Preliminary 2013 Results

RNS Number : 8425F

Trinity Exploration & Production

30 April 2014

 



Trinity Exploration & Production plc

(the "Company" or "Trinity"; AIM:TRIN)

Preliminary 2013 Results

30 April 2014

Trinity, the leading independent E&P company focused on Trinidad and Tobago, is pleased to present its preliminary financial results for year ended 31 December 2013.

Financial highlights

           ·     Closed acquisition and re-admission process in February 2013, concurrently raising USD 90 million of equity

           ·     Revenues of USD 123.8 million (2012: USD 77.7 million)

           ·     EBITDA of USD 34.8 million (2012: USD 24.1 million)

           ·     Cash inflow from operating activities of USD 17.0 million (2012: USD 3.7 million)

           ·     Operating profit before exceptional items of USD 21.6 million (2012: USD 16.4 million). Operating profit
               after exceptional items of USD 50.4 million (2012: USD 1.0 million loss)

           ·     Cash balances of USD 25.1 million at 31 December 2013 (2012: USD 22.7 million)

           ·     Secured USD 25.0 million additional debt facility to fund the Company's future growth

           ·     Led fiscal lobbying to secure increased capital allowances

Operating highlights

·     Exited 2013 with average Q4 production of 4,200 boepd

·     Delivered production growth of 23% since taking operational control on 14 February 2013

·     Delivered and reserves growth of 34% versus year end 2012 (excluding TGAL-1 discovery)

·     Third most active driller in Trinidad during 2013 completing nine onshore development wells, one offshore development well and two offshore exploration wells

·     Drilled the successful TGAL‐1 exploration well offshore the East Coast with estimated original oil in place ("OOIP") of 50‐115 million barrels ("mmbbl")

·     Converted Petrotrin's working interest at Trintes to an overriding royalty in order to increase operating flexibility

·     Successfully integrated two businesses and delivered all operations safely

Outlook

·     2014 net average production rate expected to be 3,800 - 4,500 boepd

·     Production growth through infill drilling and recompletions

·     Pilot new "J" type well design at Trintes field to improve initial production rates and recoverable volumes per well

·     Targeting FDP submission for TGAL-1 discovery by Q1 2015 to deliver first oil as rapidly as possible

·     Accelerate high grading of exploration prospects along the Galeota Ridge. On success, these prospects will form part of a phased Galeota Ridge development

·     Actively review business development opportunities in Trinidad consistent with the Company's stated strategy

Joel "Monty" Pemberton, Chief Executive Officer of Trinity, commented:

"2013 was an exciting and transformational year for Trinity.  Having successfully raised USD 90 million in February, the focus has been on drilling activities to grow our production and reserves.  In 2013 Trinity was the third most active driller in Trinidad and our TGAL discovery was the only successful exploration well in Trinidad during the year.  This discovery reaffirms our confidence in the Galeota block and the key priority is to develop a cost efficient development plan within the shortest possible time frame.  Our continued focus on improving drilling performance is beginning to yield positive results and we expect to see further benefits over time.

The Trinidad upstream industry continues to evolve and Trinity is pursuing various business development opportunities to further growth the Company in line with the existing business model."

Trinity will be hosting a conference call at 8.30am for analysts and investors to discuss the results.  Dial-in details are below:

Dial-In:                                 [phone]

Conference ID:                   30340154

Competent Person's Statement:

The information contained in this announcement has been reviewed and approved by Clive Deokie, Subsurface Manager for Trinity Exploration & Production plc, who has over 25 years of relevant experience in the oil and gas industry. Mr Deokie holds a BSc Hons in Geology from the University of the West Indies and is a member of the Geological Society of Trinidad & Tobago.

Enquiries

Trinity Exploration & Production Joel "Monty" Pemberton, Chief Executive Officer Robert Gair, Corporate Development Manager	Tel: [phone]
RBC Capital Markets (NOMAD & Joint Broker) Tim Chapman Matthew Coakes Daniel Conti	Tel: [phone]
Jefferies (Joint Broker) Chris Zeal Graham Hertrich	Tel: [phone]
Brunswick Group LLP (PR Adviser) Patrick Handley Pip Green	Tel: [phone]

Executive Chairman's & Chief Executive Officer's Review

Onshore operations

Average 2013 net production for onshore was 2,088 bopd.

In 2013, Trinity drilled nine new onshore wells (5 in WD-5/6, 3 in WD-2 and 1 in Guapo) and brought 10 wells onto production (including 2 drilled in 2012) and drilled nine onshore developments.  This programme was very successful with actual initial production rates averaging c. 100 bopd per well versus budget of 50 bopd.  Since year end, Trinity has suspended drilling operations while discussions are ongoing with Petrotrin regarding upgrading the Company's onshore licenses to improve efficiency, reduce operating costs and assess enhanced oil recovery opportunities on the combined acreage.

Trinity also completed various modifications and infrastructure upgrades including relocation of the Fyzabad office and upgrading of the fire suppressant system at its FZ-2 lease operatorship battery station.

West Coast operations

Average 2013 net production for West Coast was 596 boepd.

During 2013 Trinity completed a major workover programme at its Brighton Marine field.  This project involved the commissioning and replacement of a new deck at the MP-8 platform to facilitate heavy workovers at seven wells.  These recompleted wells declined more rapidly than expected due to gas management issues.  Following gas lift optimisation in the Brighton field and workovers and recompletions at various PGB wells during early 2014, West Coast production has stabilised at c. 600 boepd.  Workover and recompletion work is also planned for the ABM-151 and ABM-150 wells.  Incremental production associated with this project is estimated at up to 200 bopd and Trinity is currently working to secure a jackup workover barge to complete these operations.

In 2013, Trinity also successful commissioned a Lease Automatic Custody Transfer (LACT) metering facility on the onshore Brighton Marine facilities.

East Coast operations

Average 2013 net production for East Coast was 1,114 bopd.

The Trintes field provided some challenges during the course of the year and several steps were taken to improve operating efficiency. Generator and pump issues significantly impacted production in January 2013 and Trinity's planned infill drilling programme was delayed by ongoing challenges with its drilling rig.  Drilling activities were suspended from September to early December 2013 as the rig was demobilised for upgrades. Drilling resumed in December 2013 on the B9X well. Trinity also leased two new surfer boats from Turbine Transfers in the United Kingdom in order to provide a safer and more efficient personnel transfer system.

The B11XX sidetrack was successfully drilled and was brought on production at an initial production rate of 265 bopd in September 2013. The B5X sidetrack was suspended in February 2013 due to drilling difficulties; the cost for this well has been impaired in 2013. During 2013, 18 workovers were performed on the Trintes field, restoring in excess of 550 bopd.

In 2013 the Galeota tank farm was modified and upgraded. These upgrades are intended to facilitate the pumping of fiscalized crude directly into the Petrotrin sales line.

Exploration update

Trinity drilled two exploration wells during 2013.

East Coast: TGAL-1 Exploration Well

The Trinity operated TGAL-1 exploration well (Trinity 65% working interest) was spudded on 28 October 2013 to target an updip extension of the producing Trintes field.  Drilling operations were undertaken utilising the Rowan Gorilla III jackup rig.

The TGAL-1 well was drilled to 5,694 feet measured depth and intersected five targets all containing good quality oil bearing reservoir sands. TGAL-1 well encountered a total of 547 feet net oil sands containing high quality 28-30 degree API oil. Original Oil In Place ("OOIP") volumes are estimated to be in the range of 50 - 115 mmbbl of oil (gross).

Under the terms of the license minimum work obligations, Trinity paid 100% of the TGAL-1 well costs.

West Coast: El Dorado Exploration Well

The Trinity operated El Dorado-1 exploration well (Trinity 70% working interest) was spudded on 7th December 2013 and completed on 3 February 2014, utilising the WS-152 jackup rig.  The primary objective of the well was to test an undrilled fault block on the west flank of the Trinity operated Brighton field.

