted EBITDA after SPT and PT Per Share - Diluted(9) US cents 3.6 2.7 33
Consolidated operating break-even(10) USD/bbl 29.0 28.4 -2
Cash balance USD MM 10.2 11.8 -14
Cash plus working capital surplus(11) USD MM 18.1 0.1 18000
1. Realised price: Actual price received for crude oil sales per
barrel ("bbl"). A discount is normally applied to the West Texas
Intermediate ("WTI") price by Petrotrin (1 January 2018 - 30
November 2018) and Heritage (effective 1 December 2018 to present)
to derive the realised price received by Trinity.
2. Annual production (mmbbls)- Production from a reserves
perspective is what is produced from the reservoir in a given year
- which is 1.04 mmbbls (2,855 bopd) in 2018. For cash flow purposes
it is the sold production in a given year which for 2018 is 1.05
mmbbls (2,871 bopd). These minor differences occur at year end due
to stock sales in December and carry forward to subsequent year.
See Reserves and resources section for further details.
3. Adjusted EBITDA (USD MM): Operating Profit before SPT and PT
for the period, adjusted for Depreciation, Depletion &
Amortisation ("DD&A"), non-cash share option expenses and Other
Expenses (derivative hedge instruments)
4. Adjusted EBITDA (USD/bbl): Adjusted EBITDA/Annual production
5. Adjusted EBITDA Margin (%): Adjusted EBITDA/Revenues
6. Adjusted EBITDA Per Share - Diluted: Adjusted EBITDA /
Weighted average ordinary shares outstanding - diluted
7. Adjusted EBITDA after SPT and PT (USD MM): Adjusted EBITDA
less Supplementary Petroleum Taxes ("SPT") and Property Taxes
("PT")
8. Adjusted EBITDA after SPT and PT (USD/bbl): Adjusted EBITDA
after SPT and PT/Annual production
9. Adjusted EBITDA after SPT and PT Per Share - Diluted:
Adjusted EBITDA after SPT and PT / Weighted average ordinary shares
outstanding - diluted
10. Consolidated operating break-even: The realised price where
Adjusted EBITDA for the entire Group is equal to zero
11. Cash plus working capital surplus: Current assets less CLN
less Trade and other payables less Taxation payable less Derivative
financial instrument (CLN and MEEI is face value of debt, including
accrued interest)
ADJUSTED EBITDA CALCULATION
Adjusted EBITDA is a non-IFRS measure used by the Group to
measure business performance. The Group presents Adjusted EBITDA
metrics as they are used in assessing the Group's growth and
operational efficiencies as they better illustrate the underlying
performance of the Group's business by excluding items not
considered by management to reflect the underlying operations of
the Group.
2018 2017
USD MM USD MM
Operating Profit before SPT and
PT 6.7 3.9
DD&A 10.7 7.1
Share option expenses 0.7 0.2
Other Expenses (derivative hedge
instruments) 1.1 1.4
Adjusted EBITDA 19.2 12.6
==================== =======
Less: SPT and PT (6.4) (2.0)
-------------------- -------
Adjusted EBITDA after SPT and
PT 12.8 10.6
Expressed in US cents
Adjusted EBITDA Per Share - diluted 5.4 3.2
Adjusted EBITDA after SPT and
PT per Share - diluted 3.6 2.7
==================== =======
See Note 22 to Consolidated Financial Statements - Adjusted
EBITDA for further details
2018 TRADING SUMMARY
A 5-year historical summary of realised price, production,
operating break-evens and Production Costs ("Opex") and General
& Administrative ("G&A") expenditure metrics is set out
below:
Details 2014 2015 2016 2017 2018
Realised Price (USD/bbl) 85.8 45.5 39.4 48.6 59.8
------ ------ ------ ------ ------
Production (bopd)
------ ------ ------ ------ ------
Onshore 2,005 1,601 1,343 1,347 1,563
------ ------ ------ ------ ------
West Coast 491 312 190 212 198
------ ------ ------ ------ ------
East Coast 1,105 983 1,009 961 1,110
------ ------ ------ ------ ------
Consolidated 3,601 2,896 2,542 2,519 2,871
------ ------ ------ ------ ------
Operating Break-Even (USD/bbl)(1)
------ ------ ------ ------ ------
Onshore 21.3 23.3 17.4 16.6 16.1
------ ------ ------ ------ ------
West Coast 24.5 40.7 37.7 26.6 26.8
------ ------ ------ ------ ------
East Coast 55.9 41.3 26.3 24.9 25.9
------ ------ ------ ------ ------
Consolidated(2) 64.3 47.2 29.2 28.4 29.0
------ ------ ------ ------ ------
Metrics (USD/bbl)
------ ------ ------ ------ ------
Opex/bbl - Onshore 14.4 15.7 11.8 11.1 11.7
------ ------ ------ ------ ------
Opex/bbl - West Coast 20.2 33.8 31.6 22.1 22.1
------ ------ ------ ------ ------
Opex/bbl - East Coast 41.6 31.6 20.1 18.9 20.1
------ ------ ------ ------ ------
G&A/bbl - Consolidated(3) 11.3 9.6 4.4 4.4 5.0
------ ------ ------ ------ ------
Notes:
1. Operating Break-even: The realised price where Adjusted
EBITDA for the respective asset or the entire Group (Consolidated)
is equal to zero
2. Consolidated Operating Break-even: Includes G&A but excludes share option expenses
3. G&A/bbl - Consolidated: Excludes share option expenses
The above production trends show clearly the impact that
returning to drilling has had with Onshore production up over 16%
year-on-year despite the new drilling mainly impacting in the final
quarter of the financial year. Similarly, the impressive impact of
active production and well management offshore the East Coast has
been to deliver a five year average volume of 1,033 bopd and a very
stable platform from which to grow when development recommences on
the East Coast.
Of particular note from a financial standpoint is that robust
constituent asset and corporate level operating break-evens were
sustained with an aggregate increase of only 2% in the Group
consolidated operating break-even to USD 29.0/bbl (2017: USD
28.4/bbl). The consolidated operating break-even includes the
Group's G&A costs and therefore captures the corporate costs
associated with supporting the asset base.
At the aggregated corporate level the maintenance of such a
robust consolidated operating level break-even reflects higher
production volumes offsetting higher expenses as detailed
below:
-- Overall Opex increased by 21% to USD 17.8 million (2017: USD
14.7 million). This variance was largely a function of a larger WO
programme, production optimisation and increased vessel and
equipment rental from higher activity levels.
-- G&A costs increased by 40% to USD 6.0 million (2017: USD
4.3 million). This is predominately a function of non-cash related
expenses (unrealised foreign exchange gain USD (0.0) million (2017:
USD (0.5) million) and share option expenses USD 0.7 million (2017:
USD 0.3 million)) as well as increased staff costs, levies and
corporate expenses.
Operating netback (Revenues minus Royalties and Production
costs) increased 47% to USD 24.4 million (2017: USD 16.7 million).
On a per barrel basis this represents a 33% increase in operating
netback to USD 23.4/bbl (2017: 17.6/bbl).
OPERATIONAL REVIEW
OUR PEOPLE
Trinity's workforce stood at 215 (2017: 188) at the year-end
December 2018 with 79% (170) male and 21% (45) female employees.
Our employees are located both in the United Kingdom ("UK") and
T&T, with the majority (97%) based in T&T at our core
operations.
HEALTH, SAFETY, SECURITY & ENVIRONMENT ("HSSE")
Trinity continues to place HSSE at the forefront of our
operations as we strive towards further improving our safety
performance by ongoing sensitisation, training, increased
monitoring, frequent reviews of our internal controls and
implementing corrective action when necessary.
The Board is fully apprised of the Company's HSSE performance
via quarterly updates. The HSSE report is considered at each Board
meeting and is one of the first matters considered on the
agenda.
Management's commitment to the See, Think, Act, Reinforce and
Track ("START") card programme has positively impacted our HSSE
culture. Behaviour based safety has been recognised as an integral
factor in our drive to an incident free environment. Notable
improvements in our HSSE performance were achieved due to our
continued emphasis on a strong HSSE culture, facilitated by an
increase in management visits to all assets, increased
communication of lessons learned and several proactive initiatives
implemented across all operations. Trinity recorded 643,400 man
hours in 2018 (2017: 486,200 man hours), a 32% increase, mainly due
to the 2018 work programme which included onshore drilling as well
as onshore and offshore RCPs and workovers. Training hours recorded
also saw an increase of 14% to 2,718 hours from 2,384 hours as
safety remained as a top priority to Trinity to ensure that
employees are competent to execute all tasks in a safe and
efficient manner.
Trinity continues to build its HSSE management system as per our
Safe to Work ("STOW") T&T certification attained in February
2018 from the Energy Chamber of T&T. The renewal process and
audit commences in Q3 2019 in preparation for recertification in
February 2020. Trinity was able to attain a two year certification
within a four month period which surpassed the 6-12 month standard
process. This is considered a great achievement since new companies
to the STOW T&T certification process rarely achieve a two year
certification. This certification provides the assurance that our
HSSE management system is developed in such a form to allow us to
have the ability to respond, control and analyse safety events and
performance data as well as allowing us to be proactive in
mitigating and managing risk. Notwithstanding our 2018
achievements, in 2019 Trinity intends to continue its focus on
sustaining and improving our HSSE management system to ensure that
we deliver our production targets safely and efficiently.
PRODUCTION
Average net production for 2018 was 2,871 bopd (2017: 2,519
bopd), an increase of 14%. A total of eight new infill development
wells, 17 RCPs, 143 WOs and reactivations along with swabbing
activities were undertaken during 2018.
We are constantly striving towards re-setting base production
upwards. This requires continuous efforts, good acreage and the
application of new technologies. An overview of these activities by
asset is given below.
Onshore Assets
Current Onshore production is from Lease Operatorship Blocks:
FZ-2, WD-2, WD-5/6, WD-13, WD-14 and Farmout Block: Tabaquite.
Average 2018 net production from the Onshore assets was 1,563
bopd which accounted for 54% of total annual average production.
This represented a 16% increase in production from the 2017 average
net production levels of 1,347 bopd. The growth in year-on-year
production averages is reflective of the step-change in investment
activities beginning to impact in adding new production whilst
simultaneously successfully maintaining base production.
The drilling programme carded for 2018 initially consisted of
four new infill wells. The first two wells were drilled in H1 2018
before expanding the campaign by drilling a further six wells in H2
2018.
Trinity's RCP campaign contemplated the completion of 12 RCPs
onshore. The programme was executed in the first 10 months of the
year, eventually recompleting 16 wells (2017: 37) across all
Onshore blocks. The RCPs and WOs were executed utilising Trinity's
internal rigs through H1, while contracting two rigs for the
remainder of the year. The internal rigs were removed from service
during H2 for upgrades and overhaul.
The Onshore WO and reactivations campaign contemplated the
completion of 84 WO's onshore. For 2018, 113 were completed (2017:
78).
Going forward, the Company intends to continue with development
activities via infill development drilling, RCPs, WOs,
reactivations and swabbing on the current well stock and identified
drilling locations to maintain base production and provide for
further production growth.
East Coast Assets
Current East Coast production is derived from the Alpha, Bravo
and Delta platforms in the Trintes Field which sits within the
Galeota Block.
Average 2018 net production from the East Coast was 1,110 bopd
which accounted for 39% of total annual average production. This
represented a 16% increase in production from the 2017 average net
production levels of 961 bopd. The increase was largely as a result
of the successful execution of a rigorous workover and reactivation
campaign. Alongside these activities the successful completion of
the first RCP undertaken by Trinity since assuming operatorship in
2013 was undertaken during Q4 2018 and put on production at a rate
ahead of Management's expectations.
In 2018, 23 restorative WOs were completed (2017: 18) which
contributed to an upward trend in production. In 2018 production
was derived from 32 of a possible 61 wellbores in the Trintes
field. The Trintes field produced by deploying numerous pumping
technologies across our well stock including; Mechanical Pumping
Hydraulic Unit ("MPHU"), Hydraulic Diaphragm Electric Submersible
Pump ("HDESP"), Electric Submersible Pump ("ESP") and Progressing
Cavity Pumps ("PCP"). The team continues to explore further means
of optimising production through the utilisation of downhole remote
monitoring, chemical treatment for the prevention of scale
formation and modified artificial lift technologies.
Various infrastructure projects were undertaken during 2018
which included crane assessment and recertification works, the
acquisition of four new generators, accommodation upgrades and the
commencement of phase 1 Front-End Engineering Design ("FEED")
process for the installation of a new 10,000 bbl oil storage tank
at the Galeota tank farm.
Trinity continues to invest in stabilising production levels via
better generator maintenance strategies and continued optimisation
of alternative artificial lift technologies to augment production
rates and maintain efficiency and cost effectiveness.
West Coast Assets
West Coast production is from the Point Ligoure-Guapo
Bay-Brighton Marine ("PGB") and Brighton Marine ("BM") fields.
Average 2018 net production from the West Coast was 198 bopd
which accounted for 7% of total annual average production. This
represented a 6% decrease in production from 2017 average levels of
212 bopd and was mainly as a result of natural production
decline.
There were no major production related activities conducted on
the West Coast assets in 2018, with the exception of three WOs
(2017: one) in the PGB field and four WO (2017: one) on the
land-based wells in the Brighton Field which were undertaken with
the intention of reducing natural production decline and
stabilising base production levels. Minor infrastructural works
were undertaken on the offshore platforms to maintain asset
integrity and production.
Management are continuing to keep the potential sale of the West
Coast assets under review. In the interim, the assets continue to
generate positive cash flow and going forward the land based wells
across both the PGB and BM fields will be targeted for
reactivations in addition to minor facility upgrades to increase
production. These assets will continue to be closely monitored as
progressive steps are taken to further optimise production through
swabbing and minimal well intervention at low operating costs.
RESERVES AND RESOURCES
A comprehensive management review of all assets has been
concluded and has estimated the current 2P reserves to be 24.49
mmstb at the end of 2018, compared to the year-end 2017 reserve
estimate of 23.21 mmstb. This represents a 6% increase of 1.28
mmstb from 2017 levels, despite production for 2018 of 1.04 mmstb
(2017: 0.92 mmstb). This increase reflects contributions from new
wells, sustained RCP production, updated decline curve analysis on
producing wells, low cost well reinstatements and, most
significantly, extensive subsurface work to generate additional
infill drilling, RCP and WO candidates.
