TIDMTRIN
RNS Number : 5848N
Trinity Exploration & Production
10 May 2018
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 preliminary results for the 12 months
ended 31 December 2017. Disciplined focus over the period resulted
in a substantial increase in operating earnings and the continued
strengthening of the balance sheet.
Key Performance Indicators
FY 2017 FY 2016 Change (%)
Average realised oil price(1) (USD/bbl) 48.6 39.4 23
Average net production (bopd) 2,519 2,542 (1)
Operating earnings(2) (USD MM) 11.0 6.2 77
Operating earnings(3) (USD/bbl) 12.0 6.7 77
Operating margin(4) (%) 24.3 17.6 39
Consolidated operating break-even(5) (USD/bbl) 30.9 29.3 6
Cash balance (USD MM) 11.8 7.6 55
Net cash/ (debt) (USD MM)(6) 0.1 (38.6) 100
1. Realised price: Actual price received for crude oil sales per
bbl. A discount is normally applied to the West Texas Intermediate
("WTI") price by the Petroleum Company of Trinidad and Tobago
("Petrotrin") to derive the realised price received by Trinity
2. Operating earnings (USD MM): Revenues less Royalties less
Production Costs ("Opex") less General and & Administrative
Expenses ("G&A") less Other Expenses (Crude oil
derivatives)
3. Operating earnings (USD/bbl): Operating earnings/ Annual
production
4. Operating margin (%): Operating earnings/ Revenues
5. Consolidated operating break-even: The realised price where
Operating Earnings for the entire Group is equal to zero
6. Net cash/ (debt): Current assets less Convertible Loan Notes
("CLNs") less Trade and other payables less Taxation payable less
Derivative financial instrument (CLNs and Ministry of Energy and
Energy Industries of Trinidad & Tobago ("MEEI") is face value
of debt, including accrued interest)
Financial Highlights
-- Maintenance of a low operating break-even and high operating margin production
o Highly profitable in the current oil price environment while
resilient to lower oil prices
-- Operating earnings increased 77% to USD 11.0 million (2016: USD 6.2 million)
-- Operating margin of 24.3% (2016: 17.6%) or USD 12.0/bbl (2016: USD 6.7/bbl)
-- Balance sheet significantly strengthened with increased cash and reduced debt
-- Accelerated payments to the Board of Inland Revenue of
Trinidad & Tobago ("BIR") and MEEI with outstanding balances of
USD 5.9 million at the period end
Operational Highlights
-- Work programme included a combination of; 37 Recompletions
("RCPs") (2016: nil), 97 well work overs (WOs) inclusive of the
reactivation of idle wells (2016: 63) and the resumption of onshore
swabbing activities
o Delivering this activity set during H2 resulted in production
growth of 10% in H2 2017 (2,641 bopd) when compared to H1 2017
(2,397 bopd)
-- Identified extensive RCP inventory and new infill well
drilling locations across asset portfolio
-- Increased Onshore 2P reserves by 50% to 5.98 mmstb (million
stock tank barrels) (2016: 3.98 mmstb)
-- Total Onshore and Offshore 2P reserves estimated to be 23.21
mmstb at the end of 2017, a 9% increase compared to the year-end
2016 reserve estimate of 21.25 mmstb, and 2C reserves estimated to
be 23.98 mmstb at the end of 2017, a 14% increase to the year-end
reserve estimate of 21.06 mmstb.
Corporate Highlights
-- Completion of refinancing and share capital restructuring
-- Strengthening of Board, with appointment of Jeremy
Bridglalsingh (Executive), David Segel (Non-Executive), Angus
Winther (Non-Executive) and James Menzies (Non-Executive)
o Complementary backgrounds and skillsets provide Trinity with
appropriate industry and capital markets experience to support
continuing efforts to grow the Company
Post Period End Highlights
-- Production and resultant cash generation remains on an upward trajectory
o Production average of 2,721 bopd as at the end of Q1 2018
-- Recommenced onshore drilling
o Two new infill development wells drilled in Q1 and on
production during Q2 2018
o Plan to continue to deliver further production growth over a
largely fixed operating cost base enabling sustained high netbacks
with robust cash conversion
-- Reduced debt and strong cash position of USD 12.2 million as at 31 March 2018
-- BIR and MEEI outstanding balances payable reduced to USD 4.2
million as at 31 March 2018, USD 3.6 million less than the amount
envisaged under the ratified payment plan
Bruce Dingwall CBE, Executive Chairman of Trinity,
commented:
"2017 was a year that was characterised by the stabilisation of
production and the building of well inventory in H1 and a return to
production growth in H2. Our low-cost production model has
underpinned a significant increase in operating profits, affording
the Company the opportunity to accelerate debt repayment whilst
also increasing cash balances. The combination of our strong
balance sheet and proven ability to grow production ensures that
the Company is well placed to realise further value in 2018 and
beyond."
All figures for the financial year 2017 are audited. Q1 2018
figures are unaudited. The Board currently expects to publish its
annual report and accounts for the year to 31 December 2017 before
the end of May 2018, with the Annual General Meeting ("AGM")
expected to take place during June 2018.
Enquiries:
Trinity Exploration & Production Tel: +44 (0) 131 240 3860
Bruce Dingwall CBE, Executive Chairman
Jeremy Bridglalsingh, Chief Financial
Officer
SPARK Advisory Partners Limited (NOMAD Tel: +44 (0) 203 368 3550
& Financial Adviser)
Mark Brady
Miriam Greenwood
Andrew Emmott
Cantor Fitzgerald Europe (Broker) Tel: +44 (0) 207 894 7000
David Porter
Nick Tulloch
Whitman Howard Limited (Equity Adviser) Tel: +44 (0) 207 659 1234
Nick Lovering
Walbrook PR Limited trinityexploration@walbrookpr.com
Nick Rome or Tel: +44 (0) 207 933
8780
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 2017 was 23.2 mmstb. Group
2C contingent resources are estimated to be 24.0 mmstb. The Group's
overall 2P plus 2C volumes are therefore 47.2 mmstb.
Trinity is listed 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 and on the Alternative Investment Market
("AIM"). 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 and efficiently to
deliver profitable returns and to prudently convert our significant
contingent ("2C") resources to 2P reserves and future
inventory.
Platform for growth and profitability established
Trinity's focus over the last 3 years has been on preserving the
integrity of our producing asset base whilst improving operational
practices and efficiencies that enabled the Company to materially
re-base costs. The dramatic positive change in the cost structure
of the business and the return to sustained operating profitability
meant that the financial impact of the improvement in crude oil
prices has been material for the financial year 2017. More
importantly, as we go into 2018 and return to more proactive
investment activities, the financial impact of new production
growth should be even more significant.
The 2017 work programme included a combination of: 37 RCPs
(2016: nil), 97 WOs inclusive of reactivations (2016: 63) and
Onshore swabbing activities with the majority of activity taking
place during H2. Whilst average production for 2017 was relatively
flat at 2,519 bopd (2016: 2,542 bopd), the resulting production
growth of 10% in H2 2017 (2,641 bopd) when compared to H1 2017
(2,397 bopd) followed a successful 2017 programme of RCPs (H1: 5 vs
H2: 32) and WOs (H1: 44 vs H2: 53). In addition to the increased
level of activity, H1 production was also affected by a decline
during Q2 2017 as a result of production being shut-in due to the
Tropical Storm Bret and the consequential electrical supply
disruptions across operations for the month of June 2017.
Thus, 2017 was a year of both the preparation for and delivery
of growth with H1 focused on stabilising base production whilst
high-grading well based activities to begin deploying growth
capital during H2. Both production and resultant cash generation
remains on an upward trajectory with the overall result being that
decline was arrested and a higher base level of production
delivered by the successful RCP and WO programme with average
production volumes of 2,777 bopd in Q4 2017.
The financial upshot of our return to growth and the improvement
in oil prices has been an increase in operating earnings of 77% to
USD 11.0 million (2016: USD 6.2 million) which is the equivalent of
USD 12.0/bbl (2016: USD 6.7/bbl). As a result, cash balances at the
year-end stood at a solid USD 11.8 million (2016: USD 7.6 million).
Amounts due to the Board of Inland Revenue of Trinidad & Tobago
("BIR") and Ministry of Energy and Energy Industries of Trinidad
& Tobago ("MEEI") were reduced to USD 5.9 million (H1 2017: USD
10.6 million), USD 3.0 million below the amount envisaged under the
ratified repayment plan. Trinity ended the year in a net cash
position of USD 0.1 million mainly due to the restructuring of debt
in January 2017 and subsequent repayments to the BIR and MEEI
(2016: net debt position USD 38.6 million).
While we resumed direct investment 'in the ground', 2017 was
also a year when we substantially grew our 2P and 2C reserves by
also refocusing resources on desktop subsurface work. This work is
continuous and has been particularly successful to date with the
identification of the extensive RCP inventory and new infill well
drilling locations across the Onshore asset portfolio. A dedicated
team worked up an incremental 16 infill drilling locations
(2016:12) for reserves to be booked against, and this effort will
be continued in 2018 to provide a stream of low risk and high value
opportunities. As a result of this renewed focus, the Company's
total 2P reserves (Onshore and Offshore) increased to 23.21 mmstb
(9% increase vs 2016: 21.25 mmstb), despite total production of
0.92 mmstb, and our 2C reserves increased to 23.98 mmstb (14%
increase vs 2016: 21.06 mmstb) , taking our total reserves and
resources to 47.18 mmstb at 31 December 2017 (12% increase vs 2016:
42.31 mmstb).
Of particular note is the increase in Onshore 2P reserves by 45%
to 5.78 mmstb (2016: 3.98 mmstb). This is all the more impressive
as these reserves stand at post-production of 0.49 mmstb for 2017,
which is testament to the quality of our Onshore portfolio.
The quantum and quality of the RCP inventory enabled us to grow
production during H2 2017 and into 2018 via these relatively low
cost/high return activities. The identification of new infill well
locations will allow for further drilling and production growth
during 2018.
Plans for 2018 and beyond
We see a number of options for further value creation across
Trinity's asset base. Our programme of phased and risk mitigated
development activities through routine RCPs, WOs, reactivations and
swabbing on the current well stock has succeeded in arresting
decline and provided for a return to production growth. More
importantly, Trinity resumed drilling Onshore with two infill wells
being drilled early in Q1 2018, production from which commenced in
Q2 2018.
The current year has started positively with a year to date
production average of 2,721 bopd as at the end of Q1 2018. The
Company intends to build on this level of base production to reach
a targeted annual average production range of 2,800 - 3,000 bopd
for 2018. This is achievable under the current fiscal regime with
the already completed two infill wells and the successful
continuation of the RCP programme, WOs, reactivations and Onshore
swabbing activities. We plan to continue to build the inventory of
additional infill well locations and further investment in the
Company's infrastructure is being undertaken, with the expectation
of further Onshore drilling later in the year (contingent on the
oil price and clarity regarding the future fiscal regime).
On the East Coast, a revised development plan for the TGAL field
is being prepared with a view to reducing the capital requirements
via a phased and risk-mitigated plan. Rework of the FDP commenced
in Q2 2018 with the target of having an updated document
resubmitted to the MEEI for approval during 2018. As part of the
next stage of development, a geological, geophysical and
engineering review of the Trintes infill drilling programme and the
Trintes-TGAL and Galeota Ridge development plan is in progress.
Well trajectory optimisation for the Trintes infill drilling
programme has commenced and Trinity's drilling rig was demobilised
to land for inspection and repair.
Management is continuing to examine a range of options regarding
the sale of the West Coast assets. In the interim, we continue to
pursue infrastructural projects to preserve asset integrity and
maintain production levels. These assets continue to generate
positive cash flow.
The Company's low consolidated operating break-even level (USD
30.9/bbl) and the hedging programme which was implemented in 2017
combine to provide financial resilience to low oil prices and give
confidence that the Company's growth and investment plans can be
delivered under a wide range of oil price scenarios. The Company
continues to explore various options to strengthen its balance
sheet further during 2018, with the intention of i) repaying the
remaining amounts due to the BIR and MEEI; ii) redemption of the
CLNs, and iii) accelerating the possibility of further Onshore
drilling.
