TIDMTRIN
RNS Number : 2949O
Trinity Exploration & Production
27 May 2015
Trinity Exploration & Production Plc
(the "Company" or "Trinity"; AIM:TRIN)
2014 Preliminary Results
27(th) May 2015
Trinity, the leading independent E&P company focused on
Trinidad and Tobago, today announces its preliminary results for
the year ended 31(st) December 2014.
Financial highlights
-- Revenues of USD 113.5 million (2013: USD 123.8 million)
-- EBITDA of USD 28.5 million (2013: USD 34.8 million)
-- General and Administrative costs reduced by 19% to USD 15.0
million (2013: USD 18.5 million)
-- Cash inflow from operating activities of USD 11.8 million (2013: USD 17.0 million)
-- Operating profit before exceptional items of USD 12.2 million (2013: USD 21.6 million)
-- Operating loss after exceptional items of USD 123.7 million (2013: USD 50.4 million profit)
-- Cash balances of USD 33.1 million at 31(st) December 2014 (2013: USD 25.1 million)
-- Post the year end, Trinity ended the first quarter of 2015
with cash and cash equivalents of USD 7.3 million, receivables of
USD 27.2 million (including USD 11.2 million VAT receivables owed
to the Company), inventories of USD 11.5 million, debt of USD 13.0
million, trade & other payables of USD 33.9 million and
taxation payable of USD 18.4 million
-- Moratorium on principal repayments relating to Trinity's
outstanding debt balance until 15 June 2015 agreed with its
lenders
Operating highlights
-- Group average production levels of 3,603 boepd (2013: 3,798 boepd)
-- Final management estimates of 2P reserves of 25.3 mmstb at
the end of 2014, compared to the year-end 2013 reserve estimate of
47.7 mmstb
-- Upgrade to management resource estimate on the TGAL discovery
to Stock Tank Oil Initially in Place ("STOIIP") of 150.0 - 210.0
mmbbls (best estimate, 186.0 mmbbls)
-- Entered into an agreement with Centrica to acquire 80%
interests in Blocks 1(a) & 1(b), containing four undeveloped
but fully appraised gas discoveries (308 bcf, 246 bcf net to 80%)
with the balance of payment due in Q3 2015
- Draft Field Development Plan ("FDP") completed on schedule
- Gas Sales Agreement discussions with potential off-takers well advanced
- Deposit of USD 2.5 million paid in January 2015; remaining USD
20.5 million plus working capital adjustments with interest accrued
due on completion
-- Post year-end, 15% reduction in pre-tax operating expenditure
("opex") with current opex per barrel of USD 21.4/bbl versus USD
25.1/bbl for the month of December 2014, leading to operating break
even across all fields
Outlook
On 8th April 2015, in light of the receipt of a number of
conditional proposals and expressions of interest in relation to
certain of the Company's assets, Trinity announced that it was
launching a strategic review of options open to the Company to
maximise value for shareholders. These options may include, but are
not limited to, a farm-out or sale of one or more of the Company's
existing assets, a corporate transaction such as a merger with or
sale of the Company to a third party or a subscription for the
Company's securities by one or more third parties. The Company is
subject to The City Code on Takeovers and Mergers (the "Code") and
has opted to conduct discussions with parties interested in making
a proposal to the Company under the framework of a "formal sale
process" as set out in the Code in order to enable discussions
relating to a merger or sale of the Company, in particular, to take
place on a confidential basis.
In response to falling oil prices, Trinity has focused on
enhancing its liquidity position by seeking a moratorium on the
principal repayments on its senior secured credit facility,
disposing of non-core assets such as Tabaquite and the WD-16 lease
operatorship block, reducing its operating and general and
administrative costs, obtaining an extension on the purchase
consideration of the 1(a) & 1(b) licences as well as pursuing
all means at its disposal with respect to the collection of
outstanding VAT payments.
Our operational focus remains on managing the portfolio to
optimise production levels and to manage further reductions in
operating costs and general administrative costs to bring all
fields break-even down further. Ensuring the health and safety of
all of our employees will remain our priority.
In addition to our operational cost reductions the
non-executives, have elected to suspend all fees relating to their
roles and Bruce Dingwall has assumed the role of Non-Executive
Chairman (previously Executive Chairman).
Our objective remains to deliver value to shareholders by
sourcing a funding solution to monetise the assets via the
strategic review and formal sales process. However, Trinity
shareholders are advised that there can be no certainty that any
offers will be made as a result of the formal sales process, that
any sale or other transaction will be concluded, nor as to the
terms on which any offer or other transaction may be made.
Joel "Monty" Pemberton, Chief Executive Officer of Trinity,
commented:
"Trinity has reacted quickly to continued global commodity price
volatility. We have reduced the overheads in our business and cut
back on discretionary costs, and as a result have seen a
substantial fall in our general and administrative and operating
costs. At the same time a rigorous subsurface review has resulted
in a significant resource upgrade on the TGAL discovery with a
joint Trintes-TGAL development plan well advanced.
Our core producing asset base continues to yield solid
production levels with declines being modest against a backdrop of
reduced investment. As a result we were able to deliver an
operating profit (pre-exceptionals) of USD 12.2 million and robust
cash conversion levels. This is a testimony to the quality of those
assets and to the hard work and abilities of the Trinity team.
Across the Onshore, West Coast and the East Coast we have an
inventory of drilling locations that could enhance production
levels on the deployment of capital.
The Strategic Review announced in April 2015 is now well
underway with the Board considering a number of options to maximise
and ensure long term value for Trinity's shareholders."
Management will be hosting a conference call for financial
analysts at 13:00 BST to discuss the results. Please contact
TEP@brunswickgroup.com for the details.
Competent Person's Statement:
The information contained in this announcement has been reviewed
and approved by Craig McCallum, Chief Operating Officer for Trinity
Exploration & Production plc, who has over 25 years of relevant
experience in the oil industry. Mr. McCallum holds a Master degree
in Petroleum Engineering.
Enquiries:
Trinity Exploration & Production Tel: +44 (0)13 1240 3860
Joel "Monty" Pemberton, Chief Executive Officer
Tracy Mackenzie, Head of Investor Relations
RBC Capital Markets Tel: +44 (0) 20 7653
Nomad & Joint Broker 4000
Matthew Coakes
Daniel Conti
Oil & Gas Advisory
Jakub Brogowski
Roland Symond Tel: +44 (0) 20 7029
8000
Jefferies (Joint Broker)
Chris Zeal
Graham Hertrich
Brunswick Group LLP (PR Adviser) Tel: +44 (0) 20 7404
Patrick Handley 5959
William Medvei
Non-Executive Chairman's & Chief Executive Officer's
Review
East Coast operations
Average 2014 net production from the East Coast was 1,106
barrels of oil per day (bopd). In line with 2013 average levels of
1,114 bopd.
The Galeota Ridge structure on the East Coast contains the
Trintes field, the TGAL-1 exploration well discovery and various
low risk prospects. Current production comes from the Alpha, Bravo
and Delta platforms in the Trintes field, and whilst on-going steps
to improve operating efficiency have been effective, challenges
remained in sustaining production at a time when capital has not
been deployed towards new drilling.
Earlier in the year production was impacted by the failure of
the D-9 electric submersible pump ("ESP") which contributed to a
loss of 230 bopd. The D-9 ESP was replaced in late June 2014 and
production was restored to its previous level. The B-9X infill well
was successfully completed, following initial problems with mud
pumps, encountering 85 feet of net oil sand in the M-sand and the
original oil water contact for the fault block. During the year
production from the B11XX well was successfully restored and the
B6X well was brought back online after both stopped producing due
to a Variable Frequency Drive ("VFD") failure.
Improved well production management has reduced the need for
workovers as the frequency of wells going offline has decreased.
Moving forward, new drilling could arrest base declines with an
inventory of new well locations identified. These have been
integrated into a joint Trintes-TGAL development plan that aims to
optimise capital allocation across our East Coast fields.
Throughout 2014 several cost saving initiatives were realised on
the East Coast and include; the benefits of a fuel subsidy which
took effect from September 2014, a renegotiation on vessel
transfers with regards to shift systems, and changing cargo vessel
transfers to a spot basis from a monthly fixed basis. Further cost
saving initiatives are ongoing, including additional efficiencies
on shift systems, and installing additional fuel capacity on
platforms which will further reduce the number of cargo vessel
transfers. These moves are working to bring optimum operating
efficiency across East Coast operations and significantly reducing
break-even levels.
Whilst the resource base on the Galeota Block is significant, we
were initially challenged with operations on the Trintes field. We
have now implemented the appropriate commercial, technical and
operational practices to enable value optimisation from this asset.
Our Onshore and West Coast assets are strong producing assets that
have performed broadly in-line with expectations, and all have
promises of further production upside.
West Coast operations
Average 2014 net production from the West Coast was 491 barrels
of oil equivalent per day (boepd). This represents a decline from
2013 average levels of 596 boepd.
Increased workover and recompletion activity on the PGB block in
H1 2014 led to a positive increase in production rates compared to
2013. However, with discretionary capital expenditure limited in H2
2014, average production levels for the year reflect a natural base
decline. The ABM-151 well and ABM-150 well both represent
recompletion ("RCP") opportunities for improving production moving
forward.
Onshore operations
Average 2014 net production from the Onshore was 2,006 bopd.
This represents a modest decline from 2013 average levels of 2,088
bopd.
The focus during 2014 continued on arresting base declines and
increasing production via workovers and RCPs. In 2014, production
levels benefited from 5 new wells which were drilled and completed
in H2 2013. New drilling operations were suspended during H1 2014
while discussions were ongoing with Petrotrin regarding upgrading
the Lease Operatorship Model to improve efficiency, reduce
operating costs and assess enhanced oil recovery opportunities and
other synergies on the combined acreage.
In total, 10 RCPs were conducted in 2014, in addition to the
routine workovers. The PS-575 well was successfully perforated in
the Upper Forest ("UF") 1 and 2 sands and added initial production
of c.200 bopd.
TGAL Development
With management resource estimates on Trinity's TGAL-1 discovery
upgraded to STOIIP of 150.0 - 210.0 mmbbls (best estimate 186.0
mmbbls), work continues apace to have the Field Development Plan
issued. The existing 3D seismic dataset over the TGAL and Trintes
areas has been reprocessed to improve data quality using Common
Reflection Surface ("CRS") technology for the first time on the
East Coast of Trinidad. The results from the application of a
leading edge processing technology were transformative in allowing
Trinity to use the seismic to image the complex subsurface
structure of the Trintes and TGAL fields.
At the end of 2014, the subsurface evaluation was approximately
90% completed, and included integration of seafloor and shallow
seismic data. The topside facility concept has been narrowed down
to two options, and it seems practical to adopt a phased approach
to developing the field by bringing onto production the reserves
nearer to the Trintes field and putting it through a Trintes
facility to shore. The revenues generated would then allow for
reinvestment in other facilities and pipeline.
Acquisition
Trinity has the potential to significantly grow our resource
base with our agreement to acquire Centrica plc's 80% ownership of
Blocks 1(a) & 1(b), potentially adding c.40.0 mmboe of 2C
resources. The asset is fully appraised with six existing wells and
a high quality 3D dataset having established excellent reservoir
quality and proven well deliverability located in shallow (20-35m)
water. Post development, a plateau production rate of 80.0 mmcf/d
(64.0 mmcf/d or 10,700 boepd net) is forecast. The acquisition is
pending completion with the balance of payment of USD 20.5 million
plus working capital adjustments with interest accruals due in Q3
2015.
Reserves and Resources
A comprehensive management review of all assets has recently
been concluded and has estimated the current 2P reserves to be 25.3
million stock tank barrels (mmstb) at the end of 2014, compared to
the year-end 2013 reserve estimate of 47.7 mmstb. The subsurface
review has defined investment programmes and constituent drilling
targets to commercialise the reserves as detailed, by asset area,
in the table below. The 2P reserve estimate is based on a fully
funded programme under the assumption that management will secure
the funding required to deliver this programme.
Management Estimates: 2P Reserves
31-Dec-13 2014 Prod'n Revisions 31-Dec-14
ASSETS mmstb mmstb mmstb mmstb
------------ ----- ---------- ------------ ---------- ----------
East Coast Oil 36.3 (0.4) (21.3) 14.6
Onshore Oil 6.8 (0.7) 0.7 6.8
West Coast Oil 4.6 (0.2) (0.5) 3.9
TOTAL 47.7 (1.3) (21.1) 25.3
=================== ========== ============ ========== ==========
The primary reduction in reserves is attributable to the Trintes
field, on the East Coast, and is due to a revised view of the
reservoirs potential in a lower commodity price world where capital
allocation is constrained.
During 2014 significant progress has been made preparing the FDP
for the TGAL discovery and a comprehensive subsurface evaluation of
the Trintes Field was subsequently completed. On this basis, a
total of c. 7.3 mmstb has been re-categorized from 2P reserves into
2C resources at Trintes. Further development potential exists along
the Galeota anticline to the NE where almost 300.0 mmstb of STOIIP
has been mapped through the integration of 3D Seismic data and the
EG-3 and EG-4 wells that define and tie the dataset to the North
East.
