Trinity Regulatory News (TRIN)

Trinity Exploration & Production Plc

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

2014 Preliminary Results

27th May 2015

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

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.

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 1st 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:

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 15th 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

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

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 PlcRegistered Number: 07535869

Trinity Exploration & Production Plc

Notes to the Consolidated Financial Statements

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 21st 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 14th 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:

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:

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:

(b) Transactions and balances

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

Intangible assets

(a) Exploration and evaluation assets

Capitalisation

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

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

Costs incurred in the exploration and evaluation of assets includes:

(i) License and property acquisition costs

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

(ii) Exploration and evaluation expenditure

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

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

Impairment

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

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

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

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

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

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

(b) Goodwill

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

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

Property, plant and equipment

(a) Oil and gas assets

Development and Producing Assets - Capitalisation

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

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

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

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

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

Development and Producing Assets - Impairment

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

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

Producing Assets - Depreciation, depletion and amortisation

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

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

Decommissioning

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

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

(b) Non-oil and gas assets

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

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

Buildings - 20 years

Plant and equipment - 4 years

Other - 4 years

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

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

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

Impairment of non-financial assets

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

Inventories

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

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

Cash and cash equivalents

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

Trade receivables

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

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

Trade payables

Trade payables are initially recognised at fair value.

Current and deferred income taxes

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

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

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

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

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

Borrowings

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

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

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

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

Provisions

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

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

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

Employee retirement benefits

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

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

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

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

Leases

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

Share capital

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

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

Operating segment information

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

Exceptional Items

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

2 Financial Risk Management

 Financial risk factors

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

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

(a) Market risk

(i) Foreign exchange risk

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

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

(ii) Price risk

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

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

 (iii) Interest rate risk

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

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

(b) Credit risk

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

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

(c) Liquidity risk

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

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

(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.

Fair value estimation

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

3 Critical Accounting Estimates and Assumptions

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

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

(a) Income taxes

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

(b) Recoverability of deferred tax assets

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

(c) Provision for decommissioning costs

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

(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:

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).

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

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).