Trinity Regulatory News (TRIN)

2 May 2017

Trinity Exploration & Production plc

("Trinity" or "the Group" or "the Company")

Preliminary Results

Trinity, the independent E&P company focused on Trinidad and Tobago, today announces its preliminary results for the 12 months ended 31 December 2016.

This was a transformational period for the Group during which it re-established itself as a robust entity with high quality producing assets and strong growth potential. As such, the main focus was on maintaining production, rebasing costs and returning to profitability.

Financial Highlights*

· Revenues of USD 35.3 million (2015: USD 48.2 million)

· Pre-tax operating expenditures ("OPEX") reduced by 29% to USD 15.6 million (2015: USD 22.0 million)

· General and Administrative ("G&A") costs reduced by 61% to USD 4.2 million (2015: USD 10.5 million)

· The Group was profitable at an operating level for the majority of 2016 generating EBITDA (before exceptional items/ exploration costs written off) of USD 6.3 million (2015: USD 1.2 million)

· Net Loss after tax and exceptional items of USD 7.0 million (2015: USD 58.6 million loss)

· Positive cash inflow from operating activities of USD 9.0 million (2015: USD 2.5 million)

· Operating break-even levels below a realised price of USD 30.0 per barrel ("/bbl") achieved ahead of target

· Cash balance at end of period of USD 7.6 million (2015: USD 8.2 million). The comparable year on year cash position is all the stronger given the prudent reclassification of USD 1.1 million of cash as an Abandonment Fund within non-current assets

· The comparable year on year ending cash position is all the stronger given the prudent reclassification of USD 1.1 million of cash as an Abandonment Fund within non-current assets

· Following the successful fundraising completed in January 2017, and payments of creditor settlements, cash balances at the end of February 2017 had increased to USD 13.0 million

· Creditor settlements have resulted in a reduction in like-for-like total pre-restructuring liabilities (outstanding debt plus current and non-current liabilities) from USD 50.7 million (as at 31 December 2016) to USD 14.2 million (pro forma post-completion of the restructuring but excluding the new Convertible Loan Note, "CLN"). This includes the remaining amounts due to State Creditors (USD 13.5 million) which are due to be repaid in 10 quarterly instalments commencing in June 2017

· No Supplementary Petroleum Taxes ("SPT) relating to 2016 payable, realisations having been below the USD 50.01/bbl threshold

· Profits from production continue to be sheltered from Petroleum Profits Taxes ("PPT) by Trinity's significant tax losses and allowances position (current tax loss pool of USD 217.6 million)

· To date, the Group has put hedging in place (through purchasing put options) which covers over 35% of the Group's production should the WTI oil price fall below USD 40.0/bbl over the next 12 months

· The Board will continue to review the options available to further hedge its oil price exposure, as market conditions permit

*All figures for the financial year 2016 are audited. Q1 2017 figures are unaudited

Operating Update

· Group average net production volumes of 2,542 bopd for the year to 31 December 2016 (2015: 2,896 bopd) due to a lack of capital investment

· Average realised price of USD 39.4/bbl (2015: USD 45.4/bbl)

· High quality reservoirs, low natural decline rates and successful low-cost workovers continue to assist in maintaining production levels, despite the backdrop of reduced investment in 2016

· Improved operating metrics (higher oil price and reduced operating costs) supported an increase in Management estimated 2P reserves to 21.3 mmbbls as at 31 December 2016 (2015: 21.0 mmbbls) despite producing 0.9 mmbbls during the year and Guapo field divestment (2P: 0.8 mmbbls)

· Combined 2P reserves and 2C resources base of 42.3 mmbbls with significant additional prospective resources

· For Q1 2017 daily production averaged c.2,500 bopd, a satisfactory performance given the reduced levels of investment in 2016

· Contingent upon the prevailing oil price environment, and subsequent investment, net average production for 2017 is expected to be in the range of 2,600 - 2,800 bopd

· Trinity is continuing to target an eventual run-rate closer to 3,000 bopd over the next 12 months (predominately contingent upon the results of the pending onshore infill drilling programme)

Corporate Update

· Completion of successful fundraising in January 2017 of approximately USD 15.0 million through an issue of ordinary shares (USD 11.7 million) and convertible loan notes (USD 3.3 million)

· Successful execution of agreements with creditors to settle outstanding debts

· All trade, senior debt and initial state creditor settlements have been made to the Trustee in accordance with the creditor arrangement

· Board significantly strengthened by the appointments of three new directors on completion of the fundraising: Jeremy N. Bridglalsingh (Executive) our current Chief Financial Officer, David A. Segel (Non-Executive) and Angus C. Winther (Non-Executive)

Strategic & Portfolio Update

· Programme of 12 recompletions ("RCP's") planned for 2017

o Two have already been undertaken

o A further four are expected to be completed before the end of June

· Re-initiation of swabbing activities, which re-commenced in April, to take place alongside drilling of new onshore wells from previously identified locations

· Initial onshore drilling programme expected to comprise four new wells in each of the next two years, again subject to market conditions

· The Company anticipates additional capital expenditure works for planned repairs and maintenance to its equipment and infrastructure

· These combined activities have the potential to increase production from current levels of c. 2,500 bopd to an eventual target-rate of approximately 3,000 bopd within 12 months of completing the initial onshore infill well drilling programme

· In addition, the Company has initiated an internal review of the Trinites infill drilling programme and the Trinites-TGAL and Galeota Ridge development plan

Bruce A. I. Dingwall CBE, Executive Chairman of Trinity, commented: 

"The Board and management endeavoured during the period to preserve as much value for shareholders and stakeholders as we could, delivering the refinancing and restructuring needed to restore the Group's financial position. We are delighted to have now completed the balance sheet restructuring and we are now focused on growing our reserves and production levels, and achieving a market value that is more reflective of our underlying assets and business.

During the period production declined due to lack of investment. However, we are now focused on reversing this trend having made significant reductions to OPEX and G&A costs, enabling the Company to maintain and enhance cash margins despite a lower oil price environment. As such, we are well placed to grow as a producing, cash flow positive business. With a low-cost asset base and strong management team in place we look forward to a busy year ahead.

On behalf of the Board, I would like to express our thanks to all of our various stakeholders and to Trinity's staff for their continued commitment and hard work to sustain and maximise the portfolio's value."

The Board currently expects to publish its annual report and accounts for the year to 31 December 2016 during May 2017, with the annual general meeting expected to take place in Edinburgh on 23 June 2017.

Competent Person's Statement

The information contained in this announcement has been reviewed and approved by Graham Stuart, the Company's Technical Advisor who has 34 years of relevant global experience in the oil industry. Mr. Stuart holds a BSC (Hons) in Geology. Reserves and resources in this announcement are based on internal management estimates in accordance with SPE PRMS guidelines (Petroleum Resources Management System 2007 & Revisions).