The Board of Directors ("Board") remains confident that the
growth in high margin production and continued focus on
strengthening the balance sheet will deliver excellent returns for
shareholders in 2018 and beyond.
Overview
This time last year our aim was to stabilise base production,
build well inventory and execute a limited investment programme
whilst maintaining a close watch on operating costs and Health,
Safety, Security and Environment ("HSSE"). The Company managed to
deliver on that initial programme resulting in an increase in
operating profits. This safely delivered programme also enabled the
Company to accelerate repayment to the BIR and MEEI, with
outstanding balances reduced to USD 4.2 million as at 31 March
2018, which is USD 3.6 million ahead of the amount envisaged under
the ratified repayment plan.
During 2017 we continued to prioritise HSSE and the well-being
of our people while promoting safe behaviours among all
stakeholders. The dedication, hard work and expertise required to
stabilise, review and return to growth on a portfolio of 1,165
wells (with 182 active wells) across 9 licences and multiple
reservoirs has required a huge effort from those involved. For this
we remain extremely thankful to our employees and the continued
support of our suppliers with whom we look forward to working
alongside as we continue to build on, and strengthen relationships
with all of our stakeholders.
With a return to Onshore infill drilling in 2018, Trinity will
be able to deliver further production growth over a largely fixed
operating cost base, leading to improved operating earnings with
robust cash conversion. Good governance remains at the core and we
remain committed to meeting all of our obligations and delivering
our strategy in a responsible and transparent manner.
The strengthening of the Board was undertaken in January 2017,
with the appointment of Jeremy Bridglalsingh (Executive) our Chief
Financial Officer ("CFO") and David Segel and Angus Winther
(Non-Executives). The Board was further strengthened with the
appointment of James Menzies (Non-Executive) in June 2017. The
result is a Board with complementary backgrounds and skillsets that
provides Trinity with the appropriate industry and capital markets
experience to support our ongoing efforts to grow.
Jonathan Murphy stepped down from the Board in June 2017 to
focus on other interests. His contribution to Trinity has been
invaluable during his tenure and we are deeply appreciative of his
steadfast support during the challenges faced in previous
years.
The Board is confident that the quality and profitability of our
underlying assets will deliver excellent returns for shareholders
from the execution of our strategy in 2018 and beyond.
KEY PERFORMANCE INDICATORS
The Group was profitable at an operating level throughout 2017
generating operating earnings of USD 11.0 million (2016: USD 6.2
million), yielding a year-end cash balance of USD 11.8 million
(2016: USD 7.6 million) and a net cash position of USD 0.1 million
(2016: net debt position USD 38.6 million). A summary of the
year-on-year operational and financial highlights are set out
below:
FY 2017 FY 2016 Change (%)
Average realised oil price(1) (USD/bbl) 48.6 39.4 23
Average net production (bopd) 2,519 2,542 (1)
Annual production (mmbbls) 0.92 0.92 0
Revenues (USD MM) 45.2 35.3 28
Operating earnings(2) (USD MM) 11.0 6.2 77
Operating earnings(3) (USD/bbl) 12.0 6.7 77
Operating margin(4) (%) 24.3 17.6 39
Consolidated operating break-even(5) (USD/bbl) 30.9 29.3 6
Cash balance (USD MM) 11.8 7.6 55
Net cash/ (debt) (USD MM)(6) 0.1 (38.6) 100
1. Realised price: Actual price received for crude oil sales per
bbl. A discount is normally applied to the WTI price by Petrotrin
to derive the realised price received by Trinity
2. Operating earnings (USD MM): Revenues less Royalties less
Opex less G&A less Other Expenses (Crude oil derivatives)
3. Operating earnings (USD/bbl): Operating earnings/ Annual
production
4. Operating margin (%): Operating earnings/ Revenues
5. Consolidated operating break-even: The realised price where
Operating Earnings for the entire Group is equal to zero
6. Net cash/ (debt): Current assets less CLNs less Trade and
other payables less Taxation payable less Derivative financial
instrument (CLNs and MEEI is face value of debt, including accrued
interest)
2017 Trading Summary
A five-year historical summary of realised price, production,
operating break-evens and Opex and G&A expenditure metrics is
set out below:
DETAILS 2013 2014 2015 2016 2017
Realised Price (USD/bbl) 91.6 85.8 45.5 39.4 48.6
------ ------ ------ ------ ------
Production (bopd)
------ ------ ------ ------ ------
Onshore 2,088 2,005 1,601 1,343 1,347
------ ------ ------ ------ ------
West Coast 493 491 312 190 212
------ ------ ------ ------ ------
East Coast 1,110 1,105 983 1,009 961
------ ------ ------ ------ ------
Consolidated 3,691 3,601 2,896 2,542 2,519
------ ------ ------ ------ ------
Operating Break-Even (USD/bbl) (1)
------ ------ ------ ------ ------
Onshore 19.0 21.3 23.3 17.4 16.6
------ ------ ------ ------ ------
West Coast 21.2 24.5 40.7 37.7 26.6
------ ------ ------ ------ ------
East Coast 69.8 55.9 41.3 26.3 24.9
------ ------ ------ ------ ------
Consolidated 62.9 64.6 47.4 29.3 30.9
------ ------ ------ ------ ------
Metrics (USD/bbl)
------ ------ ------ ------ ------
Opex/bbl - Onshore 12.8 14.4 15.7 11.8 11.1
------ ------ ------ ------ ------
Opex/bbl - West Coast 17.4 20.2 33.8 31.6 22.1
------ ------ ------ ------ ------
Opex/bbl - East Coast 52.0 41.6 31.6 20.1 18.9
------ ------ ------ ------ ------
G&A/bbl - Consolidated 13.8 11.4 9.9 4.5 4.7
------ ------ ------ ------ ------
1. Operating Break-even: The realised price where Operating
Earnings for the respective asset or the entire Group
(Consolidated) is equal to zero
Of particular note is that the constituent asset level operating
break-evens were further reduced year-on-year as follows:
Onshore reduced by 5% in 2017 versus 2016 (2016 reduced 25%
year-on-year )
West Coast reduced by 29% in 2017 versus 2016 (2016 reduced 7%
year-on-year )
----------------------------------------------------
East Coast reduced by 5% in 2017 versus 2016 (2016 reduced 36%
year-on-year )
----------------------------------------------------
At the aggregated corporate level the maintenance of such a
robust consolidated operating level break-even reflects the
following:
-- Overall Opex reduced by 6% to USD 14.7 million (2016: USD
15.6 million). This was achieved through various cost efficiency
measures including lower East Coast personnel transfer costs and
reduced labour costs resulting from the restructuring.
-- Opex is largely of a fixed cost nature and therefore an
increase in production over a largely fixed cost base has a
significant leverage effect;
-- G&A costs increased by 2% to USD 4.3 million (2016: USD
4.2 million) and are on target to be sustained around this level;
and
-- Crude oil derivative costs of USD 1.4 million incurred for the first time.
OPERATIONAL REVIEW
OUR EMPLOYEES
Trinity's workforce stood at 188 at the year-end December 2017
with 78% (146) male and 22% (42) female employees. Our employees
are positioned across the United Kingdom and T&T, with the
majority (98%) 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.
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 "zero" incident rates. 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 learnt and
several proactive initiatives implemented across all operations. In
June 2017, our HSSE performance was recognised by Petrotrin, and we
were awarded the Star of Excellence HSE Award for our contribution
towards Safety Leadership Engagement.
Trinity was successfully assessed via a Safe to Work ("STOW")
T&T Audit in December 2017 and our HSSE Management System was
granted a 2 year certification by the Energy Chamber of T&T in
February 2018. This system enhances our ability to respond, control
and analyse safety events and performance data as well as allows us
to be proactive in mitigating and managing risk.
Notwithstanding our 2017 achievements, in 2018 Trinity intends
to continue its focus on initiatives to foster further improvement
of our HSSE Management System and associated performance.
PRODUCTION
Average net production for 2017 was 2,519 bopd (2016: 2,542 bopd
inclusive of GU-1/ 2,519 bopd exclusive of GU-1) (the GU-1 Lease
Operatorship was disposed of in May 2016), which represents only a
1% decline in overall average production levels for the year. A
total of 37 RCPs and 97 WOs and reactivations and swabbing
activities were undertaken during 2017.
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 2017 net production from the Onshore assets was 1,347
bopd which accounted for 54% of total annual average production.
The maintenance of year-on-year production averages is reflective
of the work programme beginning to impact and successfully arrest
reservoir and low activity decline rates. 2016 net Onshore
production exclusive of GU-1 (divested May 2016 at a 5-month
average of 57 bopd) production was 1,320 bopd which represents a
like-for-like increase of 2%.
The drilling programme carded for 2017 initially consisted of 4
new infill wells with the first well anticipated to spud in Q3
2017. However, after further evaluation of our inventory of
opportunities, we identified over 200 up-hole resistive (not
perforated) sands in the existing wells across the Onshore assets
to be screened as potential RCP candidates.
Trinity opted to prioritise the acceleration of its high return
on capital RCP programme whilst working to increase and high grade
new infill drilling locations. To address the step-change in
activities, an additional rig was contracted to target the approved
RCPs, whilst our two in-house rigs facilitated both RCPs and
routine WOs to arrest reservoir decline rates and grow production.
In total 37 RCPs (2016: nil) and 78 WOs and reactivations (2016:
60) and were undertaken across our Onshore fields.
Going forward the Company intends to implement development
activities via infill drilling, routine RCPs, WOs, reactivations
and swabbing on the current well stock to maintain base production
and provide for a return to production growth.
East Coast Asset
Current East Coast production is derived from the Alpha, Bravo
and Delta platforms in the Trintes Field.
Average 2017 net production from the East Coast was 961 bopd
which accounted for 38% of total annual average production. This
represented a 5% decline in production from the 2016 average net
production levels of 1,009 bopd. The decrease was largely as a
result of electrical outages and subsequent delays in bringing the
wells back onto production as well as a one-off production
shut-down due to the Tropical Storm Bret in H1 2017.
In 2017, 18 restorative WOs were completed (2016: 2) which
contributed to an upward trend in production. In June 2017 Trinity
was able to install a sucker rod pumping system on a slanted
wellhead in an offshore environment. This was possible through the
utilisation of a Mechanical Pumping Hydraulic Unit ("MPHU") on
surface and a conventional sucker rod pump downhole. An automated
and real-time monitoring system along with a downhole sensor was
also installed to aid in the efficient monitoring of the system and
the achievement of optimum production. The unit has been operating
for over 6 months. Additionally, we were able to reactivate 9 wells
via the use of progressive cavity pumps.
Various infrastructure projects were undertaken during 2017
which included the Trintes cranes assessment and recertification
works, replacement of the Galeota tank farm fire water pump,
installation of additional diesel storage, Alpha crane boom change
out, securing the 8" incoming production line and phase 1
(Front-End Engineering Design) of 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, continued optimisation and
review of alternative artificial lift technologies to augment
production rates and maintain efficiency and cost
effectiveness.
The next stage of development involving an internal geological,
geophysical and engineering review of the Trintes infill drilling
programme and the Trintes-TGAL and Galeota Ridge development plan
is in progress. Well trajectory optimisation for the Trintes infill
drilling programme has commenced; and Trinity's drilling rig was
demobilised to land for inspection. A revised development plan for
the TGAL field is being prepared with a view to reducing the
capital requirements via a phased and risk mitigated plan. Rework
of the FDP began in Q2 2018 with the view to having an updated
document resubmitted to the MEEI for approval during 2018.
West Coast Assets
Currently, West Coast production is from the Point Ligoure-Guapo
Bay-Brighton Marine ("PGB") and Brighton Marine ("BM") fields.
Average 2017 net production from the West Coast was 212 bopd
which accounted for 8% of total annual average production. This
represented a 12% increase in production from 2016 average levels
of 190 bopd. This increase was facilitated by a pipeline change-out
programme undertaken in the latter part of Q4 2016 in BM that
resulted in sustained production levels.
There were no major production related activities conducted on
the West Coast assets in 2017, with the exception of 1 WO (2016: 1)
in the PGB field. In 2017, infrastructural works were undertaken on
the offshore platforms to maintain asset integrity and
production.
