2014 Preliminary Results

RNS Number : 2949O

Trinity Exploration & Production

27 May 2015

Trinity Exploration & Production Plc

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

2014 Preliminary Results

27^th May 2015

Trinity, the leading independent E&P company focused on Trinidad and Tobago, today announces its preliminary results for the year ended 31^st December 2014.

Financial highlights

· Revenues of USD 113.5 million (2013: USD 123.8 million)

· EBITDA of USD 28.5 million (2013: USD 34.8 million)

· General and Administrative costs reduced by 19% to USD 15.0 million (2013: USD 18.5 million)

· Cash inflow from operating activities of USD 11.8 million (2013: USD 17.0 million)

· Operating profit before exceptional items of USD 12.2 million (2013: USD 21.6 million)

· Operating loss after exceptional items of USD 123.7 million (2013: USD 50.4 million profit)

· Cash balances of USD 33.1 million at 31^st December 2014 (2013: USD 25.1 million)

· Post the year end, Trinity ended the first quarter of 2015 with cash and cash equivalents of USD 7.3 million, receivables of USD 27.2 million (including USD 11.2 million VAT receivables owed to the Company), inventories of USD 11.5 million, debt of USD 13.0 million, trade & other payables of USD 33.9 million and taxation payable of USD 18.4 million

· Moratorium on principal repayments relating to Trinity's outstanding debt balance until 15 June 2015 agreed with its lenders

Operating highlights

· Group average production levels of 3,603 boepd (2013: 3,798 boepd)

· Final management estimates of 2P reserves of 25.3 mmstb at the end of 2014, compared to the year-end 2013 reserve estimate of 47.7 mmstb

· Upgrade to management resource estimate on the TGAL discovery to Stock Tank Oil Initially in Place ("STOIIP") of 150.0 - 210.0 mmbbls (best estimate, 186.0 mmbbls)

· Entered into an agreement with Centrica to acquire 80% interests in Blocks 1(a) & 1(b), containing four undeveloped but fully appraised gas discoveries (308 bcf, 246 bcf net to 80%) with the balance of payment due in Q3 2015

- Draft Field Development Plan ("FDP") completed on schedule

- Gas Sales Agreement discussions with potential off-takers well advanced

- Deposit of USD 2.5 million paid in January 2015; remaining USD 20.5 million plus working capital adjustments with interest accrued due on completion

· Post year-end, 15% reduction in pre-tax operating expenditure ("opex") with current opex per barrel of USD 21.4/bbl versus USD 25.1/bbl for the month of December 2014, leading to operating break even across all fields

Outlook

On 8th April 2015, in light of the receipt of a number of conditional proposals and expressions of interest in relation to certain of the Company's assets, Trinity announced that it was launching a strategic review of options open to the Company to maximise value for shareholders. These options may include, but are not limited to, a farm-out or sale of one or more of the Company's existing assets, a corporate transaction such as a merger with or sale of the Company to a third party or a subscription for the Company's securities by one or more third parties. The Company is subject to The City Code on Takeovers and Mergers (the "Code") and has opted to conduct discussions with parties interested in making a proposal to the Company under the framework of a "formal sale process" as set out in the Code in order to enable discussions relating to a merger or sale of the Company, in particular, to take place on a confidential basis.

In response to falling oil prices, Trinity has focused on enhancing its liquidity position by seeking a moratorium on the principal repayments on its senior secured credit facility, disposing of non-core assets such as Tabaquite and the WD-16 lease operatorship block, reducing its operating and general and administrative costs, obtaining an extension on the purchase consideration of the 1(a) & 1(b) licences as well as pursuing all means at its disposal with respect to the collection of outstanding VAT payments.

Our operational focus remains on managing the portfolio to optimise production levels and to manage further reductions in operating costs and general administrative costs to bring all fields break-even down further. Ensuring the health and safety of all of our employees will remain our priority.

In addition to our operational cost reductions the non-executives, have elected to suspend all fees relating to their roles and Bruce Dingwall has assumed the role of Non-Executive Chairman (previously Executive Chairman).

Our objective remains to deliver value to shareholders by sourcing a funding solution to monetise the assets via the strategic review and formal sales process. However, Trinity shareholders are advised that there can be no certainty that any offers will be made as a result of the formal sales process, that any sale or other transaction will be concluded, nor as to the terms on which any offer or other transaction may be made.

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

"Trinity has reacted quickly to continued global commodity price volatility. We have reduced the overheads in our business and cut back on discretionary costs, and as a result have seen a substantial fall in our general and administrative and operating costs. At the same time a rigorous subsurface review has resulted in a significant resource upgrade on the TGAL discovery with a joint Trintes-TGAL development plan well advanced.

Our core producing asset base continues to yield solid production levels with declines being modest against a backdrop of reduced investment. As a result we were able to deliver an operating profit (pre-exceptionals) of USD 12.2 million and robust cash conversion levels. This is a testimony to the quality of those assets and to the hard work and abilities of the Trinity team. Across the Onshore, West Coast and the East Coast we have an inventory of drilling locations that could enhance production levels on the deployment of capital.

The Strategic Review announced in April 2015 is now well underway with the Board considering a number of options to maximise and ensure long term value for Trinity's shareholders."

Management will be hosting a conference call for financial analysts at 13:00 BST to discuss the results. Please contact TEP@brunswickgroup.com for the details.

Competent Person's Statement:

The information contained in this announcement has been reviewed and approved by Craig McCallum, Chief Operating Officer for Trinity Exploration & Production plc, who has over 25 years of relevant experience in the oil industry. Mr. McCallum holds a Master degree in Petroleum Engineering.

Enquiries:

Trinity Exploration & Production

Joel "Monty" Pemberton, Chief Executive Officer

Tracy Mackenzie, Head of Investor Relations

Tel: +44 (0)13 1240 3860

RBC Capital Markets

Nomad & Joint Broker

Matthew Coakes

Daniel Conti

Oil & Gas Advisory

Jakub Brogowski

Roland Symond

Jefferies (Joint Broker)

Chris Zeal

Graham Hertrich

Tel: +44 (0) 20 7653 4000

Tel: +44 (0) 20 7029 8000

Brunswick Group LLP (PR Adviser)

Patrick Handley

William Medvei

Tel: +44 (0) 20 7404 5959

Non-Executive Chairman's & Chief Executive Officer's Review

East Coast operations

Average 2014 net production from the East Coast was 1,106 barrels of oil per day (bopd). In line with 2013 average levels of 1,114 bopd.

The Galeota Ridge structure on the East Coast contains the Trintes field, the TGAL-1 exploration well discovery and various low risk prospects. Current production comes from the Alpha, Bravo and Delta platforms in the Trintes field, and whilst on-going steps to improve operating efficiency have been effective, challenges remained in sustaining production at a time when capital has not been deployed towards new drilling.

Earlier in the year production was impacted by the failure of the D-9 electric submersible pump ("ESP") which contributed to a loss of 230 bopd. The D-9 ESP was replaced in late June 2014 and production was restored to its previous level. The B-9X infill well was successfully completed, following initial problems with mud pumps, encountering 85 feet of net oil sand in the M-sand and the original oil water contact for the fault block. During the year production from the B11XX well was successfully restored and the B6X well was brought back online after both stopped producing due to a Variable Frequency Drive ("VFD") failure.

Improved well production management has reduced the need for workovers as the frequency of wells going offline has decreased. Moving forward, new drilling could arrest base declines with an inventory of new well locations identified. These have been integrated into a joint Trintes-TGAL development plan that aims to optimise capital allocation across our East Coast fields.

Throughout 2014 several cost saving initiatives were realised on the East Coast and include; the benefits of a fuel subsidy which took effect from September 2014, a renegotiation on vessel transfers with regards to shift systems, and changing cargo vessel transfers to a spot basis from a monthly fixed basis. Further cost saving initiatives are ongoing, including additional efficiencies on shift systems, and installing additional fuel capacity on platforms which will further reduce the number of cargo vessel transfers. These moves are working to bring optimum operating efficiency across East Coast operations and significantly reducing break-even levels.

Whilst the resource base on the Galeota Block is significant, we were initially challenged with operations on the Trintes field. We have now implemented the appropriate commercial, technical and operational practices to enable value optimisation from this asset. Our Onshore and West Coast assets are strong producing assets that have performed broadly in-line with expectations, and all have promises of further production upside.

West Coast operations

Average 2014 net production from the West Coast was 491 barrels of oil equivalent per day (boepd). This represents a decline from 2013 average levels of 596 boepd.

Increased workover and recompletion activity on the PGB block in H1 2014 led to a positive increase in production rates compared to 2013. However, with discretionary capital expenditure limited in H2 2014, average production levels for the year reflect a natural base decline. The ABM-151 well and ABM-150 well both represent recompletion ("RCP") opportunities for improving production moving forward.

Onshore operations

Average 2014 net production from the Onshore was 2,006 bopd. This represents a modest decline from 2013 average levels of 2,088 bopd.

The focus during 2014 continued on arresting base declines and increasing production via workovers and RCPs. In 2014, production levels benefited from 5 new wells which were drilled and completed in H2 2013. New drilling operations were suspended during H1 2014 while discussions were ongoing with Petrotrin regarding upgrading the Lease Operatorship Model to improve efficiency, reduce operating costs and assess enhanced oil recovery opportunities and other synergies on the combined acreage.

In total, 10 RCPs were conducted in 2014, in addition to the routine workovers. The PS-575 well was successfully perforated in the Upper Forest ("UF") 1 and 2 sands and added initial production of c.200 bopd.

TGAL Development

With management resource estimates on Trinity's TGAL-1 discovery upgraded to STOIIP of 150.0 - 210.0 mmbbls (best estimate 186.0 mmbbls), work continues apace to have the Field Development Plan issued. The existing 3D seismic dataset over the TGAL and Trintes areas has been reprocessed to improve data quality using Common Reflection Surface ("CRS") technology for the first time on the East Coast of Trinidad. The results from the application of a leading edge processing technology were transformative in allowing Trinity to use the seismic to image the complex subsurface structure of the Trintes and TGAL fields.

At the end of 2014, the subsurface evaluation was approximately 90% completed, and included integration of seafloor and shallow seismic data. The topside facility concept has been narrowed down to two options, and it seems practical to adopt a phased approach to developing the field by bringing onto production the reserves nearer to the Trintes field and putting it through a Trintes facility to shore. The revenues generated would then allow for reinvestment in other facilities and pipeline.

Acquisition

Trinity has the potential to significantly grow our resource base with our agreement to acquire Centrica plc's 80% ownership of Blocks 1(a) & 1(b), potentially adding c.40.0 mmboe of 2C resources. The asset is fully appraised with six existing wells and a high quality 3D dataset having established excellent reservoir quality and proven well deliverability located in shallow (20-35m) water. Post development, a plateau production rate of 80.0 mmcf/d (64.0 mmcf/d or 10,700 boepd net) is forecast. The acquisition is pending completion with the balance of payment of USD 20.5 million plus working capital adjustments with interest accruals due in Q3 2015.

Reserves and Resources

A comprehensive management review of all assets has recently been concluded and has estimated the current 2P reserves to be 25.3 million stock tank barrels (mmstb) at the end of 2014, compared to the year-end 2013 reserve estimate of 47.7 mmstb. The subsurface review has defined investment programmes and constituent drilling targets to commercialise the reserves as detailed, by asset area, in the table below. The 2P reserve estimate is based on a fully funded programme under the assumption that management will secure the funding required to deliver this programme.

Management Estimates: 2P Reserves
		31-Dec-13	2014 Prod'n	Revisions	31-Dec-14
ASSETS		mmstb	mmstb	mmstb	mmstb
East Coast	Oil	36.3	(0.4)	(21.3)	14.6
Onshore	Oil	6.8	(0.7)	0.7	6.8
West Coast	Oil	4.6	(0.2)	(0.5)	3.9
TOTAL		47.7	(1.3)	(21.1)	25.3

The primary reduction in reserves is attributable to the Trintes field, on the East Coast, and is due to a revised view of the reservoirs potential in a lower commodity price world where capital allocation is constrained.

During 2014 significant progress has been made preparing the FDP for the TGAL discovery and a comprehensive subsurface evaluation of the Trintes Field was subsequently completed. On this basis, a total of c. 7.3 mmstb has been re-categorized from 2P reserves into 2C resources at Trintes. Further development potential exists along the Galeota anticline to the NE where almost 300.0 mmstb of STOIIP has been mapped through the integration of 3D Seismic data and the EG-3 and EG-4 wells that define and tie the dataset to the North East.

The TGAL discovery has estimated gross 2C resources of 22.1 mmstb (14.4 mmstb net to Trinity's 65.0% interest), a modest recovery factor of 12% based on STOIIP best estimate of 186.0 mmstb. Therefore, notwithstanding further, identified potential in the Galeota block, estimated combined 2P and 2C resources from the Trintes-TGAL area totals over 36.0 mmstb.

Financial review

In 2014 Trinity generated USD 12.2 million operating profit and a USD 141.2 million loss after tax due to exceptional items(principally asset impairment and exploration costs written off), finance costs, currency translation and taxation of USD 135.9 million, USD 5.1 million, USD 0.2 million and USD 12.7 million respectively.

Statement of Comprehensive Income

Trinity's financial results for 2014 showed a Total Comprehensive Loss of USD 141.2 million (2013: USD 38.8 million loss) on gross revenues of USD 113.5 million.