This announcement contains inside information for the purposes of Article 7 of EU Regulation 596/2014.

Enquiries:

About Trinity

Trinity is an independent oil and gas exploration and production company focused solely on Trinidad and Tobago. Trinity operates producing and development assets both onshore and offshore, in the shallow water West and East Coasts of Trinidad. Trinity's portfolio includes current production, significant near-term production growth opportunities from low risk developments and multiple exploration prospects with the potential to deliver meaningful reserves/resources growth. The Company operates all of its nine licences and, across all of the Group's assets, management's estimate of 2P reserves as at the end of 2016 was 21.3 mmbbls (excluding the Guapo-1 license which was disposed of in April 2016). Group 2C contingent resources are estimated to be 21.1 mmbbls. The Group's overall 2P plus 2C volumes are therefore 42.3 mmbbls.

Trinity is listed on the AIM market of the London Stock Exchange under the ticker TRIN.

Executive Chairman's Statement

Strategic Report

Strategy

Trinity's vision and strategy remains unchanged through the continued focus on Trinidad, retaining the integrity of the core producing proved and probable ("2P") reserves base, investing to grow production and cash flow when appropriate and warehousing further significant resource volumes to monetise in the future.

Securing a Future

Trinity entered 2016 with a distressed balance sheet compounded by a persistent low oil price environment and reduced production levels as a result of these capital constraints. The Board and Management's primary objectives during 2016 were to deliver a financial solution that would free the balance sheet from its working capital overhang and return the operating business to profitability, within a depressed oil price environment. During this time, we continued to focus on maintaining the integrity of our producing asset base whilst adopting better operational practices and efficiencies that enabled the Company to materially rebase it costs and thus reduce the break-even economics on our assets.

The forbearance and ongoing co-operation from the Trinidad &Tobago State creditors, senior debt holder and supply chain creditors allowed the Company the time needed to implement these cost saving initiatives thereby sustaining direct employment, where possible, as well as the services of a significant number of contractors during a difficult economic period in Trinidad & Tobago. For that support we remain extremely thankful and look forward to continuing to build on and strengthen the existing relationships with our stakeholders.

The drastic change in the cost structure of the business and return to operating profitability provided the impetus for the Company to accelerate the several potential funding solutions that were presented throughout 2016. In December 2016, we announced the proposed fundraising of approximately USD 15.0 million ("the Fundraising") in relation to the financial restructuring of the Company that not only enabled settlements to be proposed and agreed with outstanding creditors but also enabled the Company to be placed into a more robust position in order to ensure that value is maximised from the current asset base. This will be realised by leveraging the benefits from maintaining and growing production with a significantly reduced cost base and operating break-even levels below a realised price of USD 30.0 per barrel ("/bbl") having been achieved ahead of the end of 2016 targeted schedule.

The execution of agreements with creditors and the subsequent completion of the Fundraising on 11 January 2017 has significantly strengthened the Group's balance sheet by reducing its like-for-like total pre-restructuring liabilities (being outstanding debt plus current liabilities and non-current liabilities) from USD 50.7 million as at 31 December 2016 to USD 14.2 million (pro forma post-completion of the restructuring but excluding the new Convertible Loan Note). The net proceeds from the Fundraising were applied toward the payments to creditors under a proposal for a scheme of arrangement between the Company's T&T incorporated subsidiaries and their creditors pursuant to Part V of the Bankruptcy and Insolvency Act (No. 27 of 2007) of Trinidad and Tobago ("the Proposal") and settlement agreements, certain one-off restructuring costs, infrastructure costs to ensure the integrity of production operations going forward and, subject to the prevailing market conditions, the re-initiation of drilling activities with an initial programme of four (4) new onshore wells.

2016 Trading Summary

A four-year historical summary of realised price, production, operating break-evens and Operating Expenditure ("Opex") and General and Administrative ("G&A") expenditure metrics is set out below:

Notes:

1. Based on realised price

2. Operating Break-even: Revenue - Over-riding Royalty - Production Royalty - Opex

3. Operating Break-even: Revenue - Over-riding Royalty - Production Royalty - Opex - G&A

The diligent efforts of the Management team and Trinity's staff during 2016 enabled a reduction in the Company's consolidated operating level break-even from USD 47.4/bbl in 2015 to USD 29.1/bbl for the full year 2016. This is all the more impressive given it was achieved despite reduced like-for-like production levels (-12%) and a lower realised oil price (-13%).

The establishment of a leaner, more efficient operating cost base year-on-year came about as follows:

· Opex reduced by 29% to USD 15.6 million (2015: USD 22.0 million). This was achieved through various cost efficiency measures taken with the highest reduction being within the Logistics on the East Coast. Opex is largely of a fixed cost nature and therefore an increase in production over a largely fixed cost base has a significant leverage effect;

· G&A costs reduced by 61% to USD 4.2 million (2015: USD 10.5 million) and are on target to be sustained at this level; and

· The consolidated operating break-even oil price for the Group for the 12 months ended 31 December 2016, including G&A, was USD 29.1/bbl which compares to consolidated break-even oil prices of USD 62.9/bbl in 2013, USD 64.6/bbl in 2014, USD 47.4/bbl in 2015.

The resultant impact on our financial performance was for the Company to be profitable at an operating level for the majority of 2016 generating an EBITDA of USD 6.3 million (2015: USD 1.2 million) and a robust operating cash flow of USD 9.0 million (2015: USD 2.6 million) and yielding a year-end cash balance of USD 7.6 million (2015: USD 8.2 million). The comparable year on year ending cash position is all the stronger given the prudent reclassification of USD 1.1 million of cash as an Abandonment Fund, which is recognised within non-current assets.

Trinity did not pay Supplementary Petroleum Taxes ("SPT) during 2016 having realisations below the USD 50.01/bbl threshold. To be clear SPT is payable on average realised prices which are at a discounted level to the prevailing West Texas Intermediate ("WTI") oil price and are partially sheltered by certain categories of capital expenditure. Furthermore, profits from production continue to be sheltered from Petroleum Profits Taxes ("PPT) by Trinity's significant tax losses and allowances position (current tax loss pool of USD 217.6 million).

Plans for the Future

Across Trinity's asset base the Company has identified clear pathways for value-creating production growth. Whilst the restructuring and re-alignment of the Company's cost base has created a much stronger platform for growth, the Board is mindful that it must maintain a disciplined approach to costs through the implementation of staged, risk-mitigated, development activities. In the short-term, the Company has embarked upon a work programme to sustain the current production base via routine work-overs ("WOs"), whilst growing current production levels from an existing wide inventory of opportunities from recompletions ("RCP's") and reactivations on its current well stock.