On 11 August 2017, Trinity announced that it had entered into a
binding Sale and Purchase Agreement ("SPA") to sell its interests
in the PGB and BM Exploration and Production Licences and related
fixed assets to a subsidiary of AIM quoted Range Resources Limited
("Range") for a cash consideration of USD 4.55 million. On 23
November 2017, Trinity announced that the transaction was unable to
complete due to the requisite regulatory approvals not being
forthcoming. Management is continuing to examine a range of options
regarding the sale of the West Coast assets. In the interim, the
assets continue to generate positive cash flow.
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 further increase production. These assets will
continue to be closely monitored as progressive steps are taken to
also optimise its 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 23.21
million stock tank barrels ("mmstb") at the end of 2017, compared
to the year-end 2016 reserve estimate of 21.25 mmstb. This
represents an increase of 1.96 mmstb (9%) from 2016 levels. This
increase is despite production for 2017 of 0.92 mmstb (2016: 0.92
mmstb) and is due to updated decline curve analysis on producing
wells, low cost well reinstatements in 2017 and, most
significantly, extensive subsurface work to generate additional
infill drilling, RCP and WO candidates. Management considers this
to be the best estimate of the quantity of reserves that will
actually be recovered from the accumulation by the assets and
represent production which is commercially recoverable, either to
licence/relevant permitted extension end or sooner through 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 2017 2P Reserves
Asset 31 December 2016 Production Revisions 31 December 2017
----------------- ----------- ---------- -----------------
Net Oil Production mmstb mmstb mmstb mmstb
----------------- ----------- ---------- -----------------
Onshore 3.98 (0.49) 2.29 5.78
----------------- ----------- ---------- -----------------
East Coast 14.68 (0.35) 0.45 14.78
----------------- ----------- ---------- -----------------
West Coast 2.59 (0.08) 0.14 2.65
----------------- ----------- ---------- -----------------
Total 21.25 (0.92) 2.88 23.21
----------------- ----------- ---------- -----------------
The best estimate of contingent resources ("2C") due to the
current economic environment and the defining technical work
pending is estimated by Management at 23.98 mmstb (2016: 21.06
mmstb).
Unaudited 2017 2C Resources
31 December 2016 Revisions 31 December 2017
----------------- ----------- -----------------
Asset mmstb mmstb mmstb
----------------- ----------- -----------------
Onshore 1.00 1.18 2.18
----------------- ----------- -----------------
East Coast 19.54 1.33 20.87
----------------- ----------- -----------------
West Coast 0.52 0.41 0.93
----------------- ----------- -----------------
Total 21.06 2.92 23.98
----------------- ----------- -----------------
Unaudited Summary of Reserves and Resources at 31 December
2017
2P 2C 2P+2C
Reserves Resources Reserves and
-------------- -------------- ----------------
Asset mmstb mmstb Resources mmstb
-------------- -------------- ----------------
Onshore 5.78 2.18 7.96
-------------- -------------- ----------------
East Coast 14.78 20.87 35.65
-------------- -------------- ----------------
West Coast 2.64 0.93 3.57
-------------- -------------- ----------------
Total 23.20 23.98 47.18
-------------- -------------- ----------------
East Coast Hub
On the East Coast, Trinity has an established production hub
with 4 offshore marine platforms; (Alpha, Bravo, Charlie &
Delta) that have a combined 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 14.78
mmstb therefore represents a low incremental recovery factor of 6%.
Within contingent resources a further 6.37 mmstb relate to the
Trintes field. Of the 31 conceptual infill targets generated in
2015 from the Petrel model, these have been risked during 2017 to
16 candidate drilling locations identified in addition to the
current producing well stock offering visibility on future organic
production growth opportunities.
The TGAL (Trinity: 65%) discovery, up-dip to the north east of
the Trintes field, has booked net contingent resources of 14.50
mmstb (gross: 22.30 mmstb) which represents a low recovery factor
of 12% on best estimate STOIIP of 186 mmstb (Management resource
estimates of STOIIP for the TGAL area remains at 150-210
mmstb).
Trinity decided that once it was in a position to allocate
resources, the previously developed TGAL FDP would be revisited
with a view to reducing the capital requirements via a more
economic topside solution. Rework of the FDP commenced in Q2
2018.
With combined 2P reserves and 2C resources of 35.65 mmstb, the
potential production growth from future Trintes drilling and TGAL
development is substantial. Within the Galeota anticline licence
area there is significant wider prospectivity with 266 mmstb STOIIP
having been mapped between the Trintes field and the EG-3 and EG-4
wells.
FINANCIAL REVIEW
2017 results overview
-- Growing Margins and increasing profitability
Following the Refinancing and Restructuring in January 2017, the
Company focused on growing margins and increasing profitability
which have contributed to a low consolidated operating break-even
price of USD 30.9/bbl (2016: USD 29.3/bbl). 2017 operating expenses
includes the cost of crude oil derivatives (none in 2016) and so a
like-for-like comparative for 2017 would have been USD 28.9/bbl
excluding crude oil derivatives. Trinity also increased its
operating margin (USD/bbl) by 77% to USD 12.0/bbl (2016: USD
6.7/bbl).
-- Significantly reduced net debt and strong cash position
The Statement of Financial Position has continued to strengthen
at the end of the financial year with a turnaround of the net debt
position into a net cash position of USD 0.1 million (2016: net
debt USD 38.6 million) and an increase in the cash balance of 55%
to USD 11.8 million (2016: USD 7.6 million).
-- Acceleration of State creditor repayments
The Company has made repayments to its T&T state creditors
("BIR" and "MEEI") in accordance with the settlement agreements on
a quarterly basis and has accelerated payments by a total of USD
3.6 million (BIR: USD 3.5 million & MEEI: USD 0.1MM) as at 31
March 2018.
-- Mitigating downside price risk
Crude oil derivatives have been implemented during 2017 to
mitigate against downside risk. A put option was purchased in April
2017 covering 31,645 bbls of production per month effective April
2017-March 2018 at a cost of USD 0.6 million (2016: nil) and
protected against WTI falling below USD 40.0/bbl. In November 2017
a zero cost collar was entered into, effective January
2018-December 2018 on 25,000 bbls of production per month with a
WTI price floor of USD 45.0/bbl and a cap of USD 59.8/bbl. A fair
value loss was recognised at the end of 2017 on the zero cost
collar and recognised as a derivative financial liability USD 0.8
million (2016: nil).
-- Completion of Refinancing and share capital restructuring
The Refinancing was completed on 11 January 2017. The Company
issued 187,600,000 new ordinary shares in relation to the Placing
for an aggregate subscription price of USD 11.7 million and issued
CLNs in the principal amount of USD 6.6 million for an aggregate
subscription price of USD 3.3 million. The Company received gross
proceeds of USD 15.0 million from the Refinancing with costs
amounting to USD 1.2 million therefore net proceeds amounted to USD
13.8 million. In order to implement the Refinancing, the Company
carried out a share capital reorganisation whereby each existing
ordinary share of a nominal value of USD 1.00 was divided and
converted into one new ordinary share of a nominal value of USD
0.01 each and one deferred share of a nominal value of USD 0.99
each.
-- Supplemental Petroleum Taxes ("SPT") and Property Taxes
Q4 2017 saw average oil prices rise above USD 50.0/bbl and SPT
of USD 1.5 million (2016: 1.0 million credit) incurred. When
realised oil prices are higher than USD 50.0/bbl SPT is charged at
a rate of 18% and 26% on Net revenues (Gross revenue - royalties -
incentives) on Onshore and Offshore assets respectively. SPT reform
has been earmarked by the Government of Trinidad and Tobago
("GORTT"), but has not yet been effected.
A Property Tax was introduced by the GORTT which was potentially
applicable for both 2016 and 2017. As a result, a charge of USD 0.5
million (2016: USD 0.6 million) was estimated in 2017. The Property
Tax (Amendment) Bill was introduced in the House of Representatives
in the Parliament of Trinidad and Tobago, which seeks to make
revisions to the Property Tax regime. The amendments provide for a
waiver of the 2016 and 2017 property tax liabilities. If, as
expected, this bill is passed and assented to in 2018 then this
would result in a reduction in Property taxes accrued of USD 1.1
million.
STATEMENT OF COMPREHENSIVE INCOME ANALYSIS
Revenues
2017 crude oil sales revenues were USD 45.2 million (2016: USD
35.3 million). This 28% increase was mainly attributable to a 23%
increase in the average realised oil price of USD 48.6/bbl (2016:
USD 39.4/bbl).
Operating expenses
Operating expenses increased by 7% in 2017 to USD (41.2) million
(2016: USD (38.6) million). Operating expenses comprised:
-- Royalties of USD (13.8) million (2016: USD (9.3) million)
-- Production costs of USD (14.7) million (2016: USD (15.6) million)
-- Depreciation, depletion and amortisation ("DD&A") of USD
(7.0) million (2016: USD (9.5) million)
-- G&A expense of USD (4.3) million (2016: USD (4.2) million)
-- Other expenses of USD (1.4) million (2016: nil). This
includes the cost of crude oil derivatives implemented during 2017
comprising put options USD (0.6) million and zero cost collar USD
(0.8) million
SPT and other taxes
-- Supplemental Petroleum Tax of USD (1.5) million (2016: USD 1.0 million credit)
-- Property Tax of USD (0.5) million (2016: USD (0.6) million)
Exceptional items
Exceptional items of USD 25.7 million (2016: USD (1.7) million)
comprised:
-- Restructuring USD 26.3 million credit (2016: USD (1.5) million)
-- Impairments USD (0.6) million (2016: USD (3.6) million)
-- Provisions USD nil (2016: USD 2.4 million)
-- Gain on disposal of GU-1 asset USD nil (2016: USD 1.0 million)
See Note 7 to Consolidated Financial Statements - Exceptional
items for further details.
The Group's operating profit after exceptional items was USD
27.6 million (2016: USD 4.6 million loss).
Net Finance Costs
In 2017, finance costs amounted to USD (2.3) million (2016: USD
(4.7) million) and comprised:
-- Unwinding of the decommissioning liability USD (1.6) million (2016: USD (1.6) million)
-- Interest on taxes nil (2016: USD (2.2) million)
-- Interest on loans: USD (0.7) USD million: (2016: USD (0.9) million)
- Interest accrued on the convertible loan note USD (0.6)
million (2016: nil)
- Interest expense on loan facilities from Citibank (Trinidad
& Tobago) Limited USD (0.04) million (2016: USD (0.9)
million)
- Effective interest on financial liability USD (0.04 million)
(2016: nil)
See Note 8 to Consolidated Financial Statements - Finance Costs
for further details
Income Tax Expense
Taxation credit for 2017 of USD 0.03 million (2016: USD 1.9
million), and its components are described below.
-- Petroleum Profits Tax ("PPT") credit USD 0.9 million (2016: (1.5) million)
-- Reduction in Deferred Tax Asset ("DTA") for the year was as a
result of tax losses de-recognised USD (1.3) million (2016: credit
of USD 3.0 million DTA recognised)
-- Reduction in Deferred Tax Liabilities ("DTL") for the year
was as a result of accelerated tax depreciation credit of USD 0.4
million (2016: credit of USD 0.4 million)
-- Unemployment levy ("UL") USD credit of 0.03 million (2016: USD nil)
See Note 9 to Consolidated Financial Statements - Income Tax
Expense for further details
CONSOLIDATED STATEMENT OF CASH FLOWS ANALYSIS
Cash inflow from operating activities
Cash inflows from operating activities were USD 9.6 million
(2016: USD 9.0 million) following adjustments for:
-- Operating activities resulted in an adjusted profit before
tax of USD 8.7 million (2016: USD 8.0 million)
-- Changes in working capital comprised of a net cash inflow of
USD 0.9 million (2016: USD 2.6 million inflow) excluding amounts
paid to unsecured creditors of USD (3.9) million and T&T state
creditors of (8.8) million under the Restructuring
-- Taxation paid nil (2016: USD (1.6) million outflow)
Cash outflow; change in working capital relating to the
Restructuring
Working capital cash outflows relating to the Restructuring
amounted to USD (12.7) million comprising:
-- Payments T&T State Creditors: USD (7.7) million to the BIR and USD (1.1) million to MEEI
-- Payments of USD (3.9) million to the Group's Unsecured Creditors
Cash outflow from investing activities
Cash outflow from investing activities was USD (3.1) million
(2016: USD (0.3) million), which was comprised of:
-- Expenditure on Property, Plant and Equipment for the year was
USD (2.8) million (2016: USD (0.3) million) which mainly included
recompletions and infrastructure upgrades
-- Purchase of Intangible assets (0.3 million) (2016: USD nil)
in the form of a new finance software package
Cash inflow from financing activities
Cash inflow from financing activities was USD 10.4 million
(2016: USD (6.2) million outflow) as a result of the Refinancing
and Restructuring:
-- Proceeds from the issue of shares (net of costs) USD 10.9 million (2016: nil)
-- Proceeds from the issue of convertible loan note (net of
costs) USD 3.0 million (2016: nil)
-- Settlement of the compromised Citibank loan of USD (3.5)
million (2016: USD (3.1) million)
-- Finance costs nil (2016: USD (3.2) million)
See Note 25 to the Consolidated Financial Statements -
Borrowings for further details.