Operating Revenues

2014 revenues were USD 113.5 million (2013: USD 123.8 million). This decrease is mainly attributable to the combination of (i) lower production across all assets and (ii) the decline in average realised oil price of USD 85.8/bbl (2013: USD 91.6/bbl)

· Production

- Production for 2014 was 1.3 mmbbls (2013: 1.4 mmbbls)

- Average production was 3,603 bopd, with 56% (2,006 bopd) sold onshore, 14% (491 bopd) attributable to the west coast and 30% (1,106 bopd) from the east coast

· Oil prices

Realised oil price for 2014 averaged USD 85.8/ bbl (2013: 91.6/ bbl)

Operating Expenses

· Operating expenses were USD 101.3 million (2013: USD 102.2 million) which are made up as follows:

- Royalties of USD 37.0 million (2013: USD 37.3 million)

- Production costs of USD 32.9 million (2013: USD 33.1 million)

- Depreciation, depletion and amortisation amounted to USD 16.3 million (2013: USD 13.2 million)

- General and administrative expenses of USD 15.0 million (2013: USD 18.5 million)

Operating Profit before Exceptional Items

Operating profit before exceptional items amounted to USD 12.2 million (2013: USD 21.6 million)

Exceptional items

Exceptional items amounted to USD 135.9 million (2013: USD 28.8 million loss) comprising mainly of the following:

- Impairment loss of USD 96.2 million of property, plant and equipment assets was recognised on the carrying values of oil and gas assets due to lower forward oil prices. Impairment of the exploration well EG-8 c. USD 22.6 million on the basis that sufficient data exist to indicate that the book value will not be recovered due to the absence of commercial reserves. The Pletmos exploration costs of c. USD 0.9 million have been impaired as there is no further exploration and evaluation planned or budgeted and management is in the process of relinquishing the license

- Exploration write off of the El Dorado 1 well of USD 14.9 million

- Exceptional items of USD 1.2 million represents a provision for a potential claim against a subsidiary of the Group by a supplier of services in the oil and gas industry

Operating Loss after Exceptional Items

The Group's operating loss after exceptional items was USD 123.7 million (2013: USD 50.4 million profit).

Net Finance Costs

In 2014 finance costs amounted to USD 5.1 million (2013: USD 2.4 million), which is made up of the unwinding of the decommissioning liability USD 1.5 million (2013: USD 1.2 million) and interest on the fully drawn (USD 20.0 million & USD 25.0 million) Citibank loans of USD 3.6 million (2013: USD 1.2 million).

Taxation

The tax charge for 2014 was USD 12.7 million (2013: USD 9.5 million), and its components are described below.

- Supplemental Petroleum Tax (SPT): All SPT due for 2013 was paid as it fell due. The SPT charge for 2014 amounted to USD 14.9 million which is still payable (2013: USD 10.4 million)

- Petroleum Profits Tax (PPT): The PPT charge for the year was USD 1.1 million (2013: USD 5.8 million), mainly incurred by Oilbelt Services Limited and Lennox Petroleum Services Limited

- Corporation tax (CT): The CT for the year amounted to USD 2.2 million (2013: USD 0.9 million)

- Deferred tax: There was a decrease in the deferred tax asset and deferred tax liability by USD 37.1 million and USD 42.6 million respectively. Hence, the combined movement resulted in a net credit of USD 5.5 million (2013: USD 7.7 million)

Total Comprehensive Income

Trinity's financial results for 2014 showed a Total Comprehensive Loss of USD 141.2 million (2013: USD 38.8 million loss) on gross revenues of USD 113.5 million (2013: USD 123.8 million).

Statement of Cash Flows

The opening cash balance as at 1^st January 2014 was USD 25.1 million and the ending cash balance at 31 December 2014 was USD 33.1 million.

Changes in Working Capital

During the year Trinity experienced working capital outflows of USD 12.8 million. Significant changes are outlined in the table below:

	Uses of Cash	Sources of Cash
	USD '000	USD '000
Inventory		121
Trade and other receivables		14,792
Trade and other payables	27,742
Change in Working Capital	12,829

The Company paid taxes of USD 3.8 million in 2014 (2013: USD 25.4 million) which were related to production taxes for 2013.

Liquidity

Trinity's revenues have decreased as a result of a sharp decline in oil prices, which has in turn limited the Company's ability to reinvest in its key assets to maintain or grow production. In addition, Trinity's covenants on its credit facility arrangement was breached with Citibank (Trinidad and Tobago) Limited. Trinity repaid USD 20.0 million in February 2015 and received a moratorium on principal payments until 15^th June, 2015. Trinity has had and continues to have pro-active discussions with its principal lender to manage the repayment profile on the remaining USD 13.0 million debt balance. Trinity has a working capital deficit of USD 16.7 million (2013: surplus USD 5.3 million).

Operating activities

Cash inflow from operating activities was USD 11.8 million (2013: USD 17.0 million), being the net effect of:

· Adjusted profit inflow of USD 28.5 million (2013: 32.0 million)

· Changes in working capital outflow of USD 12.8 million (2013: inflow of USD 10.5 million)

- VAT refunds due at year-end totalled USD 11.6 million with USD 10.3 million VAT due from the T&T tax authority while USD 1.3 million due from the UK. Notably, VAT refunds of USD 18.3 million were received in 2014

- Taxation paid of USD 3.8 million (2013: USD 25.4 million)

Investing activities

Cash outflow from investing activities was USD 16.9 million (2013: USD 85.6 million), and is made up of capital expenditure

Capital expenditure during 2014 totalled USD 16.9 million (2013: USD 92.1 million) with spend occurring across all of the Group's assets:

· Exploration and evaluation assets: The majority of expenditure of USD 5.0 million in 2014 relates to drilling of the El Dorado 1 exploration well which straddled December 2013 into February 2014. The total cost of this well was USD 14.9 million which was classified as exploration cost write off due to uncommercial reserves being discovered

· Property plant and equipment: expenditure on property, plant and equipment for the year was USD 11.9 million (2013: USD 56.7 million). This included:

- Wells drilled: USD 8.7 million was spent to drill 2 wells, which included 1 onshore well and 1 east coast, both of which were unsuccessful and had unrealised production

- Infrastructure upgrades: USD 3.2 million was spent on a number of projects, across the onshore, west coast and east coast assets, which were required to sustain current production and create capacity for future production growth

Cash inflow from financing activities

Cash inflow from financing activities was USD 13.0 million (2013: USD 71.1 million), being the net effect of: Full drawdown of the Citibank USD 25.0 million facility, Debt repayment and finance costs:

- Repayment of borrowings of USD 8.0 million (2013: USD 6.2 million) includes principal repayments of both Citibank loans

- Payment of loan finance costs of USD 4.0 million (2013: USD 1.2 million)

Closing Cash Balance

Trinity's cash balance at 31st December 2014 was USD 33.1 million.

Trinity Exploration & Production Plc

Consolidated and Company Financial Statements

(Expressed In United States Dollars)

31st December, 2014


Trinity Exploration & Production Plc Consolidated Statement of Comprehensive Income for the year ended 31st December, 2014 (Expressed in United States Dollars)
	Notes		2014	2013
			$'000	$'000
Operating Revenues
Crude oil sales			113,319	123,585
Other income			144	234
			113,463	123,819

Operating Expenses
Royalties			(36,980)	(37,343)
Production costs			(32,931)	(33,099)
Depreciation, depletion and amortisation	5		(16,335)	(13,211)
General and administrative expenses			(15,019)	(18,539)
			(101,265)	(102,192)

Operating Profit Before Exceptional Items			12,198	21,627

Exceptional Items	29		(120,939)	28,766
Exploration cost write off			(14,929)	--

Operating (Loss)/Profit After Exceptional Items	19		(123,670)	50,393

Finance Income			33	--

Finance Costs	20		(5,151)	(2,357)

(Loss)/Profit Before Income Tax			(128,788)	48,036

Income Tax Expense	21		(12,657)	(9,481)

(Loss)/Profit For The Year			(141,445)	38,555

Other Comprehensive Income:
Items that may be subsequently reclassified to profit or loss
Currency Translation			263	277

Total Comprehensive (Loss)/Income For The Year			(141,182)	38,832


Earnings per share (expressed in dollars per share)
Basic	30	(1.49)			0.45
Diluted	30	(1.49)			0.43

Trinity Exploration & Production Plc Consolidated Statement of Financial Position as at 31st December, 2014 (Expressed in United States Dollars)
	Notes	2014	2013
ASSETS		$'000	$'000

Non-current Assets
Property, plant and equipment	5	85,655	177,592
Intangible assets	6	25,676	59,002
Deferred tax assets	17	27,630	64,693
		138,961	301,287
Current Assets
Inventories	8	11,909	12,029
Trade and other receivables	7	21,990	36,803
Non-current asset held-for-sale	14	672	--
Taxation recoverable	9	548	528
Cash and cash equivalents	10	33,084	25,145
		68,203	74,505
Total Assets		207,164	375,792

Equity and liabilities

Equity Attributable to Owners of the Parent
Share capital	11	94,800	94,800
Share premium	11	116,395	116,395
Share warrants	12	71	71
Share based payment reserve	28	11,834	11,523
Merger reserves	13	75,467	74,808
Reverse acquisition reserve	13	(89,268)	(89,268)
Translation reserve		527	567
Accumulated (deficit)/surplus		(131,070)	10,375
Total Equity		78,756	219,271

Non-current Liabilities
Borrowings	15	--	11,910
Provision for other liabilities	16	39,775	29,027
Deferred tax liabilities	17	3,778	46,387
		43,553	87,324

Current Liabilities
Trade and other payables	18	33,374	61,117
Borrowings	15	33,000	3,989
Taxation payable	9	18,481	4,091
		84,855	69,197
Total Liabilities		128,408	156,521
Total Equity and Liabilities		207,164	375,792

The financial statements on pages 3 to 45 were authorised for issue by the Board of Directors on 27th May, 2015 and were signed on its behalf by:

___________________________________

Joel M. C. Pemberton

Chief Executive Officer

27th May 2015
Trinity Exploration & Production Plc Company Statement of Financial Position as at 31st December, 2014 (Expressed in United States Dollars)
	Notes	2014	2013
ASSETS		$'000	$'000

Non-current Assets
Investment in subsidiaries	22	44,513	94,401
Trade and other receivables	7	10,106	160,760
		54,619	255,161
Current Assets
Trade and other receivables	7	1,106	1,007
Cash and cash equivalents	10	10	4,189
		1,116	5,196
Total Assets		55,735	260,357

Equity and liabilities
Equity Attributable to Owners of the Parent
Share capital	11	94,800	94,800
Share premium	11	116,395	116,395
Share based payment reserve		1,419	1,127
Merger reserves		56,652	56,652
Accumulated deficit		(215,838)	(9,991)
Total Equity		53,428	258,983

Current Liabilities
Trade and other payables	18	1,147	1,374
Tax payable		1,160	--
		2,307	1,374
Total Liabilities		2,307	1,374
Total Equity and Liabilities		55,735	260,357

The financial statements on pages 3 to 45 were authorised for issue by the Board of Directors on 27th May, 2015 and were signed on its behalf by:

____________________________________

Joel M. C. Pemberton

Chief Executive Officer

27th May 2015

Trinity Exploration & Production Plc
Registered Number: 07535869

Trinity Exploration & Production Plc Consolidated Statement of Changes in Equity for the year ended 31st December, 2014 (Expressed in United States Dollars)
Year ended 31st December, 2013	Share Capital	Share Premium	Share Warrant	Share Based Payment Reserve	Reverse Acquisition Reserve	Merger Reserve	Translation Reserve	Accumulated (Losses)/ Retained Earnings	Total Equity
	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000

At 1st January, 2013	34	17,550	71	7,295	--	52,853	290	(27,180)	50,913

Acceleration of share options (note 28)	--	--	--	4,708	--	--	--	--	4,708
Placing shares issued (note 11)	47,500	41,523	--	--	--	--	--	--	89,023
Share options exercised	--	--	--	(411)	--	--	--	--	(411)
Shares issued to previous equity holders of TEPL (note 11 & 13)	25,618	(17,550)	--	--	(30,421)	22,353	--	--	--
Legacy TEP Plc share capital	21,648	80,817	--	--	(58,800)	--	--	--	43,665
Cost of raising equity (note 11)	--	(5,945)	--	--	--	--	--	--	(5,945)
Share options granted (note 28)	--	--	--	187	--	--	--	--	187
LTIP's granted (note 28)	--	--	--	88	--	--	--	--	88
Legacy share options (note 28)	--	--	--	(262)	--	--	--	--	(262)
Non-controlling interest	--	--	--	--	--	--	--	(1,000)	(1,000)
Translation difference	--	--	--	(82)	(47)	(398)	--	--	(527)
Comprehensive income for the year	--	--	--	--	--	--	277	38,555	38,832

At 31st December, 2013	94,800	116,395	71	11,523	(89,268)	74,808	567	10,375	219,271

At 1st January, 2014	94,800	116,395	71	11,523	(89,268)	74,808	567	10,375	219,271
Share based payment charge (note 28)	--	--	--	163	--	--	--	--	163
Translation difference	--	--	--	148	--	659	(303)	--	504
Comprehensive loss for the year	--	--	--	--	--	--	263	(141,445)	(141,182)

At 31st December, 2014	94,800	116,395	71	11,834	(89,268)	75,467	527	(131,070)	78,756

Trinity Exploration & Production Plc Company Statement of Changes in Equity for the year ended 31st December, 2014 (Expressed in United States Dollars)
	Share Capital	Share Premium	Share Based Payment Reserve	Merger Reserve	Accumulated Losses	Total Equity
	$'000	$'000	$'000	$'000	$'000	$'000
Year ended 31st December, 2013

At 1st January, 2013	21,648	80,817	1,117	34,228	(7,296)	130,514
Shares issued to previous holders of TEPL	25,652	--	--	22,424	--	48,076
Placing shares issued	47,500	41,523	--	--	--	89,023
Cost of raising equity	--	(5,945)	--	--	--	(5,945)
Legacy share option adjustment	--	--	(262)	--	--	(262)
Share options granted	--	--	226	--	--	226
LTIP granted	--	--	53	--	--	53
Translation difference	--	--	(7)	--	--	(7)
Comprehensive loss for the year	--	--	--	--	(2,695)	(2,695)

At 31st December, 2013	94,800	116,395	1,127	56,652	(9,991)	258,983

At 1st January, 2014	94,800	116,395	1,127	56,652	(9,991)	258,983
Share based payment charge	--	--	292	--	--	292
Comprehensive loss for the year	--	--	--	--	(205,847)	(205,847)