A programme of 12 RCP's is planned for 2017 with 2 having already been undertaken and a further 4 expected to be completed before the end of June. The re-initiation of swabbing activities commenced in April and will continue to take place alongside the drilling of new onshore wells from previously identified locations. The recommenced onshore drilling programme is expected to comprise four new onshore wells in each of the next two years, subject to market conditions, most notably the prevailing oil price. Additionally, the Company anticipates capital expenditure works for planned repairs and maintenance to equipment and infrastructure.

These combined activities provide scope to grow production from current levels of c. 2,500 bopd to an eventual target-rate of approximately 3,000 bopd within 12 months of completing the initial onshore infill well drilling programme.

In addition the Company has initiated an internal review of the Trinites infill drilling programme and the Trinites-TGAL and Galeota Ridge development plan.

Operational Review

Health, Safety, Security and the Environment ("HSSE")

Employees are Trinity's most important resource and personal safety is a paramount driving factor in our HSSE initiatives. The initiatives employed year-on-year since 2013 have resulted in improved safety performance with a 9% improvement of the Incident Rates in 2016 compared to 2015. The Company will seek to maintain a year on year improvement for the Incident Rates in 2017 from 2016, despite the increased levels of activity planned for 2017, through the continued development of positive safety behaviours and focusing on areas with potential for further improvement. This endorses the Company's drive to improve its HSSE Management System by progressing towards Safe to Work ("STOW") certification that is expected to be completed during the second half of 2017. This will further advance our ability to respond, control and analyse safety events and performance data.

Production

Total average net production for 2016 was 2,542 bopd (2015: 2,896 bopd) which represents an overall 12% decline in production levels over the year, but normalised to a net overall (2016: 2,518 bopd vs 2015: 2,832 bopd) 11% decline as the GU-1 asset (2016: 5-month average: 57 bopd) was divested in May 2016.

Onshore Assets

Current onshore production is from Lease Operatorship Blocks; WD-2, WD-5/6, WD-13, WD-14 and FZ-2 in southern and south-western Trinidad.

Average 2016 net production from the Onshore assets (inclusive of GU-1) was 1,343 bopd which accounted for 53% of total production for the year. This represents a 16% decrease in production from the 2015 average net production levels of 1,600 bopd. 2016 net Onshore production exclusive of GU-1 production represents a like-for-like decline of 14%.

The decrease in production was due to natural decline across all assets and certain wells being off for prolonged periods, as the main focus in 2016 was maintaining base production through routine WOs, reactivations and production optimisation. These activities were subject to a highly constrained capital budget. There was also no swabbing conducted during 2016 which compounded the overall lower production trend. In total, 60 routine WOs were executed across the onshore assets utilising Trinity's internal rig resources (2015: 91 routine WOs). The reduction in the quantity of WOs in 2016 was again due to capital constraints. Capital expenditure on production enhancing projects was absent in 2016 resulting in no heavy WOs, RCPs or drilling activities.

East Coast Asset

Current East Coast production is from the Alpha, Bravo and Delta platforms on the Trintes Field. Despite the cessation of investment, ongoing steps to improve operating efficiency have been effective in sustaining production with current levels ranging between 950 - 1,100 bopd.

Average 2016 net production from the East Coast was 1,009 bopd which accounted for 40% of total production for the year. This represented a 3% increase in production from the 2015 average net production levels of 983 bopd.

The retention of such stable production levels via better generator maintenance strategies and improved competency for remote monitoring on important wells, at a time when no capital has been deployed towards new drilling, is testament to the quality of the reservoirs and the technical capability and the knowledge of the operations within Trinity's team.

The two WOs completed in Q4 2015 influenced an upward trend in production, as the rates were realised in 2016. Similarly, two WOs conducted in Q4 2016, which included the installation of progressing cavity pump ("PCP") technology on the Delta platform added approximately 20 bopd. This significant test of the improved PCP technology will charter a more cost effective strategy in producing from lower rate wells on the East Coast offshore facilities.

Trinity will continue optimising and reviewing alternative artificial lift technologies to maintain base production and augment these production rates in an attempt to further improve efficiency and cost effectiveness.

West Coast Assets

Currently, West Coast production is from the Point Ligoure-Guapo Bay ("PGB") and Brighton Marine ("BM") fields.

Average 2016 net production from the West Coast was 190 bopd which accounted for 7% of Trinity's total production for the year. This represented a 39% reduction in production from 2015 average levels of 313 bopd.

There were no major activities conducted on the West Coast assets in 2016, with the exception of one routine WO, and no WOs were conducted in 2015 due to funding restrictions. The general downward trend in production is due to the ABM-151 well (~89 bopd) being closed-in due to high volume sand production tendencies. Given that this is the main gas source in the field, the resultant production impact was adversely compounded given the absence of the gas lift to optimise production across the field's wells. While gas lift will depend on both the ABM-151 well being brought back on production and the change-out of the high pressure and low pressure pipelines, the incremental production benefit is expected to be significant. Additional production curtailments were experienced across the BM field due to pipeline and platform landing stage integrity issues.

In the latter part of Q4 2016, a pipeline change-out programme was completed in BM resulting in a production increase of 55 bopd. However these rates will only be realised in 2017. The low energy prices and the higher cost of the application being predominantly offshore, has dampened activities on the asset. However, moving forward, the land based wells across both the PGB and BM fields will be targeted for reactivation in addition to minor facility upgrades as the means to increase production.

Reserves and Resources

A comprehensive Management review of all assets has been concluded and has estimated the current 2P reserves to be 21.3 mmstb at the end of 2016, compared to the year-end 2015 reserve estimate of 20.9 mmstb (exclusive of 0.8 mmstb for GU-1). This represents an increase of 0.3 mmstb (1.6%) increase vs 2015. This increase, despite the disposal of the GU-1 asset and production for 2016 (0.9 mmstb) is largely due to reduced operating costs, revised capital expenditure and a more favourable crude oil futures price deck (compared to 2015).

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 reserves estimate is based on the assumption of a fully funded programme.

Note (*): Exclusive of GU-1 asset

The best estimate of contingent resources ("2C") due to the current economic environment and the defining technical work pending is estimated by Management at 21.1 mmstb (2015: 19.9 mmstb).