See Note 8 to the Consolidated Financial Statements - Finance
Costs for further details.
NET CASH/ (DEBT) CALCULATION
At 31 December 2017 the Group showed a net cash position of USD
0.1 million (audited 2016: USD 38.6 million net debt position)
based on Management's view. The turnaround from the net debt
position on a year-on-year basis to a net cash position was a
result of the Refinancing and Restructuring of the Group's
Statement of Financial Position and the Group's strong cash flow
generation during the year which have enabled it to accelerate
repayments under the ratified payment plan.
Statement of Financial FY 2017 FY 2017 FY 2016 FY 2016
Position Extract
USD MM USD MM USD MM USD MM
Unaudited Audited(2) Unaudited Audited
Mgmt. View(1) Pro forma
Current Assets
Cash and cash
equivalents 11.8 11.8 11.9 7.6
Trade and other
receivables 5.2 5.2 4.8 5.5
Inventories 3.8 3.8 3.8 3.8
A: Total Current Assets 20.8 20.8 20.5 16.9
======================= ======================= ================== ======================
Liabilities
Non-current
Trade and other
payables 1.0 0.9 9.4 -
Convertible loan
note 7.0 3.0 6.6 -
Total Non-Current
Liabilities(3) 8.0 3.9 16.0 -
Current
Trade and other
payables 10.2 10.1 6.7 42.8
Taxation payable 1.7 1.7 2.7 2.7
Derivative
Financial
Instrument 0.8 0.8 - -
Borrowings - - - 10.0
Total Current
Liabilities(4) 12.7 12.6 9.4 55.5
B: Total
Liabilities(3,4) 20.7 16.5 25.4 55.5
======================= ======================= ================== ======================
(A-B): Net cash/(debt) 0.1 4.3 (4.9) (38.6)
Notes:
1. Based on the face value of the CLN and MEEI liabilities
(including accrued interest) as opposed to amortised cost stated in
the Financials
2. Based on the amortised cost of the CLN and MEEI liabilities
as stated in the Financials (see Notes 27 and 24 to the Financial
Statements)
3. Non-Current Liabilities excludes DTL & Provision for other liabilities
4. Current Liabilities excludes Provision for other liabilities
During 2017, the Group made payments of USD 3.5 million to
Citibank, USD 7.7 million to the BIR, USD 1.1 million to the MEEI
and USD 3.9 million to unsecured creditors in accordance with the
various settlement agreements forming part of the Restructuring and
Refinancing.
As at 31 December 2017, the remaining amounts outstanding to the
BIR and MEEI under the ratified repayment plans were USD 5.0
million and USD 0.9 million respectively.
Trinity Exploration & Production Plc
Consolidated Statement of Comprehensive Income
For the year ended 31 December 2017
(Expressed in United States Dollars)
Note 2017 2016
(Restated(1)
)
$'000 $'000
Operating Revenues
Crude oil sales 44,957 35,303
Other income 210 --
------------ -------------
45,167 35,303
Operating Expenses
Royalties (13,755) (9,326)
Production costs (14,737) (15,569)
Depreciation, depletion and amortisation 12 (7,055) (9,539)
General and administrative expenses (4,326) (4,154)
Other expenses (1,362) --
------------ -------------
(41,235) (38,588)
------------ -------------
Operating Profit/(Loss) Before SPT and
Property Taxes 3,932 (3,285)
Supplemental petroleum taxes (1,533) 951
Property taxes (497) (603)
------------ -------------
Operating Profit/(Loss) Before Exceptional
Items 1,902 (2,937)
Exceptional Items 7 25,718 (1,675)
Operating Profit/(Loss) 27,620 (4,612)
Net finance costs 8 (2,300) (4,733)
Profit/(Loss) Before Taxation 25,320 (9,345)
Taxation credit 9 28 1,878
------------ -------------
Profit/(Loss) for the period 25,348 (7,467)
Other Comprehensive Income/(Expense)
Items that may be subsequently reclassified
to profit or loss
Currency translation 74 (112)
------------ -------------
Total Comprehensive Income/(Expense) For
The Year 25,424 (7,579)
============ =============
Earnings per share (expressed in dollars
per share)
Basic 10 0.09 (0.08)
Diluted 10 0.06 (0.08)
(1 see note 5 for restatement)
Trinity Exploration & Production Plc
Consolidated Statement of Financial Position
at 31 December 2017
(Expressed in United States Dollars)
Note 2017 2016
(Restated(1)
)
ASSETS $'000 $'000
Non-current Assets
Property, plant and equipment 12 52,450 59,632
Intangible assets 13 25,591 25,406
Abandonment fund 14 1,650 1,072
Performance bond 15 253 --
Deferred tax assets 16 4,179 5,496
84,123 91,606
---------- -------------
Current Assets
Inventories 17 3,766 3,787
Trade and other receivables 18 5,155 5,449
Cash and cash equivalents 19 11,792 7,615
---------- -------------
20,713 16,851
---------- -------------
Total Assets 104,836 108,457
========== =============
Equity and liabilities
Capital and Reserves Attributable to Equity
Holders
Share capital 20 96,676 94,800
Share premium 20 125,362 116,395
Share warrants 21 -- 71
Other equity 24 590 --
Share based payment reserve 22 12,553 12,244
Merger reserves 23 75,467 75,467
Reverse acquisition reserve 23 (89,268) (89,268)
Translation reserve (1,678) (1,997)
Accumulated losses (171,112) (196,460)
---------- -------------
Total Equity 48,590 11,252
---------- -------------
Non-current Liabilities
Trade and other payables 27 881 --
Convertible loan notes 24 3,019 --
Deferred tax liabilities 16 2,538 2,927
Provision for other liabilities 26 37,151 38,318
43,589 41,245
---------- -------------
Current Liabilities
Trade and other payables 27 10,092 42,799
Provision for other liabilities 26 115 470
Derivative financial instruments 29 762 --
Borrowings 25 -- 9,950
Taxation payable 30 1,688 2,741
---------- -------------
12,657 55,960
---------- -------------
Total Liabilities 56,246 97,205
---------- -------------
Total Equity and Liabilities 104,836 108,457
========== =============
(1 see note 5 for restatement)
Trinity Exploration & Production Plc
Company Statement of Financial Position
at 31 December 2017
(Expressed in United States Dollars)
Note 2017 2016
ASSETS $'000 $'000
Non-current Assets
Investment in subsidiaries 11 51,416 44,802
========== ==========
Current Assets
Trade and other receivables 18 89 813
Intercompany 18 2,447 1,857
Cash and cash equivalents 19 6,024 758
---------- ----------
8,560 3,428
---------- ----------
Total Assets 59,976 48,230
========== ==========
Equity and liabilities
Capital and Reserves Attributable to Equity
Holders
Share capital 20 96,676 94,800
Share premium 20 125,362 116,395
Other equity 590 --
Share based payment reserve 1,853 1,544
Merger reserves 56,652 56,652
Accumulated losses (225,459) (222,235)
---------- ----------
Total Equity 55,674 47,156
---------- ----------
Non - Current Liabilities
Convertible loan notes 24 3,019 --
---------- ----------
Current Liabilities
Trade and other payables 27 521 739
Derivative financial instruments 29 762 --
Intercompany -- 335
---------- ----------
1,283 1,074
---------- ----------
Total Liabilities 4,302 1,074
---------- ----------
Total Equity and Liabilities 59,976 48,230
========== ==========
Trinity Exploration & Production Plc
Consolidated Statement of Changes in Equity
for the year ended 31 December 2017
(Expressed in United States Dollars)
Year ended 31 Share Share Other Share Share Reverse Merger Translation Accumulated Total
December Capital Premium Equity Warrants Based Acquisition Reserves Reserve Losses Equity
2016 Payment Reserve
Reserve
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
At 1 January
2016 94,800 116,395 -- 71 12,178 (89,268) 75,467 (557) (188,993) 20,093
Share based
payment
charge
(Note 22) -- -- -- -- 66 -- -- -- -- 66
Restated ( See
Note 5) -- -- -- -- -- -- -- -- (603) (603)
Translation
difference -- -- -- -- -- -- -- (1,328) -- (1,328)
Total
comprehensive
expense
for the
period -- -- -- -- -- -- -- (112) (6,864) (6,976)
-------- --------- ------- --------- -------- ------------ --------- ------------ ------------ --------
At 31 December
2016 restated 94,800 116,395 -- 71 12,244 (89,268) 75,467 (1,997) (196,460) 11,252
======== ========= ======= ========= ======== ============ ========= ============ ============ ========
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
charge
(Note 22) -- -- -- -- 309 -- -- -- -- 309
Share warrants
expired -- -- -- (71) -- -- -- -- -- (71)
Translation
difference -- -- -- -- -- -- -- 246 -- 246
Total
comprehensive
income
for the
period -- -- -- -- -- -- -- 73 25,348 25,421
-------- --------- ------- --------- -------- ------------ --------- ------------ ------------ --------
At 31 December
2017 96,676 125,362 590 -- 12,553 (89,268) 75,467 (1,678) (171,112) 48,590
======== ========= ======= ========= ======== ============ ========= ============ ============ ========
Trinity Exploration & Production Plc
Company Statement of Changes in Equity
for the year 31 December 2017
(Expressed in United States Dollars)
Share Share Other Equity Share Based Merger Accumulated Total Equity
Capital Premium Payment Reserves Losses
Reserve
$'000 $'000 $'000 $'000 $'000 $'000 $'000
Year ended 31
December 2016
At 1 January
2016 94,800 116,395 -- 1,505 56,652 (218,234) 51,118
Share based
payment
charge -- -- -- 39 -- -- 39
Total
comprehensive
expense
for the year -- -- -- -- -- (4,001) (4,001)
At 31
December
2016 94,800 116,395 -- 1,544 56,652 (222,235) 47,156
============= ============= ============= ============ ============= ============ =============
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
charge -- -- -- 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
============= ============= ============= ============ ============= ============ =============
Trinity Exploration & Production Plc
Consolidated Statement of Cash Flows
for the year ended 31 December 2017
(Expressed in United States Dollars)
Note 2017 2016
$'000 $'000
Operating Activities (Restated)
Profit/(Loss) before taxation 25,320 (9,345)
Adjustments for:
Translation difference (663) 2,275
Finance cost - loans and interest 8 579 3,156
Share based payment charge 22 235 66
Finance cost - decommissioning provision 26 1,643 1,577
Depreciation, depletion and amortisation 12 7,055 9,539
Gain on disposal of assets -- (954)
Impairment of property, plant and equipment 12 -- 2,420
Release of provision for restructuring -- (1,870)
Release of provision for claim -- (1,218)
Provisions recorded -- 712
Impairment of receivables 348 1,071
Impairment of inventory 264 --
Impairment of payables -- (157)
Gain on extinguishment of financial liabilities (210) --
Unsecured creditors' claims -- 697
Fair value zero cost collar 762 --
Compromised creditor balances (26,672) --
8,661 7,969
--------- -----------
Changes In Working Capital
Inventories 17 (243) 26
Available for-sale non-financial assets -- 1,896
Trade and other receivables 18 (887) (746)
Trade and other payables 27 2,023 1,393
Restructuring (Unsecured Creditors) (3,857) --
State creditors (BIR and MEEI) (8,775) --
--------- -----------
(11,739) 2,569
--------- -----------
Taxation paid -- (1,551)
--------- -----------
Net Cash (Outflow)/Inflow From Operating
Activities (3,078) 8,987
--------- -----------
Investing Activities
Purchase of computer software 13 (250) --
Purchase of property, plant and equipment 12 (2,868) (266)
Net Cash Outflow From Investing Activities (3,118) (266)
--------- -----------
Financing Activities
Finance costs -- (3,156)
Issue of shares (net of costs) 20 10,843 --
Issue of Convertible loan notes (net
of costs) 24 3,030 --
Repayment of borrowings 25 (3,500) (3,050)
--------- -----------
Net Cash Inflow/ (Outflow) From Financing
Activities 10,373 (6,206)
--------- -----------
Increase in Cash and Cash Equivalents 4,177 2,515
========= ===========
Cash And Cash Equivalents
At beginning of year 7,615 8,200
Less funds held for abandonment -- (3,100)
Increase in cash and cash equivalents 4,177 2,515
--------- -----------
At end of year 19 11,792 7,615
========= ===========
Trinity Exploration & Production Plc
Company Statement of Cash Flows
for the year ended 31 December 2017
(Expressed in United States Dollars)
Note 2017 2016
$'000 $'000
Operating Activities
Loss before taxation (3,161) (4,259)
Adjustments for:
Translation differences 69 78
Finance income (270) (289)
Finance cost 579 12
Share based payment charge 91 39
Fair value zero cost collar 762 --
Impairment intragroup loan -- 4,014
Compromised creditor balances 446 --
---------- -----------------
(1,484) (405)
Changes In Working Capital
Trade and other receivables 134 5,246
Trade and other payables (553) (2,958)
---------- -----------------
(419) 2,288
---------- -----------------
Taxation Paid -- (1,402)
---------- -----------------
Net Cash (Outflow)/Inflow from Operating
Activities (1,903) 481
---------- -----------------
Financing Activities
Finance income 270 289
Finance cost (579) (12)
Capital contributed to subsidiary 11 (6,395) --
Issue of shares (net of costs) 20 10,843 --
Issue of Convertible loan notes (net of
costs) 24 3,030 --
Net Cash Inflow from Financing Activities 7,169 277
---------- -----------------
Increase In Cash And Cash Equivalents 5,266 758
========== =================
Cash And Cash Equivalents
At beginning of year 758 --
Increase in cash and cash equivalents 5,266 758
At end of year 19 6,024 758
========== =================
Trinity Exploration & Production Plc
Notes to the Consolidated Financial Statements
31 December 2017
(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") 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 ("the Company") and its subsidiaries (together "the
Group") are involved in the exploration, development and production
of oil and gas reserves in Trinidad.