Onshore reserves grew by 26% as a result of our ongoing
continued investment in subsurface analysis. This follows on from a
45% increase delivered in 2017. Management considers this to be the
best estimate of the quantity of reserves that will actually be
recovered from the assets at the end of 2018. 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 defined investment programmes and
constituent drilling targets to commercialise the reserves as
detailed, by asset area, in the table below:
Unaudited 2018 2P Reserves
Asset 31 December 2017 Production (*) Revisions 31 December 2018
mmstb mmstb mmstb mmstb
Net Oil Production
Onshore 5.78 (0.56) 2.08 7.30
----------------- --------------- ---------- -----------------
East Coast 14.78 (0.41) 0.43 14.80
----------------- --------------- ---------- -----------------
West Coast 2.65 (0.07) (0.19) 2.39
----------------- --------------- ---------- -----------------
Total 23.21 (1.04) 2.32 24.49
----------------- --------------- ---------- -----------------
Note (*): Production from a reserves perspective is what is
produced from the reservoir in a given year-in this case 2,855
bopd. For cash flow purposes it is the sold production in a given
year and this figure is given elsewhere as 2,871 bopd. These minor
differences occur at year end due to stock sales in December and
carry forward to subsequent year.
The best estimate of 2C resources due to the current economic
environment and the defining technical work pending is estimated by
management at 18.77 mmstb (2017: 23.98 mmstb).
Unaudited 2018 2C Resources
Asset 31 December 2017 Revisions 31 December 2018
mmstb mmstb mmstb
Onshore 2.18 (0.68) 1.50
----------------- ---------- -----------------
East Coast 20.87 (4.49) 16.38
----------------- ---------- -----------------
West Coast 0.93 (0.04) 0.89
----------------- ---------- -----------------
Total 23.98 (5.21) 18.77
----------------- ---------- -----------------
Unaudited Summary of Reserves and Resources
at 31 December 2018
Asset 2P Reserves 2C Resources 2P+2C Reserves and
mmstb mmstb Resources mmstb
Onshore 7.30 1.50 8.80
------------ ------------- -------------------
East Coast 14.80 16.38 31.18
------------ ------------- -------------------
West Coast 2.39 0.89 3.28
------------ ------------- -------------------
Total 24.49 18.77 43.26
------------ ------------- -------------------
EAST COAST
Trintes (Trinity: 100% WI)
On the East Coast, Trinity has an established production hub on
the Trintes field with 4 offshore marine platforms; (Alpha, Bravo,
Charlie & Delta) that have an aggregate of 61 platform wells.
Current 2P reserves underpin only the producing Trintes field.
However, across the East Coast Galeota anticline licence area,
Management estimates total gross Stock Tank Oil Initially In Place
("STOIIP") of over 700 mmstb of which 249 mmstb of STOIIP is mapped
against the Trintes field. Trintes (current booked East Coast) 2P
reserves of 14.8 mmstb therefore represents a low incremental
recovery factor of 6%. Within contingent resources a further 5.96
mmstb relates to the Trintes field.
TGAL Field Development Plan (Trinity: 65% WI)
The TGAL area carries an internal best estimate STOIIP of 186
mmstb. The TGAL updip fault panel was confirmed as oil bearing in
all major reservoir horizons by the TGAL-1 discovery well and is
now incorporated in the 2018 FDP. In November 2018 the first phase
of the FDP for the TGAL Area, located on the Galeota Block (updip
from and on the same anticline as the Trintes field), was submitted
to the MEEI. This FDP is the first phase of a potential wider
step-out development moving across the Galeota anticline to fully
develop the reserves potential from the large volumes of oil in
place (see Reserves & Resources review for further
details).
Work is progressing on FEED studies and environmental approvals
as we move towards a FID during H1 2020, at which time the optimal
scheme for financing the development will have been selected and
agreed between all stakeholders. The 2018 FDP envisages 10 wells
and is a lower development cost solution targeting the deeper sands
using vertical conductors when compared to scheme outlined in the
2015 FDP which previously outlined 17 wells and the following key
features:
-- Conductor Support Platform ("CSP") designed to accommodate a platform rig
-- 25 year design life
-- A 6" ID Thermoplastic Composite Pipeline ("TCP") from the TGAL platform to shore
-- Subsea power cable from shore to the platform
-- First oil estimated being produced by H1 2022 and peak production estimated at 5,800 bopd
-- 2C resources c.16.02 mmstb gross (10.41 mmstb net)
-- At FID Trinity anticipate the net 2C resources would be reclassified as 2P reserves
This 2018 FDP is viewed as the first phase of a potential
broader development moving across the Galeota anticline to
commercialise the reserves potential from the large volumes of oil
in place (c. 700 mmstb). The shallow sands (which were to be
accessed via 7 wells in the 2015 FDP) but necessitate drilling
slanted conductors/drilling have been moved to the 3C category
(9.20 mmstb gross, 5.98 mmstb net) pending the integration of a
technical solution into the current vertical conductor CSP platform
concept. The current TGAL total 2C+3C volumes are therefore 25.22
mmstb (16.4 mmstb net). Within the Galeota anticline licence area
there is also significant additional prospectivity with 266 mmstb
STOIIP having been mapped over and above the Trintes and TGAL
areas. Even excluding this further upside potential, with current
combined 2P reserves and 2C resources of 32.68 mmstb, the potential
growth from future Trintes drilling and TGAL development is
substantial.
FINANCIAL REVIEW
This consolidated financial information has been prepared on a
going concern basis, in accordance with International Financial
Reporting Standards ("IFRS") as adopted by the European Union
("EU"), IFRS Interpretations Committee ("IFRS IC") interpretations
as adopted by the EU and those parts of the Companies Act 2006 as
applicable to companies reporting under IFRS. 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 3 of the
Financial Statements. The Group has adopted additional accounting
policies in the year ended 31 December 2018 as set out in Note 3 of
the Financial Statements.
Throughout this report reference is made to adjusted results and
measures. The directors 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 normalised underlying cash earnings achieved in
the year. In exercising this judgment, the directors have taken
appropriate regard of International Accounting Standards ("IAS") 1
"Presentation of financial statements". For the reasons stated
above, Adjusted EBITDA excludes the impact of DD&A, non-cash
share option expenses, and the impact of derivative hedge
instruments ("adjustment items") and these are summarised on the
face of the Consolidated Income Statement as well as being
described in Note 22 to the financial statements.
Results for the year
Trinity and its subsidiaries ("the Group") recorded an Adjusted
EBITDA of USD 19.2 million (2017: USD 12.6 million), a reported
loss for the year of USD (5.3) million (2017: USD 25.4 million
profit), an ending cash balance of USD 10.2 million (2017: USD 11.8
million) and a net cash plus working capital surplus position of
USD 18.1 million (2017: USD 0.1 million).
-- Revenue growth from increased production and oil price
realisations: The combination of a 14% increase in production to
2,871 bopd (2017: 2,519 bopd) and a 23% increase in average oil
price realisations to USD 59.8/bbl (2017: USD 48.6/bbl) resulted in
a 38% increase in revenues to USD 62.6 million (2017: USD 45.2
million).
-- Successful capital expenditure work programme: USD 12.5
million (2017: USD 3.1 million) incurred in predominately
production related and infrastructure expenditure. 2018 saw the
company return to drilling, with 8 Onshore development wells, 16
Onshore RCP's and the first RCP on the East Coast since acquiring
the asset in 2013. Infrastructure capital expenditure were also
conducted across the assets to support the production
initiatives.
-- Further growth in operating margins and increased operating
profitability: The Company maintained its focus on growing margins
and increasing operating profitability which is evident in a 51%
increase in Adjusted EBITDA to USD 19.2 million (2017: USD 12.7
million) and maintaining a robust consolidated operating break-even
price of USD 29.0/bbl (2017: USD 28.5/bbl), while increasing
Adjusted EBITDA Margin to 31% in 2018 (2017: 28%). On a per barrel
basis this represents a 33% increase in Adjusted EBITDA to USD
18.3/bbl (2017: USD 13.8/bbl) and Adjusted EBITDA per share -
diluted increased 69% to 5.4 cents (2017: 3.2 cents).
-- Supplementary Petroleum Taxes ("SPT") and Property Taxes
("PT"): 2018 saw average oil price realisations rise above USD
50.0/bbl (2018: USD 59.8/bbl) into the SPT paying range. As a
result, SPT of USD 7.1 million was incurred in 2018 (2017: USD 1.5
million). For each quarter that realised oil prices are higher than
USD 50.01/bbl SPT is charged at a rate of 18% and 26% on net
revenues (gross revenue - royalties - incentives) on Onshore and
Offshore assets respectively. The headline SPT rates are, however,
partially mitigated by investment tax credits of 20%. SPT is seen
by many commentators as being a regressive tax, which negatively
impacts on investment and unfairly penalises oil (as opposed to
gas) companies. SPT reform has been earmarked by the Government of
Trinidad and Tobago ("GORTT"), but has not yet been effected.
The passing of the Property Tax Amendment Bill by the T&T
House of Representatives resulted in a PT credit of USD 0.7 million
(2017: USD (0.5) million charge) with the USD 1.1 million reversal
for 2016 and 2017 offsetting a USD 0.4 million charge for the
current year.
-- Impairment loss: During the year the Group recorded an
impairment loss of USD 2.6 million (2017: nil) within exceptional
items on its oil and gas assets held within property plant and
equipment. The carrying values of certain of the Group's cash
generating units were higher than their recoverable amount measured
utilising discounted cash flow approach to Fair Value less Cost of
Disposal. This was largely driven by the lower oil price forward
curve at 31 December 2018, and a more conservative cost of capital
assumption being applied.
-- Reported Profitability and Cash conversion: Bottom-line
profitability and cash conversion was negatively impacted by SPT.
The like for like comparison of Adjusted EBITDA after SPT and PT is
USD 12.8 million (USD 12.2/bbl and 3.6 cents per share - diluted)
for 2018 versus USD 10.6 million (USD 11.5/bbl and USD 2.7 cents
per share - diluted) for 2017.
The inclusion of DD&A, hedging costs, other non-cash items,
exceptional items and net finance costs yielded a reported post tax
loss for the period of USD 5.3 million (2017: USD 25.4 million
profit). Notably, in 2017 there was an exceptional non-cash credit
of USD 26.7 million, which related to the restructuring that
occurred in January of that year.
Operating Cash Flow ("OCF") for 2018 was USD 12.1 million (2017:
USD 8.7million). Net OCF after changes in working capital movements
and income taxes was USD 5.2 million (2017: USD 9.6 million). The
reduction is mainly a function of a USD 4.4 million year-on-year
increase in cash taxes paid (largely related to SPT) and an
increase in trade receivables totalling USD 6.7 million. The
increase in trade receivables was due to delayed revenue receipts
of USD 6.7 million as a result of the Petrotrin restructuring (see
details below). Post the year end, USD 4.1 million of the
outstanding receivables from Petrotrin have been collected and full
collection of the remaining USD 2.6 million is expected to occur by
the end of H1 2019. Stripping out the increase in receivables, the
like for like OCF after changes in working capital would have been
USD 11.8 million versus USD 9.6 million for 2017.
-- Strong net cash plus working capital surplus: The lower OCF
after changes in working capital combined with higher capital
expenditure of USD 12.5 million (2017: USD 3.1 million) and the
repayment of all outstanding debts to T&T state creditors and
CLN holders (USD 5.8 million and USD 7.2 million respectively)
pushed down cash balances at year end. Cash balances at the
year-end stood at USD 10.2 million (2017: USD 11.8 million).
Nevertheless, Trinity had a strong net cash plus working capital
surplus of USD 18.1 million (versus USD 0.1 million in 2017).
Crucially, the Company is now debt free, with no dilutive CLN
overhang, and has the financial flexibility to grow by the most
effective means.
-- Mitigating downside price risk: In 2018, a USD 1.0 million
loss was incurred on the crude oil derivative instrument and
recorded within Other Expenses which protected against downside oil
prices below USD 45.0/ bbl utilising a Zero Cost Collar. For 2018
the WTI price ranged from USD 62.3/bbl to USD 70.7/bbl between
January and October 2018. The WTI price traded in a range of USD
59.8/bbl to USD 56.7/bbl in November and USD 49.1/bbl for December
2018, hence no settlements were incurred in those months. This
hedge expired on 31 December 2018 and so no hedge valuations are
included for the year end financials.
STATEMENT OF COMPREHENSIVE INCOME ANALYSIS
Revenues
2018 crude oil sales revenues were USD 62.6 million (2017: USD
45.2 million). This 38% increase was attributable to a 14% increase
in production volumes to 2,871 bopd (2017: 2,519 bopd) and a 23%
increase in the average realised oil price to USD 59.8/bbl (2017:
USD 48.6/bbl).
Operating expenses
Operating expenses increased by 24% in 2018 to USD (55.9)
million (2017: USD (41.2) million). Operating expenses
comprised:
-- Royalties of USD 20.4 million (2017: USD 13.8 million) have
increased due to a combination of increased sales volume and
price.
-- Production costs of USD (17.8) million (2017: USD (14.7)
million) have increased due to more workovers, production
optimisation and vessel and equipment costs complimenting the
increased activity levels.
-- G&A expense of USD (6.0) million (2017: USD (4.3)
million), increased mainly due to non-cash share option expense of
USD (0.7) million (2017: USD (0.3) million) and unrealised foreign
exchange gain USD 0.0 million (2017: USD 0.5 million)
-- Depreciation, depletion and amortisation ("DD&A") of USD
(10.7) million (2017: USD (7.0) million).
-- Other Expenses of USD (1.0) million (2017: (1.4) million)
includes the impact of derivative hedge instruments in relation to
the Zero Cost Collar in effect during 2018 USD (1.0) million (2017:
USD (0.8) million) and Put Options nil (2017: USD (0.6)
million).
Supplemental Petroleum Tax and Property Tax
SPT and PT were USD (6.5) million (2017: USD (2.0) million) and
comprised:
-- SPT of USD (7.1) million (2017: USD (1.5) million) due to
realised oil prices being above USD 50.01/bbl.
-- PT credit of USD 0.6 million (2017: USD (0.5) million) which
included the current year charge of USD (0.4) million and the
reversal of the 2016 and 2017 accrual of USD 1.1 million.
Exceptional items
Exceptional items were USD (2.3) million (2017: USD 25.7 million
credit) and comprised:
-- Impairment of plant property, equipment, receivables,
recompletions and inventory USD (2.6) million (2017: USD (0.6)
million).