The TGAL discovery has estimated gross 2C resources of 22.1
mmstb (14.4 mmstb net to Trinity's 65.0% interest), a modest
recovery factor of 12% based on STOIIP best estimate of 186.0
mmstb. Therefore, notwithstanding further, identified potential in
the Galeota block, estimated combined 2P and 2C resources from the
Trintes-TGAL area totals over 36.0 mmstb.
Financial review
In 2014 Trinity generated USD 12.2 million operating profit and
a USD 141.2 million loss after tax due to exceptional
items(principally asset impairment and exploration costs written
off), finance costs, currency translation and taxation of USD 135.9
million, USD 5.1 million, USD 0.2 million and USD 12.7 million
respectively.
Statement of Comprehensive Income
Trinity's financial results for 2014 showed a Total
Comprehensive Loss of USD 141.2 million (2013: USD 38.8 million
loss) on gross revenues of USD 113.5 million.
Operating Revenues
2014 revenues were USD 113.5 million (2013: USD 123.8 million).
This decrease is mainly attributable to the combination of (i)
lower production across all assets and (ii) the decline in average
realised oil price of USD 85.8/bbl (2013: USD 91.6/bbl)
-- Production
- Production for 2014 was 1.3 mmbbls (2013: 1.4 mmbbls)
- Average production was 3,603 bopd, with 56% (2,006 bopd) sold
onshore, 14% (491 bopd) attributable to the west coast and 30%
(1,106 bopd) from the east coast
-- Oil prices
Realised oil price for 2014 averaged USD 85.8/ bbl (2013: 91.6/
bbl)
Operating Expenses
-- Operating expenses were USD 101.3 million (2013: USD 102.2
million) which are made up as follows:
- Royalties of USD 37.0 million (2013: USD 37.3 million)
- Production costs of USD 32.9 million (2013: USD 33.1 million)
- Depreciation, depletion and amortisation amounted to USD 16.3 million (2013: USD 13.2 million)
- General and administrative expenses of USD 15.0 million (2013: USD 18.5 million)
Operating Profit before Exceptional Items
Operating profit before exceptional items amounted to USD 12.2
million (2013: USD 21.6 million)
Exceptional items
Exceptional items amounted to USD 135.9 million (2013: USD 28.8
million loss) comprising mainly of the following:
- Impairment loss of USD 96.2 million of property, plant and
equipment assets was recognised on the carrying values of oil and
gas assets due to lower forward oil prices. Impairment of the
exploration well EG-8 c. USD 22.6 million on the basis that
sufficient data exist to indicate that the book value will not be
recovered due to the absence of commercial reserves. The Pletmos
exploration costs of c. USD 0.9 million have been impaired as there
is no further exploration and evaluation planned or budgeted and
management is in the process of relinquishing the license
- Exploration write off of the El Dorado 1 well of USD 14.9 million
- Exceptional items of USD 1.2 million represents a provision
for a potential claim against a subsidiary of the Group by a
supplier of services in the oil and gas industry
Operating Loss after Exceptional Items
The Group's operating loss after exceptional items was USD 123.7
million (2013: USD 50.4 million profit).
Net Finance Costs
In 2014 finance costs amounted to USD 5.1 million (2013: USD 2.4
million), which is made up of the unwinding of the decommissioning
liability USD 1.5 million (2013: USD 1.2 million) and interest on
the fully drawn (USD 20.0 million & USD 25.0 million) Citibank
loans of USD 3.6 million (2013: USD 1.2 million).
Taxation
The tax charge for 2014 was USD 12.7 million (2013: USD 9.5
million), and its components are described below.
- Supplemental Petroleum Tax (SPT): All SPT due for 2013 was
paid as it fell due. The SPT charge for 2014 amounted to USD 14.9
million which is still payable (2013: USD 10.4 million)
- Petroleum Profits Tax (PPT): The PPT charge for the year was
USD 1.1 million (2013: USD 5.8 million), mainly incurred by Oilbelt
Services Limited and Lennox Petroleum Services Limited
- Corporation tax (CT): The CT for the year amounted to USD 2.2 million (2013: USD 0.9 million)
- Deferred tax: There was a decrease in the deferred tax asset
and deferred tax liability by USD 37.1 million and USD 42.6 million
respectively. Hence, the combined movement resulted in a net credit
of USD 5.5 million (2013: USD 7.7 million)
Total Comprehensive Income
Trinity's financial results for 2014 showed a Total
Comprehensive Loss of USD 141.2 million (2013: USD 38.8 million
loss) on gross revenues of USD 113.5 million (2013: USD 123.8
million).
Statement of Cash Flows
The opening cash balance as at 1(st) January 2014 was USD 25.1
million and the ending cash balance at 31 December 2014 was USD
33.1 million.
Changes in Working Capital
During the year Trinity experienced working capital outflows of
USD 12.8 million. Significant changes are outlined in the table
below:
Uses of Cash Sources of Cash
USD '000 USD '000
Inventory 121
Trade and other receivables 14,792
Trade and other payables 27,742
----------------------------- ------------- ----------------
Change in Working Capital 12,829
The Company paid taxes of USD 3.8 million in 2014 (2013: USD
25.4 million) which were related to production taxes for 2013.
Liquidity
Trinity's revenues have decreased as a result of a sharp decline
in oil prices, which has in turn limited the Company's ability to
reinvest in its key assets to maintain or grow production. In
addition, Trinity's covenants on its credit facility arrangement
was breached with Citibank (Trinidad and Tobago) Limited. Trinity
repaid USD 20.0 million in February 2015 and received a moratorium
on principal payments until 15(th) June, 2015. Trinity has had and
continues to have pro-active discussions with its principal lender
to manage the repayment profile on the remaining USD 13.0 million
debt balance. Trinity has a working capital deficit of USD 16.7
million (2013: surplus USD 5.3 million).
Operating activities
Cash inflow from operating activities was USD 11.8 million
(2013: USD 17.0 million), being the net effect of:
-- Adjusted profit inflow of USD 28.5 million (2013: 32.0 million)
-- Changes in working capital outflow of USD 12.8 million (2013: inflow of USD 10.5 million)
- VAT refunds due at year-end totalled USD 11.6 million with USD 10.3 million VAT due from the T&T tax authority while USD 1.3 million due from the UK. Notably, VAT refunds of USD 18.3 million were received in 2014
- Taxation paid of USD 3.8 million (2013: USD 25.4 million)
Investing activities
Cash outflow from investing activities was USD 16.9 million
(2013: USD 85.6 million), and is made up of capital expenditure
Capital expenditure during 2014 totalled USD 16.9 million (2013:
USD 92.1 million) with spend occurring across all of the Group's
assets:
-- Exploration and evaluation assets: The majority of
expenditure of USD 5.0 million in 2014 relates to drilling of the
El Dorado 1 exploration well which straddled December 2013 into
February 2014. The total cost of this well was USD 14.9 million
which was classified as exploration cost write off due to
uncommercial reserves being discovered
-- Property plant and equipment: expenditure on property, plant
and equipment for the year was USD 11.9 million (2013: USD 56.7
million). This included:
- Wells drilled: USD 8.7 million was spent to drill 2 wells,
which included 1 onshore well and 1 east coast, both of which were
unsuccessful and had unrealised production
- Infrastructure upgrades: USD 3.2 million was spent on a number
of projects, across the onshore, west coast and east coast assets,
which were required to sustain current production and create
capacity for future production growth
Cash inflow from financing activities
Cash inflow from financing activities was USD 13.0 million
(2013: USD 71.1 million), being the net effect of: Full drawdown of
the Citibank USD 25.0 million facility, Debt repayment and finance
costs:
- Repayment of borrowings of USD 8.0 million (2013: USD 6.2
million) includes principal repayments of both Citibank loans
- Payment of loan finance costs of USD 4.0 million (2013: USD 1.2 million)
Closing Cash Balance
Trinity's cash balance at 31st December 2014 was USD 33.1
million.
Trinity Exploration & Production Plc
Consolidated and Company Financial Statements
(Expressed In United States Dollars)
31st December, 2014
Trinity Exploration & Production Plc
Consolidated Statement of Comprehensive Income for the year ended
31st December, 2014
(Expressed in United States Dollars)
--------------------------------------------------------------------------------------------
Notes 2014 2013
$'000 $'000
Operating Revenues
Crude oil sales 113,319 123,585
Other income 144 234
------------ --------------
113,463 123,819
Operating Expenses
Royalties (36,980) (37,343)
Production costs (32,931) (33,099)
Depreciation, depletion and amortisation 5 (16,335) (13,211)
General and administrative expenses (15,019) (18,539)
------------ --------------
(101,265) (102,192)
------------ --------------
Operating Profit Before Exceptional
Items 12,198 21,627
Exceptional Items 29 (120,939) 28,766
Exploration cost write off (14,929) --
Operating (Loss)/Profit After Exceptional
Items 19 (123,670) 50,393
Finance Income 33 --
Finance Costs 20 (5,151) (2,357)
(Loss)/Profit Before Income Tax (128,788) 48,036
Income Tax Expense 21 (12,657) (9,481)
------------ --------------
(Loss)/Profit For The Year (141,445) 38,555
Other Comprehensive Income:
Items that may be subsequently reclassified
to profit or loss
Currency Translation 263 277
------------ --------------
Total Comprehensive (Loss)/Income For
The Year (141,182) 38,832
============ ==============
Earnings per share (expressed in
dollars per share)
Basic 30 (1.49) 0.45
Diluted 30 (1.49) 0.43
------------ ----------------
Trinity Exploration & Production Plc
Consolidated Statement of Financial Position
as at 31st December, 2014
(Expressed in United States Dollars)
-----------------------------------------------------------------------------
Notes 2014 2013
ASSETS $'000 $'000
Non-current Assets
Property, plant and equipment 5 85,655 177,592
Intangible assets 6 25,676 59,002
Deferred tax assets 17 27,630 64,693
---------- ----------
138,961 301,287
---------- ----------
Current Assets
Inventories 8 11,909 12,029
Trade and other receivables 7 21,990 36,803
Non-current asset held-for-sale 14 672 --
Taxation recoverable 9 548 528
Cash and cash equivalents 10 33,084 25,145
---------- ----------
68,203 74,505
---------- ----------
Total Assets 207,164 375,792
========== ==========
Equity and liabilities
Equity Attributable to Owners of the Parent
Share capital 11 94,800 94,800
Share premium 11 116,395 116,395
Share warrants 12 71 71
Share based payment reserve 28 11,834 11,523
Merger reserves 13 75,467 74,808
Reverse acquisition reserve 13 (89,268) (89,268)
Translation reserve 527 567
Accumulated (deficit)/surplus (131,070) 10,375
---------- ----------
Total Equity 78,756 219,271
---------- ----------
Non-current Liabilities
Borrowings 15 -- 11,910
Provision for other liabilities 16 39,775 29,027
Deferred tax liabilities 17 3,778 46,387
---------- ----------
43,553 87,324
---------- ----------
Current Liabilities
Trade and other payables 18 33,374 61,117
Borrowings 15 33,000 3,989
Taxation payable 9 18,481 4,091
---------- ----------
84,855 69,197
---------- ----------
Total Liabilities 128,408 156,521
---------- ----------
Total Equity and Liabilities 207,164 375,792
========== ==========
The financial statements on pages 3 to 45 were authorised for
issue by the Board of Directors on 27th May, 2015 and were signed
on its behalf by:
___________________________________
Joel M. C. Pemberton
Chief Executive Officer
27th May 2015
Trinity Exploration & Production Plc
Company Statement of Financial Position
as at 31st December, 2014
(Expressed in United States Dollars)
------------------------------------------------------------------------------
Notes 2014 2013
ASSETS $'000 $'000
Non-current Assets
Investment in subsidiaries 22 44,513 94,401
Trade and other receivables 7 10,106 160,760
---------- -----------
54,619 255,161
---------- -----------
Current Assets
Trade and other receivables 7 1,106 1,007
Cash and cash equivalents 10 10 4,189
---------- -----------
1,116 5,196
---------- -----------
Total Assets 55,735 260,357
========== ===========
Equity and liabilities
Equity Attributable to Owners of the Parent
Share capital 11 94,800 94,800
Share premium 11 116,395 116,395
Share based payment reserve 1,419 1,127
Merger reserves 56,652 56,652
Accumulated deficit (215,838) (9,991)
---------- -----------
Total Equity 53,428 258,983
---------- -----------
Current Liabilities
Trade and other payables 18 1,147 1,374
Tax payable 1,160 --
----------
2,307 1,374
---------- -----------
Total Liabilities 2,307 1,374
---------- -----------
Total Equity and Liabilities 55,735 260,357
========== ===========
The financial statements on pages 3 to 45 were authorised for
issue by the Board of Directors on 27th May, 2015 and were signed
on its behalf by:
____________________________________
Joel M. C. Pemberton
Chief Executive Officer
27th May 2015
Trinity Exploration & Production Plc
Registered Number: 07535869
Trinity Exploration & Production Plc
Consolidated Statement of Changes in Equity
for the year ended 31st December, 2014
(Expressed in United States Dollars)
----------------------------------------------------------------------------------------------------------------
Year ended 31st Share Share Share Share Reverse Merger Translation Accumulated Total
December, Capital Premium Warrant Based Acquisition Reserve Reserve (Losses)/ Equity
2013 Payment Reserve Retained
Reserve Earnings
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