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, modified for fair values under IFRS.
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.
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 $3.2 million (2016 $4.0 million loss).
Going Concern
In making their going concern assessment, the Board have
considered the Group's budget and cash flow forecasts. The Group is
incurring expenditure in order to continue operations from its
existing fields as well as maintain overheads. At the 31 December
2017, the Group had net current assets of $8.1 million, compared to
2016, where the Group had a net current liability of $39.1
million.
On the 11 January 2017, the Group was able to secure a
refinancing solution enabling the Company to retire its existing
senior debt facility, reduce outstanding payables to unsecured
trade creditors, significantly modify repayment terms to state
creditors namely the Board of Inland Revenue ("BIR") and the
Ministry of Energy and Energy Industries ("MEEI") and raise
additional capital through the issuing of ordinary shares and
Convertible Loan Notes ("CLNs"). As part of the refinancing,
significant balances were compromised with the senior debt holder
and with the Group's unsecured creditors in accordance with the
senior debt settlement and unsecured creditor settlement
agreements.
Subsequent to the refinancing 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 should be able to
operate within the level of its current cash resources. Should
there be a down turn in the oil prices within the industry the
Board of Directors and Management have a number of actions within
control that can be effected. These include deferral of its capital
expenditure spend and further reducing operating costs to
manageable levels. For these reasons, the Board of Directors have a
reasonable expectation that the Group has adequate resources to
continue operational existence for the foreseeable future. The
Group therefore continues to adopt the going concern basis of
preparing the financial statements.
The financial statements have been prepared on the going concern
basis based on the financing provided by the shareholders which
provides the necessary financial support to the Group to enable it
to pay its debts as they fall due 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 in the foreseeable
future and is poised for continued growth. For this reason, the
Board of Directors continues to adopt the going concern basis of
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
2017:
IAS 12 The amendment to the standard deals with the Periods beginning on / after 1 January 2017
Income Taxes recognition of Deferred Tax Assets for
Unrealised
Losses. The diversity in practice around the
recognition of a deferred tax asset that is
related
to a debt instrument measured at fair value
is mainly attributable to uncertainty about
the
application of some of the principles in IAS
12. The adoption of the amendment did not
have
any impact on the amounts recognised in
prior periods.
========================= ============================================= ============================================
IAS 7 The amendments are intended to clarify IAS 7 Periods beginning on / after 1 January 2017
Statement of Cash Flows to improve information provided to users of
financial
statements about an entity's financing
activities. The adoption of the amendment
did not have
any impact on the amounts recognised in
prior periods.
========================= ============================================= ============================================
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 2017 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 15 Revenue from Contracts with The new standard for revenue replaces Periods beginning on / after 1
Customers IAS 18, and will have a significant January 2017
impact on some entities.
The changes could have an impact on
the timing of when revenue is
recognised and the period
over which it is recognised as well
as on the financial statement
disclosures. The Group does
not expect this standard to have a
material impact on revenue.
====================================== ====================================== ======================================
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
does not expect the new guidance to
affect the classification
and measurement of these financial
assets. The Group doesn't expect a
material impact in accounting
for financial liabilities that are
designated at fair value through
profit or loss.
====================================== ====================================== ======================================
IFRS 16 Leases This is a new accounting standard Periods beginning on / after 1 Jan
which will result in almost all 2019
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. Although its
impact is still being assessed,
the Group doesn't expects there to be
a material impact as the majority of
leases are short
term and low value.
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.
Business combination
The acquisition of subsidiaries is accounted for using the
acquisition method. Identifying the acquirer in a business
combination is based on the concept of 'control'. However in
certain circumstances the positions may be reversed and it is the
legal subsidiary entity's shareholders who effectively control the
combined Group even though the other party is the legal parent.
IFRS 3 requires, in a business combination effected through an
exchange of equity interests, all relevant facts and circumstances
be considered to determine which of the combining entities has the
power to govern the financial and operating policies of the other
entity. These combinations are commonly referred to as 'reverse
acquisitions'.
For each business combination, the cost of the acquisition is
measured at the aggregate of the fair values, at the date of
exchange, of assets given, liabilities incurred or assumed, and
equity instruments issued by the Group in exchange for control of
the acquiree. Transaction costs are expensed directly to the Income
Statement. The acquiree's identifiable assets, liabilities and
contingent liabilities that meet the conditions for recognition
under IFRS 3 are recognised at their fair value at the acquisition
date. Where the Group has acquired assets held in a subsidiary
undertaking that do not meet the definition of a business
combination, purchase consideration is allocated to the net assets
acquired and the interests of non-controlling shareholders are
initially measured at their proportionate share of the acquiree's
net assets.
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:
2017 2016
-------------------------- --------------------------
$ GBP $ GBP
Average rate TTD= $/GBP 6.751 8.831 6.626 9.143
Closing rate TTD= $/GBP 6.771 9.207 6.754 8.401
(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 administrative
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 to sell 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.
-- 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 exist 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 costs. Acquisitions of oil and gas properties are
accounted for under the purchase 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 Geological and Geophysical (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 to sell 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 and amortisation
The provision for depreciation, depletion and amortisation 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
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 to sell 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. If collection is expected
in one year or less (or in the normal operating cycle of the
business if longer), they are classified as current assets. The
Group considers the following as indicators of impairment:
-- Collectability is in doubt
-- Age of the receivable
-- Cashflow position of the debtor
Trade receivables are recognised initially at fair value less
provision for impairment. Appropriate provisions for estimated
irrecoverable amounts are recognised in the statement of
comprehensive income when there is objective evidence that the
Group will not be able to collect all amounts due according to the
original terms of sale.
Trade payables
Trade payables are recognised initially at fair value and
subsequently measured at amortised cost using the effective
interest method.
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
Property taxes 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 Property tax rate. The
Property tax rate applicable to the Group are industrial with
building rates at 6% and industrial without building 3%.
Revenue recognition
Revenue is measured at the fair value of the consideration
received or receivable. Amounts disclosed as revenue are net of
returns, trade allowances, rebates and amounts collected on behalf
of third parties.
The Group recognises revenue when the amount of revenue can be
reliably measured, it is probable that future economic benefits
will flow to the entity and specific criteria have been met for
each of the Group's activities as described below. The Group bases
its estimates on historical results, taking into consideration the
type of customer, the type of transaction and the specifics of each
arrangement. The specific accounting policies for the Group's main
types of revenue are explained in Note 3.
Other income is recognised when earned unless collectability is
in doubt.
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 comprise
convertible loan notes that can, in certain circumstances, be
converted to share capital at the option of the holder, and the
number of shares to be issued does 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 Operating 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 2017, 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 $2.1 million (2016: $0.8
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 2017, if commodity prices had been 20%
higher/lower with all other variables held constant, post-tax
profit/(loss) for the year would have been $8.7million (2016:
$7.0million) lower/higher. The sensitivity doesn't take into
consideration the impact of the put options and zero cost collar 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 2017, there were no loan commitments to attract
interest rates on foreign currency-denominated borrowings. However
in 2016 if the interest had been 1% higher/lower with all other
variables held constant, post-tax (loss)/profit for the year would
have been $0.1 million lower/higher, mainly as a result of
higher/lower interest expense on floating rate borrowings.
(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 - the Petroleum
Company of Trinidad & Tobago ("Petrotrin") and management
assesses risk based on the credit quality of the customer, their
financial position and past experience. The compliance with credit
terms are monitored regularly by management.
(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 $11.8 million (2016:$7.6
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 "Going
Concern" for more information regarding the factors considered by
the Company in managing liquidity risk.
The tables below analyse 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 2017 $'000 $'000 $'000 $'000 $'000
Non-derivatives
Trade and other payables 10,092 881 -- 10,973 10,973
Convertible loan notes
(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
At 31 December 2016
Non-derivatives
Trade payables 42,799 -- -- 42,799 42,799
Borrowings (including
interest) 10,766 -- -- 10,766 10,766
Total Non-derivatives 53,565 -- -- 53,565 53,565
---------- ----------- ----------- ------------------ ---------
(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 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 debt.
2017 2016
$'000 $'000
---------- ---------
Convertible loan notes and borrowings* 3,019 9,950
Less: cash and cash equivalents (11,792) (7,615)
---------- ---------
Net (cash)/debt (8,773) 2,335
Total equity 48,590 11,252
---------- ---------
Total capital 39,817 13,587
Gearing ratio (22.0)% 17.2%
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. 2016 relates to the
outstanding principal balance on the (Citibank Trinidad &
Tobago) Limited loan.
(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).
The following table presents the Group's financial assets and
liabilities that are measured at fair value at 31 December
2017.
Level 1 Level 2 Level 3 Total
------------------- --------- --------- -------- ------
$'000 $'000 $'000 $'000
Liabilities
Zero cost collar -- -- 762 762
Total liabilities -- -- 762 762
=================== ========= ========= ======== ======
The Group had no financial assets and liabilities measured at
fair value at 31 December 2016.
Fair value measurements using significant unobservable inputs
(Level 3)
Zero cost
Put options collar
$'000 $'000
1st January 2017 -- --
Purchased 600 --
Losses recognised (600) (762)
31 December 2017 -- (762)
============ ==========
Put Options / Zero Cost Collar - For put/call options at fair
value through the profit or loss, an assessment of oil price
movement in terms of the volatility at 31 December 2017 was done
recognising a charge of $1.4 million (2016: nil). The charge was
included within 'Other expenses' in the consolidated statement of
comprehensive income.