The well was drilled to a total depth of 6,174 feet measured depth ("MD") and intersected a shallow gas sand in the Pliocene section and marginal thin bedded oil pay in the Miocene section.  In aggregate approximately 13 feet of net oil sands and 32 feet of net gas sands were encountered, however these were not deemed commercial and the well was plugged and abandoned.

Under the terms of the license minimum work obligations, Trinity paid 100% of the El Dorado-1 well costs.

South Africa: Pletmos Inshore Block

Trinity has initiated a farmout process to find a partner for the next exploration phase on this license.

Financial review             

Statement of Comprehensive Income

Trinity's financial results for 2013 showed a Total Comprehensive Income of USD 38.8 million (2012: USD 15.2 million loss) on gross revenues of USD 123.8 million.

Operating Revenues

2013 revenues were USD 123.8 million (2012: USD 77.7 million).  This increase was mainly attributable to (i) increased onshore production and (ii) the revenues generated by the Galeota Asset, which was acquired in February 2013.

         ·     Production

-   Production for 2013 was 1.4 mmbbls (2012: 0.8 mmbbls)

-   Average production was 3,798 boepd, with 55.0% (2,088 bopd) sold onshore, 15.7% (596 boepd) attributable to the west coast and 29.3% (1,114 bopd) from the east coast

         ·     Oil prices

-   Realised oil price for 2013 averaged USD 91.6/ bbl (2012: 92.5/ bbl)

Operating Expenses

         ·     Operating expenses were USD 102.2 million (2012: USD 61.4 million) which are made up as follows:

-   Royalties of USD 37.3 million (2012: USD 29.2 million)

-   Production costs of USD 33.1 million (2012: USD 12.2 million)

-   Depreciation, depletion and  amortisation amounted to USD 13.2 million (2012: USD 7.7 million)

-   General and administrative expenses of USD 18.5 million (2012: USD 12.3 million)

Operating Profit before Exceptional Items

Operating profit before exceptional items amounted to USD 21.6 million (2012: USD 16.4 million)

Exceptional items

Exceptional items amounted to USD 28.8 million (2012: USD 17.4 million loss) comprising mainly of the following:

         ·     Negative goodwill of USD 52.1 million, which is a gain on purchase and was recognised in respect of the reverse             acquisition of Bayfield Energy Holdings plc by Trinity Exploration & Production (UK) Limited, as the fair value of             net assets acquired was in excess of the fair value of consideration exchanged

         ·     Other exceptional items combined to a total expense of USD 23.3 million

Operating Profit after Exceptional Items

Operating profit after exceptional items amounted to USD 50.4 million (2012: USD 1.0 million loss)

Net Finance Costs

In 2013 finance costs amounted to USD 2.4 million (2012: USD 1.8 million), which is made up of the unwinding of the decommissioning liability USD 1.2 million (2012: USD 0.5 million) and interest on the fully drawn (USD 20.0 million) Citibank loan of USD 1.2 million (2012: USD 1.3 million).

Taxation

The tax charge for 2013 was USD 9.4 million (2012: USD 12.5 million), and its components are described below.

         ·     Supplemental Petroleum Tax (SPT): USD 10.4 million (2012: 8.4 USD million).

         ·     Petroleum Profits Tax (PPT):USD 5.8 million (2012: USD 5.5 million)

         ·     Corporation Tax: The CT for the year amounted to USD 0.9 million (2012: nil).

         ·     Deferred Tax: The combined movement of the deferred tax asset and liability accounts was a net credit of USD             7.7 million (2012: USD 1.3 million).  There was an increase in the deferred tax asset of USD 17.9 million (2012:             USD 0.9 million), due to increases in tax losses carried forward.

Total Comprehensive Income

Trinity's financial results for 2013 showed a Total Comprehensive Income of USD 38.8 million (2012: USD 15.2 million loss) on gross revenues of USD 123.8 million (2012: USD 77.7 million). Adjusted for exceptional items Trinity showed Total Comprehensive Income of USD 10.1 million (2012: USD 2.1 million)

Statement of Cash Flows

The opening cash balance as at 1 January 2013 was USD 22.7 million and the ending cash balance at 31 December 2013 was USD 25.1 million.

Changes in Working Capital

During the year Trinity experienced working capital outflows of USD 15.0 million. Significant changes are outlined in the table below:

	Uses of Cash (USD '000)	Sources of Cash (USD '000)
Inventory	472
Trade and other receivables	2,922
Trade and other payables		13,842
Taxation Paid	25,430
Change in Working Capital	(14,982)

The Company paid taxes of USD 25.4 million in 2013 (2012: USD 10.1 million) of which USD 11.8 million were related to production taxes for 2012.

Operating activities

Cash inflow from operating activities was USD 17.0 million (2012: USD 3.7 million), being the net effect of:

         ·     Adjusted profit inflow of USD 32.0 million (2012: 23.0 million)

         ·     Changes in working capital inflow of USD 10.5 million (2012: outflow of USD 9.3 million)

-     VAT refunds due at year-end totalled USD 20.7 million with the majority relating to VAT due from the T&T tax authority. Notably, VAT refunds of USD 3.2 million were received in Q4 2013

Investing activities

Cash outflow from investing activities was USD 85.6 million (2012: USD 13.5 million), and is made up of capital expenditure and cash acquired in acquisition:

Capital expenditure during 2013 totalled USD 92.1 million (2012: USD 13.6 million) with spend occurring across all of the Group's assets;

         ·     Exploration and evaluation assets:  The majority of spend here relates to the two exploration wells, TGAL-1 and              El Dorado-1.  TGAL-1 (USD 23.7 million) was drilled during 2013 and El Dorado-1 (USD 9.4 million), started in              December 2013 but completed in February 2014.  The remainder of spend relates to Exploration Geological and              Geophysical studies

         ·     Expenditure on property, plant and equipment for the year was USD 56.7 million (2012: USD 13.6 million).  This              included development wells drilled (USD 31.4 million), infrastructure upgrades (USD 18.2 million)

Cash inflow from financing activities 

Cash inflow from financing activities was USD 71.1 million (2012: USD 5.7 million), being the net effect of:

Net equity raise proceeds: USD 84.9 million (2012: Nil) of equity raised in February, net proceeds

Debt proceeds/ repayment and finance costs:

         ·     Repayment of convertible shareholder loan  to Centrica notes of USD 6.4 million (2012: USD 0.5 million)

         ·     Repayment of borrowings of USD 6.2 million (2012: USD 7.4 million inflow) includes; repayment of Segel debt              facilities (USD 2.1 million) and principal repayments of the Citibank loan (USD 4.1 million)

         ·     Payment of loan finance costs of USD 1.2 million (2012: USD 1.3 million)

Additional debt facility: In August 2013, Trinity secured an additional USD 25.0 million debt facility with Citibank to fund future growth. As at 31 December 2013 this facility remained undrawn.

Closing Cash Balance

Trinity's cash balance at 31 December 2013 was USD 25.1 million inclusive of cash acquired on acquisition of USD 6.5 million.