-- Reversal of bad debt USD 0.2 million credit (2017: nil) for
recovered VAT refunds in relation to 2013 previously written
off.
-- Restructuring USD (0.0) million (2017: USD 26.3 million credit).
-- Unsecured creditors compromised USD 0.1 million credit (2017:
nil) relating to write off of remaining creditor balances
compromised.
See Note 6 to Consolidated Financial Statements - Exceptional
items for further details. The Group's operating loss after
exceptional items was USD (2.0) million (2017: USD 27.6 million
profit).
Net Finance Costs
In 2018, finance costs amounted to USD (2.1) million (2018: USD
(2.3) million) and comprised:
-- Unwinding of the decommissioning liability USD (1.6) million (2017: USD (1.6) million).
-- Interest accrued on the CLNs USD (0.5) million (2017: (0.7) million).
See Note 7 to Consolidated Financial Statements - Finance Costs
for further details.
Income Tax Expense
Taxation charge for 2018 of USD (1.3) million (2017: USD 0.03
million credit), and its components are described below.
-- Increase in Deferred Tax Asset ("DTA") for the year with tax
losses recognised of USD 1.8 million credit (2017: USD (1.3)
million).
-- Increase in Deferred Tax Liabilities ("DTL") for the year
resulting from accelerated tax depreciation USD (3.1) million
(2017: credit of USD 0.4 million).
-- Unemployment levy ("UL") USD (0.0) million (2017: USD 0.03 million credit).
See Note 8 to Consolidated Financial Statements - Taxation
(expense)/credit for further details.
CONSOLIDATED STATEMENT OF CASH FLOWS ANALYSIS
Cash inflow from operating activities
Operating Cash Flow ("OCF") was USD 12.1 million (2017: USD 8.7
million):
-- Loss before income tax of USD (4.1) million (2017: USD 25.3
million profit) included non-cash items amounting to USD 16.2
million (2017: USD (16.7) million).
-- Changes in working capital of USD (6.8) million (2017: USD
0.9 million inflow), primarily as a result of the increased level
of trade receivables at the year end.
-- Current income taxation paid USD (0.1) million outflow (2017: nil).
Cash outflow relating to the restructuring
Cash outflow relating to full and final repayment of T&T
State Creditors amounted to USD (5.8) million (2017: USD (12.6)
million).
Cash outflow from investing activities
Cash outflow from investing activities was USD (12.5) million
(2017: USD (3.1) million):
-- Expenditure on Property, Plant and Equipment for the year was
USD (12.3) million (2017: USD (2.8) million) which mainly included
8 Onshore development wells, 17 recompletions and infrastructure
upgrades.
-- Expenditure on exploration and evaluation assets USD (0.2 million) (2017: nil).
-- Expenditure on new software USD (0.0) million (2017: USD (0.3) million).
Cash inflow from financing activities
Cash inflow from financing activities was USD 11.5 million
(2017: USD 10.3 million):
-- Issue of shares (net of costs and conversion of CLN) USD 12.4
million (2017: 10.8 million).
-- Repayment of CLN USD (0.9) million (2017: nil.).
-- Issue of CLN (net of costs) nil (2017: USD 3.0 million).
-- Settlement of the compromised Citibank loan nil (2017: USD (3.5) million).
See Note 23 to the Consolidated Financial Statements -
Convertible loan notes for further details and see Note 19 to the
Consolidated Financial Statements - Issue of shares for further
details.
CASH PLUS WORKING CAPITAL SURPLUS
Statement of Financial Position FY 2018 FY 2017 FY 2017
Extract
USD MM USD MM USD MM
Unaudited Audited(1) Unaudited(2)
Mgmt. View
A: Current Assets
Cash and cash equivalents 10.2 11.8 11.8
Trade and other receivables 13.3 5.2 5.2
Inventories 3.7 3.8 3.8
Total Current Assets 27.2 20.8 20.8
====================== ================== ====================
B: Liabilities
Non-current(3)
Trade and other payables - 0.9 1.0
CLN - 3.0 7.0
Total Non-Current Liabilities - 3.9 8.0
Current(4)
Trade and other payables 9.1 10.1 10.2
Taxation payable - 1.7 1.7
Derivative Financial Instrument - 0.8 0.8
Total Current Liabilities 9.1 12.6 12.7
Total Liabilities 9.1 16.5 20.7
====================== ================== ====================
(A-B): Cash plus working capital
surplus 18.1 4.3 0.1
Notes:
1. States the amortised cost of the CLN and MEEI liabilities
as stated in the Financials (see Notes 2, 23 and 25 to the
financial statements)
2. States the Face Value of the CLN and MEEI liabilities as
opposed to amortised cost stated in the unaudited 2018 financials
and audited 2017 financials
3. Non-Current Liabilities excludes Deferred tax liability
& Provision for other liabilities
4. Current Liabilities excludes Provision for other
liabilities
Events since the Year End
1. On 2 January 2019 the Company issued awards under its
Long-Term Incentive Plan ("LTIP"). The Company awarded the grant of
Options over 2,824,000 ordinary shares (representing 0.735% of the
Company's issued share capital) under the LTIP.
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 1 January 2021. These
awards have been made in accordance with the policy announced to
the market on 25 August 2017 and have been made to certain
individuals in respect of the performance of the Group for the
financial year ended 31 December 2017.
2. On 15 January 2019, the Group announced that the effective
transition date to the new national oil company, Heritage, was 1
December 2018 and the restructuring process with Petrotrin was
ongoing. There have been some delays in the receipt of payments for
October and November crude oil revenues from Petrotrin with an
amount outstanding of USD 6.7 million at year end. The Group has to
date received USD 4.1 million of these delayed payments, with the
remaining USD 2.6 million which is outstanding expected to be
collected by the end of H1 2019.
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2018
(Expressed in United States Dollars)
Note 2018 2017
$'000 $'000
Operating Revenues
Crude oil sales 62,578 44,957
Other income 15 210
------------ ------------
62,593 45,167
Operating Expenses
Royalties (20,390) (13,755)
Production costs (17,754) (14,737)
Depreciation, Depletion & Amortisation
("DD&A") 11,12 (10,694) (7,055)
General & Administrative ("G&A") expenses (5,960) (4,326)
Other Expenses (1,075) (1,362)
------------ ------------
(55,873) (41,235)
------------ ------------
Operating Profit Before Supplemental Petroleum
Taxes ("SPT") and Property Taxes ("PT") 6,720 3,932
SPT (7,050) (1,533)
PT 607 (497)
------------ ------------
Operating Profit Before Exceptional Items 277 1,902
Exceptional Items 6 (2,312) 25,718
Operating (Loss)/Profit (2,035) 27,620
Net finance costs 7 (2,056) (2,300)
(Loss)/Profit Before Income Taxation (4,091) 25,320
Income Taxation (expense)/credit 8 (1,270) 28
------------ ------------
(Loss)/Profit for the year (5,361) 25,348
Other Comprehensive Income
Items that may be subsequently reclassified
to profit or loss
Currency translation 40 76
------------ ------------
Total Comprehensive (Loss)/ Income For
The Year (5,321) 25,424
============ ============
Earnings per share (expressed in dollars
per share)
Basic 9 (0.02) 0.09
Diluted 9 (0.02) 0.06
Company Statement of Financial Position
at 31 December 2018
(Expressed in United States Dollars)
Note 2018 2017
ASSETS $'000 $'000
Non-current Assets
Property, plant and equipment 11 53,599 52,450
Intangible assets 12 25,757 25,591
Abandonment fund 13 2,979 1,650
Performance bond 14 253 253
Deferred tax assets 15 5,973 4,179
88,561 84,123
---------- ----------
Current Assets
Inventories 16 3,738 3,766
Trade and other receivables 17 13,343 5,155
Cash and cash equivalents 18 10,201 11,792
---------- ----------
27,282 20,713
---------- ----------
Total Assets 115,843 104,836
========== ==========
Equity and liabilities
Capital and Reserves Attributable to Equity
Holders
Share capital 19 97,692 96,676
Share premium 19 139,879 125,362
Other equity -- 590
Share based payment reserve 20 13,290 12,553
Merger reserves 21 75,467 75,467
Reverse acquisition reserve 21 (89,268) (89,268)
Translation reserve (1,638) (1,678)
Accumulated losses (176,473) (171,112)
---------- ----------
Total Equity 58,949 48,590
---------- ----------
Non-current Liabilities
Trade and other payables 25 -- 881
Convertible Loan Notes ("CLN") 23 -- 3,019
Deferred tax liabilities 15 5,598 2,538
Provision for other liabilities 24 41,802 37,151
47,400 43,589
---------- ----------
Current Liabilities
Trade and other payables 25 9,147 10,092
Provision for other liabilities 24 347 115
Derivative financial instruments 27 -- 762
Taxation payable 28 -- 1,688
---------- ----------
9,494 12,657
---------- ----------
Total Liabilities 56,894 56,246
---------- ----------
Total Equity and Liabilities 115,843 104,836
========== ==========
Company Statement of Financial Position
at 31 December 2018
(Expressed in United States Dollars)
Note 2018 2017
ASSETS $'000 $'000
Non-current Assets
Investment in subsidiaries 10 58,489 51,416
========== ==========
Current Assets
Trade and other receivables 17 84 89
Intercompany 17 6,539 2,447
Cash and cash equivalents 18 4,056 6,024
---------- ----------
10,679 8,560
---------- ----------
Total Assets 69,168 59,976
========== ==========
Equity and liabilities
Capital and Reserves Attributable to Equity
Holders
Share capital 19 97,692 96,676
Share premium 19 139,879 125,362
Other equity -- 590
Share based payment reserve 2,590 1,853
Merger reserves 56,652 56,652
Accumulated losses (228,126) (225,459)
---------- ----------
Total Equity 68,687 55,674
---------- ----------
Non - Current Liabilities
CLN 23 -- 3,019
---------- ----------
Current Liabilities
Trade and other payables 25 481 521
Derivative financial instruments 27 -- 762
Intercompany 25 -- --
---------- ----------
481 1,283
---------- ----------
Total Liabilities 481 4,302
---------- ----------
Total Equity and Liabilities 69,168 59,976
========== ==========
Consolidated Statement of Changes in Equity
for the year ended 31 December 2018
(Expressed in United States Dollars)
Share Share Other Share Share Reverse Merger Translation Accumulated Total
Capital Premium Equity Warrants Based Acquisition Reserves Reserve Losses Equity
Payment Reserve
Reserve
Year ended 31 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
December
2017
At 1 January
2017 94,800 116,395 -- 71 12,244 (89,268) 75,467 (1,997) (196,460) 11,252
Other equity
net of
transaction
cost -- -- 590 -- -- -- -- -- -- 590
Issue of
shares 1,876 8,967 -- -- -- -- -- -- -- 10,843
Share based
payment
expense -- -- -- -- 309 -- -- -- -- 309
Share warrants
expired -- -- -- (71) -- -- -- -- -- (71)
Translation
difference -- -- -- -- -- -- -- 243 -- 243
Total
comprehensive
income for
the period -- -- -- -- -- -- -- 76 25,348 25,424
-------- --------- ------- --------- -------- ------------ --------- ------------ ------------ --------
At 31 December
2017 96,676 125,362 590 -- 12,553 (89,268) 75,467 (1,678) (171,112) 48,590
======== ========= ======= ========= ======== ============ ========= ============ ============ ========
Year ended 31
December
2018
At 1 January
2018 96,676 125,362 590 -- 12,553 (89,268) 75,467 (1,678) (171,112) 48,590
Issue of
shares 1,016 18,984 -- -- -- -- -- -- -- 20,000
Cost of
raising
equity -- (1,202) -- -- -- -- -- -- -- (1,202)
CLN - discount -- (3,265) -- -- -- -- -- -- -- (3,265)
CLN -
conversion -- -- (590) -- -- -- -- -- -- (590)
Share based
payment
expense (Note
20) -- -- -- -- 737 -- -- -- -- 737
Total
comprehensive
expense for
the year -- -- -- -- -- -- -- 40 (5,361) (5,321)
-------- --------- ------- --------- -------- ------------ --------- ------------ ------------ --------
At 31 December
2018 97,692 139,879 -- -- 13,290 (89,268) 75,467 (1,638) (176,473) 58,949
======== ========= ======= ========= ======== ============ ========= ============ ============ ========
Company Statement of Changes in Equity
for the year 31 December 2018
(Expressed in United States Dollars)
Share Capital Share Premium Other Share Based Merger Accumulated Total Equity
Equity Payment Reserves Losses
Reserve
$'000 $'000 $'000 $'000 $'000 $'000 $'000
Year ended 31
December
2017
At 1 January
2017 94,800 116,395 -- 1,544 56,652 (222,235) 47,156
Other equity
net of
transaction
costs -- -- 590 -- -- -- 590
Issue of
ordinary
shares 1,876 8,967 -- -- -- -- 10,843
Share based
payment
expense -- -- -- 309 -- -- 309
Total
comprehensive
expense
for the year -- -- -- -- -- (3,224) (3,224)
-------------- -------------- -------- ------------ --------------- ------------ -------------
At 31 December
2017 96,676 125,362 590 1,853 56,652 (225,459) 55,674
============== ============== ======== ============ =============== ============ =============
Year ended 31
December
2018
At 1 January
2018 96,676 125,362 590 1,853 56,652 (225,459) 55,674
Issue of
ordinary
shares 1,016 18,984 -- -- -- -- 20,000
Cost of raising
equity -- (1,202) -- -- -- -- (1,202)
CLN - discount -- (3,265) -- -- -- -- (3,265)
CLN -
conversion -- -- (590) -- -- -- (590)
Share based
payment
expense -- -- -- 737 -- -- 737
Total
comprehensive
expense
for the year -- -- -- -- -- (2,667) (2,667)
At 31 December
2018 97,692 139,879 -- 2,590 56,652 (228,126) 68,687
============== ============== ======== ============ =============== ============ =============
Consolidated Statement of Cash Flows
for the year ended 31 December 2018
(Expressed in United States Dollars)
Note 2018 2017
$'000 $'000
Operating Activities
(Loss)/Profit before taxation (4,091) 25,320
Adjustments for:
Translation difference 330 (663)
Finance cost - loans and interest 7 499 579
Share based payment expense 20 737 235
Finance cost - decommissioning provision 24 1,557 1,643
DD&A 11 10,694 7,055
Loss on disposal of assets 11 (6) --
Impairment of property, plant and equipment 11 2,561 --
Impairment of receivables -- 348
Impairment of inventory -- 264
Gain on extinguishment of financial liabilities -- (210)
Unsecured creditors' claims (192) --
Fair value zero cost collar -- 762
Compromised creditor balances -- (26,672)
12,089 8,661
---------------------- -------------------
Changes In Working Capital
Inventories 16 28 (243)
Trade and other receivables 17 (9,513) (887)
Trade and other payables 25 2,731 2,023
Income Taxation paid (128) --
---------------------- -------------------
Net Cash Inflow From Operating Activities 5,207 9,554
---------------------- -------------------
Restructuring related payments
Unsecured creditors -- (3,857)
T&T State creditors (BIR and MEEI) (5,835) (8,775)
---------------------- -------------------
(5,835) (12,632)
---------------------- -------------------
Investing Activities
Purchase of exploration and evaluation assets 12 (170) --
Purchase of computer software 12 (26) (250)
Purchase of property, plant and equipment 11 (12,264) (2,868)
Net Cash Outflow From Investing Activities (12,460) (3,118)
---------------------- -------------------
Financing Activities
Issue of shares (net of costs) 19 12,361 10,843
Repayment of CLN 23 (770) --
Finance Cost- CLN Interest 23 (94)
Issue of CLN (net of costs) 23 -- 3,030
Repayment of borrowings -- (3,500)
---------------------- -------------------
Net Cash Inflow From Financing Activities 11,497 10,373
---------------------- -------------------
(Decrease)/Increase in Cash and Cash Equivalents (1,591) 4,177
====================== ===================
Cash And Cash Equivalents
At beginning of year 11,792 7,615
(Decrease)/increase in cash and cash equivalents (1,591) 4,177
---------------------- -------------------
At end of year 18 10,201 11,792
====================== ===================
Company Statement of Cash Flows
for the year ended 31 December 2018
(Expressed in United States Dollars)
Note 2018 2017
$'000 $'000
Operating Activities
Loss before taxation (2,667) (3,161)
Adjustments for:
Translation differences 10 69
Finance income (215) (270)
Finance cost 418 579
Share based payment expense 123 91
Fair value zero cost collar -- 762
Compromised creditor balances -- 446
-------- ----------
(2,331) (1,484)
Changes In Working Capital
Trade and other receivables (4,088) 134
Trade and other payables (802) (553)
-------- ----------
(4,890) (419)
-------- ----------
Taxation Paid -- --
-------- ----------
Net Cash Outflow from Operating Activities (7,221) (1,903)
-------- ----------
Financing Activities
Finance income 215 270
Finance cost (94) (579)
Capital contributed to subsidiary 10 (6,459) (6,395)
Issue of shares (net of costs) 19 12,361 10,843
Issue of CLN (net of costs) 23 -- 3,030
Repayment of CLN (770) --
Net Cash Inflow from Financing Activities 5,253 7,169
-------- ----------
(Decrease)/Increase In Cash And Cash
Equivalents (1,968) 5,266
======== ==========
Cash And Cash Equivalents
At beginning of year 6,024 758
(Decrease)/Increase in cash and cash
equivalents (1,968) 5,266
At end of year 18 4,056 6,024
======== ==========
Trinity Exploration & Production Plc
Notes to the Consolidated Financial Statements
31 December 2018
(Expressed in United States Dollars)