At 1st January,
2013 34 17,550 71 7,295 -- 52,853 290 (27,180) 50,913
Acceleration of
share options
(note 28) -- -- -- 4,708 -- -- -- -- 4,708
Placing shares
issued (note
11) 47,500 41,523 -- -- -- -- -- -- 89,023
Share options
exercised -- -- -- (411) -- -- -- -- (411)
Shares issued to
previous
equity holders
of TEPL
(note 11 & 13) 25,618 (17,550) -- -- (30,421) 22,353 -- -- --
Legacy TEP Plc
share capital 21,648 80,817 -- -- (58,800) -- -- -- 43,665
Cost of raising
equity
(note 11) -- (5,945) -- -- -- -- -- -- (5,945)
Share options
granted (note
28) -- -- -- 187 -- -- -- -- 187
LTIP's granted
(note 28) -- -- -- 88 -- -- -- -- 88
Legacy share
options (note
28) -- -- -- (262) -- -- -- -- (262)
Non-controlling
interest -- -- -- -- -- -- -- (1,000) (1,000)
Translation
difference -- -- -- (82) (47) (398) -- -- (527)
Comprehensive
income for
the year -- -- -- -- -- -- 277 38,555 38,832
-------- --------- -------- --------- ------------ --------- ------------ ------------ -----------
At 31st
December, 2013 94,800 116,395 71 11,523 (89,268) 74,808 567 10,375 219,271
======== ========= ======== ========= ============ ========= ============ ============ ===========
At 1st January,
2014 94,800 116,395 71 11,523 (89,268) 74,808 567 10,375 219,271
Share based
payment charge
(note 28) -- -- -- 163 -- -- -- -- 163
Translation
difference -- -- -- 148 -- 659 (303) -- 504
Comprehensive
loss for
the year -- -- -- -- -- -- 263 (141,445) (141,182)
-------- --------- -------- --------- ------------ --------- ------------ ------------ -----------
At 31st
December, 2014 94,800 116,395 71 11,834 (89,268) 75,467 527 (131,070) 78,756
======== ========= ======== ========= ============ ========= ============ ============ ===========
Trinity Exploration & Production Plc
Company Statement of Changes in Equity
for the year ended 31st December, 2014
(Expressed in United States Dollars)
----------------------------------------------------------------------------------------------------------------------
Share Capital Share Premium Share Based Merger Accumulated Total Equity
Payment Reserve Losses
Reserve
$'000 $'000 $'000 $'000 $'000 $'000
Year ended 31st December, 2013
At 1st January, 2013 21,648 80,817 1,117 34,228 (7,296) 130,514
Shares issued to previous
holders
of TEPL 25,652 -- -- 22,424 -- 48,076
Placing shares issued 47,500 41,523 -- -- -- 89,023
Cost of raising equity -- (5,945) -- -- -- (5,945)
Legacy share option adjustment -- -- (262) -- -- (262)
Share options granted -- -- 226 -- -- 226
LTIP granted -- -- 53 -- -- 53
Translation difference -- -- (7) -- -- (7)
Comprehensive loss for the year -- -- -- -- (2,695) (2,695)
At 31st December, 2013 94,800 116,395 1,127 56,652 (9,991) 258,983
============== ============== ============ ========= ============ =============
At 1st January, 2014 94,800 116,395 1,127 56,652 (9,991) 258,983
Share based payment charge -- -- 292 -- -- 292
Comprehensive loss for the year -- -- -- -- (205,847) (205,847)
At 31st December, 2014 94,800 116,395 1,419 56,652 (215,838) 53,428
============== ============== ============ ========= ============ =============
Trinity Exploration & Production Plc
Consolidated Statement of Cash Flows
for the year ended 31st December, 2014
(Expressed in United States Dollars)
---------------------------------------------------------------------------------
Notes 2014 2013
$'000 $'000
Operating Activities
(Loss)/Profit before taxation (128,788) 48,036
Adjustments for:
Translation difference (232) 79
Finance cost - loans and interest 20 3,985 1,179
Share based payment charge 28 163 4,721
Finance cost - decommissioning provision 16 1,167 1,178
Finance income (33) --
Depreciation, depletion and amortisation 5 16,335 13,211
Goodwill 29 -- 2,746
Negative goodwill 29 -- (52,070)
Abandonment 5 -- 1,624
Potential claim 29 1,270 --
Exploration cost write off 6 14,929 --
Impairment of property, plant and equipment 5 96,242 3,468
Impairment of intangibles 6 23,430 7,786
28,468 31,958
---------- ---------
Changes In Working Capital
Inventories 8 121 (472)
Trade and other receivables 7 14,792 (2,922)
Trade and other payables 18 (27,742) 13,842
15,639 42,406
Taxation paid (3,837) (25,430)
---------- ---------
Net Cash Inflow From Operating Activities 11,802 16,976
---------- ---------
Investing Activities
Purchase of exploration and evaluation
assets 6 (4,970) (35,396)
Purchase of property, plant and equipment 5 (11,941) (56,736)
Cash and cash equivalent acquired in
acquisition -- 6,529
---------- ---------
Net Cash Outflow From Investing Activities (16,911) (85,603)
---------- ---------
Financing Activities
Finance income 33 --
Issue of shares (net of costs) -- 84,868
Repayment of convertible shareholder
loan notes 14 -- (6,355)
Finance cost - loans 20 (3,985) (1,179)
Repayment of borrowings 15 (8,000) (6,217)
Proceeds from new borrowings 15 25,000 --
---------- ---------
Net Cash Inflow From Financing Activities 13,048 71,117
---------- ---------
Increase in Cash and Cash Equivalents 7,939 2,490
========== =========
Cash And Cash Equivalents
At beginning of year 25,145 22,655
Increase in cash and cash equivalents 7,939 2,490
---------- ---------
At end of year 10 33,084 25,145
========== =========
Trinity Exploration & Production Plc
Company Statement of Cash Flows
for the year ended 31st December, 2014
(Expressed in United States Dollars)
-----------------------------------------------------------------------------
Notes 2014 2013
$'000 $'000
Operating Activities
Loss before taxation (204,690) (2,695)
Adjustments for:
Finance income - intragroup loans (8,420) (1,311)
Finance cost - interest on taxes 3 --
Share based payment charge 79 (224)
Impairment of investment in subsidiaries 22 50,100 --
Impairment of intragroup loans 161,569 --
----------
(1,359) (4,230)
Changes In Working Capital
Trade and other receivables 7 (11,013) (75,719)
Trade and other payables 18 (224) (407)
---------- ---------
Net Cash Outflow from Operating Activities (12,596) (80,356)
---------- ---------
Financing Activities
Finance income - intragroup loans 8,420 1,311
Finance cost - interest on taxes (3) --
Share capital issued (net of costs) 11 -- 83,078
----------
Net Cash Inflow from Financing Activities 8,417 84,389
---------- ---------
(Decrease)/Increase In Cash And
Cash Equivalents (4,179) 4,033
========== =========
Cash And Cash Equivalents
At beginning of year 4,189 154
(Decrease) / Increase in cash and
cash equivalents (4,179) 4,033
Exchange rate differences -- 2
---------- ---------
At end of year 10 10 4,189
========== =========
Trinity Exploration & Production Plc
Notes to the Consolidated Financial Statements
31st December, 2014
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 ("TEP Plc") previously
Bayfield Energy Holdings plc ("Bayfield") was incorporated and
registered in England and Wales on 21(st) February, 2011 and traded
on the Alternative Investment Market ("AIM"), a market operated by
London Stock Exchange plc. On 14th February, 2013, Bayfield was
acquired by Trinity Exploration & Production (UK) Limited
("TEPL"), a Company incorporated in Scotland, through a reverse
acquisition. On the 14(th) February, 2013, the enlarged Group was
re-admitted to trading on AIM and Bayfield changed its name to
Trinity Exploration & Production plc. TEP Plc ("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 as adopted by the European Union (IFRS as
adopted by the EU), IFRS Interpretations Committee (IFRS IC)
interpretations as adopted by the European Union 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 $205.8 million (2013 $2.7 million loss) due to the
impairment of intragroup loans and investment in subsidiaries.
Going Concern
In making their going concern assessment, the Directors 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 a much reduced level of
overheads. Discussion with the Group's bankers is ongoing and,
under the assumption that the Group's remaining external debt is
not recalled following expiry of the current moratorium on 15 June
2015, has sufficient cash flow to continue operating for at least
the next 12 months from the date of approval of these financial
statements. However, the Group's intended expenditure for the
development of the business and delivery of its full 2P reserve
potential, exceeds the existing cash reserves and as such the Group
will need to generate additional funding in the near term in order
to continue the development of these operations.
The Company has commenced a formal sales process along with
consideration of alternative funding options including the sale of
one or more existing assets, a farm-out or corporate transaction.
At the date of signing the accounts, a number of conditional
proposals and expressions of interest had been received but not
concluded.
The Board of Directors has carefully considered and formed a
reasonable judgement that, at the time of approving the financial
statements, there is a reasonable expectation that the Company will
be able to obtain sufficient funding to continue operations for the
foreseeable future. For this reason, the Board of Directors
continues to adopt the going concern basis of preparing the
financial statements. However, the need for additional funding
indicates the existence of a material uncertainty which may cast
significant doubt on the Company and the Group's ability to
continue as a going concern and, therefore the Group and Company
may be unable to fully realise their assets and discharge their
liabilities in the normal course of business. The financial
statements do not include the adjustments that would be necessary
if the Group and Company were unable to continue as a going
concern.
New and amended standards adopted by the Group:
The following standards and amendments to existing standards
have been published and are effective for periods beginning after
1st January, 2014 but had no significant impact on the Group:
IFRS 10 Consolidated Financial This is a new standard that replaces Periods beginning on / after 1st
Statements existing guidance on this area and January, 2013
introduces new criteria
for determining whether an entity
should be consolidated within the
results of the Group,
with the key determinant now being
whether the Group controls the entity
(ie has the power
to direct the level of returns the
entity makes, and whether the Group
receives variable returns
from the Group.
-------------------------------------- -------------------------------------- --------------------------------------
IFRS 11 Joint Arrangements As with the above, this is a new Periods beginning on / after 1 Jan
standard, which reduces the number of 2013
categories of and therefore
options for accounting for joint
arrangements. Joint ventures are
accounted for using the
equity method, and a joint operator
in a joint operation will recognise
its share of assets,
liabilities, revenues and expenses in
its own financial statements. The
previous accounting
policy choice has been removed.
====================================== ====================================== ======================================
IFRS 12 Disclosure of Interests in This new standard sets out the Periods beginning on / after 1st
Other Entities disclosure requirements in the January, 2013
financial statements in respect
of IFRS 10 and IFRS 11 The key
additional disclosure above those
already required under existing
standards, is that additional
information is required on the
nature, risks and financial effects
of the Company's interests in other
entities.
====================================== ====================================== ======================================
IAS 19 Employee Benefits A further amendment to IAS 19R is Periods beginning on / after 1st
designed to clarify the application July, 2014
of the standard to plans
that require employees or third
parties to contribute towards the
cost of benefits. Contributions
that are linked to service, but do
not vary with the length of the
employee service are to
be deducted from the cost of benefits
earned in the period that the service
is provided. However,
contributions that vary according to
the length of service must be spread
over the service
period. Contributions not linked to
service are reflected in the
measurement of the balance
sheet liability.
-------------------------------------- -------------------------------------- --------------------------------------
IAS 36 Impairment of Assets Some narrow scope amendments have Periods beginning on / after 1st
been made to the Standard, which will January 2014
impact entities who
recognise or reverse an impairment
loss on non-financial assets by
altering some of the associated
disclosure requirements.
-------------------------------------- -------------------------------------- --------------------------------------
IAS 39 Financial Instruments: The amendment clarifies the Periods beginning on / after 1st
recognition and measurement accounting impact on hedge accounting January 2014
when entities novate derivative
contracts to central counterparties
to reduce counterparty risk.
-------------------------------------- -------------------------------------- --------------------------------------
New and amended standards not yet adopted by the Group:
The following standards and amendments to existing standards
have been published and are effective for periods beginning after
1st January, 2014 and have not been applied in preparing these
consolidated financial statement. None of these is expected to have
a significant effect on the Group:
IFRS 15 Revenue from Contracts with The new standard for revenue replaces Periods beginning on / after 1st
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.