Trinity Exploration & Production plc
(Formerly Bayfield Energy Holdings plc)

Consolidated and Company Financial Statements

(Expressed in United States Dollars)

31 December 2013

  

Consolidated Statement of Comprehensive Income for the year ended 31 December 2013 (Expressed in United States Dollars)
		Notes		2013		2012
				$'000		$'000
Operating Revenues
Crude oil sales				123,585		77,285
Other income				234		427
				123,819		77,712
Operating Expenses
Royalties				(37,343)		(29,154)
Production costs				(33,099)		(12,200)
Depreciation, depletion and  amortisation		5		(13,211)		(7,690)
General and administrative expenses				(18,539)		(12,308)
				(102,192)		(61,352)
Operating Profit Before Exceptional Items				21,627		16,360
Exceptional Items		29		28,766		(17,357)
Operating Profit/(Loss) After Exceptional Items		19		50,393		(997)
Finance Income				--		65
Finance Costs		20		(2,357)		(1,764)
Profit /(Loss) Before Income Tax				48,036		(2,696)
Income Tax Expense		21		(9,481)		(12,532)
Profit /(Loss) For The Year				38,555		(15,228)
Other Comprehensive Income:
Items that may be subsequently reclassified to profit or loss
Currency Translation				277		7
Total Comprehensive Income /(Loss) For The Year				38,832		(15,221)
Total Comprehensive Income/(Loss) attributed to:
Owners of the parent				38,832		(15,221)
Non-controlling interest				--		--
Earnings per share (expressed in dollars  per share)
Basic		30		0.45		(0.59)
Diluted		30		0.43		(0.59)

Consolidated Statement of Financial Position as at 31 December 2013 (Expressed in United States Dollars)
	Notes	2013		2012
ASSETS		$'000		$'000
Non-current Assets
Property, plant and equipment	5	177,592		64,720
Intangible assets	6	59,002		7,856
Deferred tax assets	17	64,693		13,787
		301,287		86,363
Current Assets
Inventories	8	12,029		3,333
Trade and other receivables	7	36,803		23,203
Taxation recoverable	9	528		471
Cash and cash equivalents	10	25,145		22,655
		74,505		49,662
Total Assets		375,792		136,025
Equity and liabilities
Equity Attributable to Owners of the Parent
Share capital	11	94,800		34
Share premium	11	116,395		17,550
Share warrants	12	71		71
Share based payment reserve	28	11,523		7,295
Merger reserves	13	74,808		52,853
Reverse acquisition reserve	13	(89,268)		--
Translation reserve		567		290
Accumulated surplus/(deficit)		10,375		(27,180)
Total Equity		219,271		50,913
Non-current Liabilities
Convertible loan notes	14	--		6,355
Borrowings	15	11,910		18,104
Provision for other liabilities	16	29,027		10,576
Deferred tax liabilities	17	46,387		19,054
		87,324		54,089
Current Liabilities
Trade and other payables	18	61,117		15,695
Borrowings	15	3,989		4,012
Taxation payable	9	4,091		11,316
		69,197		31,023
Total Liabilities		156,521		85,112
Total Equity and Liabilities		375,792		136,025

Company Statement of Financial Position as at 31 December 2013  (Expressed in United States Dollars)
	Notes	2013		2012
ASSETS		$'000		$'000
Non-current Assets
Investment in subsidiaries	22	94,401		46,085
Trade and other receivables	7	160,760		84,664
		255,161		130,749
Current Assets
Trade and other receivables	7	1,007		1,384
Cash and cash equivalents	10	4,189		154
		5,196		1,538
Total Assets		260,357		132,287
Equity and liabilities
Equity Attributable to Owners of the Parent
Share capital	11	94,800		21,648
Share premium	11	116,395		80,817
Share based payment reserve	28	1,127		1,117
Merger reserves	13	56,652		34,228
Accumulated deficit		(9,991)		(7,296)
Total Equity		258,983		130,514
Current Liabilities
Trade and other payables	18	1,374		1,773
		1,374		1,773
Total Liabilities		1,374		1,773
Total Equity and Liabilities		260,357		132,287

Consolidated Statement of Changes in Equity For the period ended 31 December 2013  (Expressed in United States Dollars)
Year ended 31 December 2012
	Share Capital	Share Premium	Share Warrant	Share Based Payment Reserve	Merger Reserve	Translation Reserve	Accumulated Deficit	Total
	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000
At 1 January 2012	33	13,751	71	--	53,172	283	(11,952)	55,358
Financial liability converted to shares	1	3,870	--	--	--	--	--	3,871
Share options granted	--	--	--	7,295	--	--	--	7,295
Translation difference	--	(71)	--	--	(319)	7	--	(383)
Comprehensive loss for the year	--	--	--	--	--	--	(15,228)	(15,228)
At 31 December 2012	34	17,550	71	7,295	52,853	290	(27,180)	50,913

Year ended 31 December 2013	Share Capital	Share Premium	Share Warrant	Share Based Payment Reserve	Reverse Acquisition Reserve	Merger Reserve	Translation Reserve	Accumulated Deficit	Total
	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000
At 1 January 2013	34	17,550	71	7,295	--	52,853	290	(27,180)	50,913
Acceleration of share options	--	--	--	4,708	--	--	--	--	4,708
Placing shares issued	47,500	41,523	--	--	--	--	--	--	89,023
Share options exercised	--	--	--	(411)	--	--	--	--	(411)
Shares issued to previous equity holders of TEPL	25,618	(17,550)	--	--	(30,421)	22,353	--	--	--
Legacy Trinity share capital	21,648	80,817	--	--	(58,800)	--	--	--	43,665
Cost of raising equity	--	(5,945)	--	--	--	--	--	--	(5,945)
Share options granted	--	--	--	187	--	--	--	--	187
LTIP's granted	--	--	--	88	--	--	--	--	88
Legacy share options	--	--	--	(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 31 December 2013	94,800	116,395	71	11,523	(89,268)	74,808	567	10,375	219,271

Company Statement of Changes in Equity for the year ended 31 December 2013 (Expressed in United States Dollars)
	Share Capital	Share Premium	Share Based Payment Reserve	Merger Reserve	Accumulated Deficit	Total
	$'000	$'000	$'000	$'000	$'000	$'000
Year ended 31 December 2012
At 1 January 2012	21,498	80,586	872	34,228	(4,252)	132,932
Loss for the year	--	--	--	--	(3,044)	(3,044)
Issue of share capital (net of share issue cost)	150	225	--	--	--	375
Share based payments	--	--	245	--	--	245
Translation difference	--	6	--	--	--	6
At 31 December 2012	21,648	80,817	1,117	34,228	(7,296)	130,514
Year ended 31 December 2013
At 1 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 31 December 2013	94,800	116,395	1,127	56,652	(9,991)	258,983

Consolidated Statement of Cash Flows for the year ended 31 December 2013 (Expressed in United States Dollars)
	Notes	2013		2012
		$'000		$'000
Operating Activities
Profit /(Loss) before taxation		48,036		(2,696)
Adjustments for:
Translation difference		79		134
Profit on disposal of property, plant and equipment	5	--		(57)
Finance cost - loans	20	1,179		1,256
Share options granted	29	4,721		7,295
Finance cost - decommissioning provision	16	1,178		508
Finance income		--		(66)
Depreciation, depletion and amortisation	5	13,211		7,690
Goodwill	29	2,746		--
Negative goodwill	29	(52,070)		--
Abandonment	5	1,624		--
Impairment of property, plant and equipment	5	3,468		--
Impairment of intangibles	6	7,786		8,963
		31,958		23,027
Changes In Working Capital
Inventories	8	(472)		(1,834)
Trade and other receivables	7	(2,922)		(12,310)
Trade and other payables	18	13,842		4,839
		42,406		13,722
Taxation paid		(25,430)		(10,061)
Net Cash Inflow From Operating Activities		16,976		3,661
Investing Activities
Purchase of exploration and evaluation assets	6	(35,396)		--
Purchase of property, plant and equipment	5	(56,736)		(13,591)
Disposal of property, plant and equipment		--		64
Cash and cash equivalent acquired in acquisition		6,529		--
Net Cash Outflow From Investing Activities		(85,603)		(13,527)
Financing Activities
Finance income		--		66
Issue of shares (net of costs)		84,868		--
Repayment of convertible shareholder loan notes	14	(6,355)		(500)
Finance cost - loans	20	(1,179)		(1,256)
Repayment of borrowings	15	(6,217)		(14,711)
Proceeds from new borrowings	15	--		22,116
Net Cash Inflow From Financing Activities		71,117		5,715
Increase/(decrease) in Cash and Cash Equivalents		2,490		(4,151)
Cash And Cash Equivalents	10
At beginning of year		22,655		26,806
Increase/(decrease) in cash and cash equivalents		2,490		(4,151)
At end of year		25,145		22,655