1 Background and 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.
Background
Trinity Exploration & Production plc ("Trinity" or "the
Company") previously Bayfield Energy Holdings plc ("Bayfield") was
incorporated and registered in England and Wales on 21 February,
2011 and traded on the Alternative Investment Market ("AIM"), a
market operated by London Stock Exchange plc. On 14 February, 2013,
Bayfield was acquired by Trinity Exploration & Production (UK)
Limited ("TEPUKL"), a Company incorporated in Scotland, through a
reverse acquisition. Bayfield changed its name to Trinity
Exploration & Production plc and the enlarged group was
re-admitted to trading on AIM. Trinity and its subsidiaries
(together "the Group") are involved in the exploration, development
and production of oil reserves in Trinidad & Tobago
("T&T").
Basis of Preparation
This consolidated financial information has been prepared on a
going concern basis, in accordance with International Financial
Reporting Standards ("IFRS") as adopted by the European Union
("EU"), IFRS Interpretations Committee ("IFRS IC") interpretations
as adopted by the EU and those parts of the Companies Act 2006 as
applicable to companies reporting under IFRS. This consolidated
financial information has been prepared under the historical cost
convention, with the exception of certain financial assets,
financial liabilities (including derivative instruments and the
CLN) and classes of property, plant and equipment which are
measured at fair value.
The preparation of the consolidated financial information in
conformity with IFRS requires the use of certain critical
accounting estimates. It also requires 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 $2.7 million (2017: $3.2 million loss).
Going Concern
In making their going concern assessment, the Board of Directors
(the "Board") have considered the Group's budget and cash flow
forecasts. The Group's main objective in 2018 was to grow
production, through a fully funded onshore drilling programme and a
low cost work programme of Recompletions ("RCPs"), Workovers
("WOs"), reactivations and swabbing.
In July 2018, gross proceeds of $20.0 million were raised
through the Fundraising. The Fundraising allowed the Group to repay
all outstanding debt to its Board of Inland Revenue of T&T
("BIR") and Ministry of Energy and Energy Industries of T&T
("MEEI") (together the "T&T State Creditors"). Subsequent to
this repayment, on 15 August 2018 Trinity settled the remaining
balance of the redeemable CLN plus accrued interest. Through the
settlement of all outstanding debts, the Group improved on its
prior year net current asset position. At 31 December 2018, the
Group held net current assets of $17.8 million (2017: $8.1
million).
The Group meets its day-to-day working capital requirements
through revenue generation and positive operating cash flows. The
Group's forecast and projections, taking account of reasonable
possible changes in oil price and sales volume, show that the Group
will be able to operate within the level of its current cash
resources. Should there be a decline in the oil price, the Board
believe there are a number of actions within their control that can
be effected. These include deferral of capital expenditure and
further reducing operating costs to manageable levels. For these
reasons, the Board have a reasonable expectation that the Group has
adequate resources to continue operational existence for the
foreseeable future.
The Board has carefully considered and formed a reasonable
judgement that, at the time of approving these financial
statements, the Group and Company are in a stable position. The
Group is able to pay its debts as they fall due for a period of at
least 12 months post approval of the financial statements and is
poised for continued growth. For this reason, the Board continues
to adopt the going concern basis when preparing these financial
statements.
New and amended standards adopted by the Group:
The Group has applied the following standards and amendments for
the first time for annual reporting period commencing 1 January
2018:
IFRS 9 Financial Instruments The standard addresses the Periods beginning on / after 1
classification, measurement and January 2018
de-recognition of financial assets
and financial liabilities, introduces
new rules for hedge accounting and a
new impairment
model for financial assets. The Group
assessed the impact with the
introduction of the new
guidance on the classification and
measurement of these financial
assets. There is no material
impact in accounting for financial
liabilities that are designated at
fair value through profit
or loss.
====================================== ====================================== ======================================
IFRS 15 Revenue from Contracts with The new standard for revenue replaces Periods beginning on / after 1
Customers IAS 18 and IAS 11. IFRS 15 specifies January 2018
how and when an
IFRS reporter will recognise revenue
as well as requiring such entities to
provide users of
the financial statements with more
informative, relevant disclosures.
The Group reviewed its
sales contracts with customers and
determined that IFRS 15 did not have
a material impact
on its revenue recognition and,
accordingly, no material impact on
the Consolidated Financial
Statements. Trinity adopted this
standard using the modified
retrospective approach, whereby
the cumulative effect of initial
adoption of the standard is
recognised as an adjustment to
retained earnings. There was no
effect on the Group's retained
earnings or prior period amounts
as a result of adopting this
standard.
====================================== ====================================== ======================================
IFRS 2 The amendments to the classification Periods beginning on / after 1
Share-based payment IFRS and measurement of share-based January 2018
payment transactions.
The amendments affect three distinct
areas. 1) Classification of
share-based payments that
have a net settlement feature within
the framework of an equity-settled
plan. 2) Accounting
for modifications that change the
classification of payments from
cash-settled to equity-settled.
3) The effects of vesting/non-vesting
conditions on cash-settled
share-based payments.
====================================== ====================================== ======================================
New and amended standards not yet adopted by the Group:
Certain new accounting standards and interpretations have been
published that are not mandatory for 31 December 2018 reporting
periods and have not been early adopted by the Group. The Group's
assessment of the impact of these new standards and interpretations
is set out below.
IFRS 16 Leases This is a new accounting standard which will result in Periods beginning on / after 1 January 2019
almost all leases being recognised
on the balance sheet, as the distinction between
operating and finance leases is removed.
Under the new standard, an asset (the right to use the
leased item) and a financial liability
to pay rentals are recognised. The only exceptions are
short-term and low-value leases. The
accounting for lessors will not significantly change.
Management has assessed the estimated
impact of the adoption of IFRS 16 on existing leases
and have determined that in the first
year of adoption there would be a $0.5 million
reclassification of operating cost to depreciation
and interest. The impact to the balance sheet would be
the recognition of a right of use asset
of $0.5 million and a lease liability of $0.5 million.
The Group will apply the standard from
its mandatory adoption date of 1 January 2019. The
Group intends to apply the simplified transition
approach and will not restate comparative amounts for
the year prior to first adoption. Right-of-use
assets for property leases will be measured on
transition as if the new rules had always been
applied. All other right-of-use assets will be
measured at the amount of the lease liability
on adoption (adjusted for any prepaid or accrued lease
expenses).
Basis of consolidation
The consolidated financial information incorporates the
financial information of the Company and entities controlled by the
Company (its subsidiaries) 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. The
excess of the cost of acquisition over the fair value of the
Group's share of the identifiable net assets acquired is recorded
as goodwill. 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
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.
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 currency of the Group operating entities
is Trinidad & Tobago Dollars ("TTD") as this is the currency 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
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:
2018 2017
-------------------- --------------------
$ GBP $ GBP
Average rate TTD=
$/GBP 6.762 9.107 6.751 8.831
Closing rate TTD=
$/GBP 6.781 8.644 6.771 9.207
(b) Transactions and balances
Foreign currency transactions are translated into the functional
currency using the exchange rates at the dates of the transactions.
Foreign exchange gains and 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 profit or loss. 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.
Foreign exchange gains and losses that relate to borrowings are
presented in the statement of profit or loss, within finance costs.
All other foreign exchange gains and losses are presented in the
statement of profit or loss on a net basis within G&A
expenses.
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 profit or loss as
part of the fair value gain or loss and translation differences on
non-monetary assets such as equities classified as
available-for-sale financial assets are recognised in other
comprehensive income.
(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 balance sheet presented are
translated at the closing rate at the date of that balance
sheet
- income and expenses for each statement of profit or loss and
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 assets
i) Capitalisation
Exploration and Evaluation assets are initially classified as
intangible assets. Such costs include those directly associated
with an exploration area. Upon discovery of commercial reserves
capitalisation is recognised within Property, Plant and
Equipment.
Oil and natural gas exploration and evaluation 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 exploration and evaluation of assets
includes:
- Licence and property acquisition costs
Exploration and property leasehold acquisition costs are
capitalised within exploration and evaluation assets.
- Exploration and evaluation 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, exploration and
evaluation expenditures are written off as a dry hole when that
determination is made.
Once commercial reserves are found, exploration and evaluation
assets are tested for impairment and transferred to development
tangible and intangible assets as applicable. No depreciation
and/or amortisation are charged during the exploration and
evaluation phase.
ii) Impairment
Exploration and evaluation 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 exploration and evaluation assets' carrying
amount exceed their recoverable amount. The recoverable amount is
the higher of the exploration and evaluations assets' fair value
less costs of disposal and their Value In Use ("VIU"). For the
purposes of assessing impairment, the exploration and evaluation
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 exploration and
evaluation in the specific area is budgeted or planned.
- Whether exploration and evaluation 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.
- Whether sufficient data exists to indicate that, although a
development in the specific area is likely to proceed, the carrying
amount of the exploration and evaluation asset is unlikely to be
recovered in full from successful development or by sale.
(b) Goodwill
Goodwill is initially measured at cost, being the excess of the
aggregate of the consideration transferred and the amount
recognised for non-controlling interest over the net identifiable
assets acquired and liabilities assumed. If this consideration is
lower than the fair value of the net assets of the subsidiary
acquired, the difference is recognised in profit or loss.
After initial recognition, goodwill is measured at cost less any
accumulated impairment losses. For the purpose of impairment
testing, goodwill acquired in a business combination is, from the
acquisition date, allocated to each of the Company's
cash-generating units that are expected to benefit from the
combination, irrespective of whether other assets or liabilities of
the acquiree are assigned to those units.
(c) 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
useful life, based on pattern of benefits (straight-line is the
default).
Property, plant and equipment
(a) Oil and 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 exploration and evaluations subsequent to finding
commercially viable reserves, development drilling and new reserve
type, infrastructure costs and development Geological and
Geophysical ("G&G") costs. Acquisitions of oil and gas
properties are accounted for under the acquisition method where the
transaction meets the definition of a business combination.
Transactions involving the purchases of an individual field
interest, or a group of field interests, that do not meet the
definition of a business (therefore do not apply business
combination accounting) are treated as asset purchases,
irrespective of whether the specific transactions involve the
transfer of the field interests directly, or the transfer of an
incorporated entity. Accordingly, the consideration is allocated to
the assets and liabilities purchased on a relative fair value
basis.
Proceeds on disposal are applied to the carrying amount of the
specific asset or development and production assets disposed of.
Any excess is recorded as a gain on disposal in the statement of
comprehensive income and any shortfall between the proceeds and the
carrying amount is recorded as a loss on disposal in the 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, 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 fair
value less costs of disposal and the VIU. For the purposes of
assessing impairment, assets are grouped at the lowest levels (its
cash generating unit) for which there are separately identifiable
cash flows. The cash generating unit applied for impairment test
purposes is generally the field. These fields are the same as that
used for reserves reporting purposes.
iii) Producing Assets - Depreciation, Depletion & Amortisation("DD&A")
The provision for DD&A of developed and producing oil and
gas assets are calculated using the unit-of-production method. Oil
and 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 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 and 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 statement of
comprehensive income.
Repairs and maintenance are charged to the 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 have an indefinite useful
life, for example, goodwill, are not subject to amortisation and
are tested for impairment. 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 fair value less
costs of disposal and value in use. For the purposes of assessing
impairment, assets are grouped at the lowest levels for which there
are separately identifiable cash flows (cash generating units).