Note (*): Exclusive of GU-1 asset

Note (*): Exclusive of GU-1 asset

East Coast Hub

On the East Coast, Trinity has an established production hub with four offshore marine platforms (Alpha, Bravo, Charlie & Delta) that across them have 61 platform wells. Current 2P reserves underpin only the producing Trintes field. However, across the East Coast Galeota anticline licence area Management estimates total gross Stock Tank Oil Initially In Place ("STOIIP") of over 700 mmstb of which 249 mmstb of STOIIP is mapped against the Trintes field. Trintes (current booked East Coast) 2P reserves of 19.5 mmstb therefore represents a low recovery factor of 8%. Within contingent resources a further 5.0 mmstb relate to the Trintes field. There are 31 candidate drilling locations identified in addition to the current producing well stock offering visibility on future organic production growth opportunities.

The TGAL (Trinity 65%) discovery, up-dip to the north east of the Trintes field, has booked net contingent resources of 14.5 mmstb (gross: 22.3 mmstb) which represents a low recovery factor of 12% on best estimate STOIIP of 186 mmstb (management resource estimates of STOIIP for the TGAL area remains at 150-210 mmstb). The draft field development plan ("FDP") was submitted to the MEEI in Trinidad & Tobago at the end of October 2015 for review and comments. The MEEI has indicated that the document is still under review, although Trinity expects to receive the MEEI's comprehensive review report in short order. However, given that the original FDP development concept arose in a significantly higher oil price environment the Company has initiated an internal review of the Trintes-TGAL and Galeota Ridge development plan for 2018 activity and beyond.

With combined 2P reserves and 2C resources of 34.2 mmstb, the potential production growth from future phased Trintes-TGAL development drilling is significant.

Within the Galeota anticline licence area there is further significant wider prospectivity with 266 mmstb STOIIP having been mapped between the Trintes field and the EG-3 and EG-4 wells.

Onshore Reserves Growth Strategy

Current booked onshore reserves only reflect wells identified and budgeted as opposed to the full well inventory potential across Trinity's extensive acreage positions. The lack of available capital has meant that little or no focus has been applied to growing the onshore well hopper and thus growing reserves via desktop subsurface analysis versus the drill bit. Going forward, this will become an area of focus for Trinity with dedicated subsurface geologists working up locations for future reserves to be booked.

The Way Forward

The combination of capital to deploy towards growing production from 2P reserves, a robust cost structure to facilitate lower break-even levels, a significant volume of additional resources being warehoused, low-risk reserves growth opportunities and significant tax losses allows the Company to look forward with confidence.

However, whilst focusing on the future, the lessons of the past remain. The forbearance of the T&T State creditors, senior debt holder and the supply chain was integral to Trinity getting through an extremely difficult period and it is imperative that we work to honour our future commitments and grow the business within its financial means.

Since completing the Fundraising, the Board has investigated the various alternatives which are available to hedge the Group's exposure to the oil price. The Board's intention is to implement a hedging programme which protects the Group from significant downward movements in the oil price, thus ensuring that the Group can fulfil its remaining obligations to the BIR and MEEI in line with the ratified creditors' proposal as well as maintaining production and investment at optimum levels for the given oil price environment. The Board's intention is for its hedging programme to be cost effective, efficient and to allow the Group to maintain exposure to upward oil price movements. To date, the Group has put hedging in place (through purchasing put options) which covers over 35% of the Group's production should the WTI oil price fall below US$40.0/bbl over the next 12 months. The Board will continue to review the options available to further hedge its oil price exposure, in line with these objectives, as market conditions permit.

Notwithstanding the seemingly insurmountable challenges, during 2016, we continued to prioritise the health, safety, security and well-being of our people while promoting the safe behaviours of contractors and partners. This is evidenced by the initiatives employed during the year having resulted in a 9% reduction in 2016 incident rates when compared to 2015. Good governance is key and we are committed to meeting all of our obligations in a responsible and transparent manner. To that end, I am very pleased to welcome three new directors to the Board: Jeremy N. Bridglalsingh (Executive) our current Chief Financial Officer ("CFO"), David A. Segel (Non-Executive) and Angus C. Winther (Non-Executive).

As we look forward I'd like to thank our staff for their hard work and loyalty. I would also like to thank our wider stakeholders and shareholders for their forbearance and support to date.

Financial Review

2016 Results Overview

During 2016, the operational focus was to return to a business model capable of being sustained in a low oil price environment. The underlying cost structure and activity set were reviewed in minute detail, taking a rigorous 'fit for purpose' approach. This commenced in late 2015 and, in the latter part of H1 2016, Trinity moved from generating an operating loss to an operating profit, that eventually produced a 2016 EBITDA of USD 6.3 million (2015: USD 1.2 million); an increase of 425% in EBITDA even though realised oil prices fell by over 13% during the period.

The following table summarises the 2016 financial results:

Financial Results Summary

Note (*): 2016 closing cash balance excludes USD 1.1 million of cash reclassified as an Abandonment Fund, under non-current assets, which if included would be USD 8.7 million (2015: USD 8.2 million).

Statement of Comprehensive Income Analysis

Revenues

2016 revenues were USD 35.3 million (2015: USD 48.2 million). This 27% decrease was mainly attributable to a combination of; (i) a 13% decline in the average realised oil price of USD 39.4/bbl (2015: USD 45.5/bbl) and; (ii) a 12% decrease in production to 2,542 bopd (2015: 2,896 bopd)

Operating expenses

Operating expenses were USD (38.6) million (2015: USD (55.3) million). There was a 33% decrease from the previous year and 2016 comprised:

• Royalties of USD (9.3) million (2015: USD (14.6) million)

• Production costs of USD (15.6) million (2015: USD (22.0) million)

• Depreciation, depletion and amortisation amounted to USD (9.5) million (2015: USD (8.2) million)

• G&A expense of USD (4.2) million (2015: USD (10.5) million)

Exceptional items

Exceptional items USD (1.7) million (2015: USD (17.2) million) comprised:

· Impairment of property, plant and equipment, intangibles, receivables and inventory USD (3.6) million (2015: USD (6.2) million)

· Fees relating to Corporate Restructuring USD (0.9) million (2015: USD (1.1) million)

· Release of provision for NIKO claim USD 1.2 million (2015: nil)

· Provision for Restructuring USD 1.9 million (2015: USD (1.9) million)

· Costs relating to unsecured claims and other provisions USD (1.3) million (2015: nil)

· Gain on disposal of GU-1 asset USD 1.0 million (2015: nil)

· Loss on disposal of assets nil (2015: USD (1.6) million)

· Written off 1(a) & 1(b) pre-acquisition cost nil (2015: USD (6.4) million)

See Note 28 to Consolidated Financial Statements - Exceptional items for further details.

The Group and Company's operating loss after exceptional items was USD 5.0 million (2015: USD 24.3 million).