Company Statement of Cash Flows for the year ended 31 December 2013 (Expressed in United States Dollars)
	Notes	2013		2012
		$'000		$'000
Operating Activities
Loss before taxation		(2,695)		(5,577)
Adjustments for:
Finance income		(1,311)		--
Share based payments		(224)		245
Impairment of receivables from Group companies		--		2,617
		(4,230)		(2,715)
Changes In Working Capital
Trade and other receivables	7	(75,719)		(33,143)
Trade and other payables	18	(407)		1,683
Net Cash (Outflow) from Operating Activities		(80,356)		(34,175)
Financing Activities
Finance income		1,311		(2)
Share capital issued (net of costs)	11	83,078		375
Net Cash Inflow from Financing Activities		84,389		373
Increase/(Decrease) In Cash And Cash Equivalents		4,033		(33,802)
Cash And Cash Equivalents	10
At beginning of period		154		33,952
Increase/(Decrease) in cash and cash equivalents		4,033		(33,802)
Exchange rate differences		2		4
At end of year		4,189		154

Notes to the Consolidated Financial Statements

31 December 2013

1     Background and Accounting Policies

The principal accounting policies applied in the preparation of this consolidated financial information are set out below. These policies have been consistently applied to all the years presented, unless otherwise stated.

Background

Trinity Exploration & Production plc ("Trinity") previously Bayfield Energy Holdings plc ("Bayfield") was incorporated and registered in England and Wales on 21 February 2011 and traded on the Alternative Investment Market ("AIM"), a market operated by London Stock Exchange plc. On 14 February 2013, Bayfield was acquired by Trinity Exploration & Production (UK) Limited ("TEPL"), a company incorporated in Scotland, through a reverse acquisition.  On the 14 February 2013, the enlarged group was re-admitted to trading on AIM and Bayfield changed its name to Trinity Exploration & Production plc. Trinity ("the Company") and its subsidiaries (together "the Group") are involved in the exploration, development and production of oil and gas reserves in Trinidad and South Africa.

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) 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 judgment 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 period was $2.7 million (2012 $3.0 million loss).

New and amended standards adopted by the Group

There are no IFRSs or IFRIC interpretations that are effective for the first time for the financial year beginning on or after 1 January 2013 that would be expected to have a material impact on the group.

New standards, amendments and interpretations issued but not effective for the financial year beginning 1 January 2013 and not early adopted

The Group is yet to assess the full impact of these new standards and amendments but does not expect them to have a material impact on the financial statements.

Basis of consolidation

The consolidated financial information incorporates the financial information of the Company and entities controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved where the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities.

The results of subsidiaries acquired or disposed of during the year are included in the consolidated statement of comprehensive income from the effective date of acquisition and up to the effective date of disposal, as appropriate.

The acquisition method of accounting is used to account for the acquisition of subsidiaries by the Group. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date, irrespective of the extent of any non-controlling interest. The excess of the cost of acquisition over the fair value of the Group's share of the identifiable net assets acquired is recorded as goodwill. If the cost of acquisition is less than the fair value of the net assets of the subsidiary acquired, the difference is recognised directly in the statement of comprehensive income.  Costs related to an acquisition are expenses 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.

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:

	2013		2012
	USD	GBP	USD	GBP
Average rate TTD= USD/GBP	6.416	10.009	6.403	10.121
Closing rate TTD= USD/GBP	6.436	10.580	6.381	10.340

(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, and 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 costs directly associated with an exploration area. Upon discovery of commercial reserves capitalisation is recognised within Property, Plant & 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.

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.

In respect of the employees of a subsidiary, retirement benefits were provided for in accordance with the terms of a Union Agreement which in the current year has been renegotiated and the existing liabilities extinguished.

Convertible loan note

Convertible loan notes are accounted for as borrowings (see note 14) in accordance with contractual terms. If loan notes are converted to shares the carrying amount is reduced with a corresponding increase in equity. Convertible loan notes are classified as a liability except where the settlement of the loan will be in shares and the number of shares to be issued upon conversion is fixed, in which case the loan notes will be classified within equity.

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 31 December 2013, if the functional currency had weakened/strengthened by 10% against the US dollar with all other variables held constant, post- tax(loss)/profit for the year would have been $3.2 million (2012: $2.0 million) lower/higher, mainly as a result of foreign exchange gain/losses on translation of US dollar-denominated borrowings and sales.

(ii)      Price risk

The Group is exposed to commodity price risk regarding its sales of crude oil which is an internationally traded commodity.

At 31 December 2013, if commodity prices had been 1% higher/lower with all other variables held constant, post-tax (loss)/profit for the year would have been $1.2 million (2012: $0.8 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 31 December 2013, if interest rates on foreign currency-denominated borrowings had been 1% higher/lower with all other variables held constant, post-tax (loss)/profit for the year would have been $0.2 million (2012: $0.4 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 maintains flexibility in funding.

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 1 year	Between 2 and 5 years
	$'000	$'000
At 31 December 2013
Borrowings (including interest) (note 15)	5,197	18,137
Accounts payable and accruals (note 18)	61,117	--
At 31 December 2012
Borrowings (note 15)	5,423	20,299
Accounts payable and accruals (note 18)	15,695	--

(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. Trinity has complied with all banking covenants during the period.

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.

	2013	2012
	$'000	$'000
Total borrowings (including convertible loan notes)	15,899	28,471
Less: cash and cash equivalents	(25,145)	(22,655)
(Funds)/net debt	(9,246)	5,816
Total equity	219,271	50,913
Total capital	210,025	56,729
Gearing ratio	(0.04)%	10.25%

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 Judgments

Estimates and judgments 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% (2012: 4.50%) and a core inflation rate of 3% (2012: 3%). The impact in 2013 of a 1% change in these variables is as follows:

	Statement of Financial Position Obligation	Statement of Comprehensive Income/Expense
	2013	2013
	$'000	$'000
Discount rate
1% increase in assumed rate	(4,632)	20
1% decrease in assumed rate	5,621	(71)
Inflation rate
1% increase in assumed rate	5,617	229
1% decrease in assumed rate	(4,712)	(190)

(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 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.

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.

All subsidiaries onshore and offshore reserve estimates were evaluated at 1 July 2012 by an independent external reserve auditor, RPS Energy Consultants Limited ("RPS Energy") and Gaffney Cline and Associates, with a report dated 12 November 2012. Management has subsequently at the end of 2013 re-evaluated the reserve estimates for all assets as a result of new information being available in respect of planned drilling and development activity.  Accordingly the final reserve estimates incorporated into these financial statements have been arrived at using management's estimates for all offshore and onshore assets respectively.

Effective 1 October 2013, Trinity's joint venture partner Petrotrin agreed to convert its 35% working interest in the Trintes field to an Overriding Royalty Agreement 'ORR'. No other financial consideration is payable beyond the ORR. The net effect of the conversion is to increase Trinity's working interest in the field to 100% and adds an additional 13 mmbl in 2P reserves. This ORR agreement only covers the Trintes field (which excludes the recent TGAL‐1 discovery) and Petrotrin retains a 35% working interest in the remainder of the Galeota License.

(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)  Estimated impairment of goodwill

The Group tests annually whether goodwill has suffered any impairment, in accordance with the policy stated in note 1. The recoverable amounts of cash-generating units have been determined based on value-in-use calculations. Should the actual amounts recovered differ significantly from these estimates the carrying value of the goodwill may be impaired.