Non-financial assets other than goodwill 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,
recompletions and workovers are stated at lower of cost and net
realisable value. Cost is determined using the average cost
method.
Cash and cash equivalents
For the purpose of presentation in the 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, and bank
overdrafts. Bank overdrafts are shown within borrowings in current
liabilities in the balance sheet.
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 30 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 expected loss rates
using a provision matrix that is based on the Group's historical
default rates observed over the expected life of the receivable and
adjusted forward-looking estimates. This is then applied to the
gross carrying amount of the receivable to arrive at the loss
allowance for the period.
Trade payables
Trade payables are recognised initially at fair value and
subsequently measured at amortised cost using the effective
interest method.
Impairment of financial assets
Financial assets recognition of impairment provisions under IFRS
9 is based on the expected credit losses ("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 for forward looking estimates. This is then applied to
the gross carrying amount of the receivables to arrive at the loss
allowance for the period.
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 deferred tax assets and liabilities 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, deferred tax
liabilities 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.
The deferred tax liability in relation to investment property
that is measured at fair value is determined assuming the property
will be recovered entirely through sale.
Deferred tax assets are recognised only if it is probable that
future taxable amounts will be available to utilise those temporary
differences and losses.
Deferred tax liabilities and assets 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.
Deferred tax assets and liabilities 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 Taxes ("PT")
PT are recognised initially at fair value and subsequently
measured at amortised cost using the effective interest method.
Assessments are 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 rate applicable to the
Group are industrial with building rates at 6% and industrial
without building 3%.
Revenue recognition
IFRS 15 Revenue from Contracts with Customers replaces IAS 18
and IAS 11 with effect from accounting periods commencing 1 January
2018. The new standard requires that revenue is recognised by
performance obligation, as or when each performance obligation is
satisfied, and that variable elements of pricing are recognised, to
the extent that is it not highly probable they will be
reversed.
The Group has evaluated its customer contract with the Petroleum
Company of Trinidad & Tobago Limited ("Petrotrin") and, from 1
December 2018, Heritage Petroleum Company Limited ("Heritage") to
identify performance obligations, timing of revenue recognition and
treatment of variable elements of pricing. Sales revenue represents
the sales value of the Group's oil sold in the year.
Oil revenue is recognised when title of the crude has passed to
the buyer by means of a sales ticket document. 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 determined by Petrotrin/Heritage, with agreed
contractual adjustments based on oil 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.
Borrowings
Borrowings are recognised initially at fair value net of
transaction costs incurred. Borrowings are subsequently stated at
amortised cost; any differences between proceeds (net of
transaction costs) and the redemption value is recognised in the
statement of comprehensive income over the period of the borrowings
using the effective interest method.
Borrowings are classified as current liabilities unless the
Group has an unconditional right to defer settlement of the
liability for at least 12 months after the statement of financial
position date.
General and specific borrowing costs directly attributable to
the acquisition, construction or production of qualifying assets,
which are assets that necessarily take a substantial period of time
to get ready for their intended use or sale, are added to the cost
of those assets, until such time as the assets are substantially
ready for their intended use or sale.
All other borrowing costs are recognised in comprehensive income
in the period in which they are incurred.
Compound Financial Instruments
Compound financial instruments issued by the Group comprised the
CLN that could, in certain circumstances, have been converted to
share capital at the option of the holder, and the number of shares
to be issued did not vary with changes in their fair value. The
liability component of a compound financial instrument is
recognised initially at the fair value of a similar liability that
does not have an equity conversion option. The equity component is
recognised initially as the difference between the fair value of
the compound financial instrument as a whole and the fair value of
the liability component. Any directly attributable transaction
costs are allocated to the liability and equity components in
proportion to their initial carrying amounts. Subsequent to initial
recognition, the liability component of a compound financial
instrument is measured at amortised cost using the effective
interest rate method. The equity component of a compound financial
instrument is not re-measured subsequent to initial recognition
except on conversion or expiry.
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
Leases in which a significant portion of the risks and rewards
of ownership are retained by the lessor are classified as operating
leases. Payments made under operating leases (net of any incentives
received from the lessor) are charged to the income statement on a
straight-line basis over the period of the Lease.
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.
Derivatives 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 derivatives are measured at fair
value through profit and loss.
Financial assets at fair value through profit or loss are
financial assets held for trading. A financial asset is 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 12 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 balance sheet only
when it is extinguished - that is, when the obligation specified in
the contract is discharged or cancelled - or expires.
Operating segment information
The steering committee is the Group's chief operating
decision-maker. Management has determined the operating segments
which are Onshore, West Coast and East Coast reported in a manner
consistent with the internal reporting provided to the chief
operating decision maker. The chief operating decision maker is
responsible for making strategic decisions inclusive of; allocating
resources and assessing performance of the operating segments. The
chief operating decision maker has been identified as the steering
committee of Management which comprises; the Executive Chairman,
Country Manager, Chief Operations Officer and Chief Financial
Officer, that makes strategic decisions in accordance with Board
policy.
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 financial
statements where it is necessary to do so to provide further
understanding of the financial performance of the Group. They are
material items of income or expense that have been shown separately
due to the non-recurring nature and the significance of their
nature or amount.
2 Financial Risk Management
Financial risk factors
The Group's activities expose it to a variety of financial
risks. The Group's overall risk management program seeks to
minimise potential adverse effects on the Group's financial
performance.
Risk management is carried out by management. Management
identifies and evaluates financial risks.
(a) Market risk
(i) Foreign exchange risk
The Group is exposed to foreign exchange risk primarily with
respect to the United States dollar. Foreign exchange 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.
At 31 December 2018, if the functional currency of the main
operating subsidiary had weakened/ strengthened by 10% against the
US dollar with all other variables held constant, post-tax
profit/(loss) for the year would have been $2.9 million (2017: $2.1
million) lower/higher, mainly as a result of foreign exchange
gain/losses on translation of US dollar-denominated borrowings and
sales.
(ii) Price risk
The Group is exposed to commodity price risk regarding its sales
of crude oil which is an internationally traded commodity.
At 31 December 2018, if commodity prices had been 20%
higher/lower with all other variables held constant, post-tax
profit/(loss) for the year would have been $12.5 million (2017:
$8.7 million) lower/higher. The sensitivity doesn't take into
consideration the impact of the derivative instruments in place
over commodity prices.
(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
maintain a balance between floating and fixed contract rates.
At 31 December 2018, there were no loan commitments to attract
interest rates on foreign currency-denominated borrowings, (2017:
nil).
(b) Credit risk
Credit risk arises from cash and cash equivalents, deposits with
banks and financial institutions, as well as credit exposures to
customers, including outstanding receivables. For banks and
financial institutions, management determines the placement of
funds based on its judgement and experience to minimise risk.
All sales are made to a state-owned entity -
Petrotrin/Heritage.
The Group applies the IFRS 9 simplified model for measuring ECL
which uses a lifetime expected loss allowance and are measured on
the days past due criterion. Having reviewed past payments combined
with the credit profile of its existing trade debtors in order to
assess the potential for impairment, the Company has concluded that
this is insignificant as there has been no history of default or
disputes arising on invoiced amounts since inception and as such
the credit loss percentage is assumed to be almost zero. No
provision for doubtful accounts against these sales has been
recorded as at 31 December 2018 and 31 December 2017.
(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 $10.2 million (2017: $11.8
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 tables below analyses the Group'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 amounts disclosed in the table are the contractual
undiscounted cash flows. Balances due within 12 months equal their
carrying balances as the impact of discounting is not
significant.
Less than Between Between Total Contractual Carrying
1 year 1-2 years 2-5 years Cash flows amount
At 31 December 2018 $'000 $'000 $'000 $'000 $'000
Non-derivatives
Trade and other payables 9,147 -- -- 9,147 9,147
Total Non-derivatives 9,147 -- -- 9,147 9,147
---------- ----------- ----------- ------------------ ---------
At 31 December 2017 $'000 $'000 $'000 $'000 $'000
Non-derivatives
Trade and other payables 10,092 881 -- 10,973 10,973
CLN
(including interest) -- 7,547 3,290 10,837 3,019
Total Non-derivatives 10,092 8,428 3,290 21,810 13,992
---------- ----------- ----------- ------------------ ---------
Derivatives
Trading derivatives 762 -- -- 762 762
(d) Capital risk management
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 debt divided by total capital. Net cash/ (debt) is
calculated as total borrowings less cash and cash equivalents.
Total capital is calculated as 'equity' as shown in the
consolidated statement of financial position plus net cash/
(debt).
2018 2017
$'000 $'000
--------- ----------
CLN and borrowings* -- 3,019
Less: cash and cash equivalents (10,201) (11,792)
--------- ----------
Net cash (10,201) (8,773)
Total equity 58,949 48,590
--------- ----------
Total capital 48,748 39,817
Gearing ratio (21.0)% (22.0)%
Note (*): 2017 relates to the fair value of the CLN at 31
December 2017. The face value of the CLN's principal plus interest
was $7.0 million at 31 December, 2017. In August 2018, the CLN was
fully settled.
(e) Fair value estimation
The table below analyses financial instruments carried at fair
value, by valuation method.
The different levels have been defined as follows:
-- Quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1).
-- Inputs other than quoted prices included within level 1 that
are observable for the asset or liability, either directly (that
is, as prices) or indirectly (that is, derived from prices) (Level
2).
-- Inputs for the asset or liability that are not based on
observable market data (that is, unobservable inputs) (Level
3).
Fair value measurements using significant unobservable inputs
(Level 3)
Zero cost
collar
$'000
1 January 2018 762
Purchased --
Payment (1,837)
Expense 1,075
31 December 2018 --
==========
3 Critical Accounting Estimates and Assumptions
The preparation of the 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
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) Income taxes
Some judgement is required in determining the provision for
income taxes. There are certain transactions and calculations for
which the ultimate tax determination is uncertain. Management
recognised liabilities for anticipated tax audit issues based on
estimates of whether additional taxes will be due. Where the final
tax outcome of these matters is different from the amounts that
were initially recorded, such differences will impact the income
tax and deferred tax provisions in the period in which such
determination is made.
(b) Recoverability of deferred tax assets
Deferred tax assets 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 deferred tax assets 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 and is
therefore inherently uncertain. To the extent assumptions regarding
future profitability change, there can be an increase or decrease
in the level of deferred tax assets recognised which can result in
a charge or credit in which the change occurs. The Group has
concluded that the deferred tax asset recognised will be
recoverable using approved business plans and budgets for the
specific subsidiaries in which the deferred tax asset arose.
(c) Provision for decommissioning costs
This provision is significantly affected by changes in
technology, laws and regulations which may affect the actual cost
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 specific risk free rates for each asset ranging
between 2.69%-2.90% (2017: 3.09%-4.65%) and a core inflation rate
at 2% (2017: 3%), See Note 24: Provision for other liabilities. The
impact in 2018 of a 1% change in these variables is as follows:
Statement of Statement of
Financial Position Comprehensive
Obligation Income/Expense
2018 2018
$'000 $'000
-------------------- --------------------
(Decrease)/Increase Increase/(Decrease)
Discount rate
1% increase in assumed rate (6,639) 95
1% decrease in assumed rate 8,083 (168)
Inflation rate
1% increase in assumed rate 8,070 291
1% decrease in assumed rate (6,749) (243)
(d) 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 2018 the Group estimated its own commercial reserves
based on 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.
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 exploration and evaluation assets, oil
and gas properties, property, plant and equipment, and goodwill may
be affected due to changes in estimated future cash flows.
- Depreciation and amortisation charges in profit or loss may
change where such charges are determined using the unit of
production method, or where the useful life of the related assets
change.
- 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.
- The recognition and carrying value of deferred tax assets may
change due to changes in the judgements regarding the existence of
such assets and in estimates of the likely recovery of such
assets.
As at 31 December 2018 all subsidiaries onshore and offshore
proved and probable ("2P") reserve estimates were re-evaluated by
management and approved by the Board.
(e) Share-based payments
Management is required to make assumptions in respect of the
inputs used to calculate the fair values of share-based payment
arrangements which include expected volatility, risk free interest
rate and current share price.
(f) Impairment of property, plant and equipment
Management performs impairment assessments on the Group's
property, plant and equipment once there are indicators of
impairment with reference to IAS 36: Impairment of Assets and in
accordance with the accounting policy stated in Note 1: Background
and Accounting policies. In order to test for impairment, the
higher of fair value less costs of disposal and values in use
calculations are prepared which require arm's length offers 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 2018 an impairment charge of $2.6 million was recognised
on the Group's property, plant and equipment (2017: no impairment)
see Note 11: Property, Plant & Equipment. The impairment charge
resulted in the carrying amount of the respective CGUs being
written down to their recoverable amount.
(g) Oil and Gas Assets $2.6 million (2017: nil) impairment
As part of this assessment, management has carried out an
impairment test on the oil and 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 Fair Value less
Costs of Disposal ("FVLCOD") and Value In Use ("VIU"). The FVLCOD
is the amount that a market participant would pay for the CGU less
the cost of disposal utilising a discounted cash flow approach to
FVLCOD. The FVLCOD 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.
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 discounted cash flow approach assessment involves judgement
as to the likely commerciality of the asset; its 2P reserves which
are estimated using standard recognised evaluation techniques on a
fully funded basis; future revenues and estimated development costs
pertaining to the CGU's; and a discount rate utilised for the
purposes of deriving a recoverable value.
2019 2020 2021 2022 2023 2024
Realised
price 43.6 45.4 46.4 47.2 47.9 48.5
------------- ------------- ------------- ------------- ------------- -------------
If the price deck used in the impairment calculation had been
10% lower than management's estimates at 31 December 2018, the
group would have $3.4 million increase on impairment of Oil and Gas
assets (2017: nil). If the price deck used in the impairment
calculation had been 10% higher than management's estimates at 31
December 2018, the group would $0.2 million decrease on impairment
of the Oil and Gas assets (2017: nil).
For the year ended 31 December 2018, management's estimate of
the Group's cost of capital was 13% (2017:10%). If the estimated
cost of capital in determining the post-tax discount rate for the
CGU's had been 1% lower than management's estimates the Group would
have $0.6 million decrease on impairment position for 2018 (2017:
nil) against Oil and Gas assets within property, plant and
equipment. If the estimated cost of capital had been 1% higher than
management's estimates the Group would have $0.6 million increase
on impairment for 2018 (2017: nil).