-------------------------------------- -------------------------------------- --------------------------------------
IFRS 9 Financial Instruments This is a new accounting standard Periods beginning on / after 1st
that introduces a new classification January 2018
approach for financial
assets and liabilities. The previous
four categories for financial assets
will be reduced
to three, being fair value through
profit and loss, fair value through
other comprehensive
income and amortised cost, and
financial liabilities will be
measured at amortised cost or
fair value through profit and loss.
This may result in additional gains
or losses being recognised
in the Income.
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 31st 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'. A detailed summary
of the business combination and financial implication of this is
provided within note 27.
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.
Revenue recognition
Revenue is measured at the fair value of the consideration
received or receivable and represents amounts receivable for the
sale of crude oil and services provided in the ordinary course of
business, net of discounts and sales related taxes. Revenue is
recognised when goods are delivered and title has passed when the
oil is transferred to Petrotrin's pipelines, at which point revenue
will be recognised. Petrotrin are the group's only customer.
Interest income is accrued on a time basis, by reference to the
principal outstanding and the interest rate applicable, unless
collectability is in doubt.
Share-based payments
The Group operates a number of equity-settled, share-based
compensation plans (warrants/options/long term incentive plans
'LTIP') 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 payment is recognised as an expense. The
total amount to be expensed is determined by reference to the fair
value of the options 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 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.
Where the services provided relate solely to the issue of share
capital, the expense will be charged to equity within the share
premium account.
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
The functional currency of the Group operating entity is
Trinidad and Tobago dollars as this is the currency of the primary
economic environment in which the entities operate. The
presentation currency is United State Dollars which better reflects
the Group's business activities and improves ability of users of
the financial statements to compare financial results with others
in the International Oil and Gas industry. The Statement of
Financial Position is translated at the closing rate and Statement
of Comprehensive Income is translated at the average rate. The
following exchange rates have been used in the preparation of these
accounts:
2014 2013
--------------------------- ---------------------------
USD GBP USD GBP
Average rate TTD= USD/GBP 6.385 10.523 6.416 10.009
Closing rate TTD= USD/GBP 6.359 9.934 6.436 10.580
(b) Transactions and balances
Foreign currency transactions are translated into the functional
currency using the exchange rates prevailing at the dates of the
transactions. Foreign exchange gains and losses resulting from the
settlement of such transactions and from the translation at
year-end exchange rates of monetary assets and liabilities
denominated in foreign currencies are recognised in the statement
of comprehensive income.
Intangible assets
(a) Exploration and evaluation assets
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:
(i) License and property acquisition costs
Exploration and property leasehold acquisition costs are
capitalised within exploration and evaluation assets.
(ii) 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.
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. For the purposes of
assessing impairment, the exploration and evaluation assets subject
to testing are Grouped with existing cash generating units (CGUs)
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.
Property, plant and equipment
(a) Oil and gas assets
Development and Producing Assets - Capitalisation
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 qualify as a
business combination 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.
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.
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 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 value in use. 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.
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.
Decommissioning
Provision for decommissioning is recognised in full 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, 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:
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 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 first in first out (FIFO) method.
Net realisable value is the estimated selling price in the ordinary
course of business, less applicable variable selling expenses.
Materials and supplies are stated at lower of cost and net
realisable value. Cost is determined using the average cost
method.
Cash and cash equivalents
Cash and cash equivalents comprises cash in hand, deposits held
at call with banks and other short-term highly liquid investments
with original maturities of three months or less.
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. If not,
they are presented as non-current assets.
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 initially recognised at fair value.
Current and deferred income taxes
The tax expense for the period comprises current and deferred
tax. Tax is recognised in the statement of comprehensive income,
except to the extent that it relates to items recognised in equity.
In this case the tax is also recognised directly in equity.
The current income tax charge is calculated on the basis of the
tax laws enacted or substantively enacted at the statement of
financial position date 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 recognised, using the liability method,
on temporary differences arising between the tax bases of assets
and liabilities and their carrying amounts in the consolidated
financial information. However, the deferred income tax is 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 or loss. Deferred income tax is determined using tax
rates (and laws) that have been enacted or substantially enacted by
the statement of financial position date and are expected to apply
when the related deferred income tax asset is realised or the
deferred income tax liability is settled.
Deferred income tax assets are recognised only to the extent
that it is probable that future taxable profit will be available
against which the temporary differences can be utilised.
Deferred income tax assets and liabilities are offset when there
is a legally enforceable right to offset current tax assets against
current tax liabilities and when the deferred income taxes assets
and liabilities relate to income taxes levied by the same taxation
authority and the Company intends to settle the balances on a net
basis.
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.
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.
Employee retirement benefits
The Group provides retirement benefits for certain employees in
the form of individual annuity policies. These are defined
contribution arrangements.
For defined contribution plans, the Group pays contributions to
publicly or privately administered pension insurance plans on a
mandatory, contractual or voluntary basis. The Group has no further
payment obligations once contributions have been paid. The
contributions are recognised as employee benefit expenses when they
are due.
Non-current assets (or disposal Groups) held for sale
Non-current assets (or disposal Groups) classified as held for
sale are measured at the lower of carrying amount and fair value
less costs to sell. Non-current assets and disposal Groups are
classified as held for sale if their carrying amount will be
recovered through a sale transaction rather than through continuing
use. This condition is regarded as met only when the sale is highly
probable and the asset (or disposal Group) is available for
immediate sale in its present condition. Management must be
committed to the sale which should be expected to qualify for
recognition as a completed sale within one year from the date of
classification.
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.
Operating segment information
The steering committee is the Group's chief operating
decision-maker. Management has determined the operating segments
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 Chief Executive Officer, Chief Operating Officer and Chief
Financial Officer, that makes strategic decisions in accordance
with Board policy.
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 programme 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 recognized assets and
liabilities which are denominated in a currency that is not the
entity's functional currency.
At 31st December, 2014, if the functional currency had
weakened/strengthened by 10 per cent against the US dollar with all
other variables held constant, post- tax(loss)/profit for the year
would have been $1.8 million (2013: $3.2 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 31st December, 2014, if commodity prices had been 1 per cent
higher/lower with all other variables held constant, post-tax
(loss)/profit for the year would have been $0.6 million (2013: $1.2
million) lower/higher.
(iii) Interest rate risk
The Group's interest rate risk arises from borrowings.
Borrowings issued at variable rates expose the Group to cash flow
interest rate risk.
At 31st December, 2014, if interest rates on foreign
currency-denominated borrowings had been 1 per cent higher/lower
with all other variables held constant, post-tax (loss)/profit for
the year would have been $0.3 million (2013: $0.2 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 and committed
transactions. For banks and financial institutions, management
determines the placement of funds based on its judgement and
experience.
All sales are made to a state-owned entity - Petrotrin. As
Petrotrin is state owned, credit risk is considered to be low.
(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 is facing liquidity issues over its current
liabilities which include Borrowings, Accounts payable, accruals
and taxes. The Groups' revenues have decreased as a result of a
sharp decline in oil prices impacting the main source of revenue
generation. In addition, the Group's credit facility arrangement
was breached with Citibank Trinidad and Tobago Limited requiring
repayment of $20.0 million in 2015, with the balance repayable
following a moratorium to June 2015 should the breach continue. The
Group has a working capital deficit of $16.7 million (2013: surplus
$5.3 million). Management has suspended investment in appraisal and
development activities and is continuing to manage its
relationships with the Bank and Suppliers in an effort to handle
the liquidity issue.
Management refers to the disclosures of note 1 "Going Concern"
for more information regarding the factors considered by the
Company in managing liquidity risk. The table below analyses the
Group's financial liabilities into relevant maturity groupings
based on the remaining period at the statement of financial
position to the contractual maturity date. The amounts disclosed
are the contractual undiscounted cash flows.
Less than Between 2
1 year and 5 years
$'000 $'000
---------- -------------
At 31st December, 2014
Borrowings (including interest) (note 33,414 --
15)
Accounts payable, accruals and taxes 51,855 --
(note 18,9)
At 31st December, 2013
Borrowings (including interest) (note
15) 5,197 18,137
Accounts payable, accruals and taxes 65,208 --
(note 18,9)
(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. At the end of 2014 the Citibank debt service
coverage ratio was breached (note 15).
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 (including 'current and non-current borrowings' as
shown in the consolidated statement of financial position) less
cash and cash equivalents. Total capital is calculated as 'equity'
as shown in the consolidated statement of financial position plus
net debt.
2014 2013
$'000 $'000
--------- ---------
Total borrowings 33,000 15,899
Less: cash and cash equivalents (33,084) (25,145)
--------- ---------
(Funds)/net debt (84) (9,246)
Total equity 78,756 219,271
--------- ---------
Total capital 78,672 210,025
--------- ---------
Gearing ratio (0.11)% (4.40)%
Fair value estimation
The carrying values of trade receivables (less impairment
provision) and payables are assumed to approximate their fair
values. The fair value of financial liabilities for disclosure
purposes is estimated by discounting the future contractual cash
flows at the current market interest rate that is available to the
Group for similar financial instruments.
3 Critical Accounting Estimates and Assumptions
Estimates and judgements are continually evaluated and are based
on historical experience and other factors, including expectations
of future events that are believed to be reasonable under the
circumstances.
Management makes estimates and assumptions concerning the
future. The resulting accounting estimates will, by definition,
seldom equal the related actual results. 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 many 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 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.
(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 oil and
gas industry. The provision has been estimated using a discount
rate of 3.9 per cent (2013: 3.9 per cent) and a core inflation rate
of 3 per cent (2013: 3 per cent). The impact in 2014 of a 1 per
cent change in these variables is as follows:
Statement of Statement of
Financial Position Comprehensive
Obligation Income/Expense
2014 2014
$'000 $'000
-------------------- ----------------
Discount rate
1 per cent increase in assumed rate (6,108) 48
1 per cent decrease in assumed rate 7,415 (142)
Inflation rate
1 per cent increase in assumed rate 7,748 206
1 per cent decrease in assumed rate (6,455) (203)
(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 become available.
The Group estimates its own commercial reserves in 2013 and 2014
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. The Group's reserve estimates are
also evaluated periodically by independent external reserve
evaluators, the last independent external reserve valuation was
done in 2012.
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.
During 2014 all subsidiaries onshore and offshore 2P reserve
estimates were evaluated by management and approved by the Board of
Directors. In 2013 management re-evaluated the reserve estimates
for all assets as a result of new information being available in
respect of planned drilling and development activity.
Effective 1st October, 2013, TEP Plc's joint venture partner
Petrotrin agreed to convert its 35 per cent working interest in the
Trintes field to an Overriding Royalty Agreement 'ORR'. No other
financial consideration is payable beyond the ORR. The impact of
this agreement provides TEP plc with 100 per cent revenue and cost
entitlement in the Trintes field, with an overriding royalty
payable to Petrotrin on crude oil produced in
accordance with the ORR agreement. There have been no changes to these working interests in 2014.
(e) Farm outs and lease operatorship agreements
The Group accounts for its farmout and lease operatorship
agreements on the basis that they will be renewed upon expiry. If
any of these farmout or lease operatorship agreements 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 an
estimate of the timing and amount of cash flows expected to arise
from the CGU, cash generating unit. A CGU represents an individual
field held by TEP plc.
During 2014 an impairment charge was recognised on the Group's
property, plant and equipment of $96.2 million (2013: $ 3.5
million) see note 6, resulting in the carrying amount of the
respective CGUs being written down to their recoverable amount:
CGU Trintes BM PGB WD 5/6 WD 14 WD Total
2
($'million)
Impairment loss (55.7) (19.9) (0.9) (14.3) (0.8) (4.6) (96.2)
----------------- -------- ------- ------ ------- ------ ------ -------
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 expected discounted cash
flows from each CGU. The period over which management has projected
its cash flow forecast, ranges between a 9-16 year economic life
based on the production 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.
This assessment involves judgement as to the likely
commerciality of the asset; its proven and probable ('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.
If the price deck used in the impairment calculation had been 10
per cent lower than management's estimates at 31st December, 2014,
the Group would have recognised a further impairment of Oil and Gas
assets by $17.4 million (2013: $3.0 million) reducing the carrying
value of property, plant and equipment. If the price deck used in
the impairment calculation had been 10 per cent higher than
management's estimates at 31st December, 2014, the Group would have
recognised a lower impairment of Oil and Gas assets by $20.4
million (2013: $3.0 million).
Price deck 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
------------ ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
2014 -- 49.4 56.6 61.6 64.4 66.2 67.3 68.1 68.4 68.4
2013 96.1 88.7 83.8 80.8 78.9 78.0 77.5 77.5 77.5 77.5
If the estimated cost of capital of 10 per cent (2013: 10 per
cent) used in determining the post-tax discount rate for the CGU's
had been 1 per cent lower than management's estimates the Group
would have recognised a lower impairment of $3.1 million (2013:
$0.6 million) against Oil and Gas assets within property, plant and
equipment. If the estimated cost of capital had been 1 per cent
higher than management's estimates the Group would have recognised
a further impairment of $2.9 million (2013: $0.6 million).
(h) Impairment of intangible 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.
The Group has utilised internal management expertise in
determining that the exploration well EG-8 and the exploration
costs accumulated in South Africa were unrecoverable during 2014
(note 6).