An impairment charge on goodwill of $7.8 million arose in the CGU, of Oilbelt Services Limited, at the end of 2013, resulting in the entire carrying amount of goodwill attributable to the CGU being written down to nil.  If the price used in the value-in-use calculation had been 10% lower than management's estimates at 31 December 2013 the resulting goodwill impairment would be unchanged.

If the estimated cost of capital used in determining the post-tax discount rate for the CGU in Oilbelt Services Limited had been 1% higher than management's estimates the resulting goodwill impairment would be unchanged.

(g) 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.

(h) Carrying value 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. In order to test for impairment, values in use calculations are prepared which require an estimate of the timing and amount of cash flows expected to arise from the cash generating unit.

At the end of the 2013 year An impairment charge on property, plant and equipment of $2.6 million arose in the CGU of Oilbelt Services Limited and $0.2 million in the CGU of Coastline International Inc., resulting in the carrying amount of the respective CGUs being written down to their recoverable amount.  If the price used in the value-in-use calculation had been 10% lower than management's estimates at 31 December 2013, the group would have recognised a further impairment of Oil and Gas assets by $3.0 million reducing the carrying value of property, plant and equipment.

If the estimated cost of capital used in determining the post-tax discount rate for the CGU in Oilbelt Services Limited and Coastline International Inc. had been 1% higher than management's estimates the group would have recognised a further impairment of $0.6 million against Oil and Gas assets within property, plant and equipment.

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 except for $1.2 million, (2012: nil) located in South Africa.

5    Property, Plant and Equipment

	Plant & Equipment	Land & Buildings	Oil & Gas Assets	Other	Total
	$'000	$'000	$'000	$'000	$'000
Year ended 31 December 2013
Opening net book amount at 1 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
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 31 December 2013	6,133	2,558	168,901	--	177,592
At 31 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
Year ended 31 December 2012
Opening net book amount at 1 January 2012	897	1,158	54,012	181	56,248
Additions	1,660	612	11,478	(159)	13,591
Adjustment to decommissioning estimate (note 16)	--	--	3,018	--	3,018
Depreciation, depletion and amortisation charge for year	(472)	(218)	(6,984)	(16)	(7,690)
Translation difference	(14)	(11)	(422)	--	(447)
Closing net book amount at 31 December 2012	2,071	1,541	61,102	6	64,720
At 31 December 2012
Cost	7,120	1,860	133,440	336	142,756
Accumulated depreciation, depletion, amortisation and impairment	(5,035)	(308)	(71,916)	(330)	(77,589)
Translation difference	(14)	(11)	(422)	--	(447)
Closing net book amount	2,071	1,541	61,102	6	64,720

6      Intangible Assets

The carrying amounts and changes in the year are as follows:

	Exploration and evaluation assets $'000	Goodwill $'000	Total $'000
At 1 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 31 December 2013	59,002	--	59,002

At 1 January 2012	--	16,952	16,952
Impairment charge	--	(8,963)	(8,963)
Translation difference	--	(133)	(133)
At 31 December 2012	--	7,856	7,856

Goodwill arose on the business combination with Oilbelt Holdings Limited and represents the excess of the purchase price over the fair value of the net assets. The acquisition of Oilbelt was effected by the amalgamation of Oilbelt Holdings Limited with a Trinity subsidiary. Oilbelt Services Limited was a subsidiary of Oilbelt Holdings Limited prior to the amalgamation, and afterwards it became a subsidiary in the Group.

After initial recognition, goodwill on acquisition 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 Group'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. The entire goodwill balance has been allocated to the WD 5/6 block which is considered to be one cash generating unit (CGU), the recoverable amount of the CGU has been determined based on value-in-use calculations.  These calculations use after tax cash flow projections based on financial budgets approved by management covering a thirteen year period.  Cash flows beyond the first year assume a growth rate of 3%.  The discount rate used was 10%.

Management re-evaluated the reserve estimate for all assets at the end of 2013 as a result of new information being available. 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.  This assessment resulted in the WD 5/6 block having 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).

Additions:

Exploration well TGAL 1 was drilled in the offshore Galeota block at a cost of $23.7 million and El Dorado in the offshore Point Ligoure-Guapo Bay-Brighton Block was in progress at a cost of $9.4 million at the end of 2013.  Subsequent to the year ended 2013 the El Dorado well was not deemed to be commercial and was permanently plugged and abandoned with the full amount of $17.4 million written off during the 2014 financial year (note 31).

7     Trade and Other Receivables

	Group		Company
	2013 $'000	2012 $'000	2013 $'000	2012 $'000
Due after more than one year
Amounts due from Group companies	--	--	160,760	84,664
Due within one year
Trade receivables	12,637	6,527	--	--
Less: provision for impairment of trade receivables	--	--	--	--
Trade receivables - net	12,637	6,527		--
Prepayments	1,906	1,287	134	136
VAT recoverable	20,653	4,923	873	61
Other receivables	1,529	357	--	--
Short term loan receivable	--	10,029	--	--
Receivables from related parties (note 23 (d))	78	80	--	1,187
	36,803	23,203	1,007	1,384

The Company provides funding to other Group companies.

The fair value of trade and other receivables approximate their carrying amounts.

As at 31 December 2013, trade receivables of $12.6 million (2012: $6.5 million) were fully performing. Trade receivables that are less than three months past due are not considered impaired. As at 31 December 2013, no trade receivables (2012: nil) were impaired and provided for.

The uncommitted term loan of $10.0 million to the borrower (Bayfield Energy (Galeota) Limited) has been fully repaid in the year.

Ageing analysis of these trade receivables is as follows:

	2013 $'000	2012 $'000
Up to 3 months	12,637	6,527
	12,637	6,527

The carrying amount of the Group's trade and other receivables are denominated in the following currencies:

	2013 $'000	2012 $'000
US Dollar	6,548	11,248
GBP	873	--
Trinidad & Tobago Dollar	29,382	11,955
	36,803	23,203

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
	2013	2012	2013	2012
	$'000	$'000	$'000	$'000
Trade receivables
Counterparties without external credit rating:
Existing customers (more than 6 months) with no defaults in the past	12,637	6,527	--	--
All trade receivables are with the Group's only customer, Petrotrin.

8    Inventories 

	2013	2012
	$'000	$'000
Crude oil	435	104
Materials and supplies	11,594	3,229
	12,029	3,333

The cost of inventories recognised as an expense and included in operating expenses amounted to $ 1.2 million (2012: $0.2 million).

9     Taxation Recoverable/(Payable)

	2013	2012
	$'000	$'000
Taxation recoverable
Production Petroleum tax (PPT)/Unemployment Levy (UL)	528	471
Taxation payable
Production Petroleum tax (PPT)/Unemployment Levy (UL)	(313)	(4,889)
Supplemental petroleum tax (SPT)	(3,778)	(6,427)
	(4,091)	(11,316)

10    Cash and Cash Equivalents

	Group		Company
	2013	2012	2013	2012
	$'000	$'000	$'000	$'000
Cash and cash equivalents	25,145	22,655	4,189	154
	25,145	22,655	4,189	154

11    Share Capital and Share Premium

		Number of shares No.	Ordinary shares $'000	Share premium $'000	Total $'000
As at 1 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 31 December 2013		94,799,986	94,800	116,395	211,195

On 14 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% controlling interest in the combined entity.  Bayfield changed its name to Trinity. On the same date a total of 47,500,000 shares were issued at GBP 1.20 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.