(h) Impairment of intangible exploration and evaluation assets
In 2018 a review for impairment triggers was carried out and
there were no further impairment losses realised against the
carrying values of the Group's Exploration and Evaluation
assets.
The Group reviews the carrying values of intangible exploration
and evaluation assets when there are impairment indicators which
would tell whether an exploration and evaluation asset has suffered
any impairment, in accordance with the accounting policy stated in
Note 1: Background. The amounts of intangible exploration and
evaluation assets represent the costs of active projects the
commerciality of which is unevaluated until reserves can be
appraised.
4 Segment Information
Management have considered the requirements of IFRS 8, in regard
to the determination of operating segments, and concluded that the
Group has only one significant operating segment being the
production, development and exploration and extraction of
hydrocarbons.
All revenue is generated from sales to one customer,
Petrotrin/Heritage. All non-current assets of the Group are located
in T&T.
5 Operating Profit Before Exceptional Items
2018 2017
$'000 $'000
------- -------
Operating profit before exceptional
items is stated after taking the following
items into account:
DD&A (Note 11) 10,664 7,055
Amortisation of computer software
(Note 12) 30 --
Employee costs (Note 31) 7,972 7,478
Operating lease rentals 568 675
Inventory recognised as expense, charged
to operating expenses 175 67
------- -------
Auditors' remuneration
During the year the Group (including its overseas subsidiaries)
obtained the following services from the Company's Auditors as
detailed below:
2018 2017
$'000 $'000
------- -------
* Fees payable to the Company's auditors' and their
associates for the audit of the parent Company and
consolidated financial statements:
* PricewaterhouseCoopers LLP (UK based) 153 119
* PricewaterhouseCoopers Limited (T&T based) 95 112
* Fees payable to the Company's auditors' and their
associates for other services:
- The audit of Company's subsidiaries 18 19
- Audit related assurance services - interim
review 35 30
Total assurance 301 280
- Tax advisory 3 --
- Other advisory 12 54
------- -------
Total auditors' remuneration 316 334
All fees are in respect of services provided by
PricewaterhouseCoopers LLP. 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.
6 Exceptional Items
Items that are material either because of their size or 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 as exceptional expenses below operating
profit in the Income Statement. An analysis of the amounts
presented as exceptional items in these financial statements are
highlighted below.
2018 2017
Exceptional items: $'000 $'000
Reversal of bad debt written off (205) --
Secured creditor compromise -- (6,472)
Unsecured creditor compromise (70) (15,639)
Interest on tax compromise -- (5,247)
Foreign exchange loss on compromised balance -- 687
Impairment of property, plant and equipment (Note 11) 2,561 --
Impairment of receivables -- 234
Impairment of recompletions -- 135
Impairment of inventory -- 264
Fees relating to corporate restructuring 26 532
Gain on extinguishment of liability -- (210)
Translation difference -- (2)
------------------------------ -------------------
Exceptional charge/(credit) 2,312 (25,718)
============================== ===================
Exceptional items 2018:
Reversal of Bad debt - $0.2 million gain recovered in UK Value
Added Tax ("VAT") relating to 2013 previously written off in
2017
Unsecured creditor compromise - $0.1 million gain under the
creditor settlements arising from compromised balances with
suppliers
Impairment on Property, Plant and Equipment - $2.6 million
charge resulting from impairment losses in Onshore and West Coast
assets
Fees relating to corporate restructuring - $0.0 million charge
in relation to trustee fees incurred in 2018 in wrapping up the
state creditor process
Exceptional items 2017:
Secured creditor compromise - $6.5 million gain under the senior
debt settlement agreement where the unpaid balance was
compromised
Unsecured creditor compromise - $15.6 million gain under the
creditor settlements arising from compromised balances with
suppliers
Interest on tax compromise - $5.2 million gain under the
creditor settlement where interest outstanding was waived with the
BIR
Foreign exchange loss on compromised balances - $0.7 million
charge under the creditor settlements arising from compromised
balances with suppliers
Impairment on receivables - $0.2 million charge resulting from
impairment of deal cost UK VAT recoverable from 2013
Impairment of recompletions - $0.1 million charge resulting from
impairment of recompletions
Impairment of inventory - $0.3 million charge resulting from
impairment of inventory
Gain on extinguishment of liability - $0.2 million gain as a
result of accounting for the liability due to the MEEI at fair
value
Fees relating to corporate restructuring - $0.5 million in fees
relating to the corporate restructuring of the Group include the
Formal Sales Process ("FSP"), the Proposal process, the cost of
advisors, as well as field restructuring
7 Net Finance Costs
2018 2017
$'000 $'000
------ ------
Decommissioning - Unwinding of discount (Note 24) 1,557 1,643
Interest on loans 499 657
2,056 2,300
====== ======
8 Income tax (expense)/ credit
2018 2017
$'000 $'000
Current tax
Petroleum profits tax 5 (926)
Unemployment levy -- (26)
Deferred tax
- Current year
Movement in asset due to tax losses (Note
15) (1,794) 1,317
Movement in liability due to accelerated
tax depreciation (Note 15) 3,059 (389)
Translation difference -- (4)
Income tax expense/ (credit) 1,270 (28)
======== ======
The Group's effective tax rate varies from the statutory rate
for UK companies of 19.0% (2017:19.25%) as a result of the
differences shown below:
2018 2017
$'000 $'000
-------- --------
(Loss)/Profit before taxation (4,091) 25,320
Tax (credit)/charge at expected rate of
19% (2017: 19.25%) (777) 4,874
Effects of:
Higher overseas tax rate 28 10,722
Disallowable expenses 1,917 (8,635)
Allowable expenses (9,549) (8,960)
Tax losses recognised for deferred tax 3,363 --
assets
Tax losses utilised to recognise deferred
tax assets 10,860 7,630
Deferred tax asset previously recognised (4,197) (5,496)
Green fund and business levy 230 149
Other differences (605) (312)
-------- --------
Income tax expense/ (credit) 1,270 (28)
======== ========
Taxation losses at 31 December 2018 available for set off
against future taxable profits amounts to approximately $244.1
million (2017: $226.1 million).Tax losses of $10.9 million were
recognised as deferred tax assets in 2018 (2017:$7.6 million).
These losses do not have an expiry date and have not yet been
confirmed by the BIR and HMRC.
9 Earnings Per Share
Basic earnings per share is calculated by dividing the earnings
attributable to ordinary shareholders by the weighted average
number of ordinary shares outstanding during the year. Diluted
earnings per share is calculated using the weighted average number
of ordinary shares adjusted to assume the conversion of all
potentially dilutive ordinary shares.
(Loss)/ Earnings Weighted Average Earnings
$'000 Number Of Shares Per Share
'000' $
Year ended 31 December
2018
Basic (5,321) 330,579 (0.02)
Diluted (5,321) 330,579 (0.02)
------------------------------ ----------------------- ------------------------ -----------------
Year ended 31 December 2017
Basic 25,424 276,746 0.09
Diluted 25,424 395,054 0.06
----------------------------------- --------------- -------------- -----------
Impact of dilutive ordinary shares:
There was no impact on the weighted average number of shares
outstanding during 2018 as all share options and LTIP's were
excluded from the weighted average dilutive share calculation
because their effect would be anti-dilutive and therefore both
basic and diluted earnings per share are the same in 2018.
In 2017, diluted earnings per share is calculated by adjusting
the weighted average number of ordinary shares outstanding to
assume conversion of all potentially dilutive ordinary shares. The
Company had two categories of dilutive ordinary shares: CLNs and
share based payments. The CLNs issued in 2017 were considered to be
potential ordinary shares and had been included in the
determination of diluted earnings per share for 2017. This is
calculated as the CLN nominal value of $6.55 million plus accrued
interest after the second anniversary of $1.0 million divided by
the conversion price of $0.08125. Long term incentives of
24,415,998 were considered potential ordinary shares and were
included in the determination of the diluted earnings per share for
2017. Share options of 1,975,084 were considered potential ordinary
shares but were not included as the exercise hurdle would not have
been met.
10 Investment In Subsidiaries
Company
2018 2017
$'000 $'000
-------------------- ------
Opening balance 51,416 44,802
Capital contributed
to subsidiary 6,459 6,395
Share based payment 614 219
Closing balance 58,489 51,416
==================== ======
The investment in subsidiaries is recognised initially at the
fair value of the consideration paid. The Group subsequently
measures the investment in subsidiaries at cost less impairments.
Increases in the investment in subsidiaries relate to capital
contributed by the Company to its subsidiary undertakings.
Listing of Subsidiaries
The Group's principal subsidiaries at 31 December 2018 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, England, 99.99998
Bayfield Energy Limited LS1 5AB, United Kingdom Holding Company %
------------------------------ ----------------- -----------
Trinity Exploration 13 Queen's Road, Aberdeen,
& Production (UK) Limited AB15 4YL, United Kingdom Holding Company 100 %
------------------------------ ----------------- -----------
Trinity Exploration c/o Pinsent Masons LLP,
and Production Services 1 Park Row, Leeds, England,
(UK) Limited LS1 5AB, United Kingdom 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 %
------------------------------ ----------------- -----------
Galeota Oilfield Services
Limited Trinidad address Oil and Gas 100 %
------------------------------ ----------------- -----------
Trinity Exploration
and Production (Galeota)
Limited Trinidad address Oil and Gas 100 %
------------------------------ ----------------- -----------
Oilbelt Services Limited Trinidad address Oil and Gas 100 %
------------------------------ ----------------- -----------
Ligo Ven Resources
Limited Trinidad address Oil and Gas 100 %
------------------------------ ----------------- -----------
Trinity Exploration
and Production Services
Limited Trinidad address Service Company 100 %
------------------------------ ----------------- -----------
Tabaquite Exploration
& Production Company
Limited Trinidad address Oil and Gas 100 %
------------------------------ ----------------- -----------
Trinity Exploration
and Production (GOP)
Limited Trinidad address Oil and Gas 100 %
------------------------------ ----------------- -----------
Trinity Exploration
and Production (GOP-1B)
Limited Trinidad address Oil and Gas 100
------------------------------ ----------------- -----------
11. Property, Plant and Equipment
Plant & Leasehold Oil &
Equipment & Buildings Gas Assets Other Total
Year ended 31 December 2018 $'000 $'000 $'000 $'000 $'000
----------- ------------- ------------ ------- -----------
Opening net book amount at
1 January 2018 3,767 1,726 46,957 -- 52,450
Disposal -- (6) -- -- (6)
Additions 483 135 11,646 -- 12,264
Adjustment to decommissioning
estimate (Note 24) -- -- 2,076 -- 2,076
Impairment(1) -- -- (2,561) -- (2,561)
Reclassification of assets
between categories (2,470) -- 2,470 --
DD&A charge for year (818) (150) (9,696) -- (10,664)
Translation difference -- -- 40 -- 40
----------- ------------- ------------ ------- -----------
Closing net book amount at
31 December 2018 962 1,705 50,932 -- 53,599
=========== ============= ============ ======= ===========
At 31 December 2018
Cost 13,391 3,245 286,172 336 303,144
Accumulated DD&A and impairment (12,429) (1,540) (235,280) (336) (249,585)
Translation difference -- -- 40 -- 40
----------- ------------- ------------ ------- -----------
Closing net book amount 962 1,705 50,932 -- 53,599
=========== ============= ============ ======= ===========
Plant & Leasehold Oil &
Equipment & Buildings Gas Assets Other Total
Year ended 31 December 2017 $'000 $'000 $'000 $'000 $'000
Opening net book amount at
1 January 2017 4,201 1,890 53,541 -- 59,632
Disposal -- (9) -- -- (9)
Additions 42 2 2,824 -- 2,868
Adjustment to decommissioning
estimate (Note 24) -- -- (2,868) -- (2,868)
DD&A charge for year (483) (147) (6,425) -- (7,055)
Translation difference 7 (10) (115) -- (118)
----------- ------------- ------------ ------- -----------
Closing net book amount at
31 December 2017 3,767 1,726 46,957 -- 52,450
=========== ============= ============ ======= ===========
At 31 December 2017
Cost 12,901 3,126 272,565 336 288,928
Accumulated DD&A and impairment (9,141) (1,390) (225,493) (336) (236,360)
Translation difference 7 (10) (115) -- (118)
----------- ------------- ------------ ------- -----------
Closing net book amount 3,767 1,726 46,957 -- 52,450
=========== ============= ============ ======= ===========
1 An impairment loss of $2.6 million was recognised on Oil and
Gas Assets (see Note 3 g (i)) 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.
12. Intangible Assets
The carrying amounts and changes in the year are as follows:
Computer Exploration Total $'000
Software and evaluation
$'000 assets
$'000
At 1 January 2018 250 25,341 25,591
Computer software 26 -- 26
Exploration and evaluation
assets -- 170 170
Amortisation (30) -- (30)
---------------- ---------------------- ------------
At 31 December 2018 246 25,511 25,757
================ ====================== ============
At 1 January 2017 -- 25,406 25,406
Computer software 250 -- 250
Translation difference -- (65) (65)
At 31 December 2017 250 25,341 25,591
================ ====================== ============
-- Computer Software: In 2018, capital cost incurred for accounting software
-- Exploration and evaluation assets: Includes the TGAL-1
exploration well and associated cost. The Group tests whether
exploration and evaluation assets has suffered any impairment
triggers on an annual basis and there were no impairment triggers
(2017: nil)
13 Abandonment Fund
2018 2017
$'000 $'000
At 1 January 1,650 1,072
Additions 1,329 578
At 31 December 2,979 1,650
====== ======
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.
14 Performance Bond
2018 2017
$'000 $'000
At 1 January 253 --
Additions -- 253
At 31 December 253 253
====== ======
A performance bond was put in place on 3 July 2017 of $ 0.3
million at 1.75% rate per annum in favour of Petrotrin/Heritage,
executed with First Citizens Bank Limited (T&T based bank) and
is effective until 31 December 2020. These funds have been
restricted to a Fixed Deposit for 36 months at the agreed interest
rate of 1.25%. The performance bond is a requirement under the
Lease Operatorship Agreement ("LOAs") as Trinity is the Operator of
the FZ2, WD2, WD 5/6, WD 13 and WD 14 fields.