At 31st December, 2014	94,800	116,395	1,419	56,652	(215,838)	53,428


Trinity Exploration & Production Plc Consolidated Statement of Cash Flows for the year ended 31st December, 2014 (Expressed in United States Dollars)
	Notes	2014	2013
		$'000	$'000
Operating Activities
(Loss)/Profit before taxation		(128,788)	48,036
Adjustments for:
Translation difference		(232)	79
Finance cost - loans and interest	20	3,985	1,179
Share based payment charge	28	163	4,721
Finance cost - decommissioning provision	16	1,167	1,178
Finance income		(33)	--
Depreciation, depletion and amortisation	5	16,335	13,211
Goodwill	29	--	2,746
Negative goodwill	29	--	(52,070)
Abandonment	5	--	1,624
Potential claim	29	1,270	--
Exploration cost write off	6	14,929	--
Impairment of property, plant and equipment	5	96,242	3,468
Impairment of intangibles	6	23,430	7,786
		28,468	31,958

Changes In Working Capital
Inventories	8	121	(472)
Trade and other receivables	7	14,792	(2,922)
Trade and other payables	18	(27,742)	13,842
		15,639	42,406

Taxation paid		(3,837)	(25,430)
Net Cash Inflow From Operating Activities		11,802	16,976

Investing Activities
Purchase of exploration and evaluation assets	6	(4,970)	(35,396)
Purchase of property, plant and equipment	5	(11,941)	(56,736)
Cash and cash equivalent acquired in acquisition		--	6,529
Net Cash Outflow From Investing Activities		(16,911)	(85,603)

Financing Activities
Finance income		33	--
Issue of shares (net of costs)		--	84,868
Repayment of convertible shareholder loan notes	14	--	(6,355)
Finance cost - loans	20	(3,985)	(1,179)
Repayment of borrowings	15	(8,000)	(6,217)
Proceeds from new borrowings	15	25,000	--
Net Cash Inflow From Financing Activities		13,048	71,117

Increase in Cash and Cash Equivalents		7,939	2,490

Cash And Cash Equivalents
At beginning of year		25,145	22,655
Increase in cash and cash equivalents		7,939	2,490
At end of year	10	33,084	25,145

Trinity Exploration & Production Plc Company Statement of Cash Flows for the year ended 31st December, 2014 (Expressed in United States Dollars)
	Notes	2014	2013
		$'000	$'000

Operating Activities
Loss before taxation		(204,690)	(2,695)
Adjustments for:
Finance income - intragroup loans		(8,420)	(1,311)
Finance cost - interest on taxes		3	--
Share based payment charge		79	(224)
Impairment of investment in subsidiaries	22	50,100	--
Impairment of intragroup loans		161,569	--
		(1,359)	(4,230)

Changes In Working Capital
Trade and other receivables	7	(11,013)	(75,719)
Trade and other payables	18	(224)	(407)

Net Cash Outflow from Operating Activities		(12,596)	(80,356)

Financing Activities
Finance income - intragroup loans		8,420	1,311
Finance cost - interest on taxes		(3)	--
Share capital issued (net of costs)	11	--	83,078

Net Cash Inflow from Financing Activities		8,417	84,389

(Decrease)/Increase In Cash And Cash Equivalents		(4,179)	4,033

Cash And Cash Equivalents
At beginning of year		4,189	154
(Decrease) / Increase in cash and cash equivalents		(4,179)	4,033
Exchange rate differences		--	2

At end of year	10	10	4,189

Trinity Exploration & Production Plc

Notes to the Consolidated Financial Statements

31st December, 2014

1 Background and Accounting Policies

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

Background

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

Basis of Preparation

This consolidated financial information has been prepared on a going concern basis, in accordance with International Financial Reporting Standards as adopted by the European Union (IFRS as adopted by the EU), IFRS Interpretations Committee (IFRS IC) interpretations as adopted by the European Union and those parts of the Companies Act 2006 as applicable to companies reporting under IFRS. This consolidated financial information has been prepared under the historical cost convention, modified for fair values under IFRS.

The preparation of the consolidated financial information in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group's accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the consolidated financial information are disclosed in note 3.

The Company has taken advantage of the exemption in Section 408 of the Companies Act 2006 not to present its own income statement or statement of comprehensive income. The loss for the Company for the year was $205.8 million (2013 $2.7 million loss) due to the impairment of intragroup loans and investment in subsidiaries.

Going Concern

In making their going concern assessment, the Directors have considered the Group's budget and cash flow forecasts. The Group is incurring expenditure in order to continue operations from its existing fields as well as maintain a much reduced level of overheads. Discussion with the Group's bankers is ongoing and, under the assumption that the Group's remaining external debt is not recalled following expiry of the current moratorium on 15 June 2015, has sufficient cash flow to continue operating for at least the next 12 months from the date of approval of these financial statements. However, the Group's intended expenditure for the development of the business and delivery of its full 2P reserve potential, exceeds the existing cash reserves and as such the Group will need to generate additional funding in the near term in order to continue the development of these operations.

The Company has commenced a formal sales process along with consideration of alternative funding options including the sale of one or more existing assets, a farm-out or corporate transaction. At the date of signing the accounts, a number of conditional proposals and expressions of interest had been received but not concluded.

The Board of Directors has carefully considered and formed a reasonable judgement that, at the time of approving the financial statements, there is a reasonable expectation that the Company will be able to obtain sufficient funding to continue operations for the foreseeable future. For this reason, the Board of Directors continues to adopt the going concern basis of preparing the financial statements. However, the need for additional funding indicates the existence of a material uncertainty which may cast significant doubt on the Company and the Group's ability to continue as a going concern and, therefore the Group and Company may be unable to fully realise their assets and discharge their liabilities in the normal course of business. The financial statements do not include the adjustments that would be necessary if the Group and Company were unable to continue as a going concern.

New and amended standards adopted by the Group:

The following standards and amendments to existing standards have been published and are effective for periods beginning after 1st January, 2014 but had no significant impact on the Group:

IFRS 10 Consolidated Financial Statements	This is a new standard that replaces existing guidance on this area and introduces new criteria for determining whether an entity should be consolidated within the results of the Group, with the key determinant now being whether the Group controls the entity (ie has the power to direct the level of returns the entity makes, and whether the Group receives variable returns from the Group.	Periods beginning on / after 1st January, 2013
IFRS 11 Joint Arrangements	As with the above, this is a new standard, which reduces the number of categories of and therefore options for accounting for joint arrangements. Joint ventures are accounted for using the equity method, and a joint operator in a joint operation will recognise its share of assets, liabilities, revenues and expenses in its own financial statements. The previous accounting policy choice has been removed.	Periods beginning on / after 1 Jan 2013
IFRS 12 Disclosure of Interests in Other Entities	This new standard sets out the disclosure requirements in the financial statements in respect of IFRS 10 and IFRS 11 The key additional disclosure above those already required under existing standards, is that additional information is required on the nature, risks and financial effects of the Company's interests in other entities.	Periods beginning on / after 1st January, 2013
IAS 19 Employee Benefits	A further amendment to IAS 19R is designed to clarify the application of the standard to plans that require employees or third parties to contribute towards the cost of benefits. Contributions that are linked to service, but do not vary with the length of the employee service are to be deducted from the cost of benefits earned in the period that the service is provided. However, contributions that vary according to the length of service must be spread over the service period. Contributions not linked to service are reflected in the measurement of the balance sheet liability.	Periods beginning on / after 1st July, 2014
IAS 36 Impairment of Assets	Some narrow scope amendments have been made to the Standard, which will impact entities who recognise or reverse an impairment loss on non-financial assets by altering some of the associated disclosure requirements.	Periods beginning on / after 1st January 2014
IAS 39 Financial Instruments: recognition and measurement	The amendment clarifies the accounting impact on hedge accounting when entities novate derivative contracts to central counterparties to reduce counterparty risk.	Periods beginning on / after 1st January 2014

New and amended standards not yet adopted by the Group:

The following standards and amendments to existing standards have been published and are effective for periods beginning after 1st January, 2014 and have not been applied in preparing these consolidated financial statement. None of these is expected to have a significant effect on the Group:

IFRS 15 Revenue from Contracts with Customers	The new standard for revenue replaces IAS 18, and will have a significant impact on some entities. The changes could have an impact on the timing of when revenue is recognised and the period over which it is recognised as well as on the financial statement disclosures.	Periods beginning on / after 1st January 2017
IFRS 9 Financial Instruments	This is a new accounting standard that introduces a new classification approach for financial assets and liabilities. The previous four categories for financial assets will be reduced to three, being fair value through profit and loss, fair value through other comprehensive income and amortised cost, and financial liabilities will be measured at amortised cost or fair value through profit and loss. This may result in additional gains or losses being recognised in the Income.	Periods beginning on / after 1st January 2018

Basis of consolidation

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

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

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

Uniform accounting policies have been adopted across the Group. All intra-Group transactions, balances, income and expenses are eliminated on consolidation.

Business combination

The acquisition of subsidiaries is accounted for using the acquisition method.

Identifying the acquirer in a business combination is based on the concept of 'control'. However in certain circumstances the positions may be reversed and it is the legal subsidiary entity's shareholders who effectively control the combined Group even though the other party is the legal parent. IFRS 3 requires, in a business combination effected through an exchange of equity interests, all relevant facts and circumstances be considered to determine which of the combining entities has the power to govern the financial and operating policies of the other entity. These combinations are commonly referred to as 'reverse acquisitions'. A detailed summary of the business combination and financial implication of this is provided within note 27.

For each business combination, the cost of the acquisition is measured at the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed, and equity instruments issued by the Group in exchange for control of the acquiree. Transaction costs are expensed directly to the Income Statement. The acquiree's identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 are recognised at their fair value at the acquisition date. Where the Group has acquired assets held in a subsidiary undertaking that do not meet the definition of a business combination, purchase consideration is allocated to the net assets acquired and the interests of non-controlling shareholders are initially measured at their proportionate share of the acquiree's net assets.

Revenue recognition

Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for the sale of crude oil and services provided in the ordinary course of business, net of discounts and sales related taxes. Revenue is recognised when goods are delivered and title has passed when the oil is transferred to Petrotrin's pipelines, at which point revenue will be recognised. Petrotrin are the group's only customer.

Interest income is accrued on a time basis, by reference to the principal outstanding and the interest rate applicable, unless collectability is in doubt.

Share-based payments

The Group operates a number of equity-settled, share-based compensation plans (warrants/options/long term incentive plans 'LTIP') as consideration for services rendered by the Group's employees. The fair value of the services received in exchange for the grant of share-based payment is recognised as an expense. The total amount to be expensed is determined by reference to the fair value of the options granted:

- including any market performance conditions (for example, an entity's share price);

- excluding the impact of any service and non-market performance vesting conditions and

- including the impact of any non-vesting conditions

Non-market performance and service conditions are included in assumptions about the number of share-based payments that are expected to vest. The total expense is recognised over the vesting period, which is the period over which all of the specified vesting conditions are to be satisfied.

At the end of each reporting period, the Group revises its estimates of the number of options that are expected to vest based on the non-market vesting conditions. It recognises the impact of the revision to original estimates, if any, in the statement of comprehensive income, with a corresponding adjustment to equity. When the options are exercised, the Group issues new shares. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium.

Where the services provided relate solely to the issue of share capital, the expense will be charged to equity within the share premium account.

The grant by the Company of options and LTIPs over its equity instruments to the employees of subsidiary undertakings in the Group is treated as a capital contribution. The fair value of employee services received, measured by reference to the grant date fair value, is recognised over the vesting period as an increase to investment in subsidiary undertakings, with a corresponding credit to equity.

Foreign currency translation

(a) Functional and presentation currency

The functional currency of the Group operating entity is Trinidad and Tobago dollars as this is the currency of the primary economic environment in which the entities operate. The presentation currency is United State Dollars which better reflects the Group's business activities and improves ability of users of the financial statements to compare financial results with others in the International Oil and Gas industry. The Statement of Financial Position is translated at the closing rate and Statement of Comprehensive Income is translated at the average rate. The following exchange rates have been used in the preparation of these accounts:

	2014		2013
	USD	£	USD	£
Average rate TTD= USD/£	6.385	10.523	6.416	10.009
Closing rate TTD= USD/£	6.359	9.934	6.436	10.580

(b) Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of comprehensive income.

Intangible assets

(a) Exploration and evaluation assets

Capitalisation

Exploration and Evaluation assets are initially classified as intangible assets. Such costs include those directly associated with an exploration area. Upon discovery of commercial reserves capitalisation is recognised within Property, Plant and Equipment.

Oil and natural gas exploration and evaluation expenditures are accounted for using the successful efforts method of accounting. Under this method, costs are accumulated on a prospect-by-prospect basis and capitalised upon discovery of commercially viable mineral reserves. If the commercial viability is not achieved or achievable, such costs are charged to expense.

Costs incurred in the exploration and evaluation of assets includes:

(i) License and property acquisition costs

Exploration and property leasehold acquisition costs are capitalised within exploration and evaluation assets.

(ii) Exploration and evaluation expenditure

Costs directly associated with an exploration well are capitalised until the determination of reserves is evaluated. Such costs include topographical, geological, geochemical, and geophysical studies, exploratory drilling costs, trenching, sampling and activities in relation to evaluating the technical feasibility and commercial viability of extracting mineral resources. Capitalisation is made within property, plant and equipment or intangible assets according to its nature however a majority of such expenditure is capitalised as an intangible asset. If commercial reserves are found, the costs continue to be carried as an asset. If commercial reserves are not found, exploration and evaluation expenditures are written off as a dry hole when that determination is made.

Once commercial reserves are found, exploration and evaluation assets are tested for impairment and transferred to development tangible and intangible assets as applicable. No depreciation and/or amortisation are charged during the exploration and evaluation phase.

Impairment

Exploration and evaluation assets are tested for impairment (in accordance with the criteria set out in IFRS 6: Exploration for and Evaluation of Mineral Resources) whenever facts and circumstances indicate impairment. An impairment loss is recognised for the amount by which the exploration and evaluation assets' carrying amount exceed their recoverable amount. The recoverable amount is the higher of the exploration and evaluations assets' fair value less costs to sell and their value in use. For the purposes of assessing impairment, the exploration and evaluation assets subject to testing are Grouped with existing cash generating units (CGUs) of related production fields located in the same geographical region. The geographical region is the same as that used for reserves reporting purposes.

The following indicators are evaluated to determine whether these assets should be tested for impairment:

· The period for which the Group has the right to explore in the specific area.