An impairment charge of $23.5 million arose in the Trintes and
South Africa CGU's during 2014, resulting in the full impairment of
the Trintes EG-8 exploration well of $22.6 million and South Africa
exploration costs of $0.9 million.
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 in Trinidad
and Tobago the Petroleum Company of Trinidad and Tobago
(Petrotrin). All non-current assets of the Group are located in
Trinidad and Tobago; previously in 2013 an asset with a value of
$1.2 million was located in South Africa. However this was written
off during 2014 see note 6.
5 Property, Plant and Equipment
Plant & Land & Oil &
Equipment Buildings Gas Assets Other Total
$'000 $'000 $'000 $'000 $'000
----------- ----------- ------------ ------ ----------
Year ended 31st December, 2014
Opening net book amount at 1st
January, 2014 6,133 2,558 168,901 -- 177,592
Additions 40 (106) 12,007 -- 11,941
Impairment (1) (note 29) -- -- (96,242) -- (96,242)
Transferred to available for sale
(note 14) -- -- (672) -- (672)
Adjustment to decommissioning
estimate (note 16) -- -- 8,156 -- 8,156
Depreciation, depletion and amortisation
charge for year (1,270) (151) (14,914) -- (16,335)
Translation difference 71 33 1,111 -- 1,215
----------- ----------- ------------ ------ ----------
Closing net book amount at 31st
December, 2014 4,974 2,334 78,347 -- 85,655
=========== =========== ============ ====== ==========
At 31st December, 2014
Cost 12,260 3,125 275,284 336 291,005
Accumulated depreciation, depletion,
amortisation and impairment (7,357) (824) (198,048) (336) (206,565)
Translation difference 71 33 1,111 -- 1,215
----------- ----------- ------------ ------ ----------
Closing net book amount 4,974 2,334 79,347 -- 85,655
=========== =========== ============ ====== ==========
(1) An impairment loss of $96.2 million was recognised in
respect of several CGU's, (see note 3 (g), (2013: $3.5 million) as
a result of a sharp fall in oil prices combined with a downward
revision in 2P reserve estimates. The recoverable amount was
determined by estimating its fair value less costs to sell. In
calculating this impairment, management used a production profile
based on proven and probable reserves estimates and a range of
assumptions, including third party oil price assumptions and a
discount rate assumption of 10 per cent (2013: 10 per cent).
Plant & Land & Oil &
Equipment Buildings Gas Assets Other Total
$'000 $'000 $'000 $'000 $'000
----------- ----------- ------------ ------ ---------
Year ended 31st December, 2013
Opening net book amount at 1st
January 2013 2,071 1,541 61,102 6 64,720
Acquisition (note 27) 911 197 70,525 -- 71,633
Additions 4,203 1,185 51,348 -- 56,736
Well Abandonment -- -- (1,624) -- (1,624)
Impairment (note 29) -- -- (3,468) -- (3,468)
Adjustment to decommissioning
estimate (note 16) -- -- 3,179 -- 3,179
Depreciation, depletion and amortisation
charge for year (944) (342) (11,919) (6) (13,211)
Translation difference (108) (23) (242) -- (373)
----------- ----------- ------------ ------ ---------
Closing net book amount at 31st
December, 2013 6,133 2,558 168,901 -- 177,592
=========== =========== ============ ====== =========
At 31st December, 2013
Cost 12,220 3,231 255,793 336 271,580
Accumulated depreciation, depletion,
amortisation and impairment (5,979) (650) (86,650) (336) (93,615)
Translation difference (108) (23) (242) -- (373)
----------- ----------- ------------ ------ ---------
Closing net book amount 6,133 2,558 168,901 -- 177,592
=========== =========== ============ ====== =========
6 Intangible Assets
The carrying amounts and changes in the year are as follows:
Exploration Goodwill Total
and evaluation $'000 $'000
assets
$'000
At 1st January, 2014 59,002 -- 59,002
Additions 4,969 -- 4,969
Exploration cost write-off (14,929) -- (14,929)
Impairment (note 29) (23,484) -- (23,484)
Translation difference 118 -- 118
---------------------- --------------- ---------------
At 31st December, 2014 25,676 -- 25,676
====================== =============== ===============
At 1st January, 2013 -- 7,856 7,856
Acquisition (note 27) 23,606 -- 23,606
Additions 35,396 -- 35,396
Impairment (note 29) -- (7,786) (7,786)
Translation difference -- (70) (70)
---------------------- ---------------
At 31st December, 2013 59,002 -- 59,002
====================== =============== ===============
The carrying amount of Goodwill arose on the business
combination with Oilbelt Holdings Limited. The entire goodwill
balance has been allocated to the WD 5/6 block which is considered
to be one CGU, cash generating unit. Management re-evaluated the
reserve estimate for all CGU's at the end of 2013 the results of
this report indicated a downward revision in the reserves estimate
of the WD 5/6 onshore block which triggered an impairment
assessment realising an impairment loss of $10.4 million. The
impairment loss was taken against the full amount of goodwill with
the remaining $2.6 million charge attributable to Oil & Gas
assets within the overall property, plant & equipment
impairment (note 5).
The exploration cost write-off relates to the El Dorado-1
exploration well which was deemed unsuccessful as the reserves
encountered were not commercial and the well permanently plugged
and abandoned at a cost of $14.9 million.
An impairment loss of $23.5 million was recognised in 2014
following an impairment review on the carrying value of exploration
and evaluation assets which included:
EG-8: the EG-8 exploration well was drilled in 2012 on
north-east Galeota and suspended as an oil and gas discovery. A
technical study performed in 2014 indicated that the reserves
encountered were not commercial and cannot justify the cost of
developing either the gas or the oil resources encountered. This
led to the impairment of the costs $22.6 million to exceptional
items on the Statement of Comprehensive Income.
South Africa: costs of $0.9 million have been written off on the
basis that TEP Plc has no further exploration or evaluation
activities planned or budgeted for this licence and are in process
of relinquishing the licence for strategic reasons.
7 Trade and Other Receivables
Group Company
---------------- ------------------
2014 2013 2014 2013
$'000 $'000 $'000 $'000
------- ------- -------- --------
Due after more than one year
Amounts due from Group companies -- -- 10,106 160,760
Due within one year
Trade receivables 3,882 12,637 -- --
Less: provision for impairment of
trade receivables -- -- -- --
------- ------- -------- --------
Trade receivables - net 3,882 12,637
Prepayments 3,986 1,906 79 134
VAT recoverable 12,144 20,653 1,027 873
Other receivables 1,978 1,529 -- --
Short term loan receivable -- -- -- --
Receivables from related parties
(note 23 (d)) -- 78 -- --
21,990 36,803 1,106 1,007
======= ======= ======== ========
The Company provides funding to other Group companies.
The fair value of trade and other receivables approximate their
carrying amounts.
At 31st December, 2014, trade receivables of $3.9 million (2013:
$12.6 million) were fully performing. Trade receivables that are
less than three months past due are not considered impaired. At
31st December, 2014, no trade receivables (2013: nil) were impaired
and provided for.
Ageing analysis of these trade receivables is as follows:
2014 2013
$'000 $'000
------- -------
Up to 3 months 3,882 12,637
------- -------
3,882 12,637
======= =======
The carrying amount of the Group's trade and other receivables
are denominated in the following currencies:
2014 2013
$'000 $'000
------- -------
US Dollar 3,606 6,548
British GBP 1,562 873
Trinidad & Tobago Dollar 16,822 29,382
------- -------
21,990 36,803
======= =======
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
----------------- ----------------
2014 2013 2014 2013
$'000 $'000 $'000 $'000
------- -------- ------- -------
Trade receivables
Counterparties without external
credit rating:
Existing customers (more than 6
months) with no defaults in the
past 3,882 12,637 -- --
======= ======== ======= =======
All trade receivables are with the Group's only customer, Petrotrin.
8 Inventories
2014 2013
$'000 $'000
------- -------
Crude oil 346 435
Materials and supplies 11,563 11,594
------- -------
11,909 12,029
======= =======
The cost of inventories recognised as an expense and included in
operating expenses amounted to $0.3 million (2013: $1.2
million).
9 Taxation Recoverable/(Payable)
Group Company
2014 2013 2014 2013
$'000 $'000 $'000 $'000
--------- -------- -------- ------
Taxation recoverable
Production Petroleum Tax (PPT)/Unemployment
Levy (UL) 548 528 -- --
--------- -------- -------- ------
Taxation payable
Production Petroleum Tax (PPT)/Unemployment
Levy (UL) (1,596) (313) -- --
Corporation Tax (1,883) -- (1,160) --
Supplemental Petroleum Tax (SPT) (15,002) (3,778) -- --
--------- -------- -------- ------
(18,481) (4,091) (1,160) --
========= ======== ======== ======
10 Cash and Cash Equivalents
Group Company
2014 2013 2014 2013
$'000 $'000 $'000 $'000
------- ------- ------ ------
Cash and cash equivalents 33,084 25,145 10 4,189
33,084 25,145 10 4,189
======= ======= ====== ======
Included within cash and cash equivalents are $2.8 million
restricted cash which have been put aside in escrow for abandonment
and environmental liabilities in accordance with contractual
obligations to be used any time during the existence of the
contract.
11 Share Capital and Share Premium
Number Ordinary Share premium Total
of shares shares
No. $'000
$'000 $'000
----------- --------- -------------- --------
As at 1st January, 2014 94,799,986 94,800 116,395 211,195
Movement -- -- -- --
As at 31st December,
2014 94,799,986 94,800 116,395 211,195
=========== ========= ============== ========
As at 1st January, 2013 34,182 34 17,550 17,584
Shares issued to previous
equity holders of TEPL 25,617,859 25,618 (17,550) 8,068
Legacy Bayfield share
capital 21,647,945 21,648 80,817 102,465
Share placing 47,500,000 47,500 41,523 89,023
Cost of equity -- -- (5,945) (5,945)
As at 31st December,
2013 94,799,986 94,800 116,395 211,195
=========== ========= ============== ========
On 14th February, 2013 TEPL acquired Bayfield through a reverse
acquisition. Bayfield issued 25,652,041 ordinary shares to the
shareholders of TEPL which gave a 55 per cent controlling interest
in the combined entity. Bayfield changed its name to TEP Plc. On
the same date a total of 47,500,000 shares were issued at GBP1.20
and the Company was readmitted to AIM (note 27). The associated
cost of the share placing was $5.9 million.
12 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.
2014 2013
$'000 $'000
------ -----------
Issued
Oriel Securities Limited 71 71
------ -----------
71 71
====== ===========
Oriel Securities Limited warrants
Oriel Securities Limited ('Oriel') was appointed to assist TEPL
in introducing potential subscribers for private placing of new
ordinary shares in 2011 (the 'Placing'). In consideration for the
services under the engagement, and subject to receipt of the gross
proceeds as a result of the Placing, TEP Plc and Oriel agreed a fee
in cash to the value of $150,000.
In addition to the fees above, Oriel was granted an option by
TEPL over shares equivalent in value to 0.25 per cent (one quarter
of one per cent) of the value of TEPL following the Placing, such
option to be exercisable at the share price at which the new funds
were raised in the Placing. The option can be exercised between the
1(st) and 5(th) anniversary of the option being granted or if later
on the 1(st) anniversary of any flotation.
The Group recognised the warrants in the financial year by
estimating the services received at fair value at the date of the
transaction. In arriving at the fair value of the services received
an estimate was received from Oriel indicating that the cost of the
service had no warrant been included would have been 1.5 per cent
of the Placing. As the cost is associated with the raising of
capital, this expense has been recognised as a deduction from share
premium.
Following the acquisition on 14th February, 2013 Oriel has
confirmed that it does not intend to exercise its 83 TEP Plc
Warrants; Oriel shall hold warrants over 62,027 shares with an
exercise price of $5.60 per share (based on the same conversion
ratio of 747.8 new shares).
13 Merger and Reverse Acquisition Reserves
Reverse Merger Reserve Total
Acquisition
Reserve
$'000 $'000 $'000
------------- --------------- ---------
At 1st January, 2014 (89,268) 74,808 (14,460)
Translation differences -- 659 659
------------- --------------- ---------
At 31st December, 2014 (89,268) 75,467 (13,801)
============= =============== =========
At 1st January, 2013 -- 52,853 52,853
Acquisition (note 27) -- 22,353 22,353
Movement (89,221) -- (89,221)
Translation differences (47) (398) (445)
------------- --------------- ---------
At 31st December, 2013 (89,268) 74,808 (14,460)
============= =============== =========
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. A detailed summary
of the business combination and financial implication of this is
provided within note 27.
14 Non-current assets held for sale
The assets relating to TEP Plc's lease operatorship block WD 16
and farmout block Tabaquite owned and operated by its indirect
subsidiaries Oilbelt Services Limited and Trinity Exploration and
Production (Trinidad and Tobago) Limited have been presented as
held for sale following approval of management and Board of
Directors in 2014 to sell. The completion date for the transaction
is expected in 2015.