15 Deferred Income Taxation
Group
The analysis of deferred tax assets is as follows:
2018 2017
$'000 $'000
-------- --------
Deferred tax assets:
-Deferred tax assets to be recovered in more
than 12 months (5,238) (4,179)
-Deferred tax assets to be recovered in less (735) --
than 12 months
Deferred tax liabilities:
-Deferred tax liabilities to be settled in
more than 12 months 5,598 2,538
Net deferred tax assets (375) (1,641)
======== ========
The movement on the deferred income tax is as follows:
2018 2017
$'000 $'000
-------- --------
At beginning of year (1,641) (2,569)
Movement for the year 1,334 986
Unwinding of deferred tax on fair value uplift (68) (58)
Net deferred tax asset (375) (1,641)
======== ========
The deferred tax balances are analysed below:
2016 Movement 2017 Movement 2018
$'000 $'000 $'000 $'000 $'000
---------- --------- ---------- ---------- ----------
Deferred tax assets
Acquisition (33,436) -- (33,436) -- (33,436)
Tax losses recognised (34,293) -- (34,293) (1,794) (36,087)
Tax losses derecognised 62,233 1,317 63,550 -- 63,550
---------- --------- ---------- ---------- ----------
(5,496) 1,317 (4,179) (1,794) (5,973)
========== ========= ========== ========== ==========
2016 Movement 2017 Movement 2018
Deferred tax liabilities $'000 $'000 $'000 $'000 $'000
Accelerated tax depreciation 14,374 (331) 14,043 3,128 17,171
Non-current asset
impairment (33,214) -- (33,214) -- (33,214)
Acquisitions 19,580 -- 19,580 -- 19,580
Fair value uplift 2,187 (58) 2,129 (68) 2,061
--------- --------- --------- --------- ---------
2,927 (389) 2,538 3,059 5,598
========= ========= ========= ========= =========
- Deferred tax assets are recognised for tax loss carry-forwards
to the extent that the realisation of the related tax benefit
through future taxable profits are probable. Deferred tax assets of
$1.8 million has been recognised for the year (2017: $1.3 million
was de-recognised) based on future taxable profits. The Group has
unrecognised deferred tax assets amounting to $117.7 million which
have no expiry date.
- Deferred tax liabilities have increased by $3.1 million as the
carrying values of property, plant and equipment and intangible
assets was higher than the tax written down values.
- Deferred tax assets and deferred tax liabilities can only be
offset in the 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).
16 Inventories
Crude oil Materials Total
and supplies
$'000 $'000 $'000
At 1 January 2018 130 3,636 3,766
Net inventory movement (41) 13 (28)
At 31 December 2018 89 3,649 3,738
========== ======================= ======
At 1 January 2017 120 3,667 3,787
Inventory movement 10 233 243
Impairment -- (264) (264)
---------- ----------------------- ------
At 31 December 2017 130 3,636 3,766
========== ======================= ======
(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.
(ii) Amounts recognised in profit or loss
Inventories recognised as an expense during the year ended 31
December 2018 amounted to $0.2 million (2017: $0.1 million); these
were included in production costs.
At the end of 2018 there were no impairments (2017: $0.3 million
impairment loss).
17 Trade and Other Receivables
Group Company
---------------- -----------------
2018 2017 2018 2017
$'000 $'000 $'000 $'000
Due after more than one year
Amounts due from Group companies
(Note 26 (d)) -- -- -- --
------- ------- -------- -------
Due within one year
Amounts due from related parties
(Note 26 (d)) -- -- 6,539 2,447
Trade receivables 10,408 3,272 -- --
Less: provision for impairment of
trade receivables -- -- -- --
------- ------- -------- -------
Trade receivables - net 10,408 3,272 6,539 2,447
Prepayments 846 631 50 58
VAT recoverable 1,610 807 34 31
Other receivables 479 445 --
13,343 5,155 6,623 2,536
======= ======= ======== =======
The fair value of trade and other receivables approximate their
carrying amounts.
The Group applies the IFRS 9 simplified model for measuring ECL
which uses a lifetime expected loss allowance and are measured on
the days past due criterion. Amounts due from related parties are
repayable on demand and entities have the ability to repay if
called immediately.
Having reviewed past payment performance combined with the
credit rating of Petrotin/Heritage in order to assess the potential
for impairment, the Group has concluded this to be insignificant as
there has been no history of default or disputes arising on
invoiced amounts in the past 5 years and as such the credit loss %
is assumed to be almost zero.
Trade receivables that are less than six months past due are not
considered impaired and at 31 December 2018, trade receivables of
$10.4 million (2017: $3.3 million) were considered to be fully
performing. There was a delay in collecting trade receivables for
October and November amounting to $6.7 million due to the
restructuring of the Group's sole customer Petrotrin/ Heritage.
However, subsequent to the year-end $4.1 million of these have been
collected to date and Management remain confident that the
remaining balance of $2.6 million will be collected during H1
2019.
At the end of 2017 there was an impairment of $0.3 million
relating to UK VAT on invoices that were no longer recoverable.
Ageing analysis of these trade receivables as at 31 December is
as follows:
2018 2017
$'000 $'000
Up to 30 days 7,616 3,272
30 - 60 days 2,792 --
----------------- ------------
10,408 3,272
================= ============
The carrying amount of the Group's trade and other receivables
are denominated in the following currencies:
Group Company
---------------- ----------------
2018 2017 2018 2017
$'000 $'000 $'000 $'000
------- ------- ------- -------
USD 7,918 2,631 6,547 2,464
GBP 62 60 76 72
TTD 5,363 2,464 -- --
------- ------- ------- -------
13,343 5,155 6,623 2,536
======= ======= ======= =======
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
--------------- --------------
2018 2017 2018 2017
$'000 $'000 $'000 $'000
------- ------ ------ ------
Trade receivables
Counterparties without external
credit rating:
Existing customers with no defaults
in the past 10,408 3,272 -- --
======= ====== ====== ======
All trade receivables are with the Group's only customer,
Petrotrin/Heritage.
18 Cash and Cash Equivalents
Group Company
2018 2017 2018 2017
$'000 $'000 $'000 $'000
------- ------- ------ ------
Cash and cash equivalents 10,201 11,792 4,056 6,024
10,201 11,792 4,056 6,024
======= ======= ====== ======
Cash and cash equivalents disclosed above and in the statement
of cash flows exclude restricted cash and are available for general
use by the Group. At the end of the year the cash balance was
impacted due to the restructuring of the Group's sole customer
Petrotrin/Heritage where $6.7 million in trade receivables relating
to October and November were not received within the expected
payment terms. .These are included within the Group's trade
receivables (see Note 17: Trade and other receivables). Subsequent
to the year-end $4.1 million of these trade receivables have been
collected to date and Management remain confident that the
outstanding $2.6 million will be collected during H1 2019.
19 Share Capital and Share Premium
Number of Ordinary Share premium Total
shares shares $'000 $'000
No. $'000
------------ --------- -------------- --------
As at 1 January 2018 282,399,986 96,676 125,362 222,038
Issue of shares 101,649,260 1,016 14,517 15,533
As at 31 December 2018 384,049,246 97,692 139,879 237,571
============ ========= ============== ========
As at 1 January 2017 94,799,986 94,800 116,395 211,195
Share Capital Reorganisation
("SCR") 187,600,000 1,876 8,967 10,843
As at 31 December 2017 282,399,986 96,676 125,362 222,038
============ ========= ============== ========
In July, 2018 the Company raised gross proceeds of $20.0 million
pursuant to the Fundraising comprising of $13.6 million proceeds of
shares issuance and $6.4 million from conversion of CLNs (Note 23-
Convertible loan notes). Details of the fundraising as follows:
- Certain existing and new institutional investors in the
Company participated in the Placing of 56,370,645 new ordinary
shares;
- Directors and senior management subscribed for 2,398,185 new
ordinary shares;;
- 88% of CLN holders elected to convert their redeemable CLNs
into 32,715,504 new ordinary shares; and
- Other qualifying participants had the opportunity to subscribe
for 10,164,926 new ordinary shares
Originally the CLN was recorded at its fair value which was
significantly lower than its face value. Upon conversion and
settlement of the CLN holders, this $3.3 million discount was
credited to share premium.
Ordinary Deferred Share
No. of Shares Shares Shares Premium Total
Year ended 31 December
2018 $'000 $'000 $'000 $'000
At 1 January 2018 282,399,986 2,824 93,852 125,362 222,038
New ordinary shares
issued 0.01 101,649,260 1,016 -- -- 1,016
Ordinary share premium 0.19 -- -- -- 18,984 18,984
CLN discount -- -- -- (3,265) (3,265)
Cost of raising equity -- -- -- (1,202) (1,202)
----------------------------- --------- --------- -------------------- --------
At 31 December 2018 384,049,246 3,840 93,852 139,879 237,571
============================= ========= ========= ==================== ========
Note: $:GBP rate 1.312:1
Year ended 31 December
2017 $'000 $'000 $'000 $'000
At 1 January 2017 1.00 94,799,986 94,800 -- 116,395 211,195
SCR 1.00 (94,799,986) (94,800) -- -- (94,800)
New ordinary shares
following the SCR 0.01 94,799,986 948 -- -- 948
Deferred ordinary shares
following SCR 0.99 -- -- 93,852 -- 93,852
New ordinary shares
issued 0.01 187,600,000 1,876 -- -- 1,876
Ordinary share premium 0.05 -- -- -- 9,849 9,849
Cost of raising equity -- -- -- (882) (882)
------------- --------- ------- -------- ---------
At 31 December 2017 282,399,986 2,824 93,852 125,362 222,038
============= ========= ======= ======== =========
Note: $:GBP rate 1.255:1
20 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 shares issued to employees
- The grant date fair value of deferred shares granted to
employees but not yet vested
- The issue of shares held by the Employee Share Trust to
employees.
During 2018 the Group had in place share-based payment
arrangements for its employees and Executive Directors, the Share
Option Plan and the LTIP. The charge in relation to these
arrangements is shown below, with further details of each scheme
following:
2018 2017
$'000 $'000
At 1 January 12,553 12,244
Share based payment expense:
LTIP 737 309
------------- -------------
At 31 December 13,290 12,553
============= =============
Share Option Plan
Share options are granted to Executive Directors and to selected
employees. The exercise price of the granted option is 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.
At 31 December 2018, the Group had two employee share option
plans which were fully vested.
Share Options outstanding at the end of the year have the
following expiry date and exercise prices:
2018 2017
Grant-Vest Expiry Exercise price Number Exercise Number of
Date per share of Options price per Options
options share options
2012-2015 2022 GBP0.86 1,685,540 GBP0.86 1,685,540
2013-2016 2023 GBP1.20 289,544 GBP1.20 289,544
1,975,084 1,975,084
============= ===========
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 1.19 GBP 1.20
Average Exercise price GBP 1.20 GBP 0.89
Expected volatility 55% 78%
Risk-free rates 4.5% 4.5%
Expected dividend yields 0% 0%
Vesting period 3 years 3 years
Long Term Incentive Plan ("LTIP")
LTIP awards are designed to provide long-term incentives for
Senior Managers and Executive Directors to deliver long-term
shareholder returns. Under the plan, participants are granted
options which only vest if certain performance standards are met.
Participation in the plan is at the Board's discretion and no
individual has a contractual right to participate in the plan or to
receive any guaranteed benefits.
LTIP awards were granted in August 2017 over 25,415,998 ordinary
shares ("2017 LTIP Award"). The 2017 LTIP Awards will normally vest
on 30 June 2022, although they may vest in full or in part on 30
June 2020 or 2021 subject to meeting performance targets relating
to:
-- In respect of 70% of the award, the Company's share price
growth from the 2017 placing price of 4.98 pence per share. If the
3 month volume-weighted price ("VWAP") at the testing date is 35
pence or more per share, this part of the award will vest in full.
If the VWAP at the testing date is 4.98 pence per share or less,
this part of the award will not vest at all. If the VWAP at the
testing date is between 4.98 pence and 35 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 on or before 30 September 2019, in accordance with the
terms of the Creditors Proposal approved in 2017. The final payment
occurred following completion of the Fundraising in 2018; and
-- In respect of 10% of the award, redemption of all the CLNs
issued in January 2017 before the second anniversary of their
issue. All of the CLNs were redeemed as part of the Fundraising in
2018.
All remaining awards under the LTIP (which were granted in 2013)
lapsed during 2017 as the performance targets were not
satisfied.
Movements in the number of LTIPs outstanding and their related
weighted average exercise prices are as follows:
2018 Average Number of 2017 Average Number of Options
exercise Options exercise price
price per per share option
share option
At 1 January GBP 0.00 25,415,998 GBP 0.00 189,600
Lapsed -- GBP 0.00 (189,600)
Granted during
the year -- GBP 0.00 25,415,998
At 31 December GBP 0.00 25,415,998 GBP 0.00 25,415,998
=============== =========== ================== ==================
LTIPs outstanding at the end of the year have the following
expiry date and exercise prices:
Exercise
Grant-Vest Expiry date price 2018 2017
2017-2022 2022 GBP 0.00 25,415,998 25,415,998
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, the LTIP
Award may vest in full or in part on 30 June 2020 or 2021 with the
appropriate charge being taken at that time. 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:
Grant Date 24 August
2017
Share price at grant date GBp10.75
Exercise price GBP0.00
Expected volatility 73.3%
Risk-free interest rates 0.44%
Expected dividend yields 0%
Vesting period 1 30 June 2020
Vesting period 2 30 June 2021
Vesting period 3 30 June 2022
21 Merger and Reverse Acquisition Reserves
Reverse Acquisition Merger Reserve Total
Reserve
$'000 $'000 $'000
-------------------- --------------- ---------
At 1 January 2018 (89,268) 75,467 (13,801)
Movement -- -- --
Translation differences -- -- --
-------------------- --------------- ---------
At 31 December 2018 (89,268) 75,467 (13,801)
==================== =============== =========
At 1 January 2017 (89,268) 75,467 (13,801)
Movement -- -- --
Translation differences -- -- --
-------------------- --------------- ---------
At 31 December 2017 (89,268) 75,467 (13,801)
==================== =============== =========
The issue of shares by the Company as part of the reverse
acquisition 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.
The insertion of the Company as the new parent to the Group has
been accounted for using business combination accounting as
described in Note 1: Background and Accounting policies. The
reverse acquisition difference recorded in the consolidated
financial statements represents the difference in accounting for
reverse acquisition transactions.
22 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 and PT for the period, adjusted for DD&A, share
option expenses and Other Expenses (derivative hedge
instruments).
The Group presents Adjusted EBITDA as it is used in assessing
the Group's growth and operational efficiencies as it illustrates
the underlying performance of the Group's business by excluding
items not considered by management to reflect the underlying
operations of the Group.