Group's valuation processes
The Group's finance department includes a team that performs the
valuations of financial assets required for financial reporting
purposes, including Level 3 fair values. For valuations requiring
the use of experts the Group outsources this function to qualified
experts. This team reports directly to the Chief Financial Officer
("CFO") who in turn reports to the Audit Committee ("AC").
Discussions of valuation processes and results are held between the
CFO and AC at least twice per year, in line with the Group's year
end reporting dates.
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
recognises 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 to the local market.
The provision has been estimated using specific risk free rates for
each asset ranging between 3.09%-4.65% (2016: 3.9%) and a core
inflation rate of 3% (2016: 3%), See Note 26. The impact in 2017 of
a 1% change in these variables is as follows:
Statement of Statement of
Financial Position Comprehensive
Obligation Income/Expense
2017 2017
$'000 $'000
-------------------- --------------------
(Decrease)/Increase (Decrease)/Increase
Discount rate
1% increase in assumed rate (5,614) 120
1% decrease in assumed rate 6,785 (205)
Inflation rate
1% increase in assumed rate 6,804 330
1% decrease in assumed rate (5,725) (275)
(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 2017 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 2017 all subsidiaries onshore and offshore
proved and probable ("2P") reserve estimates were re-evaluated by
management and approved by the Board.
(e) Farm outs and lease operatorship agreements
The Group financial statements are prepared on the assumption
that it's Farmout and Lease Operatorship agreements ('LOAs") will
be renewed upon expiry. If any of these Farmout or LOAs are not
renewed or renewed on disadvantageous terms this may severely
impact the profitability and ongoing operations of the Group.
(f) 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.
(g) 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. In order to
test for impairment, the higher of fair value less costs to sell
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 2017 no impairment charge was recognised on the Group's
property, plant and equipment (2016: $2.4 million) see Note 12. In
2016 the impairment charge resulted in the carrying amount of the
respective CGUs being written down to their recoverable amount.
(i) Oil and Gas Assets nil (2016: $1.1 million) 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 VIU. The FVLCOD is the amount that
a market participant would pay for the CGU less the cost of
disposal or utilising a discounted cash flow approach to FVLCOD.
The FVLCOD approach utilised a discounted cash flow based on the 2P
reserve estimates of the CGU's of the Group. The period over which
management has projected its cash flow forecast, ranges between
8-25 year economic lives based on the field economic limit 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.
The forward price curve used was as follows:
Price Strip 2018 2019 2020 2021 2022
USD/bbl 56.7 58.9 62.5 64.2 58.0
If the price deck used in the impairment calculation had been
10% lower than management's estimates at 31 December 2017, the
Group would have nil impairment on the Oil and Gas assets (2016:
$0.7 million increase). If the price deck used in the impairment
calculation had been 10% higher than management's estimates at 31
December 2017, the Group would have nil impairment on the Oil and
Gas assets in 2017 (2016: $0.6 million decrease).
If the estimated cost of capital of 10% (2016: 10%) used in
determining the post-tax discount rate for the CGU's had been 1%
lower than management's estimates the Group would have had no
changes to its impairment position for 2017 (2016: $0.1 million
decrease) 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 had no impairment
changes in 2017 (2016: $0.03 million increase).
(ii) Slant Rig nil (2016:$1.3 million) impairment.
In 2017 there were no impairments on Rigs. The impairment of the
Slant Rig occurred in 2016, since it was last utilised by the Group
in 2013-2014 for offshore drilling on the Trintes field and was not
used afterwards. An impairment test was carried out in 2016 and the
Slant Rig was impaired as the recoverable amount was deemed lower
than the carrying amount. The recoverable amount was determined
using a fair value less cost of disposal estimate provided by a
third party.
(h) Impairment of intangible exploration and evaluation assets
In 2017 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. 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.
All non-current assets of the Group are located in Trinidad &
Tobago.
5 Correction of error in accruing for Property Taxes
Adjustments to the 2016 issued financial statements have been
made as a result of the correction of a prior period omission.
During 2016, the Government of Trinidad and Tobago announced
that property tax, under the Property Tax Act 2009, was to be
reintroduced with effect from 1 January 2016. There were no clear
guidelines provided in terms of the estimation of the annual rental
value upon which the liability was calculated. The Group omitted to
accrue an estimate for 2016 and as a consequence the Property Taxes
had been underestimated.
31 December
2016 2016 2016
$'000 $'000 $'000
Equity and Liabilities Previous Adjustment Restated
Accumulated Losses (195,857) (603) (196,460)
Current Liabilities
Trade and other payables 42,196 603 42,799
The error of omission has been corrected by restating each of
the affected financial statement line items for the prior period as
follows in the Statement of Financial Position extract and
Statement of Comprehensive Income extract below:
31 December
2016 2016 2016
$'000 $'000 $'000
Operating expenses Previous Adjustment Restated
Property taxes -- 603 603
Basic and diluted earnings per share for 2016 have also been
restated. The amount for the correction for both basic and diluted
earnings per share was a decrease of $0.01 cents per share.
6 Operating Profit Before Exceptional Items
2017 2016
$'000 $'000
------- -------
Operating profit before exceptional items is stated
after taking the following items into account:
Depreciation, depletion and amortisation (Note
12) 7,055 9,539
Employee costs (Note 33 ) 7,475 7,938
Operating lease rentals 675 779
Inventory recognised as expense, charged to operating
expenses 67 67
------- -------
Auditors' remuneration
During the year the Group (including its overseas subsidiaries)
obtained the following services from the Company's Auditors as
detailed below:
2017 2016
$'000 $'000
------- -------
- Fees payable to the Company's auditors' and its
associates for the audit of the parent Company
and consolidated financial statements 192 197
- Fees payable to the Company's auditors' and its
associates for other services:
- The audit of Company's subsidiaries 58 58
- Audit related assurance services - interim review 30 20
Total assurance 280 275
- Tax advisory -- 50
- Other advisory 54 --
------- -------
Total auditors' remuneration 334 325
All fees are in respect of services provided by
PricewaterhouseCoopers LLP (PwC). 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.
7 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.
2017 2016
Exceptional items: $'000 $'000
Secured creditor compromise (6,472) --
Unsecured creditor compromise (15,639) --
Interest on tax compromise (5,247) --
Foreign exchange loss on compromised balance 687 --
Impairment of property, plant and equipment
(Note 12) -- 2,420
Impairment of receivables 234 1,071
Impairment of recompletions 135 --
Impairment of inventory 264 --
Fees relating to corporate restructuring 532 940
Gain on extinguishment of liability (210) --
Release of provision - potential claim -- (1,218)
Release provision for restructuring -- (1,870)
Other provisions -- 712
Unsecured creditor claims -- 545
Gain on disposal of GU-1 -- (954)
Translation difference (2) 29
------------------- ------------------
Exceptional (credit)/charge (25,718) 1,675
=================== ==================
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
Board of Inland Revenue ("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 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
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
Gain on extinguishment of liability - $0.2 million in gain as a
result of accounting for the liability due to the Ministry of
Energy and Energy Industries ("MEEI") at fair value
Exceptional items 2016:
Impairment - $2.4 million charge for impairment. In 2016
impairment reviews were carried out over the non-current and
current assets on the Statement of Financial Position with
impairment losses being recognised on property, plant and
equipment, receivables and payables
Fees relating to corporate restructuring - $0.9 million in fees
relating to the corporate restructuring of the Group include the
Formal Sales Process ("FSP"), the Proposal process and the cost of
advisors incurred in relation to both in 2016
Release of provision: potential claim - In December 2015, a
provision was created in the sum of $1.2 million for a potential
claim, against Trinity Exploration and Production (Galeota)
Limited, for a matter that arose before the merger with the
Bayfield Group. However, due to the elapse in time (4 years ended
September, 2016) for NIKO to make a 'call' for payments under the
Limitations of Certain Actions Act Chapter 7:09, the provision was
reversed in 2016
Other Provisions: restructuring - At the end of 2015 management
held a provision for restructuring totalling $1.9 million which
wasn't utilised because the intending restructuring did not occur
in 2016. Accordingly in line with the Group's policy the
restructuring provision was released at the end of 2016
Other Provisions - $0.7 million
-- $0.5 million provision recognised based on litigation
obligations raised under the Proposal and;
-- $0.2 million revision to the provision recognised for Oilbelt
Services Limited retirement benefit
Unsecured creditor claims - An amount of $0.5 million has been
recognised following a reconciliation to the Proposal filed and
accepted under the Notice of Intention
Gain on disposal of GU-1 - This asset held for sale was disposed
in 2016 for a gain of $1.0 million
8 Finance Costs
2017 2016
$'000 $'000
------ ------
Decommissioning (Note 26) 1,643 1,577
Interest on taxes -- 2,215
Interest on loans 657 941
2,300 4,733
====== ======
9 Income Tax Expense
2017 2016
Current tax $'000 $'000
Petroleum profits tax (926) 1,533
Corporation tax -- 27
Unemployment levy (26) --
Deferred tax
- Current year
Movement in asset due to tax losses (Note
16) 1,317 (3,036)
Movement in liability due to accelerated
tax depreciation (Note 16) (389) (381)
Translation difference (4) (21)
Income tax credit (28) (1,878)
====== ========
The Group's effective tax rate varies from the statutory rate
for UK companies of 19.25% as a result of the differences shown
below:
2017 2016
$'000 $'000
Profit/ (Loss) before taxation 25,320 (9,345)
Tax charge at expected rate of 19.25% (2016:
20%) 4,874 (1,869)
Effects of:
Higher overseas tax rate 10,722 (1,783)
Disallowable expenses (8,635) (745)
Deferred tax asset not recognised (8,960) (5,979)
Tax loss generated not recognised -- (1,197)
Tax losses utilised 7,630 9,993
Tax losses previously recognised (5,496) (2,420)
Green fund levy 149 151
Other differences (312) 1,971
Tax credit (28) (1,878)
Taxation losses at 31 December 2017 available for set off
against future taxable profits amounts to approximately $226.1
million (2016: $217.6 million), with tax losses recognised of $7.6
million in 2017. These losses do not have an expiry date and have
not yet been confirmed by the BIR.
10 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.
Earnings Weighted Average Earnings Per
$'000 Number Of Shares Share $
'000'
Year ended 31 December
2017
Basic 25,348 276,746 0.09
Diluted 25,348 395,054 0.06
------------------------------ --------------- ------------------------ -------------------
Year ended 31 December
2016
Basic (7,467) 94,800 (0.08)
Diluted (7,467) 94,800 (0.08)
------------------------------ -------------- ------------- -------------
Impact of dilutive ordinary shares:
Diluted earnings per share is calculated by adjusting the
weighted average number of ordinary shares outstanding to assume
conversion of all potentially dilutive potential ordinary shares.
The Company has two categories of dilutive ordinary shares: CLNs
and share based payments. The CLNs issued during the year are
considered to be potential ordinary shares and have been included
in the determination of diluted earnings per share. 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 are considered potential ordinary shares. They have been
included in the determination of the diluted earnings per share.
Share options of 1,975,084 are considered potential ordinary shares
and have not been included as the exercise hurdle would not have
been met.
11 Investment In Subsidiaries
Company
2017 2016
$'000 $'000
------ ------
Opening balance 44,802 44,775
Capital contributed to subsidiary 6,395 27
Share based payment 219 --
Closing balance 51,416 44,802
====== ======
The investment in Group undertakings is recorded at cost less
impairments which is the fair value of the consideration paid.