(a) Net Book Value of assets of the disposal Group classified as
held for sale
2014 2013
Property, plant and equipment: $'000 $'000
------ ------
WD 16 block 104 --
Tabaquite block 568 --
672 --
====== ======
15 Borrowings
2014 2013
$'000 $'000
Non-current portion:
Citibank (Trinidad & Tobago) Limited -- 11,910
Total -- 11,910
======= =======
Current portion:
Citibank (Trinidad & Tobago) Limited 33,000 3,989
Total 33,000 3,989
======= =======
Drawn Loan Facilities
Citibank (Trinidad & Tobago) Limited Loan 1
The key terms of the loan are as follows:
-- Principal amount $20.0 million
-- Interest rate is set at three month US LIBOR plus 600 basis points per annum
-- Debenture over the fixed and floating assets of Trinity
Exploration and Production (Trinidad and Tobago) Limited and its
subsidiaries.
-- Principal repayment in equal quarterly instalments commencing
on 20th March, 2013 and ending on 20th December, 2017
-- Interest payable monthly in arrears commencing on 20th March, 2013
Citibank (Trinidad & Tobago) Limited Loan 2
The Group negotiated a floating rate medium term facility on
17th August, 2013 of $25.0 million with Citibank (Trinidad &
Tobago) Limited 'Citibank' which at 31st December, 2014 was fully
drawdown.
The key terms of the loan are as follows:
-- Principal amount $25.0 million. Initial drawdown on 22nd
January, 2014 of $5.0 million and a second drawdown of $20.0
million on 4th August, 2014
-- Interest rate is set at three month US LIBOR plus 575 basis
points per annum. The negotiated principal repayments in two
initial quarterly instalments of 16.0 per cent following 6.5 per
cent to 7.0 per cent quarterly instalments commencing on 21st
November, 2014 and ending on 21st August, 2017
-- A $20.0 million repayment of the loan was made in first quarter 2015
Financial covenants applicable to each of the above facilities
are:
-- Minimum debt service coverage 1.4:1
-- Maximum total debt to EBITDA-Operating taxes 2.75:1
-- Minimum EBITDA-Operating taxes to Interest Expense 1.5:1
The carrying value of borrowings is not materially different
from their fair value. At the end of 2014, TEP Plc was not in
compliance with the debt service coverage ratio (the minimum
requirement being 1.4:1, however the actual ratio was c. 1.0:1).
The entire borrowings in 2014 have been classified as current due
to the breach of the debt service coverage ratio. This breach was
disclosed to Citibank, and TEP Plc was required to repay $20.0
million on the 6th February, 2015. Subsequently, a six month
moratorium on repayment of the remaining principal has been agreed
until 15th June, 2015.
Analysis of net debt
At 31st December,
Cash flow 2014
At 1st January,
2014 $'000 $'000 $'000
---------------- ---------- ------------------
Cash and cash equivalents 25,145 7,939 33,084
Financial liabilities - borrowings
current (3,989) (18,611) (22,600)
Financial liabilities - borrowings
non-current (11,910) 1,510 (10,400)
9,246 (9,162) 84
---------------- ---------- ------------------
16 Provisions and Other Liabilities
Potential Decommissioning Total
Claim cost
$'000 $'000 $'000
Year ended 31st December, 2014
Opening amount as at 1st January,
2014 -- 29,027 29,027
Adjustment to estimates (note
5) -- 8,156 8,156
Record potential claim 1,270 -- 1,270
Unwinding of discount (note
20) -- 1,167 1,167
Translation differences -- 155 155
---------- ---------------- -------
Closing balance at 31st December,
2014 1,270 38,505 39,775
========== ================ =======
Year ended 31st December, 2013
Opening amount as at 1st January,
2013 -- 9,891 9,891
Acquisition (note 27) -- 14,869 14,869
Adjustment to estimates (note
5) -- 3,179 3,179
Unwinding of discount (note
20) -- 1,178 1,178
Translation differences -- (90) (90)
---------- ---------------- -------
Closing balance at 31st December,
2013 -- 29,027 29,027
========== ================ =======
Potential claim
The amounts represent a provision for a potential claim against
a subsidiary of the Group by a supplier of services in the oil and
gas industry. The charge is recognised in the statement of
comprehensive income within 'exceptional items'. In management's
opinion these claims will not give rise to any significant losses
beyond the amounts provided at 31st December, 2014. The potential
claim is anticipated to be settled no later than September
2016.
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 and pipeline infrastructures. The amounts are
calculated based on the provisions of existing contractual
agreements with Petrotrin. 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 per cent (2013: 3 per cent)
b. Risk free rate - 3.9 per cent (2013: 3.9 per cent)
c. Estimated market value/decommissioning cost
d. Estimated life of each asset
See note 3(b) for the rates used and sensitivity analysis.
Adjustment to estimates
The Group makes provision for the cost of decommissioning its
oil and gas infrastructure at the completion of their useful lives.
Decommissioning is estimated to be required in various fields
during 2024-2036. In the current year there was an increase in the
provision mainly due to a revision of assumptions used in
determining the estimated cost to decommission the Group's oil and
gas platform facilities of $1.5 million and finalisation of the
decommissioning terms in the PGB block of $6.9 million. There has
been a corresponding increase in the carrying amount of property
plant and equipment (note 5). A study is being done on the
estimated cost to decommission the Group's tank farm facilities
which are not included in the current provision.
17 Deferred Income Taxation
Group
The analysis of deferred tax assets is as follows:
2014 2013
$'000 $'000
--------- ---------
Deferred tax assets:
-Deferred tax assets to be recovered in more
than 12 months (27,630) (51,988)
-Deferred tax assets to be recovered in less
than 12 months -- (12,705)
Deferred tax liabilities:
-Deferred tax liabilities to be settled in
more than 12 months -- 37,403
-Deferred tax liabilities to be settled in
less than 12 months 3,778 8,984
--------- ---------
Net deferred tax asset (23,852) (18,306)
========= =========
The movement on the deferred income tax is as follows:
2014 2013
$'000 $'000
--------- ---------
At beginning of year (18,306) 5,267
Deferred tax assumed on acquisition -- (18,606)
Deferred tax on fair value uplift arising
from acquisition -- 2,746
Movement for the year 3,849 (5,412)
Unwinding of deferred tax on fair value uplift (9,395) (2,247)
Translation differences -- (54)
--------- ---------
Net deferred tax asset (23,852) (18,306)
========= =========
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:
2012 Movement 2013 Movement 2014
$'000 $'000 $'000 $'000 $'000
--------- --------- --------- --------- ---------
Deferred tax assets
Acquisition (410) (33,026) (33,436) -- (33,436)
Tax losses recognised (13,377) (17,880) (31,257) -- (31,257)
Tax losses derecognised -- -- -- 37,063 37,063
--------- --------- --------- --------- ---------
(13,787) (50,906) (64,693) 37,063 (27,630)
========= ========= ========= ========= =========
Deferred tax liabilities
Accelerated tax depreciation 2,364 12,414 14,778 -- 14,778
Non-current asset impairment -- -- -- (33,214) (33,214)
Acquisitions 5,160 14,420 19,580 -- 19,580
Fair value uplift 11,530 499 12,029 (9,395) 2,634
--------- --------- --------- --------- ---------
19,054 27,333 46,387 (42,609) 3,778
========= ========= ========= ========= =========
Deferred income tax assets are recognised for tax loss
carry-forwards to the extent that the realisation of the related
tax benefit through future taxable profits is probable. Deferred
tax assets of $37.1 million have been derecognised as
recoverability is now considered, these continue to be available
for realisation whenever future taxable profits are probable. The
Group has unrecognised tax losses amounting to $118.3 million which
have no expiry date. Deferred tax liabilities have reduced by $42.6
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.
18 Trade and Other Payables
Group Company
---------------- ----------------
2014 2013 2014 2013
$'000 $'000 $'000 $'000
------- ------- ------- -------
Trade payables 16,712 19,224 26 36
Accruals 8,888 37,170 142 92
VAT payable 433 2,289 -- --
Other payables 1,778 1,393 -- --
Amounts due to related parties (note
23 (d)) 5,563 1,041 979 1,246
33,374 61,117 1,147 1,374
======= ======= ======= =======
19 Operating Profit Before Exceptional Items
2014 2013
$'000 $'000
------- -------
Operating profit before exceptional items is stated
after taking the following items into account:
Depreciation, depletion and amortisation (note 5) 16,335 13,211
Employee costs (note 26) 12,781 21,598
Abandonment (note 5) -- 1,624
Operating lease rentals 3,122 1,374
Inventory recognised as expense, charged to operating
expenses 262 1,235
------- -------
Auditors' remuneration
During the year the Group (including its overseas subsidiaries)
obtained the following services from the Company's Auditor as
detailed below:
2014 2013
$'000 $'000
------- -------
- Fees payable to the Company's auditors' and
its associates for the audit of the parent Company
and consolidated financial statements 73 73
- Fees payable to the Company's auditors' and
its associates for other services:
- The audit of Company's subsidiaries 173 167
- Audit related assurance services - interim
review 52 50
- Reporting accountant work in respect of the
merger and admission to trading on AIM -- 318
------- -------
Total assurance 298 608
- Tax advisory -- 26
- Other advisory 48 216
------- -------
Total auditors' remuneration 346 850
All fees are in respect of services provided by
PricewaterhouseCoopers LLP 'PwC' with the majority in prior year
relating to reporting accountants work during the merger of TEP Plc
and Bayfield. The independence and objectivity of the external
auditors is considered on a regular basis by the Audit Committee,
with particular regard to the level of non-audit fees incurred.
20 Finance Costs
2014 2013
$'000 $'000
------ ------
Decommissioning (note 16) 1,167 1,178
Interest on taxes 2,134 --
Interest on loans 1,850 1,179
5,151 2,357
====== ======
Interest on taxes $2.1 million (2013; nil) relate to interest
accrued on late payment of corporation tax, supplemental petroleum
taxes and petroleum profits taxes for 2014.
21 Income Tax Expense
2014 2013
$'000 $'000
Current tax
- Current year
Petroleum profits tax 1,075 5,821
Corporation tax 2,182 926
Supplemental petroleum tax 14,931 10,393
Deferred tax
- Current year
Movement in asset due to tax losses (note 17) 37,063 (17,880)
Movement in liability due to accelerated tax
depreciation (note 17) (33,214) 12,414
Unwinding of deferred tax on fair value uplift (9,396) (2,247)
Translation difference 16 54
Income tax expense 12,657 9,481
========= =========
The Group's effective tax rate varies from the statutory rate
for UK companies of 21.50 per cent as a result of the differences
shown below:
2014 2013
$'000 $'000
---------- -------------
(Loss) /Profit before taxation (128,788) 48,036
Tax charge at expected rate of 21.50 per cent
(2013: 23.25 per cent) (27,677) 11,168
Effects of:
Higher overseas tax rate (43,157) 15,372
Profits not subject to tax -- (32,276)
Disallowable expenses 123,498 11,772
Deferred tax asset not recognised 5,517 20
Tax loss generated not recognised 3,562 915
Tax losses utilised 8,111 --
Tax losses previously recognised (64,693) (626)
Supplemental petroleum tax 7,508 3,110
Green fund levy 83 178
Other differences (95) (152)
---------- -------------
Tax charge 12,657 9,481
========== =============
Taxation losses as at 31st December, 2014 available for set off
against future taxable profits amount to approximately $171.3
million (2013: $127.0 million), with tax losses recognised of $52.9
million. The Finance Act 2013 reduced the UK Corporation tax rate
from 23 per cent to 21 per cent with effect from 1st April 2014. A
further reduction to the UK tax rate was announced to reduce the
rate from 21 per cent to 20 per cent with effect from 1st April
2015. This reduction had not been substantively enacted at the
balance sheet date and, therefore, is not recognised in these
financial statements.
22 Investment In Subsidiaries
Company
2014 2013
$'000 $'000
-------- ------
Opening balance 94,401 46,085
Additions -- 48,076
Capital contribution relating to share based
payment 212 240
Impairment (50,100) --
-------- ------
Closing balance 44,513 94,401
======== ======
The investment in Group undertakings is recorded at cost which
is the fair value of the consideration paid. An impairment loss of
$50.1 million was recognised on the investment in subsidiary as a
result of property plant and equipment impairments recognised in
the operating subsidiaries of the Group due to a sharp fall in oil
prices and a downgrade in reserve estimates of certain fields (see
note 5).
During 2014 Bayfield Energy New Ventures Limited a subsidiary of
Bayfield Energy Limited was wound up.
In December 2014 the Group restructured its Trinidadian
subsidiaries with the aim of reducing the administrative costs
associated with the operations of several individual subsidiaries.
On 15th December 2014 a vertical amalgamation was done with
Antilles Resources Limited, NAKT Company Limited, Pioneer Petroleum
Company Limited, Lennox Production Services Limited and Ten Degrees
North Operating Company Limited 'TDNOCL'. The surviving entity
following the vertical amalgamation was TDNOCL.