Adjusted EBITDA is calculated as follows:
2018 2017
$'000 $'000
-------- --------
Operating Profit Before SPT
and PT 6,720 3,932
DD&A 10,694 7,055
Share option expenses 737 235
Loss on oil derivative hedge instruments 1,075 1,362
Adjusted EBITDA 19,226 12,584
'000 '000
-------- --------
Weighted average ordinary shares outstanding
- basic 330,579 276,746
Weighted average ordinary shares outstanding
- diluted 355,995 395,054
$ $
Adjusted EBITDA per share - basic 0.058 0.045
Adjusted EBITDA per share - diluted 0.054 0.032
Adjusted EBITDA after the impact of SPT and PT is calculated as
follows:
2018 2017
$'000 $'000
-------- --------
Adjusted EBITDA 19,226 12,584
SPT (7,050) (1,533)
PT 607 (497)
Adjusted EBITDA After SPT and PT 12,783 10,554
'000 '000
-------- --------
Weighted average ordinary shares outstanding
- basic 330,579 276,746
Weighted average ordinary shares outstanding
- diluted 355,995 395,054
$ $
Adjusted EBITDA After SPT and PT per
share - basic 0.039 0.038
Adjusted EBITDA After SPT and PT per
share - diluted 0.036 0.027
23 Convertible Loan Notes ("CLN")
On 11 January 2017 the Company issued at a 50% discount
6,550,000 one dollar, unsecured CLNs. The notes mature 7 years from
the issue date at their nominal value of $6.55 million plus
quarterly accrued, aggregated and compounded interest. Repayments
or conversion prior to the maturity date can be made in certain
circumstances:
-- Early Redemption
Subject to the settlement of the debts owed to the BIR and the
MEEI the Company before the second anniversary of the CLN's issue
date, redeem all or a portion of the CLN giving 5 business days'
written notice to the Noteholder. The Noteholders do not have the
option to convert under this arrangement.
-- Redemption
The Company can, after satisfying the debts owed to the BIR and
the MEEI or after two years from the issue dates (whichever is the
latter), elect to redeem all the CLN before the maturity date. The
redemption date in this scenario must not be less than 20 days from
the Early Redemption Notice. The Noteholders can serve a Conversion
Notice.
-- Conversion
Each Noteholder can after the second anniversary of the issue
date serve a Conversion Notice. The principal amount plus the
outstanding interest shall be converted into new fully paid
ordinary shares at a Conversion Price of $0.08125.
On 12 July 2018, $6.4 million in relation to the holders of CLNs
opted to convert the value of their CLNs inclusive of accrued
interest in ordinary shares and on 15 August 2018 the remaining
holders of the CLNs who did not elect to convert their CLNs
pursuant to the subscription were repaid in cash, which amounted to
$0.9 million.
Total
Year ended 31 December 2018 $'000
Opening amount as at 1 January 2018 3,019
Effective interest 118
Interest accrued(2) 300
Equity component 590
Share premium (difference in fair
value on CLN) 3,265
Settlement of CLN via conversion
to ordinary shares (6,437)
Settlement of CLN in Cash (864)
Translation difference 9
Closing balance at 31 December 2018 --
Year ended 31 December 2017
Opening amount as at 1 January 2017 --
Nominal value of CLN issued(1) 6,550
Issued at a 50% discount (3,275)
Fair value of CLN 3,275
Expenses incurred (245)
Fair value of CLN (net of costs) 3,030
Equity component (590)
Liability component at initial recognition 2,440
Effective interest 105
Interest accrued(2) 474
Closing balance at 31 December 2017 3,019
Notes:
(1) The amount repayable on the CLN is the nominal value of $6.6
million plus accrued interest.
(2) Interest is calculated by applying the effective interest
rate of 23.7 % to the liability component.
In 2017 the CLN was initially recognised and measured at its
fair value of $3.3 million. The fair value of the liability
component was determined using a market interest rate of 22.4% for
an equivalent non-convertible bond at the issue date. The liability
is subsequently recognised on an amortised cost basis until
extinguished on conversion or maturity of the notes. The remainder
of the proceeds are allocated to the conversion option and
recognised in shareholders' equity net of transaction cost, and not
subsequently re-measured.
24 Provision for Other Liabilities
(a) Non-current: Decommissioning Employee Retirement Total
cost Benefit
$'000 $'000 $'000
Year ended 31 December 2018
Opening amount as at 1 January
2018 37,151 -- 37,151
Unwinding of discount (Note
7) 1,557 -- 1,557
Increase in provisions for
new wells 1,164 -- 1,164
Revision to estimates 867 -- 867
Decommissioning contribution 1,074 -- 1,074
Translation differences (11) -- (11)
Closing balance at 31 December
2018 41,802 -- 41,802
Year ended 31 December 2017
Opening amount as at 1 January
2017 37,970 348 38,318
Unwinding of discount (Note
7) 1,643 -- 1,643
Restructuring provision settled -- (348) (348)
Revision to estimates (2,868) -- (2,868)
Decommissioning contribution 497 -- 497
Translation differences (91) -- (91)
Closing balance at 31 December
2017 37,151 -- 37,151
Decommissioning cost
The Group operates Oil fields and this cost represents an
estimate of the amounts required for abandonment of the Group's
wells, platforms, gathering station and pipeline infrastructures.
The amounts are calculated based on the provisions of existing
contractual agreements with Petrotrin/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% (2017: 3%)
b. Risk free rate - 2.69% - 2.90% (2017: 3.09% - 4.65% )
c. Estimated market value/decommissioning cost
d. Estimated life of each asset
See Note 3(c): Critical Accounting Estimates and Assumptions for
the rates used and sensitivity analysis.
Employee Retirement benefit
In 2017 the employee retirement benefit provision was
extinguished under the restructuring process.
(b) Current:
Litigation Closure Total
claims of Pits
$'000 $'000 $'000
Year ended 31 December 2018
Opening amount as at 1 January
2018 115 -- 115
Increase in provision -- 232 232
Closing balance at 31 December
2018 115 232 347
Year ended 31 December 2017
Opening amount as at 1 January
2017 470 -- 470
Decrease in provision (355) ---- (355)
Closing balance at 31 December
2017 115 -- 115
Litigation claims
In 2017 the Litigation claims were written down to the
compromised amount.
Closure of Pits
In 2018 there was an increase in the provision of $0.2 million
relating to the remedy and closure of pits associated with drilling
new onshore wells
25 Trade and Other Payables
Group Company
---------------- ----------------
(a) Non- Current: 2018 2017 2018 2017
$'000 $'000 $'000 $'000
------- ------- ------- -------
Due to BIR Interest on taxes(1) -- 417 -- --
Due to MEEI(2) -- 231 -- --
Other Payables -- 233 -- --
-- 881 -- --
======= ======= ======= =======
(b) Current: 2018 2017 2018 2017
$'000 $'000 $'000 $'000
------- ------- ------- -------
Trade payables 3,076 555 58 67
Accruals 3,454 2,547 423 454
VAT payable -- 272 -- --
Other payables 701 701 -- --
SPT and PT 1,916 2,626 -- --
Due to BIR Interest on taxes and -- 2,865
SPT(1) -- --
Due to MEEI(2) -- 526 -- --
9,147 10,092 481 521
======= ======= ======= =======
Notes:
1. The amounts due to the BIR under the settlement agreement was fully repaid in 2018.
2. The amounts due to the MEEI under the settlement agreement was fully repaid in 2018
26 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. The following are the major
transactions and balances with related parties:
(a) Sales of services and loans issued
to subsidiaries Group Company
2018 2017 2018 2017
$'000 $'000 $'000 $'000
Group subsidiaries:
Trinity Exploration and Production Services
(UK) Limited -- -- 3,176 347
Trinity Exploration and Production (UK) -- -- 14 --
Limited
Trinity Exploration and Production (Galeota)
Limited -- -- 13 (498)
Bayfield Energy Limited -- -- 14 --
Oilbelt Services Limited -- -- 1,197 --
Trinity Exploration and Production (Trinidad
and Tobago) Limited -- -- (501) 910
Trinity Exploration and Production Services
Limited -- -- 179 (168)
-- -- 4,092 591
Related party sales transactions and loans issued to
subsidiaries are exchanged at arm's length and are comparable to
terms that would be available to third parties.
(b) Purchases of services
Group Company
2018 2017 2018 2017
$'000 $'000 $'000 $'000
--------
Related party:
Trinity Exploration and Production Services
(UK) Limited -- -- -- (335)
-- -- -- (335)
=====================================================
(c) Key Management and Directors' compensation
Key Management includes Directors (Executive &
Non-Executive) and the Country Manager. The compensation paid or
payable to Key Management for employee services is shown below:
Group
2018 2017
$'000 $'000
-------
Salaries and short-term employee benefits 1,108 993
Post-employment benefits 33 53
Share-based payment expense (Note 20) 737 309
-------
1,878 1,355
(d) Year-end balances arising from sales/purchases of
services
Group Company
2018 2017 2018 2017
$'000 $'000 $'000 $'000
-------
Receivables from related parties:
Trinity Exploration and Production Services
Limited -- -- 867 688
Trinity Exploration and Production (UK)
Limited -- -- 14 --
Trinity Exploration and Production (Galeota)
Limited -- -- 13 --
Bayfield Energy Limited -- -- 14 --
Oilbelt Services Limited -- -- 1,197 --
Trinity Exploration and Production (Trinidad)
Limited -- -- 408 909
Trinity Exploration and Production Services
(UK) Limited -- -- 4,026 850
-- -- 6,539 2,447
Payables to related parties:
Trinity Exploration and Production Services
Limited -- -- -- --
Trinity Exploration and Production Services
(UK) Limited -- -- -- --
-- -- -- --
Group and Company
The receivables from related parties arise mainly from sales.
The receivables are unsecured and bear no interest. No provisions
are held against receivables from related parties (2017: nil).
The payables to related parties arise mainly from purchase
transactions and are due two months after the date of purchase. The
payables bear no interest.
27 Derivative financial instruments
31 December 31 December
2018 2017
$'000 $'000
Zero cost collar -- 762
-- 762
28 Taxation Payable
Group Company
2018 2017 2018 2017
$'000 $'000 $'000 $'000
------
Taxation payable
PPT/ UL -- 66 -- --
Due to BIR (PPT, CT and UL)(1) -- 1,622 -- --
-- 1,688 -- --
Notes:
(1.) 2018 nil balance. 2017: Due to the BIR under the settlement
agreement is PPT; CT and UL taxes of $1.6 million
29 Financial Instruments by Category
At 31 December 2018 and 2017, the Group held the following
financial assets at amortised cost:
Group Company
2018 2017 2018 2017
$'000 $'000 $'000 $'000
------- ------
Trade and other receivables - current 13,343 5,155 6,623 2,536
Abandonment fund - non current 2,979 1,650 -- --
Cash and cash equivalents 10,201 11,792 4,056 6,024
26,523 18,597 10,679 8,560
======= ======
At 31 December 2018 and 2017, the Group held the following
financial liabilities at amortised cost:
Group Company
2018 2017 2018 2017
$'000 $'000 $'000 $'000
------ ------
Accounts payable and accruals 9,147 10,092 481 521
Convertible Loan Note -- 3,019 -- 3,019
------ ------
9,147 13,111 481 3,540
At 31 December 2018 and 2017, the Group held the following
financial liabilities at fair value:
Group Company
2018 2017 2018 2017
$'000 $'000 $'000 $'000
Derivative financial instrument -- 762 -- 762
-- 762 -- 762
========================================= ======
30 Commitments and Contingencies
a) Commitments
There are commitments for decommissioning costs of the wells and
facilities under the Group's agreements with Petrotrin/ Heritage,
which have been provided for as described in Note 24: Provision for
other liabilities.
The Group leases vehicles, offices and copiers under cancellable
operating lease agreements. The lease terms are between 1 and 5
years, and the majority of lease agreements are renewable at the
end of the lease period. The lease expenditure charged to the
income statement during the year is as follows:
Group
2018 2017
$'000 $'000
Not later than 1 year 139 534
Later than 1 year and no later than 5 years 21 34
160 568
b) Contingent Liabilities
i) The farm-out agreement for the Tabaquite Block (held by
Coastline International Inc.) has expired. There may be additional
liabilities arising when a new agreement is finalised, but these
cannot be presently quantified until a new agreement is
available.
ii) Parent company guarantee. A Letter of Guarantee has been
established over the Point Ligoure, Guapo Bay & Brighton
("PGB") Block where a subsidiary of Trinity is obliged to carry out
a Minimum Work Programme to the value of $8.4 million. The
guarantee shall be reduced at the end of each twelve month period
upon presentation of all technical data and results of the Minimum
Work Programme performed.
iii) The Group is party to various claims and actions.
Management have 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 financial statements.
iv) On 3 June 2017 a performance bond was established by the
Group's Lease Operatorship Assets ("LOA"). A performance bond in
the form of a cash deposit of $0.3 million in the name of the
beneficiary Petrotrin/ Heritage was established for due and
punctual observance of the matters under the LOA effective until 31
December 2020.
31 Employee Costs
Employee costs for the Group during the year 2018 2017
$'000 $'000
Wages and salaries 6,602 6,778
Other pension costs 633 391
Share based payment expense (Note 20) 737 309
7,972 7,478
Average monthly number of people (including 2018 2017
Executive and Non-Executive Directors') employed number number
by the Group
Executive and Non-Executive Directors 6 5
Administrative staff 76 64
Operational staff 120 122
202 191
32 Events after the Reporting Year
1. On 2 January 2019 the Company issued awards under its LTIP
("2019 LTIP award"). The Company awarded the grant of Options over
2,824,000 ordinary shares (representing 0.735% of the Company's
issued share capital) under the 2019 LTIP award. 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 1 January 2021. These awards have been made in
accordance with the policy announced to the market on 25 August
2017 and have been made to certain individuals in respect of the
performance of the Group as at the end of the financial year ended
31 December 2017.
2. On 15 January 2019, the Group announced that the effective
transition date to the new national oil company, Heritage was 1
December 2018 and the restructuring process with Petrotrin to date
is ongoing. There have been some delays in the timing of payments
for October and November crude oil revenues from Petrotrin with an
amount outstanding of $6.7 million at year end. The Group has
received $4.1 million of these delayed payments to date, with the
remaining $2.6 million which is outstanding expected to be
collected during H1 2019.
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
END
FR EAXLFEAENEFF
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