	2013	2012
	$'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, Trinity 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% (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% 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 14 February 2013 Oriel has confirmed that it does not intend to exercise its 83 Trinity 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 Acquisition Reserve	Merger Reserve	Total
	$'000	$'000	$'000
At 1 January 2013	--	52,853	52,853
Acquisition (note 27)	--	22,353	22,353
Movement	(89,221)	--	(89,221)
Translation differences	(47)	(398)	(445)
At 31 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   Convertible Loan Notes

	Group and Company
	2013	2012
	$'000	$'000
At 1 January 2013	6,355	6,837
Payments	(6,355)	(500)
Translation differences	--	18
At 31 December 2013	--	6,355

Trinity Exploration and Production (Trinidad and Tobago) Limited a subsidiary of the Group (formerly known as Ten⁰North Energy Limited) created $15.0 million of Unsecured Convertible Subordinated Loan Notes due 2010-2014 by virtue of a Converted Loan Note instrument dated 16 December 2005. Trinity Exploration and Production (Trinidad and Tobago) Limited (formerly known as Ten⁰ North Energy Limited) issued $10.0 million of Unsecured Convertible Subordinated Loan Notes 2010 - 2014 created by that loan note instrument (the 'Original Notes') to Venture Production plc (now Venture Production Limited) on 16 December 2005 which were transferred to Centrica Upstream Investment Limited (formerly named Venture Investment Holdings Limited ('Centrica'))  by way of a Deed of Transfer dated 26 June 2007.

During 2010, Trinity Exploration and Production (Trinidad and Tobago) Limited (formerly known as Ten⁰ North Energy Limited) repaid $1.5 million of the Original Notes issued to Centrica leaving $8.5million in principal amount of the Original Notes outstanding.

The Original Notes were transferred and novated to the Company by way of a deed of novation so that Trinity became liable to Centrica for the repayment of the amount outstanding under the Original Notes. Trinity entered into a new restated and amended loan converted loan note instrument on 8 December 2011 (the 'Restated and Amended Loan Note Instrument') which replaced the original loan note instrument issued in 2005 and issued $9,337,246 of new unsecured convertible subordinated loan notes thereunder (the $8.5 million principal plus a further $837,246 of interest) to Centrica in replacement of the Original Notes (the 'Convertible Loan Notes').

$2.5 million of the Convertible Loan Notes were repaid after the Amalgamations in 2011 in accordance with the Restated and Amended Loan Note Instrument and a further $0.5 million of the Convertible Loan Notes were repaid at the end of 2012 resulting in $6,337,246 of principal outstanding under the Convertible Loan Notes to Centrica as at 31 December 2012. The full amount outstanding under the Convertible Loan Notes (the principal plus accrued interest) was repaid on 6 March 2013 shortly after the completion of the merger of with Trinity Exploration & Production plc.

15   Borrowings

	2013	2012
	$'000	$'000
Non-current portion:
Citibank (Trinidad & Tobago) Limited	11,910	16,047
David & Christina Segel Living Trust loan note (see note 23(e))	--	2,057
Total	11,910	18,104
Current portion:
Citibank (Trinidad & Tobago) Limited	3,989	4,012
Total	3,989	4,012

Drawn Loan Facilities

Citibank (Trinidad & Tobago) Limited Loan 1

The key terms of the loan are as follows:

·    Principal amount $20.0 million

·    Maturity date 20 December 2017 Interest rate 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 20 March 2013 and ending on 20 December 2017

·    Interest payable monthly in arrears commencing on 20 March 2013

Financial covenants:

·    The Group/Company was in compliance with its covenants throughout the year

·    Minimum debt service coverage 1.4:1

·    Maximum total debt to EBITDA 2.75:1

·    Minimum EBITDA to Interest Expense 1.5:1

The comparative current portion was due to Citibank (Trinidad & Tobago) Limited and was repaid in the financial year ended 31 December 2013. The carrying value is not materially different from the fair value.

Undrawn Loan Facilities

Citibank (Trinidad & Tobago) Limited Loan 2

The Group has on 17 August 2013 negotiated a floating rate medium term facility of $25.0 million with Citi Bank (Trinidad and Tobago) Limited which at 31 December 2013 remains undrawn.

The key terms of the loan are as follows:

·      Tenor four years from closing date.

·      Interest rate is set at US LIBOR for a period of three months plus 575 bps per annum.

·      Principal repayment is quarterly in amounts to be determined beginning three months after the end of the availability period (20 August 2014).

·      Multiple drawdowns permitted within the availability period.

Financial covenants:

·    Minimum debt service coverage 1.4:1

·    Maximum total debt to EBITDA-Operating taxes 3.0:1

·    Minimum EBITDA-Operating taxes to Interest Expense 1.5:1

David & Christina Segel Living TrustPromissory note

Key terms of the loan note are as follows:

·      Issue Date - 1 October 2012

·      Interest Rate - Fixed 10% per annum (30/360 day basis)

·      Principal sum - $2,051,111.11

·      Maturity Date - 30 September 2014

·      Interest and principal will be repaid on the Maturity Date

·      Rollover Provision - The Issuer may request that some or the entire outstanding principal of the note be rolled-over following conditions disclosed in the agreement

On 1 July 2012, Oilbelt Services Limited a subsidiary of the Group borrowed $2.0 million from David & Christina Segel Living Trust. This has been fully repaid on 6 March 2013.

Analysis of net debt

	At 1 January 2013  $'000	Cashflow $'000	At 31 December 2013 $'000
Cash and cash equivalents	22,655	2,490	25,145
Financial liabilities - borrowings current	(4,012)	23	(3,989)
Financial liabilities - borrowings non-current	(18,104)	6,194	(11,910)
Convertible loan note (note 13)	(6,355)	6,355	--
	(5,816)	15,062	9,246

16   Provisions and Other Liabilities

	Decommissioning cost		Employee retirement benefit	Total
	$'000		$'000	$'000
Year ended 31 December 2013
Opening amount as at 1 January 2013	9,891		685	10,576
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
Decrease in the provision	(90)		(685)	(775)
Closing balance at 31 December 2013	29,027		--	29,027
Year ended 31 December 2012
Opening amount as at 1 January 2012	6,402		728	7,130
Adjustment to estimates (note 5)	3,018		--	3,018
Unwinding of discount (note 20)		508	--	508
Decrease in the provision		(37)	(43)	(80)
Closing balance at 31 December 2012		9,891	685	10,576

Decommissioning cost

This represents an estimate of the amounts required for abandonment of the Group's wells and facilities. 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% (2012: 3%) 

b.    Risk free rate - 3.9% (2012: 4.5%)

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 producing wells 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 facilities. There has been a corresponding increase in the carrying amount of property plant and equipment (note 5).

Employee Retirement Benefit

Upon the acquisition of Oilbelt Services Limited, the Group assumed a legal obligation based on an agreement between Oilbelt Services Limited and the Oilfield Workers Trade Union which entitles members to certain service benefits. This arrangement is a defined contribution scheme. The final level of benefit is not defined and can vary based upon certain criteria, such as the length of service.  During 2013 this liability was extinguished under the new collective bargaining agreement.

17   Deferred Income Taxation

	2013	2012
	$'000	$'000
At beginning of year	5,267	6,622
Deferred tax assumed on acquisition	(18,606)	--
Deferred tax on fair value uplift arising from acquisition	2,746	--
Movement for the year	(5,412)	(10)
Unwinding of deferred tax on fair value uplift	(2,247)	(1,345)
Translation differences	(54)	--
Net deferred tax (liability)/asset	(18,306)	5,267

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:

	2011 $'000	Movement $'000	2012 $'000	Movement $'000	2013 $'000
Deferred tax assets
Acquisition	(410)	--	(410)	(33,026)	(33,436)
Tax losses recognised	(12,472)	(905)	(13,377)	(17,880)	(31,257)
	(12,882)	(905)	(13,787)	(50,906)	(64,693)
Deferred tax liabilities
Accelerated tax depreciation	1,469	895	2,364	12,414	14,778
Acquisitions	5,160	--	5,160	14,420	19,580
Fair value uplift	12,875	(1,345)	11,530	499	12,029
	19,504	(450)	19,054	27,333	46,387

Tax losses were recognised. These losses relate to Ten⁰ North Operating Company. Pioneer Petroleum Company Limited and Trinity Exploration and Production (Galeota) Limited. It is expected that the losses will be recovered within the next five years.