· Whether substantive expenditure on further exploration and evaluation in the specific area is budgeted or planned.

· Whether exploration and evaluation in the specific area have not led to the discovery of commercially viable quantities and the Company has decided to discontinue such activities in the specific area.

· Whether sufficient data exist to indicate that, although a development in the specific area is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale.

(b) Goodwill

Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred and the amount recognised for non-controlling interest over the net identifiable assets acquired and liabilities assumed. If this consideration is lower than the fair value of the net assets of the subsidiary acquired, the difference is recognised in profit or loss.

After initial recognition, goodwill is measured at cost less any accumulated impairment losses. For the purpose of impairment testing, goodwill acquired in a business combination is, from the acquisition date, allocated to each of the Company's cash-generating units that are expected to benefit from the combination, irrespective of whether other assets or liabilities of the acquiree are assigned to those units.

Property, plant and equipment

(a) Oil and gas assets

Development and Producing Assets - Capitalisation

Acquisitions of oil and gas properties are accounted for under the purchase method where the transaction meets the definition of a business combination.

Transactions involving the purchases of an individual field interest, or a Group of field interests, that do not qualify as a business combination are treated as asset purchases, irrespective of whether the specific transactions involve the transfer of the field interests directly, or the transfer of an incorporated entity. Accordingly, the consideration is allocated to the assets and liabilities purchased on a relative fair value basis.

Proceeds on disposal are applied to the carrying amount of the specific asset or development and production assets disposed of. Any excess is recorded as a gain on disposal in the statement of comprehensive income and any shortfall between the proceeds and the carrying amount is recorded as a loss on disposal in the statement of comprehensive income.

Expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development commercially proven wells is capitalised according to its nature. When development is completed on a specific field it is transferred to Production Assets. No depreciation and/or amortisation are charged during the development phase.

Expenditure on Geological and Geophysical (G&G) surveys used to locate and identify properties with the potential to produce commercial quantities of oil and gas as well as to determine the optimal location for development wells are capitalised.

Development and Producing Assets - Impairment

An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount. Impairment triggers include but not limited to, declining long term market prices for oil and gas, significant downward reserve revisions, increased regulations or fiscal changes, deteriorating local conditions such that it become unsafe to continue operations and obsolescence

The carrying value is compared against the expected recoverable amount. The recoverable amount is the higher of an asset's fair value less costs to sell and the value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels (its cash generating unit) for which there are separately identifiable cash flows. The cash generating unit applied for impairment test purposes is generally the field. These fields are the same as that used for reserves reporting purposes.

Producing Assets - Depreciation, depletion and amortisation

The provision for depreciation, depletion and amortisation of developed and producing oil and gas assets are calculated using the unit-of-production method.

Oil and gas assets are depreciated generally on a field-by-field basis using the unit-of-production method which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future development costs. Changes in the estimates of commercial reserves or future development costs are dealt with prospectively.

Decommissioning

Provision for decommissioning is recognised in full at the commencement of oil and gas production. The amount recognised is the net present value of the estimated cost of decommissioning at the end of the economic producing lives of the wells and the end of the useful lives of refinery and storage units. Such costs include removal of equipment, restoration of land or seabed. The unwinding of the discount on the provision is included in the statement of comprehensive income within finance costs.

A corresponding asset is also created at an amount equal to the provision. This is subsequently depleted as part of the capital costs of the production assets. Any change in the present value of the estimated expenditure or discount rates are reflected as an adjustment to the provision and the asset and dealt with prospectively.

(b) Non-oil and gas assets

All property, plant and equipment are recorded at historical cost less accumulated depreciation and any impairment losses. Historical cost includes the original purchase price of the asset and expenditure that is directly attributable to bringing the asset to its working condition for its intended use. Subsequent costs are included in the asset's carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably.

The provision for depreciation with respect to operations other than oil and gas producing activities is computed using the straight-line method based on estimated useful lives as follows:

Buildings - 20 years

Plant and equipment - 4 years

Other - 4 years

The assets' residual values and useful lives are reviewed, and adjusted if appropriate at each statement of financial position date. An asset's carrying amount is written down immediately to its recoverable amount if the asset's carrying amount is greater than its estimated recoverable amount.

Gains and losses on disposals are determined by comparing proceeds with carrying amounts and are included in the statement of comprehensive income.

Repairs and maintenance are charged to the statement of comprehensive income during the financial period in which they are incurred. The cost of major renovations is included in the carrying amount of the asset when it is probable that future economic benefits in excess of the originally assessed standard of performance of the existing assets will flow to the Group. Major renovations are depreciated over the remaining useful life of the related asset.

Impairment of non-financial assets

At each reporting date, assets that have an indefinite useful life, for example, goodwill, are not subject to amortisation and are tested for impairment. Assets that are subject to amortisation are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognised for the amount by which the asset's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash generating units). Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.

Inventories

Crude oil is stated at the lower of cost and net realisable value. Cost is determined by the first in first out (FIFO) method. Net realisable value is the estimated selling price in the ordinary course of business, less applicable variable selling expenses.

Materials and supplies are stated at lower of cost and net realisable value. Cost is determined using the average cost method.

Cash and cash equivalents

Cash and cash equivalents comprises cash in hand, deposits held at call with banks and other short-term highly liquid investments with original maturities of three months or less.

Trade receivables

Trade receivables are amounts due from customers for crude oil sold in the ordinary course of business. If collection is expected in one year or less (or in the normal operating cycle of the business if longer), they are classified as current assets. If not, they are presented as non-current assets.

Trade receivables are recognised initially at fair value less provision for impairment. Appropriate provisions for estimated irrecoverable amounts are recognised in the statement of comprehensive income when there is objective evidence that the Group will not be able to collect all amounts due according to the original terms of sale.

Trade payables

Trade payables are initially recognised at fair value.

Current and deferred income taxes

The tax expense for the period comprises current and deferred tax. Tax is recognised in the statement of comprehensive income, except to the extent that it relates to items recognised in equity. In this case the tax is also recognised directly in equity.

The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the statement of financial position date in the countries where the Company's subsidiaries and associates operate and generate taxable income. Management periodically evaluates positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. It establishes provisions where appropriate on the basis of amounts expected to be paid to the tax authorities.

Deferred income tax is recognised, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial information. However, the deferred income tax is not accounted for if it arises from initial recognition of an asset or liability in a transaction other than a business combination that at the time of the transaction affects neither accounting nor taxable profit or loss. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted by the statement of financial position date and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.

Deferred income tax assets are recognised only to the extent that it is probable that future taxable profit will be available against which the temporary differences can be utilised.

Deferred income tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets against current tax liabilities and when the deferred income taxes assets and liabilities relate to income taxes levied by the same taxation authority and the Company intends to settle the balances on a net basis.

Borrowings

Borrowings are recognised initially at fair value net of transaction costs incurred. Borrowings are subsequently stated at amortised cost; any differences between proceeds (net of transaction costs) and the redemption value is recognised in the statement of comprehensive income over the period of the borrowings using the effective interest method.

Borrowings are classified as current liabilities unless the Group has an unconditional right to defer settlement of the liability for at least 12 months after the statement of financial position date.

General and specific borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.

All other borrowing costs are recognised in comprehensive income in the period in which they are incurred.

Provisions

Provisions are recognised when the Group has a present legal or constructive obligation as a result of past events, where it is probable that an outflow of resources will be required to settle the obligation, and a reliable estimate of the amount of the obligation can be made. Provisions are not recognised for future operating losses.

Where there are a number of similar obligations, the likelihood that an outflow will be required in settlement is determined by considering the class of obligations as a whole. A provision is recognised even if the likelihood of an outflow with respect to any one item included in the same class of obligations may be small.

Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to passage of time is recognised as a finance cost.

Employee retirement benefits

The Group provides retirement benefits for certain employees in the form of individual annuity policies. These are defined contribution arrangements.

For defined contribution plans, the Group pays contributions to publicly or privately administered pension insurance plans on a mandatory, contractual or voluntary basis. The Group has no further payment obligations once contributions have been paid. The contributions are recognised as employee benefit expenses when they are due.

Non-current assets (or disposal Groups) held for sale

Non-current assets (or disposal Groups) classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell. Non-current assets and disposal Groups are classified as held for sale if their carrying amount will be recovered through a sale transaction rather than through continuing use. This condition is regarded as met only when the sale is highly probable and the asset (or disposal Group) is available for immediate sale in its present condition. Management must be committed to the sale which should be expected to qualify for recognition as a completed sale within one year from the date of classification.

Leases

Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Payments made under operating leases (net of any incentives received from the lessor) are charged to the income statement on a straight-line basis over the period of the lease.

Share capital

Ordinary shares are classified as equity. The nominal value of any shares issued is recognised in share capital with the excess above the nominal amount paid being shown within share premium.

Incremental costs directly attributable to the issue of new ordinary shares are shown in equity. Where, on issuing shares, share premium has been recognised, the expenses of issuing those shares and any commission paid on the issue of those shares have been written off against the share premium account.

Operating segment information

The steering committee is the Group's chief operating decision-maker. Management has determined the operating segments reported in a manner consistent with the internal reporting provided to the chief operating decision maker. The chief operating decision maker is responsible for making strategic decisions inclusive of; allocating resources and assessing performance of the operating segments. The chief operating decision - maker has been identified as the steering committee of Management which comprises; the Chief Executive Officer, Chief Operating Officer and Chief Financial Officer, that makes strategic decisions in accordance with Board policy.

Exceptional Items

Exceptional items are disclosed separately in the financial statements where it is necessary to do so to provide further understanding of the financial performance of the Group. They are material items of income or expense that have been shown separately due to the non-recurring nature and the significance of their nature or amount.

2 Financial Risk Management

Financial risk factors

The Group's activities expose it to a variety of financial risks. The Group's overall risk management programme seeks to minimise potential adverse effects on the Group's financial performance.

Risk management is carried out by management. Management identifies and evaluates financial risks.

(a) Market risk

(i) Foreign exchange risk

The Group is exposed to foreign exchange risk primarily with respect to the United States dollar. Foreign exchange risk arises from future commercial transactions and recognized assets and liabilities which are denominated in a currency that is not the entity's functional currency.

At 31st December, 2014, if the functional currency had weakened/strengthened by 10 per cent against the US dollar with all other variables held constant, post- tax(loss)/profit for the year would have been $1.8 million (2013: $3.2 million) lower/higher, mainly as a result of foreign exchange gain/losses on translation of US dollar-denominated borrowings and sales.

(ii) Price risk

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

At 31st December, 2014, if commodity prices had been 1 per cent higher/lower with all other variables held constant, post-tax (loss)/profit for the year would have been $0.6 million (2013: $1.2 million) lower/higher.

(iii) Interest rate risk

The Group's interest rate risk arises from borrowings. Borrowings issued at variable rates expose the Group to cash flow interest rate risk.

At 31st December, 2014, if interest rates on foreign currency-denominated borrowings had been 1 per cent higher/lower with all other variables held constant, post-tax (loss)/profit for the year would have been $0.3 million (2013: $0.2 million) lower/higher, mainly as a result of higher/lower interest expense on floating rate borrowings.

(b) Credit risk

Credit risk arises from cash and cash equivalents, deposits with banks and financial institutions, as well as credit exposures to customers, including outstanding receivables and committed transactions. For banks and financial institutions, management determines the placement of funds based on its judgement and experience.

All sales are made to a state-owned entity - Petrotrin. As Petrotrin is state owned, credit risk is considered to be low.

Prudent liquidity risk management implies maintaining sufficient cash and short-term funds and the availability of funding through an adequate amount of committed credit facilities. Management monitors rolling forecasts of the Group's liquidity and cash and cash equivalents on the basis of expected cash flow. At the end of the year the Group is facing liquidity issues over its current liabilities which include Borrowings, Accounts payable, accruals and taxes. The Groups' revenues have decreased as a result of a sharp decline in oil prices impacting the main source of revenue generation. In addition, the Group's credit facility arrangement was breached with Citibank Trinidad and Tobago Limited requiring repayment of $20.0 million in 2015, with the balance repayable following a moratorium to June 2015 should the breach continue. The Group has a working capital deficit of $16.7 million (2013: surplus $5.3 million). Management has suspended investment in appraisal and development activities and is continuing to manage its relationships with the Bank and Suppliers in an effort to handle the liquidity issue.

Management refers to the disclosures of note 1 "Going Concern" for more information regarding the factors considered by the Company in managing liquidity risk. The table below analyses the Group's financial liabilities into relevant maturity groupings based on the remaining period at the statement of financial position to the contractual maturity date. The amounts disclosed are the contractual undiscounted cash flows.

	Less than 1 year	Between 2 and 5 years
	$'000	$'000
At 31st December, 2014
Borrowings (including interest) (note 15)	33,414	--
Accounts payable, accruals and taxes (note 18,9)	51,855	--

At 31st December, 2013
Borrowings (including interest) (note 15)	5,197	18,137
Accounts payable, accruals and taxes (note 18,9)	65,208	--

(d) Capital risk management

The Group's objectives when managing capital are to safeguard the Group's ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. At the end of 2014 the Citibank debt service coverage ratio was breached (note 15).

In order to maintain or adjust the capital structure, the Group may adjust the amount of dividends paid to shareholders, issue new shares or sell assets to reduce debt.

Consistent with others in the industry, the Group monitors capital on the basis of the gearing ratio. This ratio is calculated as net debt divided by total capital. Net debt is calculated as total borrowings (including 'current and non-current borrowings' as shown in the consolidated statement of financial position) less cash and cash equivalents. Total capital is calculated as 'equity' as shown in the consolidated statement of financial position plus net debt.

	2014	2013
	$'000	$'000
Total borrowings	33,000	15,899
Less: cash and cash equivalents	(33,084)	(25,145)

(Funds)/net debt	(84)	(9,246)
Total equity	78,756	219,271

Total capital	78,672	210,025

Gearing ratio	(0.11)%	(4.40)%

Fair value estimation

The carrying values of trade receivables (less impairment provision) and payables are assumed to approximate their fair values. The fair value of financial liabilities for disclosure purposes is estimated by discounting the future contractual cash flows at the current market interest rate that is available to the Group for similar financial instruments.