On 31st December, 2014 a horizontal amalgamation was done
between TDNOCL and Oilbelt Service Limited 'OSL' and the surviving
entity following the restructuring was OSL, which holds the Group's
onshore and west coast fields.
On 20th November, 2014 Bayfield Energy (St Lucia) Limited was
dissolved.
During 2013 Astrakhanskaya Gas and Oil Company (AGOC), a
subsidiary of Trinity Exploration & Production plc which held
an interest in the Karalatsky licence was wound up. The winding up
of this entity was completed on 5th September 2013.
Listing of Subsidiaries
The Group's principal subsidiaries at 31st December, 2014 are
listed below:
Name Country of Nature of Business Proportion
Incorporation of ordinary
shares held
by the Group
(per cent)
--------------------------------- --------------- ------------------- --------------
Bayfield Energy Limited UK Holding Company 100 per cent
--------------------------------- --------------- ------------------- --------------
Trinity Exploration and
Production Services (UK)
Limited UK Service Company 100 per cent
--------------------------------- --------------- ------------------- --------------
Bayfield Energy (Alpha)
Limited UK Holding Company 100 per cent
--------------------------------- --------------- ------------------- --------------
Trinity Exploration and
Production (Pletmos) Limited UK Oil and Gas 100 per cent
--------------------------------- --------------- ------------------- --------------
Bayfield Energy do Brasil
Ltda Brazil Dormant 100 per cent
--------------------------------- --------------- ------------------- --------------
Trinity Exploration & Production
(Barbados) Limited Barbados Holding Company 100 per cent
--------------------------------- --------------- ------------------- --------------
Trinity Exploration and
Production (Trinidad and Trinidad &
Tobago) Limited Tobago Holding Company 100 per cent
--------------------------------- --------------- ------------------- --------------
Galeota Oilfield Services Trinidad &
Limited Tobago Oil and Gas 100 per cent
--------------------------------- --------------- ------------------- --------------
Trinity Exploration and Trinidad &
Production (Galeota) Limited Tobago Oil and Gas 100 per cent
--------------------------------- --------------- ------------------- --------------
Trinidad &
Oilbelt Services Limited Tobago Oil and Gas 100 per cent
--------------------------------- --------------- ------------------- --------------
Coastline International Trinidad &
Inc. Tobago Oil and Gas 100 per cent
--------------------------------- --------------- ------------------- --------------
Trinidad &
Ligo Ven Resources Limited Tobago Oil and Gas 100 per cent
--------------------------------- --------------- ------------------- --------------
Trinity Exploration and Trinidad &
Production Services Limited Tobago Service Company 100 per cent
--------------------------------- --------------- ------------------- --------------
Tabaquite Exploration & Trinidad &
Production Company Limited Tobago Oil and Gas 100 per cent
--------------------------------- --------------- ------------------- --------------
Trinity Exploration and Trinidad &
Production (GOP) Limited Tobago Oil and Gas 100 per cent
--------------------------------- --------------- ------------------- --------------
Trinity Exploration and Trinidad &
Production (GOP-1B) Limited Tobago Oil and Gas 100 per cent
--------------------------------- --------------- ------------------- --------------
23 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
---------------- -------------------
2014 2013 2014 2013
$'000 $'000 $'000 $'000
------- ------- ---------- -------
Related party:
Well Services Petroleum Company Limited 142 -- -- --
Group subsidiaries:
Bayfield Energy Limited - loan -- -- (89,840) --
Bayfield Energy Alpha - loan -- -- (535) --
Trinity Exploration and Production Services
(UK) Limited - loan -- -- (62) 9,513
Trinity Exploration and Production (Galeota)
Limited - loan -- -- (71,194) 65,400
142 -- (161,631) 74,913
======= ======= ========== =======
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
---------------- ----------------
2014 2013 2014 2013
$'000 $'000 $'000 $'000
------- ------- ------- -------
Purchases of services:
Related party:
Bayfield Energy Limited -- -- -- 5
Blanket Security Limited 794 866 -- --
Rigtech Services Limited 589 996 -- --
Well Services Petroleum Company Limited 9,265 9,875 -- --
Trinity Lift Boat Services Limited 52 -- -- --
Group subsidiaries:
Trinity Exploration and Production Services
(UK) Limited -- -- (267) --
10,700 11,737 (267) 5
======= ======= ======= =======
Goods and services are bought from entities controlled by
certain Non-Executive Director Charles Anthony Brash Junior on
normal commercial terms and conditions, with the majority coming
from the Well Services Group, which includes; Blanket Securities
Limited, Rigtech Services Limited, Well Services Petroleum Company
Limited, Trinity Lift Boat Services Limited and Trinity
Infrastructure Construction Limited.
(c) Key management and Directors' compensation
Key management includes Directors' (executive and
non-executive), the Chief Operating Officer and Chief Financial
Officer. The compensation paid or payable to key management for
employee services is shown below:
Group
----------------
2014 2013
$'000 $'000
------- -------
Salaries and short-term employee benefits 1,958 2,469
Post-employment benefits 137 53
Share-based payment (note 28) 217 2,590
------- -------
2,312 5,112
======= =======
(d) Year-end balances arising from sales/purchases of
services
Group Company
---------------- -----------------
2014 2013 2014 2013
$'000 $'000 $'000 $'000
------- ------- ------- --------
Receivables from related parties:
Well Services Petroleum Company Limited -- 78 -- --
Bayfield Energy Limited - loan -- -- -- 84,659
Trinity Exploration and Production (Galeota)
Limited -- -- 655 66,057
Trinity Exploration and Production Services
(UK) Limited -- -- 9,451 9,513
Bayfield Energy Alpha -- -- -- 531
-- 78 10,106 160,760
======= ======= ======= ========
Payables to related parties:
Blanket Securities Limited 431 164 -- --
Rigtech Services Limited 328 238 -- --
Well Services Petroleum Company Limited 4,804 639 -- --
Trinity Exploration and Production Services
(UK) Limited -- -- 4 4
Trinity Exploration & Production (UK)
Limited -- -- 975 1,242
5,563 1,041 979 1,246
======= ======= ======= ========
Post the year end the Group has endeavoured to reduce the
payables due to related parties through an exchange of casing and
tubing see note 31. Subsequent to this the related party Well
Services Petroleum Company Limited has brought a legal claim
against a subsidiary of the Group to recover the balance owed of
$2.5 million.
Company
Loans to subsidiaries
At the end of 2014 an impairment review on the Company's loan
receivables was carried out by comparing the carrying value of the
loans to subsidiaries against their recoverable amount. From the
borrowers perspective the subsidiaries have been forgiven by TEP
plc and the obligation extinguished. The following are the loan
receivable debt forgiven by TEP plc:
Company
-----------------
2014 2013
$'000 $'000
-------- -------
Trinity Exploration and Production (Galeota) Limited 71,194 --
Bayfield Energy Limited 89,840 --
Bayfield Energy Alpha Limited 535 --
-------- -------
161,569 --
======== =======
Group and Company
The receivables from related parties arise mainly from sale
transactions and are due two months after the date of sales. The
receivables are unsecured and bear no interest. No provisions are
held against receivables from related parties (2013: 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.
(e) Loans from related parties
There are no loans from related parties
24 Financial Instruments by Category
The accounting policies for financial instruments have been
applied to the line items below:
Group Company
---------------- -----------------
2014 2013 2014 2013
$'000 $'000 $'000 $'000
------- ------- ------- --------
Trade and other receivables - non
current -- -- 10,106 160,760
Trade and other receivables - current 21,990 36,803 1,106 1,007
Cash and cash equivalents 33,084 25,145 10 4,189
55,074 61,948 11,222 165,956
======= ======= ======= ========
The only category of financial assets held by the Group is loans
and receivables. There are no assets held at fair value through
profit or loss, derivatives used for hedging and available-for-sale
financial instruments.
Group Company
---------------- --------------
2014 2013 2014 2013
$'000 $'000 $'000 $'000
------- ------- ------ ------
Borrowings 33,000 15,899 -- --
Amounts due to related party -- -- 979 1,246
Accounts payable and accruals 33,374 61,117 168 128
66,374 77,016 1,147 1,374
======= ======= ====== ======
The only category of financial liabilities held by the Group is
liabilities at amortised cost. There are no liabilities held at
fair value through profit or loss and derivatives used for
hedging.
25 Commitments and Contingencies
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
2014 2013
$'000 $'000
Not later than 1 year 529 442
Later than 1 year and no later than 5 years 2,593 932
------ ------
3,122 1,374
====== ======
Contingent Liabilities
i) One of the subsidiaries has received an assessment from the
tax authority of Trinidad and Tobago namely, the Board of Inland
Revenue (BIR), in respect of Petroleum Profits Tax. The subsidiary
has filed a notice of objection with the BIR and until the matters
are determined, the assessments raised are not considered final. No
material unrecorded liabilities are expected to crystallise and
accordingly no provision has been made in these financial
statements.
ii) A subsidiary Company is a defendant in certain legal
proceedings. A claim was made against the subsidiary by Mora Ven
Holdings limited. The claim being made was that the subsidiary
bought the shares of Ligo Ven Resources Limited, a fellow
subsidiary, at gross under-value. Management, after taking
appropriate professional advice, is of the view that no material
liabilities will crystallise and accordingly no provision has been
made in the financial statements for any potential liabilities.
iii) Parent Company guarantees:
a) A Letter of Guarantee has been established over the Point
Ligoure-Guapo Bay-Brighton Block where a subsidiary of TEP Plc is
obliged to carry out a Minimum Work Programme to the value of $8.4
million.
b) A letter of Guarantee is in place with Citibank (Trinidad
& Tobago) Limited for the full $25.0 million loan facility
should there be a default. There was a default at the end of 2014
and a repayment of $20.0 million was made in February 2015. Further
disclosure is made in note 15.
iv) The Group has certain liabilities in respect of entering a
rig share agreement for the Rowan Gorilla III which it used to
drill the TGAL-1 well. The agreement was made amongst four parties
and the liabilities are joint and several. The liabilities cannot
be presently quantified and no estimates have been included in the
financial statements. The Group has incurred in 2014 $0.1 million
of this liability and does not expect that these liabilities will
be material.
v) The Group has certain decommissioning provisions in respect
of the tank farm infrastructure in its Brighton Marine and Trintes
fields, these have not been provided for, as an estimate of the
provision cannot presently be quantified. A study is being
undertaken to determine an appropriate cost.
vi) 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.
26 Employee Costs
Employee costs for the Group during the year 2014 2013
$'000 $'000
-------- --------
Wages and salaries 11,982 16,484
Other pension costs 636 393
Share based payment expense (note 28) 163 4,721
-------- --------
12,781 21,598
======== ========
Average monthly number of people 2014 2013
(including executive and non-executive Directors') number Number
employed by the Group
-------- --------
Executive and non-executive Directors 7 7
Administrative staff 179 138
Operational staff 120 140
306 285
======== ========
27 Business Combination
There were no business combination transactions during 2014. The
summary below relates to the 2013 financial year end.
a) Summary of acquisition
On 14th February, 2013, Trinity Exploration & Production
(UK) Limited (formerly Trinity Exploration & Production
Limited) ("TEPL") acquired Bayfield Energy Holdings plc
("Bayfield") by way of a reverse acquisition.
Whilst Bayfield became the legal parent of the Group on that
date, the shareholders of TEPL obtained control of Bayfield and the
transaction was deemed a reverse acquisition. In order to execute
the transaction Bayfield issued 25,652,041 ordinary shares,
representing 55 per cent of its share capital, to the shareholders
of TEPL in exchange for 100 per cent (34,182 shares) of the share
capital of TEPL. Bayfield changed its name to Trinity Exploration
& Production Plc and was readmitted to trading on AIM on 14th
February, 2013.
The acquisition represented a strategic fit for TEPL as it has
allowed TEPL to acquire production and reserves in a hydrocarbon
basin which it previously had no exposure to whilst simultaneously
providing an opportunity to recapitalize the Company through the
issue of new shares.
Details of the fair value of the assets and liabilities acquired
are as follows:
$'000
================================================ =========
Purchase consideration (refer to b) 40,525
================================================ =========
Fair value of net identifiable assets acquired
(refer to c) 92,595
================================================ =========
Negative goodwill (refer to c) (52,070)
================================================ =========
b) Purchase consideration
The purchase consideration is calculated as the fair value of
all equity instruments of Bayfield (21,647,945 ordinary shares)
prior to the acquisition, based on a share price of GBP1.20 which
was the value of placing shares traded on the day of the admission
and the acquisition being unconditional. An exchange rate of USD:
GBP is used, being $1.56 on the date of the acquisition.
c) Assets and liabilities acquired
Recognised amounts of identified assets acquired and liabilities
assumed:
$'000
============================================ =========
Cash and cash equivalents 6,529
============================================ =========
Trade and other receivables (note 7) 10,735
============================================ =========
Inventories (note 8) 8,224
============================================ =========
Deferred tax asset (note 17) 18,606
============================================ =========
Exploration and evaluation assets (note 6) 23,606
============================================ =========
Property, plant and equipment (note 5) 71,633
============================================ =========
Trade and other payables (note 18) (31,869)
============================================ =========
Decommissioning liability (note 16) (14,869)
============================================ ---------
Fair Value of Net assets 92,595
At the acquisition date, all contractual cash flows are expected
to be collected. The decommissioning liability was increased by
$8.9 million and is in respect of decommissioning of wells and
platform which is expected at the end of the field life when
production ceases. An impairment loss of $11.1 million was
recognised on exploration and evaluation assets in respect of costs
which did not relate to exploration and evaluation activity with a
further reallocation of $1.9 million to property, plant and
equipment. There was an impairment of $1.0 million within property,
plant and equipment for a rig which was in a state of disrepair and
unusable at the acquisition date.