Listing of Subsidiaries
The Group's principal subsidiaries at 31 December 2017 are
listed below:
Name Registered Address/Country Nature % Shares held
of Incorporation of Business by the Group
c/o Pinsent Masons LLP,
1 Park Row, Leeds, England, Holding
Bayfield Energy Limited LS1 5AB, United Kingdom Company 99.99998 %
------------------------------ -------------- --------------
Trinity Exploration 13 Queen's Road, Aberdeen, Holding
& Production (UK) Limited AB15 4YL, United Kingdom Company 100 %
------------------------------ -------------- --------------
Trinity Exploration c/o Pinsent Masons LLP,
and Production Services 1 Park Row, Leeds, England, Service
(UK) Limited LS1 5AB, United Kingdom Company 100 %
------------------------------ -------------- --------------
Av. Presidente Vargas 509,
Bayfield Energy do Brasil Rio de Janeiro, 20071-003,
Ltda Brazil Dormant 100 %
------------------------------ -------------- --------------
Trinity Exploration Ground Floor, One Welches,
& Production (Barbados) Welches, Holding
Limited St. Thomas BB22025, Barbados Company 100 %
------------------------------ -------------- --------------
3(rd) Floor Southern Supplies
Limited Building, 40 -44
Trinity Exploration Sutton Street, San Fernando,
and Production (Trinidad Trinidad & Tobago ("Trinidad Holding
and Tobago) Limited address") Company 100 %
------------------------------ -------------- --------------
Galeota Oilfield Services Oil and
Limited Trinidad address Gas 100 %
------------------------------ -------------- --------------
Trinity Exploration
and Production (Galeota) Oil and
Limited Trinidad address Gas 100 %
------------------------------ -------------- --------------
Oil and
Oilbelt Services Limited Trinidad address Gas 100 %
------------------------------ -------------- --------------
Oil and
Ligo Ven Resources Limited Trinidad address Gas 100 %
------------------------------ -------------- --------------
Trinity Exploration
and Production Services Service
Limited Trinidad address Company 100 %
------------------------------ -------------- --------------
Tabaquite Exploration
& Production Company Oil and
Limited Trinidad address Gas 100 %
------------------------------ -------------- --------------
Trinity Exploration
and Production (GOP) Oil and
Limited Trinidad address Gas 100 %
------------------------------ -------------- --------------
Trinity Exploration
and Production (GOP-1B) Oil and
Limited Trinidad address Gas 100 %
------------------------------ -------------- --------------
12 Property, Plant and Equipment
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 17) -- -- (2,868) -- (2,868)
Depreciation, depletion and
amortisation 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 depreciation,
depletion, amortisation 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
=========== ============= ============ ====== ==========
Plant & Leasehold Oil &
Equipment & Buildings Gas Assets Other Total
Year ended 31 December 2016 $'000 $'000 $'000 $'000 $'000
----------- ------------- ------------ ------ ----------
Opening net book amount at
1 January 2016 3,966 1,629 40,548 -- 46,143
Disposal (16) -- -- -- (16)
Additions 19 -- 247 -- 266
Impairment(*) -- -- (2,420) -- (2,420)
Transferred to available for
sale 831 399 26,361 -- 27,591
Depreciation, depletion and
amortisation charge for year (641) (176) (8,722) -- (9,539)
Translation difference 42 38 (2,473) -- (2,393)
----------- ------------- ------------ ------ ----------
Closing net book amount at
31 December 2016 4,201 1,890 53,541 -- 59,632
=========== ============= ============ ====== ==========
At 31 December 2016
Cost 12,815 3,095 275,081 336 291,327
Accumulated depreciation,
depletion, amortisation and
impairment (8,656) (1,243) (219,067) (336) (229,302)
Translation difference 42 38 (2,473) -- (2,393)
----------- ------------- ------------ ------ ----------
Closing net book amount 4,201 1,890 53,541 -- 59,632
=========== ============= ============ ====== ==========
Note (*): An impairment loss of $2.4 million was recognised on
Oil and Gas Assets and Slant Rig (see Note 3 (g (i) (ii)), as a
result of the carrying value being higher than the recoverable
amount. The recoverable amount was determined by utilising its fair
value less costs of disposal.
13 Intangible Assets
The carrying amounts and changes in the year are as follows:
Computer Software Exploration Total $'000
$'000 and evaluation
assets
$'000
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
======================== ====================== ============
At 1 January 2016 -- 26,751 26,751
Translation difference -- (1,345) (1,345)
At 31 December 2016 -- 25,406 25,406
======================== ====================== ============
-- Computer Software: In 2017, a new accounting software was purchased
-- Exploration and evaluation assets: Includes the TGAL-1
exploration well and development costs. The Group tests whether
E&E has suffered any impairment on an annual basis and there
were no impairment triggers (2016: nil)
14 Abandonment Fund
2017 2016
$'000 $'000
At 1 January 1,072 --
Additions 578 --
Reclassified -- 1,072
------ ------
At 31 December 1,650 1,072
====== ======
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.
15 Performance Bond
2017 2016
$'000 $'000
At 1 January -- --
Additions 253 --
At 31 December 253 --
====== ======
A performance bond was put in place on 3 July 2017 for the
Group's Lease Operatorship Assets ("LOA") effective until 31
December 2020. The performance bond is a requirement under the
Lease Operatorship Agreement.
16 Deferred Income Taxation
Group
The analysis of deferred tax assets is as follows:
2017 2016
$'000 $'000
-------- --------
Deferred tax assets:
-Deferred tax assets to be recovered in
more than 12 months (4,179) (5,496)
Deferred tax liabilities:
-Deferred tax liabilities to be settled
in more than 12 months 2,538 2,927
Net deferred tax assets (1,641) (2,569)
======== ========
The movement on the deferred income tax is as follows:
2017 2016
$'000 $'000
-------- --------
At beginning of year (2,569) 848
Movement for the year 928 (3,417)
Net deferred tax asset (1,641) (2,569)
======== ========
Deferred tax assets and liabilities are only offset where there
is a legally enforceable right of offset and there is an intention
to settle the balances net. The deferred tax balances are analysed
below:
2015 Movement 2016 Movement 2017
$'000 $'000 $'000 $'000 $'000
--------- --------- --------- --------- ---------
Deferred tax assets
Acquisition (33,436) -- (33,436) -- (33,436)
Tax losses recognised (31,257) (3,036) (34,293) -- (34,293)
Tax losses derecognised 62,233 -- 62,233 1,317 63,550
--------- --------- --------- --------- ---------
(2,460) (3,036) (5,496) 1,317 (4,179)
========= ========= ========= ========= =========
2015 Movement 2016 Movement 2017
Deferred tax liabilities $'000 $'000 $'000 $'000 $'000
Accelerated tax
depreciation 14,374 -- 14,374 (331) 14,043
Non-current asset
impairment (33,214) -- (33,214) -- (33,214)
Acquisitions 19,580 -- 19,580 -- 19,580
Fair value uplift 2,568 (381) 2,187 (58) 2,129
--------- --------- --------- --------- ---------
3,308 (381) 2,927 (389) 2,538
========= ========= ========= ========= =========
- 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
$1.3 million has been derecognised (2016: $3.0 million was
recognised) based on future taxable profits. The Group has
unrecognised deferred tax asset amounting to $119.6 million which
have no expiry date.
- Deferred tax liabilities have reduced by $0.4 million as the
carrying values of property, plant and equipment and intangible
assets which gave rise to the temporary differences have been
written down to their recoverable amount.
17 Inventories
Crude oil Materials Total
and supplies
$'000 $'000 $'000
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
=========== ======================= ===========
At 1 January 2016 160 3,802 3,962
Inventory movement (40) (135) (175)
At 31 December 2016 120 3,667 3,787
=========== ======================= ===========
(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 2017 amounted to $0.1 million (2016: $0.1 million); these
were included in production costs.
At the end of 2017 an impairment loss of $0.3 million (2016:
nil) was recognised against the materials and supplies inventory.
Write-downs of inventories to net realisable value amounted to $0.0
million (2016: nil). These were recognised within exceptional items
during the year ended 31 December 2017.
18 Trade and Other Receivables
Group Company
---------------- ----------------------
2017 2016 2017 2016
$'000 $'000 $'000 $'000
Due after more than one year
Amounts due from Group companies
(Note 28 (d)) -- -- -- --
------- ------- -------- ------------
Due within one year
Amounts due to related parties
(Note 28 (d)) -- -- 2,447 1,857
Trade receivables 3,272 2,849 -- --
Less: provision for impairment
of trade receivables -- -- -- --
------- ------- -------- ------------
Trade receivables - net 3,272 2,849 2,447 1,857
Prepayments 631 1,140 58 334
VAT recoverable 807 1,315 31 479
Other receivables 445 145 -- --
5,155 5,449 2,536 2,670
======= ======= ======== ============
The fair value of trade and other receivables approximate their
carrying amounts.
At 31 December 2017, trade receivables of $3.3 million (2016:
$2.9 million) were fully performing. Trade receivables that are
less than six months past due are not considered impaired. At the
end of 2016 there was an impairment of $1.1 million relating to a
recoverable amount from the former owners of the WD2 and FZ2
assets. At the end of 2017 there was an impairment of $0.3 million
relating to VAT on invoices that were no longer recoverable.
Ageing analysis of these trade receivables is as follows:
2017 2016
$'000 $'000
Up to 30 days 3,272 2,849
----------------- ------------
3,272 2,849
================= ============
The carrying amount of the Group's trade and other receivables
are denominated in the following currencies:
Group Company
---------------- ----------------
2017 2016 2017 2016
$'000 $'000 $'000 $'000
------- ------- ------- -------
USD 2,631 2,249 2,464 2,167
GBP 60 1,033 72 503
TTD 2,464 2,167 -- --
------- ------- ------- -------
5,155 5,449 2,536 2,670
======= ======= ======= =======
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
-------------- --------------
2017 2016 2017 2016
$'000 $'000 $'000 $'000
------ ------ ------ ------
Trade receivables
Counterparties without external
credit rating:
Existing customers with no defaults
in the past 3,272 2,849 -- --
====== ====== ====== ======
All trade receivables are with the Group's only customer,
Petrotrin.
19 Cash and Cash Equivalents
Group Company
2017 2016 2017 2016
$'000 $'000 $'000 $'000
------- ------ ------ ------
Cash and cash equivalents 11,792 7,615 6,024 758
11,792 7,615 6,024 758
======= ====== ====== ======
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.
20 Share Capital and Share Premium
Number of Ordinary Share premium Total
shares shares $'000
No. $'000 $'000
------------ --------- -------------- --------
As at 1 January 2017 94,799,986 94,800 116,395 211,195
Share Capital Reorganisation 187,600,000 1,876 8,967 10,843
As at 31 December
2017 282,399,986 96,676 125,362 222,038
============ ========= ============== ========
As at 1 January 2016 94,799,986 94,800 116,395 211,195
Movement -- -- -- --
As at 31 December
2016 94,799,986 94,800 116,395 211,195
============ ========= ============== ========
The Company effected a Share Capital Reorganisation ("SCR") on
the 11 January 2017 whereby each existing Ordinary Share was
divided and converted into one new Ordinary Share of a nominal
value of $0.01 each and one Deferred Share of a nominal value of
$0.99 each. The deferred shares have no voting or dividend rights
and on a return of capital on a winding up has no valuable economic
rights. Subsequent to the SCR the Company raised $11.7 million
before expenses by issuing 187,600,000 new ordinary shares at a
placing price of GBP0.0498. The nominal value of the new ordinary
shares are $0.01 each issued at a premium of $0.05 per share.
Share Capital and No. of Ordinary Deferred Share
Share Premium Shares Shares Shares Premium Total
$'000 $'000 $'000 $'000
At 1 January 2017 1.00 94,799,986 94,800 -- 116,395 211,195
Share capital reorganisation 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
21 Share Warrants
The Group's policy with respect to equity-settled share-based
payment transactions is to measure the value of the good or service
received with the corresponding increase in equity at the fair
value of the services received. If the Group cannot estimate
reliably the fair value of the good or services received it then
shall measure their value and the corresponding increase in equity
indirectly by reference to the fair value of the equity
instrument.
2017 2016
$'000 $'000
Oriel Securities Limited -- 71
-- 71
Oriel Securities Limited warrants
The warrants over 62,027 shares which had originally been
granted to Oriel Securities Limited in connection with a 2011
private placing lapsed on the 22 November 2017 in accordance with
the warrant conditions.
22 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 2017 the Group had in place share-based payment
arrangements for its employees and Executive Directors, the Share
Option Plan and the Long Term Incentive Plan ('LTIP'). The charge
in relation to these arrangements is shown below, with further
details of each scheme following:
2017 2016
$'000 $'000
At 1 January 12,244 12,178
Share based payment expense:
Share option expense -- 30
Long term incentive plan 306 36
At 31 December 12,550 12,244
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 2017, 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:
2017 2016
Grant-Vest Expiry Exercise Number Exercise Number
Date price per of Options price per of Options
share 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:
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
Long Term Incentive Plan awards were was granted in August 2017
over 25,415,998 ordinary shares ('2017 LTIP Award"). The 2017 LTIP
Award is designed to provide long-term incentives for Senior
Managers and Executive Directors to deliver long-term shareholder
returns. Under the plan, participants were 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.