3 Critical Accounting Estimates and Assumptions

Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.

Management makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below:

(a) Income taxes

Some judgement is required in determining the provision for income taxes. There are many transactions and calculations for which the ultimate tax determination is uncertain. Management recognises liabilities for anticipated tax audit issues based on estimates of whether additional taxes will be due. Where the final tax outcome of these matters is different from the amounts that were initially recorded, such differences will impact the income tax and deferred tax provisions in the period in which such determination is made.

(b) Recoverability of deferred tax assets

Deferred tax assets are recognised only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse, and a judgement as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the level of deferred tax assets recognised which can result in a charge or credit in which the change occurs.

This provision is significantly affected by changes in technology, laws and regulations which may affect the actual cost of decommissioning to be incurred at a future date. The estimate is also impacted by the discount rates used in the provisioning calculations. The discount rates used are the Group's risk-free rate and the core inflation rate applicable to the local oil and gas industry. The provision has been estimated using a discount rate of 3.9 per cent (2013: 3.9 per cent) and a core inflation rate of 3 per cent (2013: 3 per cent). The impact in 2014 of a 1 per cent change in these variables is as follows:

	Statement of Financial Position Obligation	Statement of Comprehensive Income/Expense
	2014	2014
	$'000	$'000

Discount rate
1 per cent increase in assumed rate	(6,108)	48
1 per cent decrease in assumed rate	7,415	(142)

Inflation rate
1 per cent increase in assumed rate	7,748	206
1 per cent decrease in assumed rate	(6,455)	(203)

(d) Estimation of reserves

All reserve estimates involve some degree of uncertainty, which depends chiefly on the amount of reliable geological and engineering data available at the time of the estimate. Generally, reserve estimates are revised as additional data become available. The Group estimates its own commercial reserves in 2013 and 2014 based on information compiled by appropriately qualified persons relating to the geological and technical data on the size, depth, shape and grade of the hydrocarbon body and suitable production techniques and recovery rates. The Group's reserve estimates are also evaluated periodically by independent external reserve evaluators, the last independent external reserve valuation was done in 2012.

As the economic assumptions used may change and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may also change. Such changes may impact the Group's reported financial position and results, which include:

- The carrying value of exploration and evaluation assets, oil and gas properties, property, plant and equipment, and goodwill may be affected due to changes in estimated future cash flows.

- Depreciation and amortisation charges in profit or loss may change where such charges are determined using the unit of production method, or where the useful life of the related assets change.

- Provisions for decommissioning may change - where changes to the reserve estimates affect expectations about when such activities will occur and the associated cost of these activities.

- The recognition and carrying value of deferred tax assets may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets.

During 2014 all subsidiaries onshore and offshore 2P reserve estimates were evaluated by management and approved by the Board of Directors. In 2013 management re-evaluated the reserve estimates for all assets as a result of new information being available in respect of planned drilling and development activity.

Effective 1st October, 2013, TEP Plc's joint venture partner Petrotrin agreed to convert its 35 per cent working interest in the Trintes field to an Overriding Royalty Agreement 'ORR'. No other financial consideration is payable beyond the ORR. The impact of this agreement provides TEP plc with 100 per cent revenue and cost entitlement in the Trintes field, with an overriding royalty payable to Petrotrin on crude oil produced in accordance with the ORR agreement. There have been no changes to these working interests in 2014.

(e) Farm outs and lease operatorship agreements

The Group accounts for its farmout and lease operatorship agreements on the basis that they will be renewed upon expiry. If any of these farmout or lease operatorship agreements are not renewed or renewed on disadvantageous terms this may severely impact the profitability and ongoing operations of the Group.

(f) Share-based payments

Management is required to make assumptions in respect of the inputs used to calculate the fair values of share-based payment arrangements which include expected volatility, risk free interest rate and current share price.

(g) Impairment of property, plant and equipment

Management performs impairment assessments on the Group's property, plant and equipment once there are indicators of impairment with reference to IAS 36: Impairment of Assets and in accordance with the accounting policy stated in note 1. In order to test for impairment, the higher of fair value less costs to sell and values in use calculations are prepared which require an estimate of the timing and amount of cash flows expected to arise from the CGU, cash generating unit. A CGU represents an individual field held by TEP plc.

During 2014 an impairment charge was recognised on the Group's property, plant and equipment of $96.2 million (2013: $ 3.5 million) see note 6, resulting in the carrying amount of the respective CGUs being written down to their recoverable amount:

CGU	Trintes	BM	PGB	WD 5/6	WD 14	WD 2	Total
($'million)
Impairment loss	(55.7)	(19.9)	(0.9)	(14.3)	(0.8)	(4.6)	(96.2)

As part of this assessment, management has carried out an impairment test on the oil and gas assets classified as property, plant and equipment. This test compares the carrying value of the assets at the reporting date with the expected discounted cash flows from each CGU. The period over which management has projected its cash flow forecast, ranges between a 9-16 year economic life based on the production profile. For the discounted cash flows to be calculated, management has used a production profile based on its best estimate of proven and probable reserves of each CGU and a range of assumptions, including an external oil and gas price profile and a discount rate which, taking into account other assumptions used in the calculation, management considers to be reflective of the risks.

This assessment involves judgement as to the likely commerciality of the asset; its proven and probable ('2P') reserves which are estimated using standard recognised evaluation techniques on a fully funded basis; future revenues and estimated development costs pertaining to the CGU's; and a discount rate utilised for the purposes of deriving a recoverable value.

If the price deck used in the impairment calculation had been 10 per cent lower than management's estimates at 31st December, 2014, the Group would have recognised a further impairment of Oil and Gas assets by $17.4 million (2013: $3.0 million) reducing the carrying value of property, plant and equipment. If the price deck used in the impairment calculation had been 10 per cent higher than management's estimates at 31st December, 2014, the Group would have recognised a lower impairment of Oil and Gas assets by $20.4 million (2013: $3.0 million).

Price deck	2014	2015	2016	2017	2018	2019	2020	2021	2022	2023
2014	--	49.4	56.6	61.6	64.4	66.2	67.3	68.1	68.4	68.4
2013	96.1	88.7	83.8	80.8	78.9	78.0	77.5	77.5	77.5	77.5

If the estimated cost of capital of 10 per cent (2013: 10 per cent) used in determining the post-tax discount rate for the CGU's had been 1 per cent lower than management's estimates the Group would have recognised a lower impairment of $3.1 million (2013: $0.6 million) against Oil and Gas assets within property, plant and equipment. If the estimated cost of capital had been 1 per cent higher than management's estimates the Group would have recognised a further impairment of $2.9 million (2013: $0.6 million).

(h) Impairment of intangible exploration and evaluation assets

The Group reviews the carrying values of intangible exploration and evaluation assets when there are impairment indicators which would tell whether an exploration and evaluation asset has suffered any impairment, in accordance with the accounting policy stated in note 1. The amounts of intangible exploration and evaluation assets represent the costs of active projects the commerciality of which is unevaluated until reserves can be appraised.

The Group has utilised internal management expertise in determining that the exploration well EG-8 and the exploration costs accumulated in South Africa were unrecoverable during 2014 (note 6).

An impairment charge of $23.5 million arose in the Trintes and South Africa CGU's during 2014, resulting in the full impairment of the Trintes EG-8 exploration well of $22.6 million and South Africa exploration costs of $0.9 million.

4 Segment Information

Management have considered the requirements of IFRS 8, in regard to the determination of operating segments, and concluded that the Group has only one significant operating segment being the production, development and exploration and extraction of hydrocarbons.

All revenue is generated from sales to one customer in Trinidad and Tobago the Petroleum Company of Trinidad and Tobago (Petrotrin). All non-current assets of the Group are located in Trinidad and Tobago; previously in 2013 an asset with a value of $1.2 million was located in South Africa. However this was written off during 2014 see note 6.

5 Property, Plant and Equipment

	Plant & Equipment	Land & Buildings	Oil & Gas Assets	Other	Total
	$'000	$'000	$'000	$'000	$'000
Year ended 31st December, 2014
Opening net book amount at 1st January, 2014	6,133	2,558	168,901	--	177,592
Additions	40	(106)	12,007	--	11,941
Impairment ¹ (note 29)	--	--	(96,242)	--	(96,242)
Transferred to available for sale (note 14)	--	--	(672)	--	(672)
Adjustment to decommissioning estimate (note 16)	--	--	8,156	--	8,156
Depreciation, depletion and amortisation charge for year	(1,270)	(151)	(14,914)	--	(16,335)
Translation difference	71	33	1,111	--	1,215

Closing net book amount at 31st December, 2014	4,974	2,334	78,347	--	85,655
At 31st December, 2014
Cost	12,260	3,125	275,284	336	291,005
Accumulated depreciation, depletion, amortisation and impairment	(7,357)	(824)	(198,048)	(336)	(206,565)
Translation difference	71	33	1,111	--	1,215

Closing net book amount	4,974	2,334	79,347	--	85,655

¹ An impairment loss of $96.2 million was recognised in respect of several CGU's, (see note 3 (g), (2013: $3.5 million) as a result of a sharp fall in oil prices combined with a downward revision in 2P reserve estimates. The recoverable amount was determined by estimating its fair value less costs to sell. In calculating this impairment, management used a production profile based on proven and probable reserves estimates and a range of assumptions, including third party oil price assumptions and a discount rate assumption of 10 per cent (2013: 10 per cent).

	Plant & Equipment	Land & Buildings	Oil & Gas Assets	Other	Total
	$'000	$'000	$'000	$'000	$'000
Year ended 31st December, 2013
Opening net book amount at 1st January 2013	2,071	1,541	61,102	6	64,720
Acquisition (note 27)	911	197	70,525	--	71,633
Additions	4,203	1,185	51,348	--	56,736
Well Abandonment	--	--	(1,624)	--	(1,624)
Impairment (note 29)	--	--	(3,468)	--	(3,468)
Adjustment to decommissioning estimate (note 16)	--	--	3,179	--	3,179
Depreciation, depletion and amortisation charge for year	(944)	(342)	(11,919)	(6)	(13,211)
Translation difference	(108)	(23)	(242)	--	(373)

Closing net book amount at 31st December, 2013	6,133	2,558	168,901	--	177,592
At 31st December, 2013
Cost	12,220	3,231	255,793	336	271,580
Accumulated depreciation, depletion, amortisation and impairment	(5,979)	(650)	(86,650)	(336)	(93,615)
Translation difference	(108)	(23)	(242)	--	(373)

Closing net book amount	6,133	2,558	168,901	--	177,592

6 Intangible Assets

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

	Exploration and evaluation assets $'000	Goodwill $'000	Total $'000

At 1st January, 2014	59,002	--	59,002
Additions	4,969	--	4,969
Exploration cost write-off	(14,929)	--	(14,929)
Impairment (note 29)	(23,484)	--	(23,484)
Translation difference	118	--	118
At 31st December, 2014	25,676	--	25,676

At 1st January, 2013	--	7,856	7,856
Acquisition (note 27)	23,606	--	23,606
Additions	35,396	--	35,396
Impairment (note 29)	--	(7,786)	(7,786)
Translation difference	--	(70)	(70)
At 31st December, 2013	59,002	--	59,002

The carrying amount of Goodwill arose on the business combination with Oilbelt Holdings Limited. The entire goodwill balance has been allocated to the WD 5/6 block which is considered to be one CGU, cash generating unit. Management re-evaluated the reserve estimate for all CGU's at the end of 2013 the results of this report indicated a downward revision in the reserves estimate of the WD 5/6 onshore block which triggered an impairment assessment realising an impairment loss of $10.4 million. The impairment loss was taken against the full amount of goodwill with the remaining $2.6 million charge attributable to Oil & Gas assets within the overall property, plant & equipment impairment (note 5).

The exploration cost write-off relates to the El Dorado-1 exploration well which was deemed unsuccessful as the reserves encountered were not commercial and the well permanently plugged and abandoned at a cost of $14.9 million.

An impairment loss of $23.5 million was recognised in 2014 following an impairment review on the carrying value of exploration and evaluation assets which included:

EG-8: the EG-8 exploration well was drilled in 2012 on north-east Galeota and suspended as an oil and gas discovery. A technical study performed in 2014 indicated that the reserves encountered were not commercial and cannot justify the cost of developing either the gas or the oil resources encountered. This led to the impairment of the costs $22.6 million to exceptional items on the Statement of Comprehensive Income.

South Africa: costs of $0.9 million have been written off on the basis that TEP Plc has no further exploration or evaluation activities planned or budgeted for this licence and are in process of relinquishing the licence for strategic reasons.

7 Trade and Other Receivables

	Group		Company
	2014 $'000	2013 $'000	2014 $'000	2013 $'000
Due after more than one year
Amounts due from Group companies	--	--	10,106	160,760

Due within one year
Trade receivables	3,882	12,637	--	--
Less: provision for impairment of trade receivables	--	--	--	--
Trade receivables - net	3,882	12,637
Prepayments	3,986	1,906	79	134
VAT recoverable	12,144	20,653	1,027	873
Other receivables	1,978	1,529	--	--
Short term loan receivable	--	--	--	--
Receivables from related parties (note 23 (d))	--	78	--	--
	21,990	36,803	1,106	1,007

The Company provides funding to other Group companies.

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

At 31st December, 2014, trade receivables of $3.9 million (2013: $12.6 million) were fully performing. Trade receivables that are less than three months past due are not considered impaired. At 31st December, 2014, no trade receivables (2013: nil) were impaired and provided for.

Ageing analysis of these trade receivables is as follows:

	2014 $'000	2013 $'000

Up to 3 months	3,882	12,637
	3,882	12,637

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

	2014 $'000	2013 $'000

US Dollar	3,606	6,548
British £	1,562	873
Trinidad & Tobago Dollar	16,822	29,382
	21,990	36,803

The maximum exposure to credit risk at the reporting date is the value of each class of receivable as shown above. The Group does not hold any collateral as security.

The credit quality of the financial assets that are neither past due nor impaired can be assessed by reference to historical information about the counterparty default rates:

	Group		Company
	2014	2013	2014	2013
	$'000	$'000	$'000	$'000
Trade receivables

Counterparties without external credit rating:

Existing customers (more than 6 months) with no defaults in the past	3,882	12,637	--	--

All trade receivables are with the Group's only customer, Petrotrin.