In undertaking the acquisition, costs of $2.3 million were
incurred and have been expensed to the consolidated statement of
comprehensive income as an exceptional item (note 29).
The acquisition of Bayfield by TEPL resulted in a gain or
bargain purchase as defined within IFRS 3, specifically paragraphs
32 and 34. The reason that the net assets acquired was greater than
the consideration transferred was due to the Bayfield Group
experiencing liquidity issues and from a going concern perspective
the Group was distressed. This was the result of lower than
expected cash flows as the underlying production growth was slower
than expected and an inability to secure any additional funding.
This eventually led to the Bayfield Group agreeing to be acquired
by TEPL. The negative goodwill recognised represents that gain
where the aggregate fair value of the identifiable assets and
liabilities at the acquisition date exceeded the fair value of the
consideration transferred. In accordance with IFRS, the gain has
been recognised immediately within the consolidated statement of
comprehensive income as an exceptional item (note 29).
Since the acquisition date, revenue of $34.9 million and loss of
$1.2 million have been included in the consolidated statement of
comprehensive income in respect of Bayfield Energy Holdings plc. If
the acquisition had occurred on 1st January, 2013, the combined
Group would report additional revenue of $4.5 million and loss of
$15.8 million for the period.
28 Share Based Payments
During 2014 the Group had in place two share-based payment
arrangements for its employees and 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:
2014 2013
$'000 $'000
Share based payment expense:
Accelerated share option charge -- 4,708
Share option expense 21 187
Legacy share options adjustment -- (262)
Long term incentive plan 142 88
----------
163 4,721
========== ============
Share Option Plan
Share options are granted to Directors and to selected
employees. The exercise price of the granted option is equal to
management's best estimate of the market price 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 31st December, 2012 TEPL had 3,638 share options outstanding.
On 14th February, 2013 following the completion of the acquisition,
120 of the 3,638 share options were exercised. The remaining 3,518
share options were surrendered in return for the grant by TEP Plc
of new options. 747.8 new ordinary shares were issued for each TEPL
share over which TEPL options were held. These options were treated
as a modification to the original share option scheme. The
modification did not increase the fair value of the equity
instruments granted, measured immediately before and after the
modification, as a result there was no incremental fair value. At
the point of acquisition Bayfield had 4,447,546 share options,
following completion of the acquisition and share consolidation,
the newly combined Group share options outstanding of:
(a) Legacy Bayfield - 444,754 share options
(b) Legacy TEPL - 2,630,759 share options
On 29th May, 2013 the Group issued 1,275,660 options at an
exercise price of GBP1.20 per option to certain employees. These
options were valued at grant date using a Black-Scholes option
pricing model. During 2014 certain employees who had share options
departed forfeiting their options.
Movement in the number of options outstanding and their related
weighted average exercise prices are as follows:
2014 2013
Average exercise Number of Average exercise Number
price per Options price per of Options
share share
At 1st January GBP1.14 4,256,419 USD1,394 3,638
Acquired 14th February -- -- GBP2.25 444,754
Granted 14th February -- -- GBP0.99 2,630,759
Granted 29th May -- -- GBP 1.20 1,275,660
Exercised 14th February -- -- USD(1,000) (120)
Surrendered -- -- USD(1,407) (3,518)
Lapsed -- -- GBP(2.57) (94,754)
Forfeited GBP(1.15) (385,000) -- --
------------------- -------------- ------------------ ----------------
At 31st December GBP1.01 3,871,419 GBP1.14 4,256,419
=================== ============== ================== ================
Share Options outstanding at the end of the year have the
following expiry date and exercise prices:
2014 2013
Grant-Vest Expiry Exercise Number Exercise Number of
Date price per of Options price per Options
share options share options
2011-15 2015 GBP1.61 350,000 GBP1.61 350,000
2012-15 2022 GBP0.86 2,238,164 GBP0.86 2,294,249
2012-15 2022 GBP0.86 336,510 GBP0.86 336,510
2013-16 2023 GBP1.20 946,745 GBP1.20 1,275,660
3,871,419 4,256,419
============= ==========
The inputs into the Black-Scholes model for options granted
during the period are as follows:
29 May 2013 14 February
2013
Share price GBP1.19 GBP1.20
Average Exercise price GBP1.20 GBP0.89
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
On 14th February, 2013 following the completion of the
acquisition 108,712 Bayfield LTIP's were outstanding. These LTIP
Awards are conditional awards of Existing Unconsolidated Ordinary
Shares and vest three years from the date of grant, subject to the
satisfaction of certain performance conditions (based on the growth
in the Company's total shareholder return). No payment is required
on vesting and there is no accelerated vesting arising as a result
of the Merger.
On 1st July, 2013 739,440 LTIP Awards were granted by the
Company to Senior Management Group (including the Executive
Directors). The LTIP awards will be tested against two performance
targets: stretching reserves growth and absolute returns targets
(share price). Performance against these measures will be assessed
based on performance to the end of the 2015 financial year and
following announcement of the Company's audited financial results.
Subject to the achievement of the performance targets all Options
will be subject to a further holding period whereby Options will
not vest until 1st January, 2017.
The measurement of growth in 2P Reserves is the aggregated total
of all fields included in the Trinity Exploration & Production
plc (formerly Bayfield Energy Holdings plc) and Trinity Exploration
& Production (UK) Limited Group as recorded at financial year
end 2012 which is 35.6 mmboe. Share price growth will be calculated
from the price at which equity was raised at the point of the
merger which was GBP1.20.
The conditions of the scheme are market and non-market based,
and therefore the scheme is valued on the date of grant and
amortised over the vesting period. The grants have been valued
using a Monte Carlo simulation model.
Movements in the number of LTIPs outstanding and their related
weighted average exercise prices are as follows:
2014 2013
Average Number Average Number of
exercise of Options exercise Options
price per price per
share share
At 1st January GBP0.00 848,152 -- --
Acquired -- -- GBP0.00 108,712
Granted -- -- GBP0.00 739,440
Forfeited GBP0.00 (75,840) -- --
------------ ------------ ----------- ----------
At 31st December GBP0.00 772,312 GBP0.00 848,152
============ ============ =========== ==========
Inputs into the Monte Carlo Simulation Model for LTIPs granted
during the period are as follows:
1st July,
2013
Share price GBP1.06
Exercise price GBP0.00
Expected volatility 55%
Risk-free rates 4.5%
Expected dividend yields 0%
Vesting period 3.5 years
29 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.
31st December, 31st December,
2014 2013
$'000 $'000
Negative goodwill (note 27) -- (52,070)
Goodwill -- 2,746
Business combination cost -- 2,254
Unrealised forex loss -- 2,342
Potential claim (note 16) 1,270 --
Impairment of property, plant and equipment
(note 5) 96,242 3,468
Impairment of intangibles (note 6) 23,484 7,786
Share based payment expense (note 28) -- 4,708
Translation difference (57) --
120,939 (28,766)
================= =================
Exceptional items 2014:
Potential claim - In 2014 a claim has been made by a supplier
for an amount of $1.3 million, relating to a matter pre-merger with
the Bayfield Group. Management has provided for this claim in 2014
(see note 16)
Impairment of property, plant and equipment - A sharp fall in
oil prices combined with a downgrade in reserve estimates triggered
an impairment review of the Group's carrying values within
property, plant and equipment. Impairment losses were incurred
relating to the CGU's which were written down to their recoverable
amount (see note 3 (h)).
Impairment of intangibles - An impairment loss was taken on the
exploration well EG-8 ($ 22.6 million) and exploration costs in
South Africa ($0.9 million) following an impairment review (see
note 6).
Exceptional items 2013:
Negative goodwill - A gain on purchase was recognised in the
reverse acquisition of Bayfield by TEPL as the fair value of net
assets acquired was in excess of the fair value of consideration
exchanged.
Goodwill -A deferred tax liability has been realised on the
acquired Oil and Gas properties acquired, this has resulted in in
the recognition of goodwill.
Business combination costs - These are advisor and other legal
costs specifically associated with the acquisition of Bayfield
Unrealised forex loss - Unrealised foreign exchange loss
recorded on the translation of share placing receipts.
Impairment of property plant and equipment - On the Trintes
field a development well was suspended and will not be completed as
a result, the cost of $0.7 million has been impaired. A downward
revision in the reserves estimate led to an impairment loss
recognised in Oilbelt Services Limited $2.6 million and Coastline
International Inc. $0.2 million.
Impairment of intangibles - Goodwill fully attributable to the
Oilbelt Services Limited CGU has been fully impaired.
Share based payment expense - During 2012 share options were
granted to certain Directors and employees. The exceptional charge
represented the acceleration of the share option charge in 2013 as
the vesting period was accelerated due to the announcement of the
acquisition of Bayfield.
30 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 period. Diluted
earnings per share is calculated using the weighted average number
of ordinary shares adjusted to assume the conversion of all
dilutive potential ordinary shares.
Earnings Weighted Average Earnings
Number Of Per Share
Shares $'000 $
$'000
Year ended 31st December, 2013
Basic 38,832 86,275 0.45
Impact of dilutive ordinary
shares:
Assumed conversion of warrants -- 54 --
Long term incentive plan -- 96 --
Share options - Legacy TEP -- 390 --
Plc
Share options - Legacy TEPL -- 2,306 --
Share options granted 29th -- 790 --
May, 2013
Long term incentive plan granted -- 371 --
1st July, 2013
Diluted 38,832 90,282 0.43
---------------------------------------- --------------- ----------------------- -----------------
Earnings Weighted Average Earnings
Number Of Per Share
Shares $'000 $
Year ended 31st December, 2014
Basic (141,182) 94,800 (1.49)
Impact of dilutive ordinary
shares:
As net losses from continuing operations were recorded in 2014,
the dilutive potential shares are anti-dilutive and both basic
and diluted earnings per share are the same.
Diluted (141,182) 94,800 (1.49)
-------------------------------------- ---------------- ----------------------- -----------------
31 Events after the Reporting Period
On the 23rd January, 2015 TEP Plc made a non-refundable deposit
of $2.5 million for Centrica's block 1a and 1b. The balance
remaining $20.5 million with interest accrued effective from 23rd
February, 2015. The completion date agreed for the transaction is
the end of July and Trinity can specify an earlier date on not less
than 2 days' notice. Centrica will be obliged to pay further
significant sums under the PSCs in early July which Trinity has to
pay in the event that completion takes place after 5 July. These
payments are to be deducted from the consideration on completion
occurring. The payments are in respect of the net PSC Financial
Obligations (Article 21 of the Blocks 1a & 1b PSCs - due by 10
July 2015) and the net Annual Holding Fees for the contract year
ending 2014 / 2015.
On the 6th February 2015 TEP Plc repaid $20.0 million of the
Citibank Trinidad and Tobago loan and obtained a repayment
moratorium on the $13.0 million balance until 15th June, 2015.
On the 10th March 2015 TEP plc sold casing and tubing to Rigtech
Services Limited, Blanket Security Limited and Well Services
Petroleum Company Limited (Purchasers) for $3.5 million. The sale
of casing and tubing to the Purchasers constitute a related party
transaction under the AIM Rules as Anthony Brash, a Director of
those entities, is also a Board member and shareholder of TEP Plc.
The proceeds of the transaction will be used to reduce amounts
owing to Purchasers in relation to services provided by the
Purchasers to the Company. The fall in the casing and tubing market
internationally resulted in a loss on sale of $1.3 million.
On the 8th April, 2015 the TEP plc announced it has decided to
conduct a review of its options which may include, but are not
limited to, a farm-out or sale of one or more of its existing
assets, a corporate transaction such as a merger with or sale of
the Company to a third party or a subscription for the Company's
securities by one or more third parties.
The Company is subject to The City Code on Takeovers and Mergers
(the "Code") and has opted to conduct discussions with parties
interested in making a proposal to the Company under the framework
of a "Formal Sale Process" as set out in the Code in order to
enable discussions relating to a merger or sale of the Company, in
particular, to take place on a confidential basis.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR SESESMFISEII
Trinity Exploration & Pr... (LSE:TRIN)
Gráfica de Acción Histórica
De Jun 2024 a Jul 2024
Trinity Exploration & Pr... (LSE:TRIN)
Gráfica de Acción Histórica
De Jul 2023 a Jul 2024