Net Finance Costs

In 2016, finance costs amounted to USD (4.7) million (2015: USD (6.7) million) comprised of the following:

· Unwinding of the decommissioning liability USD (1.6) million (2015: USD (1.5) million)

· Combined interest related to the fully drawn (USD 20.0 million & USD 25.0 million) Citibank (Trinidad & Tobago) Limited ("Citibank") loans USD (0.9) million (2015: USD (1.1) million)

· Interest accrued on outstanding taxes USD (2.2) million (2015: USD (4.1) million)

See Note 20 to Consolidated Financial Statements - Finance Costs for further details.

Income Tax Expense

Taxation for 2016 was a credit of USD 2.8 million (2015: USD (27.0) million), and its components are described below.

• Supplemental Petroleum Tax ("SPT") for 2016 amounted to a credit of USD 0.9 million (2015: USD (1.8) million). There were no SPT charges in relation to 2016. The credit was as a result of adjustments made to align to the BIR records as the BIR applied credits to outstanding SPT liabilities from prior years in 2016

• The Petroleum Profits Taxes ("PPT") charge for the year ended was USD (1.5) million (2015: credit of USD 0.2 million)

• Corporation Tax ("CT") for the year amounted to nil (2015: USD (0.6) million)

• The Deferred Tax Asset ("DTA") for the year was as a result of tax losses recognised based on tax losses available for utilisation against future profits contributing to the credit of USD 3.4 million (2015: USD (24.7) million DTA derecognised)

See Note 21 to Consolidated Financial Statements - Income Tax Expense for further details.

Consolidated Statement of Cash Flows Analysis

Cash inflow from operating activities

Cash inflow from operating activities was USD 9.0 million (2015: USD 2.5 million) following adjustments for:

• Operating activities resulting in a net cash inflow of USD 7.6 million (2015: USD 1.1 million inflow)

• Changes in working capital of comprising a net cash inflow of USD 2.9 million (2015: USD 1.5 million)

• Taxation paid of USD (1.6) million (2015: USD (0.1) million)

Cash outflow from investing activities

Cash outflow from investing activities was USD (0.3) million (2015: USD (2.2) million), which was comprised of the following:

· Expenditure on property, plant and equipment for the year was USD (0.3) million (2015: USD (1.0) million) which mainly included infrastructure upgrades

· Costs related to the purchase of exploration and evaluation assets (nil) (2015: USD (1.2) million)

Cash outflow from financing activities

Cash outflow from financing activities was USD (6.2) million (2015: USD (25.2) million) as a result of debt repayment and finance costs:

• Repayment of borrowings of USD (3.0) million (2015: USD (20.0) million) includes principal repayment toward the Citibank USD 20.0 million loan and USD 25.0 million loan

• Finance costs of USD (3.2) million (2015: USD (5.2) million) included USD (2.2) million interest accrued on unpaid taxes and USD (1.0) million related to interest paid on loans.

See Note 15 to the Consolidated Financial Statements - Borrowings for further details.

See Note 20 to the Consolidated Financial Statements - Finance Costs for further details.

Accounting Policies

The Group prepares its financial statements in accordance with the European regulations to report consolidated statements that conform to International Financial Reporting Standards ("IFRS").

The Group and Company's accounting policies and details of accounting judgements and critical accounting estimates are disclosed within the notes to the financial statements. The Group has not made any changes to its accounting policies in the year ended 31 December 2016.

Formal Sales Process and Asset Sale Update

The Company announced on 8 April 2015 that it was initiating a Formal Sales Process ("FSP") and strategic review of the options available to the Company to maximise value for shareholders.

The sale of the Group's 100% interest in the Block GU-1 asset to New Horizon Exploration Trinidad and Tobago Unlimited ("New Horizon") for a cash consideration of USD 2.8 million (the "GU-1 Transaction") was agreed on 1 September 2015 and reached financial close on 24 May 2016. All the conditions precedent for the GU-1 transaction were satisfied including standard regulatory approvals, which were granted on 15 April 2016. The transaction was subsequently finalised with the closure of the cash settlement on 24 May 2016. The cash proceeds were used by Trinity to repay senior debt and for working capital purposes.

A Sale and Purchase Agreement ("SPA") was executed on 16 October 2015 between Trinity and Touchstone Exploration Inc. ("Touchstone") in relation to the proposed purchase of the WD-2, WD-5/6, WD-13, WD-14, and FZ-2 onshore Lease Operatorship assets for a total cash consideration of USD 20.8 million. This SPA had a backstop date of 13 March 2016 which expired without all of the conditions precedent being satisfied. Trinity circulated a termination notice in respect of the SPA to Touchstone on 14 March 2016. As a result, the sale of the blocks to Touchstone was not completed and the deposit of USD 2.1 million, held in escrow, was released to Touchstone under the terms of the SPA.

On 9 December 2016, Trinity announced that the FSP process and offer period for the sale of one or more of the Company's assets had terminated with immediate effect as the Restructuring, along with Fundraising had matured suitably.

Restructuring and Fundraising

On 14 March 2016, following the expiry of the SPA with Touchstone, Trinity announced that the Company had engaged two specialist refinancing advisers, Imperial Capital LLC of New York, USA and Cantor Fitzgerald Europe based in London, UK. Management was encouraged by the interest levels from several potential investors. Trinity's near term objective was to conclude a comprehensive refinancing that would enable the Company to retire its existing senior debt facilities, reduce other outstanding payables and provide sufficient additional capital to retain the integrity of its assets and grow production and cash flow. As part of the refinancing it was expected that there would have to be significant discounts agreed with the Company's senior debt holder and with Trinity's other creditors. Without such a refinancing, it was envisaged that the Group would be unlikely to be able to continue as a going concern.

On 16 August 2016, the Group's Trinidad & Tobago subsidiaries namely Trinity Exploration and Production (Trinidad and Tobago) Limited, Galeota Oilfield Services Limited, Trinity Exploration and Production (Galeota) Limited, Tabaquite Exploration & Production Company Limited, Trinity Exploration and Production (GOP) Limited, Trinity Exploration and Production (GOP-1B) Limited, Oilbelt Services Limited, Trinity Exploration and Production Services Limited and Ligo Ven Resources Limited (together the "Subsidiaries") filed a consolidated Notice of Intention ("NOI") to make a proposal to creditors ("the Proposal") under the Bankruptcy and Insolvency Act Ch. 9:70 of Trinidad and Tobago ("the BIA"). The NOI allowed the Trinidad subsidiaries to continue operating while submitting a Proposal to reach a settlement with their outstanding creditors. During this period, that being post 31 July 2016 and to date, all creditors were kept current for all costs incurred. The filing of the NOI provided the subsidiaries with a stay of proceedings from all of their creditors. The Directors believed that the Subsidiaries making the Proposal and benefiting from the stay of proceedings provided the most efficient and orderly route to concluding its restructuring negotiations with potential funders and securing refinancing to the benefit of all stakeholders. In accordance with the BIA, Ms. Maria Daniel was appointed to act as trustee under the Proposal (the "Trustee").