18   Trade and Other Payables

	Group		Company
	2013 $'000	2012 $'000	2013 $'000	2012 $'000
Trade payables	19,224	4,857	36	765
Accruals	37,170	9,149	92	1,008
VAT payable	2,289	536	--	--
Other payables	1,393	669	--	--
Amounts due to related parties (note 23 (d))	1,041	484	1,246	--
	61,117	15,695	1,374	1,773

19   Operating Profit Before Exceptional Items

	2013 $'000	2012 $'000
Operating profit before exceptional items is stated after taking the following items into account:
Depreciation, depletion and amortisation (note 5)	13,198	7,690
Profit on disposal of property, plant and equipment	--	(57)
Employee costs (note 26)	21,598	15,777
Abandonment (note 5)	1,624	--
Operating lease rentals	1,374	1,432
Inventory recognised as expense, charged to operating expenses	1,235	216

Auditor's remuneration

During the year the Group (including its overseas subsidiaries) obtained the following services from the Company's auditor as detailed below:

	2013 $'000	2012 $'000
- Fees payable to the Company's auditors' and its associates for the audit of the parent company and consolidated financial statements	73	53
- Fees payable to the Company's auditors' and its associates for other services: - The audit of company's subsidiaries	167	117
-  Audit related assurance services - interim review	50	29
- Reporting accountant in respect of the merger and admission to trading on AIM	318	852
Total assurance	608	1,051
- Tax advisory	26	--
- Other advisory	216	17
Total auditors' remuneration	850	1,068

All fees are in respect of services provided by PwC with the majority relating to reporting accountants work during the merger of Trinity and Bayfield.  Following the merger, Trinity have completed a competitive tender for audit services and have selected PwC as the external auditor of the enlarged group.  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

	2013	2012
	$'000	$'000
Decommissioning (note 16)	1,178	508
Interest on loans	1,179	1,256
	2,357	1,764

21   Income Tax Expense

	2013	2012
	$'000	$'000
Current tax
- Current year
Petroleum profits tax	5,821	5,452
Corporation tax	926	--
Supplemental petroleum tax	10,393	8,391
Deferred tax
- Current year
Movement in asset due to tax losses (note 17)	(17,880)	(905)
Movement in liability due to accelerated tax depreciation	12,414	895
Unwinding of deferred tax on fair value uplift	(2,247)	(1,345)
Translation difference	54	44
Income tax expense	9,481	12,532

The Group's effective tax rate varies from the statutory rate for UK companies of 23.25% as a result of the differences shown below:

	2013	2012
	$'000	$'000
Profit/(loss) before taxation	48,036	(2,696)
Tax charge at expected rate of 23.25% (2012: 24.5%)	11,048	(661)
Effects of:
Higher overseas tax rate	15,372	836
Profits not subject to tax	(32,276)	--
Disallowable expenses	11,772	8,275
Deferred tax asset not recognised	20	179
Tax loss generated not recognised	915	554
Tax losses utilised but not previously recognised	(626)	(1,310)
Supplemental petroleum tax	3,110	3,755
Green fund levy	178	148
Other differences	(32)	756
Tax charge	9,481	12,532

Taxation losses as at 31 December 2013 available for set off against future taxable profits amount to approximately $127.0 million (2012: $36.0 million), with tax losses recognised as a deferred tax asset of $ 118.0 million. 

22   Investment In Subsidiaries

	Company
	2013	2012
	$'000	$'000
Opening balance	46,085	46,979
Additions	48,076	--
Capital contribution relating to share based payment	240	(894)
Closing balance	94,401	46,085

The investment in group undertakings is recorded at cost which is the fair value of the consideration paid.The capital contribution relating to share based payments granted by the Company to employees of subsidiary undertakings in the Group. Refer to note 28 for further details of the group's share based schemes.

Astrakhanskaya Gas and Oil Company (AGOC), a subsidiary of Trinity Exploration & Production plc which held an interest in the Karalatsky licence which was in an exploration phase was wound up  The winding up of this entity was completed on 5 September 2013.

Listing of Subsidiaries 

The Group's principal subsidiaries at 31 December 2013 are listed below:

Name	Country of Incorporation	Nature of Business	Proportion of ordinary shares held by the group (%)
Bayfield Energy Limited	UK	Holding Company	100%
Trinity Exploration and Production Services (UK) Ltd	UK	Service company	100%
Bayfield Energy (Alpha) Limited	UK	Holding Company	100%
Trinity Exploration and  Production (Pletmos) Limited	UK	Oil and Gas	100%
Bayfield Energy do Brasil Ltda	Brazil	Dormant	100%
Bayfield Energy New Ventures Limited	UK	Holding Company	100%
Bayfield Energy (St Lucia) Limited	St Lucia	Holding Company	100%
Trinity Exploration & Production (Barbados) Limited	Barbados	Holding Company	100%
Trinity Exploration and Production (Trinidad and Tobago) Limited	Trinidad & Tobago	Holding Company	100%
Galeota Oilfield Services Limited	Trinidad & Tobago	Oil and Gas	100%
Trinity Exploration and Production (Galeota) Limited	Trinidad & Tobago	Oil and Gas	100%
Ten0 North Operating Company Limited	Trinidad & Tobago	Holding Company	100%
NAKT Company Limited	Trinidad & Tobago	Oil and Gas	100%
Antilles Resources Limited	Trinidad & Tobago	Oil and Gas	100%
Lennox Production Services Limited	Trinidad & Tobago	Oil and Gas	100%
Pioneer Petroleum Company Limited	Trinidad & Tobago	Oil and Gas	100%
Oilbelt Services Limited	Trinidad & Tobago	Oil and Gas	100%
Coastline International Inc.	Trinidad & Tobago	Oil and Gas	100%
Ligo Ven Resources Limited	Trinidad & Tobago	Oil and Gas	100%
Trinity Exploration and Production Services Limited	Trinidad & Tobago	Service company	100%
Tabaquite Exploration & Production Company Limited	Trinidad & Tobago	Oil and Gas	100%

23   Related Party Transactions

Group

The following transactions were carried out with the Group's subsidiaries.  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
	2013 $'000	2012 $'000	2013 $'000	2012 $'000
Well Services Petroleum Company Limited	--	159	--	--
Bayfield Energy Limited - loan	--	--	--	531
Trinity Exploration and Production Services (UK) Limited - loan	--	--	9,513	--
Trinity Exploration and Production (Galeota) Limited - loan	--	--	65,400	656
	--	159	74,913	1,187

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
		2013 $'000	2012 $'000	2013 $'000	2012 $'000
Purchases of services:
Blanket Securities Limited	--		760	--	--
Rigtech Services Limited	996		940	--	--
Well Services Petroleum Company Limited	9,875		1,250	--	--
Dingwall Energy Advisors Limited	--		365	--	--
Trinity Infrastructure Construction Limited	--		91	--	--
Bayfield Energy Limited	--		--	5	--
	10,871		3,406	5	--

Goods and services are bought from entities controlled by certain Directors' 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 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
	2013 $'000	2012   $'000
Short-term employee benefits	2,469	2,833
Post-employment benefits	53	7
Share-based payment (note 28)	2,590	4,454
	5,112	7,294

(d) Year-end balances arising from sales/purchases of services

	Group		Company
	2013 $'000	2012 $'000	2013 $'000	2012 $'000
Receivables from related parties:
Well Services Petroleum Company Limited	78	80	--	--
Bayfield Energy Limited - loan	--	--	84,659	84,664
Trinity Exploration and  Production Services (UK) Limited - loan	--	--	9,513	--
Bayfield Energy Alpha - loan	--	--	531	531
Trinity Exploration and Production (Galeota) Limited - loan	--	--	66,057	656
	78	80	160,760	85,851
Payables to related parties:
Blanket Securities Limited	164	21	--	--
Rigtech Services Limited	238	372	--	--
Well Services Petroleum Company Limited	639	--	--	--
Trinity Exploration and Production Services (UK) Limited	--	--	4	--
Trinity Exploration & Production (UK) Limited	--	--	1,242	--
Trinity Infrastructure Construction Limited	--	91	--	--
	1,041	484	1,246	--

Loans to subsidiaries

Loans receivable from Bayfield Energy Limited and Trinity Exploration and Production (Galeota) Limited carry interest of LIBOR + 3% per annum. 