8 Inventories

	2014	2013
	$'000	$'000
Crude oil	346	435
Materials and supplies	11,563	11,594
	11,909	12,029

The cost of inventories recognised as an expense and included in operating expenses amounted to $0.3 million (2013: $1.2 million).

9 Taxation Recoverable/(Payable)

	Group		Company
	2014	2013	2014	2013
	$'000	$'000	$'000	$'000
Taxation recoverable
Production Petroleum Tax (PPT)/Unemployment Levy (UL)	548	528	--	--

Taxation payable
Production Petroleum Tax (PPT)/Unemployment Levy (UL)	(1,596)	(313)	--	--
Corporation Tax	(1,883)	--	(1,160)	--
Supplemental Petroleum Tax (SPT)	(15,002)	(3,778)	--	--
	(18,481)	(4,091)	(1,160)	--

10 Cash and Cash Equivalents

	Group		Company
	2014	2013	2014	2013
	$'000	$'000	$'000	$'000

Cash and cash equivalents	33,084	25,145	10	4,189
	33,084	25,145	10	4,189

Included within cash and cash equivalents are $2.8 million restricted cash which have been put aside in escrow for abandonment and environmental liabilities in accordance with contractual obligations to be used any time during the existence of the contract.

11 Share Capital and Share Premium

	Number of shares No.	Ordinary shares $'000	Share premium $'000	Total $'000
As at 1st January, 2014	94,799,986	94,800	116,395	211,195
Movement	--	--	--	--
As at 31st December, 2014	94,799,986	94,800	116,395	211,195


As at 1st January, 2013	34,182	34	17,550	17,584
Shares issued to previous equity holders of TEPL	25,617,859	25,618	(17,550)	8,068
Legacy Bayfield share capital	21,647,945	21,648	80,817	102,465
Share placing	47,500,000	47,500	41,523	89,023
Cost of equity	--	--	(5,945)	(5,945)
As at 31st December, 2013	94,799,986	94,800	116,395	211,195

On 14th February, 2013 TEPL acquired Bayfield through a reverse acquisition. Bayfield issued 25,652,041 ordinary shares to the shareholders of TEPL which gave a 55 per cent controlling interest in the combined entity. Bayfield changed its name to TEP Plc. On the same date a total of 47,500,000 shares were issued at £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.

	2014	2013
	$'000	$'000
Issued
Oriel Securities Limited	71	71
	71	71

Oriel Securities Limited warrants

Oriel Securities Limited ('Oriel') was appointed to assist TEPL in introducing potential subscribers for private placing of new ordinary shares in 2011 (the 'Placing'). In consideration for the services under the engagement, and subject to receipt of the gross proceeds as a result of the Placing, TEP Plc and Oriel agreed a fee in cash to the value of $150,000.

In addition to the fees above, Oriel was granted an option by TEPL over shares equivalent in value to 0.25 per cent (one quarter of one per cent) of the value of TEPL following the Placing, such option to be exercisable at the share price at which the new funds were raised in the Placing. The option can be exercised between the 1^st and 5^th anniversary of the option being granted or if later on the 1^st anniversary of any flotation.

The Group recognised the warrants in the financial year by estimating the services received at fair value at the date of the transaction. In arriving at the fair value of the services received an estimate was received from Oriel indicating that the cost of the service had no warrant been included would have been 1.5 per cent of the Placing. As the cost is associated with the raising of capital, this expense has been recognised as a deduction from share premium.

Following the acquisition on 14th February, 2013 Oriel has confirmed that it does not intend to exercise its 83 TEP Plc Warrants; Oriel shall hold warrants over 62,027 shares with an exercise price of $5.60 per share (based on the same conversion ratio of 747.8 new shares).

13 Merger and Reverse Acquisition Reserves

	Reverse Acquisition Reserve	Merger Reserve	Total
	$'000	$'000	$'000

At 1st January, 2014	(89,268)	74,808	(14,460)
Translation differences	--	659	659
At 31st December, 2014	(89,268)	75,467	(13,801)

At 1st January, 2013	--	52,853	52,853
Acquisition (note 27)	--	22,353	22,353
Movement	(89,221)	--	(89,221)
Translation differences	(47)	(398)	(445)
At 31st December, 2013	(89,268)	74,808	(14,460)

The issue of shares by the Company as part of the reverse acquisition met the criteria for merger relief such that no share premium was recorded. As allowed under the UK Companies Act 2006 and required by IAS 27 ('Consolidated and separate financial statements'), a merger reserve equal to the difference between the fair value of the shares acquired by the Company and the aggregation of the nominal value of the shares issued by the Company has been recorded.

The insertion of the Company as the new parent to the Group has been accounted for using business combination accounting as described in note 1. The reverse acquisition difference recorded in the consolidated financial statements represents the difference in accounting for reverse acquisition transactions. A detailed summary of the business combination and financial implication of this is provided within note 27.

14 Non-current assets held for sale

The assets relating to TEP Plc's lease operatorship block WD 16 and farmout block Tabaquite owned and operated by its indirect subsidiaries Oilbelt Services Limited and Trinity Exploration and Production (Trinidad and Tobago) Limited have been presented as held for sale following approval of management and Board of Directors in 2014 to sell. The completion date for the transaction is expected in 2015.

(a) Net Book Value of assets of the disposal Group classified as held for sale

	2014	2013
Property, plant and equipment:	$'000	$'000
WD 16 block	104	--
Tabaquite block	568	--
	672	--

15 Borrowings

	2014	2013
	$'000	$'000
Non-current portion:
Citibank (Trinidad & Tobago) Limited	--	11,910
Total	--	11,910
Current portion:
Citibank (Trinidad & Tobago) Limited	33,000	3,989
Total	33,000	3,989

Drawn Loan Facilities

Citibank (Trinidad & Tobago) Limited Loan 1

The key terms of the loan are as follows:

· Principal amount $20.0 million

· Interest rate is set at three month US LIBOR plus 600 basis points per annum

· Debenture over the fixed and floating assets of Trinity Exploration and Production (Trinidad and Tobago) Limited and its subsidiaries.

· Principal repayment in equal quarterly instalments commencing on 20th March, 2013 and ending on 20th December, 2017

· Interest payable monthly in arrears commencing on 20th March, 2013

Citibank (Trinidad & Tobago) Limited Loan 2

The Group negotiated a floating rate medium term facility on 17th August, 2013 of $25.0 million with Citibank (Trinidad & Tobago) Limited 'Citibank' which at 31st December, 2014 was fully drawdown.

The key terms of the loan are as follows:

· Principal amount $25.0 million. Initial drawdown on 22nd January, 2014 of $5.0 million and a second drawdown of $20.0 million on 4th August, 2014

· Interest rate is set at three month US LIBOR plus 575 basis points per annum. The negotiated principal repayments in two initial quarterly instalments of 16.0 per cent following 6.5 per cent to 7.0 per cent quarterly instalments commencing on 21st November, 2014 and ending on 21st August, 2017

· A $20.0 million repayment of the loan was made in first quarter 2015

Financial covenants applicable to each of the above facilities are:

· Minimum debt service coverage 1.4:1

· Maximum total debt to EBITDA-Operating taxes 2.75:1

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

The carrying value of borrowings is not materially different from their fair value. At the end of 2014, TEP Plc was not in compliance with the debt service coverage ratio (the minimum requirement being 1.4:1, however the actual ratio was c. 1.0:1). The entire borrowings in 2014 have been classified as current due to the breach of the debt service coverage ratio. This breach was disclosed to Citibank, and TEP Plc was required to repay $20.0 million on the 6th February, 2015. Subsequently, a six month moratorium on repayment of the remaining principal has been agreed until 15th June, 2015.

Analysis of net debt

	At 1st January, 2014 $'000	Cash flow $'000	At 31st December, 2014 $'000
Cash and cash equivalents	25,145	7,939	33,084
Financial liabilities - borrowings current	(3,989)	(18,611)	(22,600)
Financial liabilities - borrowings non-current	(11,910)	1,510	(10,400)
	9,246	(9,162)	84

16 Provisions and Other Liabilities

	Potential Claim	Decommissioning cost	Total
	$'000	$'000	$'000
Year ended 31st December, 2014
Opening amount as at 1st January, 2014	--	29,027	29,027
Adjustment to estimates (note 5)	--	8,156	8,156
Record potential claim	1,270	--	1,270
Unwinding of discount (note 20)	--	1,167	1,167
Translation differences	--	155	155
Closing balance at 31st December, 2014	1,270	38,505	39,775


Year ended 31st December, 2013
Opening amount as at 1st January, 2013	--	9,891	9,891
Acquisition (note 27)	--	14,869	14,869
Adjustment to estimates (note 5)	--	3,179	3,179
Unwinding of discount (note 20)	--	1,178	1,178
Translation differences	--	(90)	(90)
Closing balance at 31st December, 2013	--	29,027	29,027

Potential claim

The amounts represent a provision for a potential claim against a subsidiary of the Group by a supplier of services in the oil and gas industry. The charge is recognised in the statement of comprehensive income within 'exceptional items'. In management's opinion these claims will not give rise to any significant losses beyond the amounts provided at 31st December, 2014. The potential claim is anticipated to be settled no later than September 2016.

Decommissioning cost

The Group operates Oil and Gas fields and this cost represents an estimate of the amounts required for abandonment of the Group's wells, platforms and pipeline infrastructures. The amounts are calculated based on the provisions of existing contractual agreements with Petrotrin. Furthermore, liabilities for decommissioning costs are recognised when the Group has an obligation to dismantle and remove a facility or an item of plant and to restore the site on which it is located, and when a reasonable estimate of that liability can be made. An obligation for decommissioning may also crystallise during the period of operation of a facility through a change in legislation or through a decision to terminate operations.

The amount recognised is the present value of the estimated future expenditure determined in accordance with local conditions and requirements. A corresponding item of property, plant and equipment of an amount equivalent to the provision is also created. This is subsequently depreciated as part of the capital costs of the facility or item of plant. Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding property, plant and equipment. Some of the key assumptions made in the present value decommissioning calculation include the following:

a. Core inflation rate - 3 per cent (2013: 3 per cent)

b. Risk free rate - 3.9 per cent (2013: 3.9 per cent)

c. Estimated market value/decommissioning cost

d. Estimated life of each asset

See note 3(b) for the rates used and sensitivity analysis.

Adjustment to estimates

The Group makes provision for the cost of decommissioning its oil and gas infrastructure at the completion of their useful lives. Decommissioning is estimated to be required in various fields during 2024-2036. In the current year there was an increase in the provision mainly due to a revision of assumptions used in determining the estimated cost to decommission the Group's oil and gas platform facilities of $1.5 million and finalisation of the decommissioning terms in the PGB block of $6.9 million. There has been a corresponding increase in the carrying amount of property plant and equipment (note 5). A study is being done on the estimated cost to decommission the Group's tank farm facilities which are not included in the current provision.

17 Deferred Income Taxation

Group

The analysis of deferred tax assets is as follows:

	2014	2013
	$'000	$'000
Deferred tax assets:
-Deferred tax assets to be recovered in more than 12 months	(27,630)	(51,988)
-Deferred tax assets to be recovered in less than 12 months	--	(12,705)
Deferred tax liabilities:
-Deferred tax liabilities to be settled in more than 12 months	--	37,403
-Deferred tax liabilities to be settled in less than 12 months	3,778	8,984
Net deferred tax asset	(23,852)	(18,306)

The movement on the deferred income tax is as follows:

	2014	2013
	$'000	$'000
At beginning of year	(18,306)	5,267
Deferred tax assumed on acquisition	--	(18,606)
Deferred tax on fair value uplift arising from acquisition	--	2,746
Movement for the year	3,849	(5,412)
Unwinding of deferred tax on fair value uplift	(9,395)	(2,247)
Translation differences	--	(54)
Net deferred tax asset	(23,852)	(18,306)

Deferred tax assets and liabilities are only offset where there is a legally enforceable right of offset and there is an intention to settle the balances net. The deferred tax balances are analysed below:

	2012	Movement	2013	Movement	2014
	$'000	$'000	$'000	$'000	$'000
Deferred tax assets
Acquisition	(410)	(33,026)	(33,436)	--	(33,436)
Tax losses recognised	(13,377)	(17,880)	(31,257)	--	(31,257)
Tax losses derecognised	--	--	--	37,063	37,063
	(13,787)	(50,906)	(64,693)	37,063	(27,630)

Deferred tax liabilities
Accelerated tax depreciation	2,364	12,414	14,778	--	14,778
Non-current asset impairment	--	--	--	(33,214)	(33,214)
Acquisitions	5,160	14,420	19,580	--	19,580
Fair value uplift	11,530	499	12,029	(9,395)	2,634
	19,054	27,333	46,387	(42,609)	3,778

Deferred income tax assets are recognised for tax loss carry-forwards to the extent that the realisation of the related tax benefit through future taxable profits is probable. Deferred tax assets of $37.1 million have been derecognised as recoverability is now considered, these continue to be available for realisation whenever future taxable profits are probable. The Group has unrecognised tax losses amounting to $118.3 million which have no expiry date. Deferred tax liabilities have reduced by $42.6 million as the carrying values of property, plant and equipment and intangible assets which gave rise to the temporary differences have been written down to their recoverable amount.