On 9 December 2016, the Group announced the proposed fundraising ("the Fundraising") in relation to its financial restructuring. Total gross proceeds of USD 15.0 million were anticipated via an issue of ordinary shares for an aggregate subscription price of USD 11.7 million ("the Placing") and the issue of Convertible Loan Notes ("CLN") for an aggregate subscription price of USD 3.3 million. The Fundraising was premised on, inter alia: (i) the Proposal becoming effective; (ii) the settlement agreements with Citibank (Trinidad & Tobago) Limited ("Citibank") and UK unsecured creditors being agreed; and (iii) the passing of relevant shareholder resolutions by the requisite majority of the Company's shareholders. The proceeds of the Fundraising were to be applied toward the payments to creditors under the Proposal, the settlement agreements and restructuring and closing costs in relation to the Placing and CLN. 

On 19 December 2016, >99% of the creditors of the Subsidiaries accepted the Proposal which was subsequently approved by Trinity shareholders at the general meeting held on the 29 December 2016. Following the year-end, the Proposal was approved by the Trinidad & Tobago High Court at a hearing on 6 January 2017 thereby paving the way for its implementation.

Events Since Year End

i. Results of Court Hearing - On 6 January 2017, the High Court of Trinidad & Tobago approved the Proposal, which was accepted by the creditors of the Subsidiaries on 19 December 2016.

ii. Completion of Fundraising and share capital restructuring - The Fundraising was completed on 11 January 2017. The Company issued 187,600,000 new ordinary shares in relation to the Placing for an aggregate subscription price of USD 11.7 million and issued CLNs in the principal amount of USD 6.6 million for an aggregate subscription price of USD 3.3 million. The Company received gross proceeds of USD 15.0 million from the Fundraising. Fundraising costs amounted to USD 1.2 million with net proceeds amounting to USD 13.8 million. In order to implement the Fundraising, the Company carried out a share capital reorganisation whereby each existing ordinary share of a nominal value of USD 1.00 was divided and converted into one new ordinary share of a nominal value of UD 0.01 each and one deferred share of a nominal value of USD 0.99 each.

iii. Share trading suspension lifted - The trading of the Company's shares on AIM was temporarily suspended on 13 July 2016, and this suspension was lifted on 11 January 2017.

iv. Creditor settlements and agreed payment plans

- The Citibank principal settlement of USD 3.5 million was paid on 23 January 2017 and the final interest settlement of USD 0.1 million was made on 25 January 2017

- Initial settlements to state creditors, including the BIR and MEEI, of USD 1.9 million were paid over to the Trustee on 8 February 2017. The remaining USD 13.5 million due to the Group's state creditors (that being both taxes due and interest thereon) will be repaid in 10 quarterly instalments which will commence effective June 2017

- Creditor settlements of USD 3.5 million in aggregate in respect of the creditors of the Subsidiaries under the Proposal were also paid over to the Trustee on 8 February 2017

- UK based unsecured creditors were fully settled on 9 February 2017 for a total of USD 0.3 million

Unaudited Pro forma Financial Position as at 31 December 2016

Set out below is the pro forma Financial Position as at 31 December 2016 which illustrates the impact of the refinancing and creditor settlements, which took place subsequent to the 31 December year end. The unaudited data specifically the Convertible Loan Notes, certain Trade and other payables and Taxation payable are shown prior to any fair value adjustment as required by International Financial Reporting Standard ("IFRS") and therefore the financial position in the table does not comply with IFRS. The Board believes that the gross values of these payables better reflects the pro forma financial position of the Group post refinancing and while this initial disclosure is not IFRS compliant, it will help investors better understand the impact of the refinancing and the creditor settlements on the Group's financial position. The Board intends that the Group's Statement of Financial Position will be measured and recognised in accordance with IFRS in Trinity's 2017 Interim Financial Statements onwards.

Notes to the Unaudited Pro forma Financial Position

1 Share Capital and Share Premium

The increase in share capital and share premium represents the 187,600,000 new ordinary shares issued at 4.98 pence. Refer to note 30 (iii) to the Financial Statements

2 Convertible loan notes

The Company issued 6,550,000 USD 1.00 Convertible loan notes ("CLNs") for proceeds of USD 3.3 million. The summary of the terms of the notes are as follows:

· Interest compounds quarterly at a rate of 7.25% per annum, and is repayable on redemption of the CLNs;

· Subject to the satisfaction of payments due to the BIR and MEEI under the Creditors Proposal, the CLN may be redeemed by the Company at any time;

· The CLN will become repayable on the occurrence of certain event(s) inter alia material breach of the terms or insolvency of any material Group company;

· The CLN's are convertible, subject to the City Code Rules, by the holder at a conversion price of USD 0.08125 per ordinary share at any time after the second anniversary of issue or on sale of the Company or material disposal; and

· If not otherwise redeemed or converted the balance of the CLNs together with compounded interest will be repayable in full on the seventh anniversary of issue

IFRS requires the CLNs to be initially measured and recognised at Fair Value with the fair value being allocated to both debt and equity. This is likely to result in a material reduction in the liability recognised on the pro forma Financial Position ("pro forma") at 31 December 2016. Management's initial assessment is that the Fair Value of the CLN will amount to USD 3.3 million in total, based on the funds raised at the time of issue. Management will align the accounting treatment in accordance with the IFRS's recognition and measurement criteria in the 2017 interim financial statements.

3 Trade and other payables

The trade and other payable balance post restructuring and initial settlements as per the pro forma has been split between non-current and current liabilities in line with the repayment terms under the proposal and settlement agreements repayable over 10 quarters commencing June 2017. Included within these liabilities are the amounts due to the MEEI and interest on the tax liabilities (described in note 4 below). The amounts presented on the pro forma represents the face values of the liabilities outstanding and does not comply with IFRS, which requires the financial liabilities to be recognised at Fair Value (given that the repayment period lasts until 30 September 2019). This is likely to result in a reduction in the liability recognised on the pro-forma. Management will align the accounting treatment in accordance with the IFRS's recognition and measurement criteria in the 2017 interim financial statements.

4 Taxation payable

The Taxation payable has been split between non-current and current and represents the principal balance owed (the treatment of the interest portion is described in point 3 above) to the BIR and repayable over 10 quarters commencing June 2017 and does not reflect the IFRS treatment which should not be materially different from that presented in the pro forma. Management will align the accounting treatment in accordance with the IFRS's recognition and measurement criteria in the 2017 interim financial statements.

5 Borrowings

The Citibank borrowings of USD 9.95 million have been fully settled on 23 January 2017 refer to Note 30 (iv) to the Financial Statements.