Loans receivable from Trinity Exploration and Production Services (UK) Limited carry interest of 1.5% per annum.

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 (2012: 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.  This loan was repaid in 2013.

(e) Loans from related parties

	Group
	2013 $'000	2012 $'000
David & Christina Segel Living Trust loan note (note 15)	--	2,057
	--	2,057

24   Financial Instruments By Category

The accounting policies for financial instruments have been applied to the line items below:

	Group		Company
	2013	2012	2013	2012
	$'000	$'000	$'000	$'000
Trade and other receivables - non current	--	--	160,760	84,664
Trade and other receivables - current	36,803	23,203	1,007	1,384
Cash and cash equivalents	25,145	22,655	4,189	154
	61,948	45,858	165,956	86,202

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
	2013	2012	2013	2012
	$'000	$'000	$'000	$'000
Borrowings	15,899	28,471	--	--
Amounts due to related party	--	--	1,246	--
Accounts payable and accruals	61,117	15,695	128	1,773
	77,016	44,166	1,374	1,773

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
	2013	2012
	$'000	$'000
Not later than 1 year	442	330
Later than 1 year and no later than 5 years	932	1,102
	1,374	1,432

      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)   The farmout agreement for the Tabaquite block (held by Coastline International Inc.) has expired. There may be additional liabilities arising when a new agreement is finalised, but these cannot be presently quantified as a new agreement has not yet been finalised by both parties which would agree any terms or conditions inherent the financial statements do not include any estimates of such liabilities.

iv)  Parent company guarantees:

a) A Letter of Guarantee has been established over the Point Ligoure-Guapo Bay-Brighton Block where a subsidiary of Trinity 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 Citi Bank (Trinidad and Tobago) Limited for the full $25.0 million loan facility should there be a default.

v)   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 does not expect that these liabilities will be material.

26   Employee Costs

Employee costs for the Group during the year	2013 $'000	2012 $'000
Wages and salaries	16,484	8,426
Other pension costs	393	56
Share based payment expense (note 28)	4,721	7,295
	21,598	15,777
Average monthly number of people (including executive Directors') employed by the Group	2013 number	2012 number
Executive Directors	7	6
Administrative staff	138	67
Operational staff	140	152
	285	225

27   Business Combination

a)  Summary of acquisition

On 14 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% of its share capital, to the shareholders of TEPL in exchange for 100% (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 14 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 GBP 1.20 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 unuseable 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 1 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 2013 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:

	2013	2012
	$'000	$'000
Share based payment expense:
Accelerated share option charge	4,708	7,295
Share option expense	187	--
Legacy share options adjustment	(262)	--
Long term incentive plan	88	--
	4,721	7,295

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 31 December 2012 TEPL had 3,638 share options outstanding.  On 14 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 Trinity of new options over 747.8 new ordinary shares 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 acquisitionBayfield 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 29 May 2013 the Group issued 1,275,660 options at an exercise price of GBP 1.20 per option to certain employees. These options were valued at grant date using a Black-Scholes option pricing model.

Movement in the number of options outstanding and their related weighted average exercise prices are as follows:

	31 December 2013		31 December 2012
	Average exercise price per share	Number of Options	Average exercise price per share	Number of Options
At 1 January	USD 1,394	3,638	--	--
Acquired 14 February	GBP 2.25	444,754	--	--
Granted 14 February	GBP 0.99	2,630,759	USD 1,394	3,638
Granted 29 May	GBP 1.20	1,275,660
Exercised 14 February	USD (1,000)	(120)	--	--
Surrendered	USD (1,407)	(3,518)	--	--
Lapsed	GBP (2.57)	(94,754)	--	--
At 31 December	GBP 1.14	4,256,419	USD 1,394	3,638

Share Options outstanding at the end of the year have the following expiry date and exercise prices:

		31 December 2013		31 December 2012
Grant-Vest	Expiry Date	Exercise price per share options	Number of Options	Exercise price per share options	Number of Options
2011-15	2015	GBP 1.61	350,000	--	--
2012-15	2022	GBP 0.86	2,294,249	USD 1,000	3,188
2012-15	2022	GBP 0.86	336,510	USD 4,185	450
2013-16	2023	GBP 1.20	1,275,660	--	--
			4,256,419		3,638

The inputs into the Black-Scholes model for options granted during the period are as follows:

	29 May 2013	14 February 2013
Share price	GBP 1.19	GBP 1.20
Average Exercise price	GBP 1.20	GBP 0.89
Expected volatility	55%	78%
Risk-free rates	4.5%	4.5%
Expected dividend yields	0%	0%
Vesting period	3 years	3 years

Long Term Incentive Plan

On 14 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 1 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 1 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 £1.20.

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:

	31 December 2013			31 December 2012
		Average exercise price per share	Number of Options	Average exercise price per share	Number of Options
At 1 January		--	--	--	--
Acquired		GBP 0.00	108,712	--	--
Granted		GBP 0.00	739,440	--	--
At 31 December		--	848,152	--	--

Inputs into the Monte Carlo Simulation Model for LTIPs granted during the period are as follows:

	1 July 2013
Share price	GBP 1.06
Exercise price	GBP 0.00
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.

		31 December 2013		31 December 2012
		$'000		$'000
Negative goodwill (note 27)			(52,070)	--
Goodwill			2,746	--
Business combination cost			2,254	--
Unrealised forex loss			2,342	--
Arbitration settlement with Petrotrin			--	1,099
Impairment of property, plant and equipment (note 5)			3,468
Impairment of intangibles (note 6)			7,786	8,963
Share based payment expense (note 28)			4,708	7,295
		(28,766)		17,357

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 this has been impaired $0.7 million.  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 represents 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 Number Of Shares $'000	Earnings Per Share $
	$'000
Year ended 31 December 2012
Basic	(15,221)	25,652	(0.59)
Impact of dilutive ordinary shares:
As net losses from continuing operations were recorded in 2012, the dilutive potential shares are anti-dilutive and both basic and diluted earnings per share are the same.
Diluted	(15,221)	25,652	(0.59)
Year ended 31 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 Trinity	--	390	--
Share options - Legacy TEPL	--	2,306	--
Share options granted 29 May 2013	--	790	--
Long term incentive plan granted 1 July 2013	--	371	--
Diluted	38,832	90,282	0.43

The earnings per share figures for the year ended 31 December 2013 are presented based upon the Group and capital structure following the reverse acquisition of Bayfield.  As a result, the comparative figures are based upon the TEPL's historic weighted average number of ordinary shares that were outstanding multiplied by the exchange ratio established by the business combination.

31   Events after the Reporting Period

On 17 January 2014 $5.0 million of the $25.0 million debt facility signed by Trinity and Citibank on 21 August 2013 was drawn.

On 6 February 2014 the El Dorado exploration well was completed at a cost of $17.4 million to a total depth of 6,174 feet measured depth ("MD") and intersected shallow gas sand in the Pliocene section and marginal thin bedded oil pay in the Miocene section. In aggregate approximately 13 ft of net oil sands and 32 ft. of net gas sands were encountered, however these are not deemed commercial and the well was permanently plugged and abandoned with the full amount of $17.4 million written off during the 2014 financial year.

 

END

 

 

FR SEEFUUFLSEEL