18 Trade and Other Payables

	Group		Company
	2014 $'000	2013 $'000	2014 $'000	2013 $'000

Trade payables	16,712	19,224	26	36
Accruals	8,888	37,170	142	92
VAT payable	433	2,289	--	--
Other payables	1,778	1,393	--	--
Amounts due to related parties (note 23 (d))	5,563	1,041	979	1,246
	33,374	61,117	1,147	1,374

19 Operating Profit Before Exceptional Items

	2014 $'000	2013 $'000
Operating profit before exceptional items is stated after taking the following items into account:
Depreciation, depletion and amortisation (note 5)	16,335	13,211
Employee costs (note 26)	12,781	21,598
Abandonment (note 5)	--	1,624
Operating lease rentals	3,122	1,374
Inventory recognised as expense, charged to operating expenses	262	1,235

Auditors' remuneration

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

	2014 $'000	2013 $'000
- Fees payable to the Company's auditors' and its associates for the audit of the parent Company and consolidated financial statements	73	73
- Fees payable to the Company's auditors' and its associates for other services: - The audit of Company's subsidiaries	173	167
- Audit related assurance services - interim review	52	50
- Reporting accountant work in respect of the merger and admission to trading on AIM	--	318
Total assurance	298	608
- Tax advisory	--	26
- Other advisory	48	216
Total auditors' remuneration	346	850

All fees are in respect of services provided by PricewaterhouseCoopers LLP 'PwC' with the majority in prior year relating to reporting accountants work during the merger of TEP Plc and Bayfield. The independence and objectivity of the external auditors is considered on a regular basis by the Audit Committee, with particular regard to the level of non-audit fees incurred.

20 Finance Costs

	2014	2013
	$'000	$'000
Decommissioning (note 16)	1,167	1,178
Interest on taxes	2,134	--
Interest on loans	1,850	1,179
	5,151	2,357

Interest on taxes $2.1 million (2013; nil) relate to interest accrued on late payment of corporation tax, supplemental petroleum taxes and petroleum profits taxes for 2014.

21 Income Tax Expense

	2014	2013
	$'000	$'000
Current tax
- Current year
Petroleum profits tax	1,075	5,821
Corporation tax	2,182	926
Supplemental petroleum tax	14,931	10,393

Deferred tax
- Current year
Movement in asset due to tax losses (note 17)	37,063	(17,880)
Movement in liability due to accelerated tax depreciation (note 17)	(33,214)	12,414
Unwinding of deferred tax on fair value uplift	(9,396)	(2,247)
Translation difference	16	54
Income tax expense	12,657	9,481

The Group's effective tax rate varies from the statutory rate for UK companies of 21.50 per cent as a result of the differences shown below:

	2014	2013
	$'000	$'000

(Loss) /Profit before taxation	(128,788)	48,036

Tax charge at expected rate of 21.50 per cent (2013: 23.25 per cent)	(27,677)	11,168
Effects of:
Higher overseas tax rate	(43,157)	15,372
Profits not subject to tax	--	(32,276)
Disallowable expenses	123,498	11,772
Deferred tax asset not recognised	5,517	20
Tax loss generated not recognised	3,562	915
Tax losses utilised	8,111	--
Tax losses previously recognised	(64,693)	(626)
Supplemental petroleum tax	7,508	3,110
Green fund levy	83	178
Other differences	(95)	(152)
Tax charge	12,657	9,481

Taxation losses as at 31st December, 2014 available for set off against future taxable profits amount to approximately $171.3 million (2013: $127.0 million), with tax losses recognised of $52.9 million. The Finance Act 2013 reduced the UK Corporation tax rate from 23 per cent to 21 per cent with effect from 1st April 2014. A further reduction to the UK tax rate was announced to reduce the rate from 21 per cent to 20 per cent with effect from 1st April 2015. This reduction had not been substantively enacted at the balance sheet date and, therefore, is not recognised in these financial statements.

22 Investment In Subsidiaries

	Company
	2014	2013
	$'000	$'000

Opening balance	94,401	46,085
Additions	--	48,076
Capital contribution relating to share based payment	212	240
Impairment	(50,100)	--
Closing balance	44,513	94,401

The investment in Group undertakings is recorded at cost which is the fair value of the consideration paid. An impairment loss of $50.1 million was recognised on the investment in subsidiary as a result of property plant and equipment impairments recognised in the operating subsidiaries of the Group due to a sharp fall in oil prices and a downgrade in reserve estimates of certain fields (see note 5).

During 2014 Bayfield Energy New Ventures Limited a subsidiary of Bayfield Energy Limited was wound up.

In December 2014 the Group restructured its Trinidadian subsidiaries with the aim of reducing the administrative costs associated with the operations of several individual subsidiaries. On 15th December 2014 a vertical amalgamation was done with Antilles Resources Limited, NAKT Company Limited, Pioneer Petroleum Company Limited, Lennox Production Services Limited and Ten Degrees North Operating Company Limited 'TDNOCL'. The surviving entity following the vertical amalgamation was TDNOCL.

On 31st December, 2014 a horizontal amalgamation was done between TDNOCL and Oilbelt Service Limited 'OSL' and the surviving entity following the restructuring was OSL, which holds the Group's onshore and west coast fields.

On 20th November, 2014 Bayfield Energy (St Lucia) Limited was dissolved.

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

Listing of Subsidiaries

The Group's principal subsidiaries at 31st December, 2014 are listed below:

Name	Country of Incorporation	Nature of Business	Proportion of ordinary shares held by the Group (per cent)
Bayfield Energy Limited	UK	Holding Company	100 per cent
Trinity Exploration and Production Services (UK) Limited	UK	Service Company	100 per cent
Bayfield Energy (Alpha) Limited	UK	Holding Company	100 per cent
Trinity Exploration and Production (Pletmos) Limited	UK	Oil and Gas	100 per cent
Bayfield Energy do Brasil Ltda	Brazil	Dormant	100 per cent
Trinity Exploration & Production (Barbados) Limited	Barbados	Holding Company	100 per cent
Trinity Exploration and Production (Trinidad and Tobago) Limited	Trinidad & Tobago	Holding Company	100 per cent
Galeota Oilfield Services Limited	Trinidad & Tobago	Oil and Gas	100 per cent
Trinity Exploration and Production (Galeota) Limited	Trinidad & Tobago	Oil and Gas	100 per cent
Oilbelt Services Limited	Trinidad & Tobago	Oil and Gas	100 per cent
Coastline International Inc.	Trinidad & Tobago	Oil and Gas	100 per cent
Ligo Ven Resources Limited	Trinidad & Tobago	Oil and Gas	100 per cent
Trinity Exploration and Production Services Limited	Trinidad & Tobago	Service Company	100 per cent
Tabaquite Exploration & Production Company Limited	Trinidad & Tobago	Oil and Gas	100 per cent
Trinity Exploration and Production (GOP) Limited	Trinidad & Tobago	Oil and Gas	100 per cent
Trinity Exploration and Production (GOP-1B) Limited	Trinidad & Tobago	Oil and Gas	100 per cent

23 Related Party Transactions

Group

The following transactions were carried out with the Group's subsidiaries and related parties. These transactions comprise sales and purchases of goods and services and funding provided in the ordinary course of business. The following are the major transactions and balances with related parties:

(a) Sales of services and loans issued to subsidiaries

	Group		Company
	2014 $'000	2013 $'000	2014 $'000	2013 $'000

Related party:
Well Services Petroleum Company Limited	142	--	--	--
Group subsidiaries:
Bayfield Energy Limited - loan	--	--	(89,840)	--
Bayfield Energy Alpha - loan	--	--	(535)	--
Trinity Exploration and Production Services (UK) Limited - loan	--	--	(62)	9,513
Trinity Exploration and Production (Galeota) Limited - loan	--	--	(71,194)	65,400
	142	--	(161,631)	74,913

Related party sales transactions and loans issued to subsidiaries are exchanged at arm's length and are comparable to terms that would be available to third parties.

(b) Purchases of services

	Group		Company
	2014 $'000	2013 $'000	2014 $'000	2013 $'000
Purchases of services:
Related party:
Bayfield Energy Limited	--	--	--	5
Blanket Security Limited	794	866	--	--
Rigtech Services Limited	589	996	--	--
Well Services Petroleum Company Limited	9,265	9,875	--	--
Trinity Lift Boat Services Limited	52	--	--	--
Group subsidiaries:
Trinity Exploration and Production Services (UK) Limited	--	--	(267)	--
	10,700	11,737	(267)	5

Goods and services are bought from entities controlled by certain Non-Executive Director Charles Anthony Brash Junior on normal commercial terms and conditions, with the majority coming from the Well Services Group, which includes; Blanket Securities Limited, Rigtech Services Limited, Well Services Petroleum Company Limited, Trinity Lift Boat Services Limited and Trinity Infrastructure Construction Limited.

Key management includes Directors' (executive and non-executive), the Chief Operating Officer and Chief Financial Officer. The compensation paid or payable to key management for employee services is shown below:

	Group
	2014 $'000	2013 $'000

Salaries and short-term employee benefits	1,958	2,469
Post-employment benefits	137	53
Share-based payment (note 28)	217	2,590
	2,312	5,112

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

	Group		Company
	2014 $'000	2013 $'000	2014 $'000	2013 $'000

Receivables from related parties:

Well Services Petroleum Company Limited	--	78	--	--
Bayfield Energy Limited - loan	--	--	--	84,659
Trinity Exploration and Production (Galeota) Limited	--	--	655	66,057
Trinity Exploration and Production Services (UK) Limited	--	--	9,451	9,513
Bayfield Energy Alpha	--	--	--	531

	--	78	10,106	160,760

Payables to related parties:

Blanket Securities Limited	431	164	--	--
Rigtech Services Limited	328	238	--	--
Well Services Petroleum Company Limited	4,804	639	--	--
Trinity Exploration and Production Services (UK) Limited	--	--	4	4
Trinity Exploration & Production (UK) Limited	--	--	975	1,242

	5,563	1,041	979	1,246

Post the year end the Group has endeavoured to reduce the payables due to related parties through an exchange of casing and tubing see note 31. Subsequent to this the related party Well Services Petroleum Company Limited has brought a legal claim against a subsidiary of the Group to recover the balance owed of $2.5 million.

Company

Loans to subsidiaries

At the end of 2014 an impairment review on the Company's loan receivables was carried out by comparing the carrying value of the loans to subsidiaries against their recoverable amount. From the borrowers perspective the subsidiaries have been forgiven by TEP plc and the obligation extinguished. The following are the loan receivable debt forgiven by TEP plc:

	Company
	2014 $'000	2013 $'000

Trinity Exploration and Production (Galeota) Limited	71,194	--
Bayfield Energy Limited	89,840	--
Bayfield Energy Alpha Limited	535	--
	161,569	--

Group and Company

The receivables from related parties arise mainly from sale transactions and are due two months after the date of sales. The receivables are unsecured and bear no interest. No provisions are held against receivables from related parties (2013: nil).

The payables to related parties arise mainly from purchase transactions and are due two months after the date of purchase. The payables bear no interest.

(e) Loans from related parties

There are no loans from related parties

24 Financial Instruments by Category

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

	Group		Company
	2014	2013	2014	2013
	$'000	$'000	$'000	$'000
Trade and other receivables - non current	--	--	10,106	160,760
Trade and other receivables - current	21,990	36,803	1,106	1,007
Cash and cash equivalents	33,084	25,145	10	4,189
	55,074	61,948	11,222	165,956

The only category of financial assets held by the Group is loans and receivables. There are no assets held at fair value through profit or loss, derivatives used for hedging and available-for-sale financial instruments.

	Group		Company
	2014	2013	2014	2013
	$'000	$'000	$'000	$'000
Borrowings	33,000	15,899	--	--
Amounts due to related party	--	--	979	1,246
Accounts payable and accruals	33,374	61,117	168	128
	66,374	77,016	1,147	1,374

The only category of financial liabilities held by the Group is liabilities at amortised cost. There are no liabilities held at fair value through profit or loss and derivatives used for hedging.

25 Commitments and Contingencies

Commitments

There are commitments for decommissioning costs of the wells and facilities under the Group's agreements with Petrotrin, which have been provided for as described in note 16.

The Group leases vehicles, offices and copiers under cancellable operating lease agreements. The lease terms are between 1 and 5 years, and the majority of lease agreements are renewable at the end of the lease period. The lease expenditure charged to the income statement during the year is as follows:

	Group
	2014	2013
	$'000	$'000
Not later than 1 year	529	442
Later than 1 year and no later than 5 years	2,593	932
	3,122	1,374

Contingent Liabilities

i) One of the subsidiaries has received an assessment from the tax authority of Trinidad and Tobago namely, the Board of Inland Revenue (BIR), in respect of Petroleum Profits Tax. The subsidiary has filed a notice of objection with the BIR and until the matters are determined, the assessments raised are not considered final. No material unrecorded liabilities are expected to crystallise and accordingly no provision has been made in these financial statements.

ii) A subsidiary Company is a defendant in certain legal proceedings. A claim was made against the subsidiary by Mora Ven Holdings limited. The claim being made was that the subsidiary bought the shares of Ligo Ven Resources Limited, a fellow subsidiary, at gross under-value. Management, after taking appropriate professional advice, is of the view that no material liabilities will crystallise and accordingly no provision has been made in the financial statements for any potential liabilities.

iii) Parent Company guarantees:

a) A Letter of Guarantee has been established over the Point Ligoure-Guapo Bay-Brighton Block where a subsidiary of TEP Plc is obliged to carry out a Minimum Work Programme to the value of $8.4 million.

b) A letter of Guarantee is in place with Citibank (Trinidad & Tobago) Limited for the full $25.0 million loan facility should there be a default. There was a default at the end of 2014 and a repayment of $20.0 million was made in February 2015. Further disclosure is made in note 15.

iv) The Group has certain liabilities in respect of entering a rig share agreement for the Rowan Gorilla III which it used to drill the TGAL-1 well. The agreement was made amongst four parties and the liabilities are joint and several. The liabilities cannot be presently quantified and no estimates have been included in the financial statements. The Group has incurred in 2014 $0.1 million of this liability and does not expect that these liabilities will be material.

v) The Group has certain decommissioning provisions in respect of the tank farm infrastructure in its Brighton Marine and Trintes fields, these have not been provided for, as an estimate of the provision cannot presently be quantified. A study is being undertaken to determine an appropriate cost.

vi) The group is party to various claims and actions. Management have considered the matters and where appropriate has obtained external legal advice. No material additional liabilities are expected to arise in connection with these matters, other than those already provided for.