Trinity Exploration & Production Plc

Consolidated Statement of Comprehensive Income

at 31 December 2016

Trinity Exploration & Production Plc

Consolidated Statement of Financial Position

at 31 December 2016

Trinity Exploration & Production Plc

Company Statement of Financial Position

at 31 December 2016

Trinity Exploration & Production Plc

Consolidated Statement of Changes in Equity

for the year ended 31 December 2016

Trinity Exploration & Production Plc

Company Statement of Changes in Equity

for the year ended 31 December 2016

Trinity Exploration & Production Plc

Consolidated Statement of Cash Flows

for the year ended 31 December 2016

Trinity Exploration & Production Plc

Company Statement of Cash Flows

for the year ended 31 December 2016

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

Basis of Preparation

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

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

The Company has taken advantage of the exemption in Section 408 of the Companies Act 2006 not to present its own income statement or statement of comprehensive income. The loss for the Company for the year was $4.0 million (2015 $2.4 million loss).

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. At the 31 December 2016 the Group had a net current liability of $39.1 million. 

During 2016, the Group had challenges as evidenced by its Statement of Financial position and the objective was to secure a refinancing solution to enable the Company to retire its existing senior debt facilities, reduce outstanding payables and provide sufficient additional capital to continue operating in the foreseeable future. As part of the refinancing deal it was expected that there would have to be significant discounts agreed on the outstanding senior debt holder and with the Groups creditors. Without such a refinancing, it was envisaged that the Group and Company would be unlikely to be able to continue as a going concern.

On 16 August 2016 the Trinidad & Tobago subsidiaries filed for a Notice of Intentions ("NOIs") under the Bankruptcy and Insolvency Act of Trinidad & Tobago ("BIA") to make a proposal to creditors ("the Proposal") and the BIA allowed the company to continue operating while it submitted its proposal to reach a settlement with its outstanding creditors whilst only paying for current operational costs post July 2016. The filing of the NOIs provided the Subsidiaries with a stay of proceedings from all creditors. The Directors believed that the Subsidiaries making the Proposal and benefiting from the stay on proceedings provided the most efficient and orderly route to conclude its restructuring negotiations with potential funders and securing a refinancing to the benefit of all stakeholders. Maria Daniel of Ernst & Young Services Limited was appointed to act as trustee under the Proposal and formal notice was sent to creditors of the Subsidiaries in accordance with the provisions of the BIA.

On 9 December 2016, the Group announced the proposed fundraising ("the Fundraising") in relation to its financial restructuring. Total gross proceeds of $15.0 million were anticipated via an issue of $11.7 million Ordinary Share Capital ("The Placing") and $3.3 million in Convertible Loan Notes ("CLN"). The Fundraising was conditional on, inter alia:

(i) The Proposal becoming effective;

(ii) The Settlement Agreements to Citibank (Trinidad & Tobago) Limited ("Citibank"), Ministry of Energy and Energy Affairs of Trinidad & Tobago ("MEEI"), Board of Inland Revenue of Trinidad & Tobago ("BIR"), Petroleum Company of Trinidad & Tobago ("Petrotrin") and United Kingdom ("UK") unsecured creditors becoming effective; and

(iii) The passing of the Shareholder Resolutions by the requisite majority of the Company's Shareholders. 

On 19 December 2016, the Trinidad & Tobago Creditors accepted the Proposal which was subsequently approved by Trinity plc shareholders at the Annual General Meeting ("AGM") held on the 29 December 2016.

Subsequent to year-end the Proposal was formally approved by the Trinidad & Tobago High Court on 6 January 2017 and the fundraising was executed on 11 January 2017. This has allowed the Group to secure funding through its ultimate parent company, whilst also reducing the group debt and creditor balances. The following actions can now be taken based on the Group's stronger Statement of Financial position and available cash flows::

- The gross proceeds from the fundraising was applied in part towards the payments to creditors under the Creditors Proposal and the Settlement Agreements, including its loan to Citibank

- The balance of the gross proceeds alongside current cash balances and organic cash flow was deployed towards certain one-off restructuring and infrastructure costs and the re-initiation of drilling activities

- The Group intends to move forward with a work programme to sustain and grow current production levels from an existing wide inventory of opportunities for workovers, recompletions and drilling

The financial statements have been prepared on the going concern basis based on the financing provided by the shareholders which provides the necessary financial support to the Group to enable it to pay its debts as they fall due for the foreseeable future.

The Board of Directors has carefully considered and formed a reasonable judgement that, at the time of approving these financial statements, the Group and Company have completed the funding required to continue operations for the foreseeable future. For this reason, the Board of Directors continues to adopt the going concern basis of preparing these financial statements.

New and amended standards adopted by the Group:

The group has applied the following standards and amendments for the first time for annual reporting period commencing 1 January 2016:

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 1 January 2016 and have not been applied in preparing these consolidated financial statements. The impact of these will be assessed in due course:

Basis of consolidation

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

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

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

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

Business combination

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

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

Share-based payments

The Group operates a number of equity-settled, share-based compensation plans comprised of warrants, options and 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 & Tobago dollars as this is the currency of the primary economic environment in which the entities operate. The presentation currency is United States 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 Consolidated Statement of Financial Position is translated at the closing rate and Consolidated Statement of Comprehensive Income is translated at the average rate. The following exchange rates have been used in the preparation of these financial statements:

(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.

(c) Translation differences

Differences arising from retranslation of the financial statements at the year-end is recognised in the Translation reserve through "Other comprehensive income".

Intangible assets

(a) Exploration and evaluation assets

i) Capitalisation

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

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

Costs incurred in the exploration and evaluation of assets includes:

ii) License and property acquisition costs

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

iii) 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.

iv) 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 ("CGU") of related production fields located in the same geographical region. The geographical region is the same as that used for reserves reporting purposes.

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

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

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

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

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

(b) Goodwill

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

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

Property, plant and equipment

(a) Oil and gas assets

i) Development and Producing Assets - Capitalisation

Development expenditures are costs incurred to obtain access to proven reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. These costs include transfers from exploration and evaluations subsequent to finding commercially viable reserves, development drilling and new reserve type, infrastructure costs and development geological and geophysical costs. Acquisitions of oil and gas properties are accounted for under the purchase method where the transaction meets the definition of a business combination.

Transactions involving the purchases of an individual field interest, or a Group of field interests, that do not 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.