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 per cent 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 per cent of the award, repayment of the
amount due to the Board of Inland Revenue of Trinidad and Tobago
("BIR") in accordance with the terms of the Creditors Proposal
approved in 2017. The final payment under the Creditors Proposal is
due on 30 September 2019; and
-- In respect of 10 per cent of the award, redemption of all the
CLNs issued in January 2017 before the second anniversary of their
issue.
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:
2017 Average Number of 2016 Average Number of
exercise price Options exercise price Options
per share option per share option
At 1 January GBP 0.00 189,600 GBP0.00 189,600
Lapsed GBP 0.00 (189,600) GBP0.00 --
Granted during GBP 0.00 25,415,998 -- --
the year
At 31 December GBP 0.00 25,415,998 GBP0.00 189,600
LTIPs outstanding at the end of the year have the following
expiry date and exercise prices:
Expiry Exercise
Grant-Vest date price 2017 2016
2017-2022 2022 GBP 0.00 25,415,998 189,600
The fair value at grant date of the 2017 LTIP awards recognised
during the year ended 31 December 2017 was $0.3 million. The total
fair value of the 2017 LTIP Award will be $2.6 million and this
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. 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 the
2017 LTIP Awards granted during the year ended 31 December 2017
included:
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
23 Merger and Reverse Acquisition Reserves
Reverse Merger Total
Acquisition Reserve
Reserve
$'000 $'000 $'000
At 1 January 2017 (89,268) 75,467 (13,801)
Movement -- -- --
Translation differences -- -- --
At 31 December 2017 (89,268) 75,467 (13,801)
At 1 January 2016 (89,268) 75,467 (13,801)
Movement -- -- --
Translation differences -- -- --
At 31 December 2016 (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. The reverse acquisition difference recorded in
the consolidated financial statements represents the difference in
accounting for reverse acquisition transactions.
24 Convertible Loan Notes
On 11 January 2017 the Company issued at a 50% discount
6,550,000 one dollar, unsecured Convertible Loan Notes ("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 (see Note 27) the Company can before the second anniversary of
the CLNs' issue date, redeem all or a portion of the CLNs 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 CLNs 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.
The fair values of the CLNs' liability and equity component were
determined at the issuance of the Loan note instrument. The CLNs
were recognised in the Statement of Financial Position as
follows:
2017 2016
$'000 $'000
Nominal value of convertible loan notes
issued(1) 6,550 --
Issued at a 50% discount (3,275) --
Fair value of convertible loan notes 3,275 --
Expenses incurred (245) --
Fair value of convertible loan notes (net
of costs) 3,030 --
Equity component (590) --
Liability component at initial recognition 2,440 --
Effective interest 105 --
Interest accrued(2) 474 --
Closing balance 3,019 --
Notes:
(1) The face value amount repayable on the CLN is the nominal
value of $6.6 million plus accrued interest of $0.5 million.
(2) Interest is calculated by applying the effective interest
rate of 23.7% to the liability component.
25 Borrowings
2017 2016
$'000 $'000
Non-current portion:
Citibank (Trinidad & Tobago) Limited -- --
Total -- --
Current portion:
Citibank (Trinidad & Tobago) Limited -- 9,950
Total -- 9,950
On the 23 January 2017 the borrowings from secured lender
Citibank (Trinidad & Tobago) Limited was repaid in full via the
senior debt settlement agreement whereby an amount of $3.5 million
plus interest was paid in lieu of full settlement on the
outstanding balance owed of $10.0 million and the entire financial
liability was extinguished. The compromised balance of $6.5 million
was recognised within exceptional items through the Consolidated
Statement of Comprehensive Income.
26 Provision for Other Liabilities
(a) Non-current: Potential Employee Total
Claim Decommissioning Retirement
cost Benefit
$'000 $'000 $'000 $'000
Year ended 31 December
2017
Opening amount as at 1
January 2017 -- 37,970 348 38,318
Unwinding of discount (Note
8) -- 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
Year ended 31 December
2016
Opening amount as at 1
January 2016 1,270 18,561 -- 19,831
Transferred from other
payables -- -- 118 118
Transferred from liabilities
held for sale -- 21,810 -- 21,810
Revision to employee retirement
benefit -- -- 230 230
Unwinding of discount (Note
8) -- 1,577 -- 1,577
Release of provision (1,218) -- -- (1,218)
Decommissioning contribution -- (1,939) (1,939)
Translation differences (52) (2,039) -- (2,091)
Closing balance at 31 December
2016 -- 37,970 348 38,318
Decommissioning cost
The Group operates Oil and Gas 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 and MEEI. Furthermore,
liabilities for decommissioning costs are recognised when the Group
has an obligation to dismantle and remove a facility or an item of
plant and to restore the site on which it is located, and when a
reasonable estimate of that liability can be made. An obligation
for decommissioning may also crystallise during the period of
operation of a facility through a change in legislation or through
a decision to terminate operations.
The amount recognised is the present value of the estimated
future expenditure determined in accordance with local conditions
and requirements. A corresponding item of property, plant and
equipment of an amount equivalent to the provision is also created.
This is subsequently depreciated as part of the capital costs of
the facility or item of plant. Any change in the present value of
the estimated expenditure is reflected as an adjustment to the
provision and the corresponding property, plant and equipment. Some
of the key assumptions made in the present value decommissioning
calculation include the following:
a. Core inflation rate - 3% (2016: 3%)
b. Risk free rate - 3.09% - 4.65% (2016: 3.95%)
c. Estimated market value/decommissioning cost
d. Estimated life of each asset
See Note 3(c) 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
claims
$'000
Year ended 31 December 2017
Opening amount as at 1 January
2017 470
Creditor compromise (355)
Closing balance at 31 December
2017 115
Year ended 31 December 2016
Opening amount as at 1 January --
2016
Provision for litigation
claims 470
Closing balance at 31 December
2016 470
Litigation claims
In 2016 following the creditors' proposal certain claims were
made under the proposal for which the outcome was uncertain and
will be decided by the Court of Trinidad and Tobago. Following the
creditor compromised settlements the Group has provided for the
specific claims made. In 2017 the claims were written down to the
compromised amount.
27 Trade and Other Payables
Group Company
(a) Non- Current: 2017 2016 2017 2016
$'000 $'000 $'000 $'000
Due to BIR Interest on taxes(1) 417 -- -- --
Due to MEEI(2) 231 -- -- --
Other Payables 233 -- -- --
881 -- -- --
Group Company
(b) Current: 2017 2016 2017 2016
$'000 $'000 $'000 $'000
Trade payables 555 18,984 67 544
Accruals 2,547 1,880 454 152
VAT payable 272 187 -- --
Other payables 701 3,927 -- 43
Supplemental petroleum and property
taxes 2,626 603 -- --
Amounts due to related parties
(Note 28 (d)) -- -- -- 335
Due to BIR Interest on taxes
and SPT(1) 2,865 15,181 -- --
Due to MEEI(2) 526 2,037 -- --
10,092 42,799 521 1,074
Notes:
1. Due to the BIR under the settlement agreement is interest on
taxes totaling $1.7million and SPT of $1.6million.
2. Financial liabilities due to the MEEI of $2.0 million were
substantially modified based on the new terms of repayment. This
transaction was accounted for as an extinguishment of the original
financial liability and the recognition of a new financial
liability of $1.9 million based on its fair value. During the
period $1.1 million was repaid with a nominal value of $0.9 million
outstanding at 31 December 2017
On 6 January 2017 the High Court of Trinidad and Tobago approved
the unsecured creditors' proposal allowing the Group to settle its
outstanding liabilities with unsecured creditors in accordance with
the unsecured creditor settlement agreement. A total of $15.5
million in unsecured creditors and $5.2 million in interest on
taxes due to the BIR were compromised in accordance with the
unsecured creditor settlements see note 7 Exceptional items.
28 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
2017 2016 2017 2016
$'000 $'000 $'000 $'000
Group subsidiaries:
Trinity Exploration and Production
Services (UK) Limited -- -- 347 (8,620)
Trinity Exploration and Production
(Galeota) Limited -- -- (498) (494)
Trinity Exploration and Production -- -- 910 --
(Trinidad and Tobago) Limited
Trinity Exploration and Production
Services Limited -- -- (168) 158
-- -- 591 (8,956)
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
2017 2016 2017 2016
$'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
2017 2016
$'000 $'000
Salaries and short-term employee benefits 643 806
Post-employment benefits 53 23
Share-based payment (Note 22) 239 67
935 896
(d) Year-end balances arising from sales/purchases of
services
Group Company
2017 2016 2017 2016
$'000 $'000 $'000 $'000
Receivables from related parties:
Trinity Exploration and Production
Services Limited -- -- 688 856
Trinity Exploration and Production
(Galeota) Limited -- -- -- 498
Trinity Exploration and Production
(Trinidad) Limited -- -- 909 --
Trinity Exploration and Production
Services (UK) Limited -- -- 850 503
-- -- 2,447 1,857
Payables to related parties:
Trinity Exploration and Production
Services (UK) Limited -- -- -- 335
-- -- -- 335
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 (2016: 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.
29 Derivative financial instruments
31 December 31 December
2017 2016
$'000 $'000
Zero cost collar 762 --
762 --
Derivatives are classified as held for trading and accounted for
at fair value through profit or loss unless they are designated as
hedges. They are presented as current assets or liabilities if they
are expected to be settled within 12 months after the end of the
reporting period.
30 Taxation Payable
Group Company
2017 2016 2017 2016
$'000 $'000 $'000 $'000
Taxation payable
PPT/ UL 66 -- -- --
Due to BIR (PPT, CT and UL)(1) 1,622 2,741 -- --
1,688 2,741 -- --
Notes:
(1.) Due to the BIR under the settlement agreement is PPT; CT
and UL taxes of $1.6 million.(2016: $2.7 million)
31 Financial Instruments by Category
The accounting policies for financial instruments have been
applied to the line items below:
Group Company
2017 2016 2017 2016
$'000 $'000 $'000 $'000
Trade and other receivables -
current 5,155 5,449 2,536 2,670
Abandonment fund - non current 1,650 1,072 -- --
Cash and cash equivalents 11,792 7,615 6,024 758
18,597 14,136 8,560 3,428
The only category of financial assets held by the Group are
loans, receivables and derivative instruments. There are no assets
held at fair value through profit or loss, derivatives used for
hedging and available-for-sale financial instruments.
Group Company
2017 2016 2017 2016
$'000 $'000 $'000 $'000
Borrowings -- 9,950 -- --
Amounts due to related companies -- -- -- 335
Derivative financial instrument 762 -- 762 --
Accounts payable and accruals 10,092 42,799 521 739
10,854 52,749 1,283 1,074
The only category of financial liabilities held by the Group is
liabilities at amortised cost.
32 Commitments and Contingencies
a) Commitments
There are commitments for decommissioning costs of the wells and
facilities under the Group's agreements with Petrotrin, which have
been provided for as described in Note 16.
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
2017 2016
$'000 $'000
Not later than 1 year 518 675
Later than 1 year and no later than 5 years 130 691
648 1,366
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.
33 Employee Costs
Employee costs for the Group during the year 2017 2016
$'000 $'000
Wages and salaries 6,778 7,588
Other pension costs 391 284
Share based payment expense (Note 22) 306 66
7,475 7,938
Average monthly number of people 2017 2016
(including Executive and Non-Executive Directors') number number
employed by the Group
Executive and Non-Executive Directors 5 2
Administrative staff 64 93
Operational staff 122 126
191 221
34 Events after the Reporting Year
On 2 February 2018 the Property Tax (Amendment) Bill was
introduced in the House of Representatives in the Parliament of
Trinidad and Tobago, which seeks to make revisions to the Property
tax regime. The amendments provide for a waiver of the 2016 and
2017 property tax liabilities. This bill is expected to be passed
and assented to in 2018. The potential impact of this would result
in a reduction in Property taxes accrued of $1.1 million.
This information is provided by RNS
The company news service from the London Stock Exchange
END
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