26 Employee Costs


Employee costs for the Group during the year	2014 $'000	2013 $'000

Wages and salaries	11,982	16,484
Other pension costs	636	393
Share based payment expense (note 28)	163	4,721
	12,781	21,598


Average monthly number of people (including executive and non-executive Directors') employed by the Group	2014 number	2013 Number

Executive and non-executive Directors	7	7
Administrative staff	179	138
Operational staff	120	140
	306	285

27 Business Combination

There were no business combination transactions during 2014. The summary below relates to the 2013 financial year end.

a) Summary of acquisition

On 14th February, 2013, Trinity Exploration & Production (UK) Limited (formerly Trinity Exploration & Production Limited) ("TEPL") acquired Bayfield Energy Holdings plc ("Bayfield") by way of a reverse acquisition.

Whilst Bayfield became the legal parent of the Group on that date, the shareholders of TEPL obtained control of Bayfield and the transaction was deemed a reverse acquisition. In order to execute the transaction Bayfield issued 25,652,041 ordinary shares, representing 55 per cent of its share capital, to the shareholders of TEPL in exchange for 100 per cent (34,182 shares) of the share capital of TEPL. Bayfield changed its name to Trinity Exploration & Production Plc and was readmitted to trading on AIM on 14th February, 2013.

The acquisition represented a strategic fit for TEPL as it has allowed TEPL to acquire production and reserves in a hydrocarbon basin which it previously had no exposure to whilst simultaneously providing an opportunity to recapitalize the Company through the issue of new shares.

Details of the fair value of the assets and liabilities acquired are as follows:

	$'000
Purchase consideration (refer to b)	40,525
Fair value of net identifiable assets acquired (refer to c)	92,595
Negative goodwill (refer to c)	(52,070)

b) Purchase consideration

The purchase consideration is calculated as the fair value of all equity instruments of Bayfield (21,647,945 ordinary shares) prior to the acquisition, based on a share price of £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: £ is used, being $1.56 on the date of the acquisition.

c) Assets and liabilities acquired

Recognised amounts of identified assets acquired and liabilities assumed:

	$'000
Cash and cash equivalents	6,529
Trade and other receivables (note 7)	10,735
Inventories (note 8)	8,224
Deferred tax asset (note 17)	18,606
Exploration and evaluation assets (note 6)	23,606
Property, plant and equipment (note 5)	71,633
Trade and other payables (note 18)	(31,869)
Decommissioning liability (note 16)	(14,869)
Fair Value of Net assets	92,595

At the acquisition date, all contractual cash flows are expected to be collected. The decommissioning liability was increased by $8.9 million and is in respect of decommissioning of wells and platform which is expected at the end of the field life when production ceases. An impairment loss of $11.1 million was recognised on exploration and evaluation assets in respect of costs which did not relate to exploration and evaluation activity with a further reallocation of $1.9 million to property, plant and equipment. There was an impairment of $1.0 million within property, plant and equipment for a rig which was in a state of disrepair and unusable at the acquisition date.

In undertaking the acquisition, costs of $2.3 million were incurred and have been expensed to the consolidated statement of comprehensive income as an exceptional item (note 29).

The acquisition of Bayfield by TEPL resulted in a gain or bargain purchase as defined within IFRS 3, specifically paragraphs 32 and 34. The reason that the net assets acquired was greater than the consideration transferred was due to the Bayfield Group experiencing liquidity issues and from a going concern perspective the Group was distressed. This was the result of lower than expected cash flows as the underlying production growth was slower than expected and an inability to secure any additional funding. This eventually led to the Bayfield Group agreeing to be acquired by TEPL. The negative goodwill recognised represents that gain where the aggregate fair value of the identifiable assets and liabilities at the acquisition date exceeded the fair value of the consideration transferred. In accordance with IFRS, the gain has been recognised immediately within the consolidated statement of comprehensive income as an exceptional item (note 29).

Since the acquisition date, revenue of $34.9 million and loss of $1.2 million have been included in the consolidated statement of comprehensive income in respect of Bayfield Energy Holdings plc. If the acquisition had occurred on 1st January, 2013, the combined Group would report additional revenue of $4.5 million and loss of $15.8 million for the period.

28 Share Based Payments

During 2014 the Group had in place two share-based payment arrangements for its employees and Directors, the Share Option Plan and the Long Term Incentive Plan ('LTIP'). The charge in relation to these arrangements is shown below, with further details of each scheme following:

	2014	2013
	$'000	$'000
Share based payment expense:
Accelerated share option charge	--	4,708
Share option expense	21	187
Legacy share options adjustment	--	(262)
Long term incentive plan	142	88
	163	4,721

Share Option Plan

Share options are granted to Directors and to selected employees. The exercise price of the granted option is equal to management's best estimate of the market price of the shares at the time of the award of the options. The Group has no legal or constructive obligation to repurchase or settle the options in cash.

At 31st December, 2012 TEPL had 3,638 share options outstanding. On 14th February, 2013 following the completion of the acquisition, 120 of the 3,638 share options were exercised. The remaining 3,518 share options were surrendered in return for the grant by TEP Plc of new options. 747.8 new ordinary shares were issued for each TEPL share over which TEPL options were held. These options were treated as a modification to the original share option scheme. The modification did not increase the fair value of the equity instruments granted, measured immediately before and after the modification, as a result there was no incremental fair value. At the point of acquisition Bayfield had 4,447,546 share options, following completion of the acquisition and share consolidation, the newly combined Group share options outstanding of:

(a) Legacy Bayfield - 444,754 share options

(b) Legacy TEPL - 2,630,759 share options

On 29th May, 2013 the Group issued 1,275,660 options at an exercise price of £1.20 per option to certain employees. These options were valued at grant date using a Black-Scholes option pricing model. During 2014 certain employees who had share options departed forfeiting their options.

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

	2014		2013
	Average exercise price per share	Number of Options	Average exercise price per share	Number of Options
At 1st January	£1.14	4,256,419	USD1,394	3,638
Acquired 14th February	--	--	£2.25	444,754
Granted 14th February	--	--	£0.99	2,630,759
Granted 29th May	--	--	£ 1.20	1,275,660
Exercised 14th February	--	--	USD(1,000)	(120)
Surrendered	--	--	USD(1,407)	(3,518)
Lapsed	--	--	£(2.57)	(94,754)
Forfeited	£(1.15)	(385,000)	--	--
At 31st December	£1.01	3,871,419	£1.14	4,256,419

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

		2014		2013
Grant-Vest	Expiry Date	Exercise price per share options	Number of Options	Exercise price per share options	Number of Options

2011-15	2015	£1.61	350,000	£1.61	350,000
2012-15	2022	£0.86	2,238,164	£0.86	2,294,249
2012-15	2022	£0.86	336,510	£0.86	336,510
2013-16	2023	£1.20	946,745	£1.20	1,275,660

			3,871,419		4,256,419

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

	29 May 2013	14 February 2013
Share price	£1.19	£1.20
Average Exercise price	£1.20	£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 14th February, 2013 following the completion of the acquisition 108,712 Bayfield LTIP's were outstanding. These LTIP Awards are conditional awards of Existing Unconsolidated Ordinary Shares and vest three years from the date of grant, subject to the satisfaction of certain performance conditions (based on the growth in the Company's total shareholder return). No payment is required on vesting and there is no accelerated vesting arising as a result of the Merger.

On 1st July, 2013 739,440 LTIP Awards were granted by the Company to Senior Management Group (including the Executive Directors). The LTIP awards will be tested against two performance targets: stretching reserves growth and absolute returns targets (share price). Performance against these measures will be assessed based on performance to the end of the 2015 financial year and following announcement of the Company's audited financial results. Subject to the achievement of the performance targets all Options will be subject to a further holding period whereby Options will not vest until 1st January, 2017.

The measurement of growth in 2P Reserves is the aggregated total of all fields included in the Trinity Exploration & Production plc (formerly Bayfield Energy Holdings plc) and Trinity Exploration & Production (UK) Limited Group as recorded at financial year end 2012 which is 35.6 mmboe. Share price growth will be calculated from the price at which equity was raised at the point of the merger which was £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:

	2014			2013
		Average exercise price per share	Number of Options	Average exercise price per share	Number of Options
At 1st January		£0.00	848,152	--	--
Acquired		--	--	£0.00	108,712
Granted		--	--	£0.00	739,440
Forfeited		£0.00	(75,840)	--	--
At 31st December		£0.00	772,312	£0.00	848,152

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

	1st July, 2013
Share price	£1.06
Exercise price	£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.

		31st December, 2014	31st December, 2013
		$'000	$'000
Negative goodwill (note 27)	--		(52,070)
Goodwill	--		2,746
Business combination cost	--		2,254
Unrealised forex loss	--		2,342
Potential claim (note 16)	1,270		--
Impairment of property, plant and equipment (note 5)	96,242		3,468
Impairment of intangibles (note 6)	23,484		7,786
Share based payment expense (note 28)	--		4,708
Translation difference	(57)		--
		120,939	(28,766)

Exceptional items 2014:

Potential claim - In 2014 a claim has been made by a supplier for an amount of $1.3 million, relating to a matter pre-merger with the Bayfield Group. Management has provided for this claim in 2014 (see note 16)

Impairment of property, plant and equipment - A sharp fall in oil prices combined with a downgrade in reserve estimates triggered an impairment review of the Group's carrying values within property, plant and equipment. Impairment losses were incurred relating to the CGU's which were written down to their recoverable amount (see note 3 (h)).

Impairment of intangibles - An impairment loss was taken on the exploration well EG-8 ($ 22.6 million) and exploration costs in South Africa ($0.9 million) following an impairment review (see note 6).

Exceptional items 2013:

Negative goodwill - A gain on purchase was recognised in the reverse acquisition of Bayfield by TEPL as the fair value of net assets acquired was in excess of the fair value of consideration exchanged.

Goodwill -A deferred tax liability has been realised on the acquired Oil and Gas properties acquired, this has resulted in in the recognition of goodwill.

Business combination costs - These are advisor and other legal costs specifically associated with the acquisition of Bayfield

Unrealised forex loss - Unrealised foreign exchange loss recorded on the translation of share placing receipts.

Impairment of property plant and equipment - On the Trintes field a development well was suspended and will not be completed as a result, the cost of $0.7 million has been impaired. A downward revision in the reserves estimate led to an impairment loss recognised in Oilbelt Services Limited $2.6 million and Coastline International Inc. $0.2 million.

Impairment of intangibles - Goodwill fully attributable to the Oilbelt Services Limited CGU has been fully impaired.

Share based payment expense - During 2012 share options were granted to certain Directors and employees. The exceptional charge represented the acceleration of the share option charge in 2013 as the vesting period was accelerated due to the announcement of the acquisition of Bayfield.

30 Earnings Per Share

Basic earnings per share is calculated by dividing the earnings attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period. Diluted earnings per share is calculated using the weighted average number of ordinary shares adjusted to assume the conversion of all dilutive potential ordinary shares.

	Earnings	Weighted Average Number Of Shares $'000	Earnings Per Share $

	$'000
Year ended 31st December, 2013

Basic	38,832	86,275	0.45

Impact of dilutive ordinary shares:
Assumed conversion of warrants	--	54	--
Long term incentive plan	--	96	--
Share options - Legacy TEP Plc	--	390	--
Share options - Legacy TEPL	--	2,306	--
Share options granted 29th May, 2013	--	790	--
Long term incentive plan granted 1st July, 2013	--	371	--

Diluted	38,832	90,282	0.43

	Earnings	Weighted Average Number Of Shares $'000	Earnings Per Share $
Year ended 31st December, 2014

Basic	(141,182)	94,800	(1.49)

Impact of dilutive ordinary shares:
As net losses from continuing operations were recorded in 2014, the dilutive potential shares are anti-dilutive and both basic and diluted earnings per share are the same.
Diluted	(141,182)	94,800	(1.49)

31 Events after the Reporting Period

On the 23rd January, 2015 TEP Plc made a non-refundable deposit of $2.5 million for Centrica's block 1a and 1b. The balance remaining $20.5 million with interest accrued effective from 23rd February, 2015. The completion date agreed for the transaction is the end of July and Trinity can specify an earlier date on not less than 2 days' notice. Centrica will be obliged to pay further significant sums under the PSCs in early July which Trinity has to pay in the event that completion takes place after 5 July. These payments are to be deducted from the consideration on completion occurring. The payments are in respect of the net PSC Financial Obligations (Article 21 of the Blocks 1a & 1b PSCs - due by 10 July 2015) and the net Annual Holding Fees for the contract year ending 2014 / 2015.

On the 6th February 2015 TEP Plc repaid $20.0 million of the Citibank Trinidad and Tobago loan and obtained a repayment moratorium on the $13.0 million balance until 15th June, 2015.

On the 10th March 2015 TEP plc sold casing and tubing to Rigtech Services Limited, Blanket Security Limited and Well Services Petroleum Company Limited (Purchasers) for $3.5 million. The sale of casing and tubing to the Purchasers constitute a related party transaction under the AIM Rules as Anthony Brash, a Director of those entities, is also a Board member and shareholder of TEP Plc. The proceeds of the transaction will be used to reduce amounts owing to Purchasers in relation to services provided by the Purchasers to the Company. The fall in the casing and tubing market internationally resulted in a loss on sale of $1.3 million.

On the 8th April, 2015 the TEP plc announced it has decided to conduct a review of its options which may include, but are not limited to, a farm-out or sale of one or more of its existing assets, a corporate transaction such as a merger with or sale of the Company to a third party or a subscription for the Company's securities by one or more third parties.

The Company is subject to The City Code on Takeovers and Mergers (the "Code") and has opted to conduct discussions with parties interested in making a proposal to the Company under the framework of a "Formal Sale Process" as set out in the Code in order to enable discussions relating to a merger or sale of the Company, in particular, to take place on a confidential basis.

This information is provided by RNS

The company news service from the London Stock Exchange

END

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2014 Preliminary Results

At 1st January, 2014

$'000

Cash and cash equivalents

25,145

7,939

33,084

Financial liabilities - borrowings current

(3,989)

(18,611)

(22,600)

Financial liabilities - borrowings non-current

(11,910)

1,510

(10,400)

9,246

(9,162)

84

Current tax

Income tax expense

(Loss) /Profit before taxation

Higher overseas tax rate

Profits not subject to tax

Disallowable expenses

Deferred tax asset not recognised

Tax loss generated not recognised

Tax losses utilised

Tax losses previously recognised

Supplemental petroleum tax

Green fund levy

Other differences

Tax charge

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