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

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

ii) Development and Producing Assets - Impairment

An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount. Impairment triggers include but 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.

iii) Producing Assets - Depreciation, depletion and amortisation

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

iv) Decommissioning

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

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

(b) Non-oil and gas assets

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

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

Leasehold and buildings - 20 years

Plant and equipment - 4 years

Other - 4 years

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

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

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

Impairment of non-financial assets

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

Inventories

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

Materials and supplies used mainly in drilling wells, recompletion and workovers 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. The Group considers the following as indicators of impairment:

· Collectability is in doubt

· Age of the receivable

· Cashflow position of the debtor

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

Trade payables

Trade payables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method.

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/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.

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 from the sale of goods is recognised when it is probable that future economic benefits will flow to the entity and when specific criteria have been met. 

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

Other income is recognised when earned unless collectability is in doubt.

Borrowings

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

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

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

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

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.

Available-for-sale non-financial assets (or disposal Groups) held-for-sale

Available-for-sale non-financial assets (or disposal Groups) classified as held-for-sale are measured at the lower of carrying amount and fair value less costs to sell. Available-for-sale non-financial assets and disposal Groups are classified as held or 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 of Management 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 Country Manager, 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. Items presented as exceptional are material items of income or expense that have been shown separately due to the non-recurring nature and the significance of their nature or amount.

2 Financial Risk Management

 Financial risk factors

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

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

(a) Market risk

(i) Foreign exchange risk

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

At 31 December 2016, if the functional currency had weakened/strengthened by 10% against the US dollar with all other variables held constant, post- tax(loss)/profit for the year would have been $0.8 million (2015: $1.0 million) lower/higher, mainly as a result of foreign exchange gain/losses on translation of US dollar-denominated borrowings and sales.

(ii) Price risk

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

At 31 December 2016, if commodity prices had been 20% higher/lower with all other variables held constant, post-tax (loss)/profit for the year would have been $7.0million (2015: $10.0million) lower/higher.

 (iii) Cash flow and fair value interest rate risk

The Group's main interest rate risk arises from borrowings which expose the Group to cash flow interest rate risk. The Group manages risk by limiting the exposure to floating interest rates and maintain a balance between floating and fixed contract rates.

At 31 December 2016, if interest rates on foreign currency-denominated borrowings had been 1% higher/lower with all other variables held constant, post-tax (loss)/profit for the year would have been $0.1 million (2015: $0.1 million) lower/higher, mainly as a result of higher/lower interest expense on floating rate borrowings.

(b) Credit risk

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

All sales are made to a state-owned entity - Petrotrin and management assesses risk based on the credit quality of the customer, their financial position and past experience. The compliance with credit terms are monitored regularly by management.

(c) Liquidity risk

Prudent liquidity risk management implies maintaining sufficient cash and short-term funds and the availability of funding through an adequate amount of committed credit facilities. Management monitors rolling forecasts of the Group's liquidity and cash and cash equivalents on the basis of expected cash flow. At the end of the year the Group was facing liquidity issues over its current liabilities which include borrowings, accounts payable, accruals and taxes. The Groups' revenues have decreased considerably as a result of a continued decline in oil prices impacting the main source of revenue generation. Subsequent to the year end the Group was able to favorably improve its liquidity position. Management refers to the disclosures in 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.

Note: There were no items in (i) and (ii) which were classified between 2 and 5 years

(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 2016 the Citibank debt covenants were in default (note 15). However the Group was operating under the Proposal which prevented any creditor from issuing a winding up order. Subsequent to the year end the Group utilised certain strategies to ensure capital was available to meet its operating obligations. See note 1 on Going Concern.

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

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

1 Under the terms of the borrowing facilities the Group is required to comply with certain financial covenants which were breached in 2015 and 2016 resulting in the loan being classified to "current". See note 15.

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

The preparation of the financial statements requires the use of accounting estimates which, by definition, seldom equal the actual results. Management also exercise judgement in applying the Group's accounting policies. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below:

(a) Income taxes

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

(b) Recoverability of deferred tax assets

Deferred tax assets mainly arise from tax losses and are recognised only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse, and a judgement as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the level of deferred tax assets recognised which can result in a charge or credit in which the change occurs. The Group has concluded that the deferred tax asset recognised will be recoverable using approved business plans and budgets for the specific subsidiaries that the deferred tax asset arose.

(c) Provision for decommissioning costs

This provision is significantly affected by changes in technology, laws and regulations which may affect the actual cost of decommissioning to be incurred at a future date. The estimate is also impacted by the discount rates used in the provisioning calculations. The discount rates used are the Group's risk-free rate and the core inflation rate applicable to the local market. The provision has been estimated using a discount rate of 3.9% (2015: 3.9%) and a core inflation rate of 3% (2015: 3%). The impact in 2016 of a 1% 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's reserve estimates are also evaluated periodically by independent external reserve evaluators, the last independent external reserve valuation was done in 2012. The Group estimated its own commercial reserves in 2015 and 2016 based on information compiled by appropriately qualified persons relating to the geological and technical data on the size, depth, shape and grade of the hydrocarbon body and suitable production techniques and recovery rates. 

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

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

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

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

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

During 2016 all subsidiaries onshore and offshore 2P reserve estimates were re-evaluated by management and approved by the Board of Directors.

(e) Farm outs and lease operatorship agreements

The Group financial statements are prepared on the assumption that its farmout and lease operatorship agreements 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 arm's length offers and an estimate of the timing and amount of cash flows expected respectively to arise from the cash generating unit (CGU). A CGU represents an individual field or asset held by Trinity.

During 2016 an impairment charge was recognised on the Group's property, plant and equipment of $2.4 million (2015: $2.6 million) see note 5, resulting in the carrying amount of the respective CGUs being written down to their recoverable amount.

(i) Oil and Gas Assets $ 1.1 million impairment

As part of this assessment, management has carried out an impairment test on the oil and gas assets classified as property, plant and equipment. This test compares the carrying value of the assets at the reporting date with the recoverable amount for each CGU. The recoverable amount is the higher of the Fair Value Less Costs of Disposal ("FVLCOD") and value in use ("VIU"). The FVLCOD is the amount that a market participant would pay for the CGU less the cost disposal or utilising a discounted cash flow approach to FVLCOD. The FVLCOD approach utilised a discounted cash flow based on the proved and probable (2P) reserve estimates of the CGUs of the Group. The FVLCOD calculations, the period over which management has projected its cash flow forecast, ranges between an 8-17 year economic lives based on the reserve limit profile. For the discounted cash flows to be calculated, management has used a production profile based on its best estimate of proven and probable reserves of each CGU and a range of assumptions, including an external oil and gas price profile and a discount rate which, taking into account other assumptions used in the calculation, management considers to be reflective of the risks.

The discounted cash flow approach assessment involves judgement as to the likely commerciality of the asset; its 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 CGUs; and a discount rate utilised for the purposes of deriving a recoverable value.

The forward price curve used was as follows:

If the price deck used in the impairment calculation had been 10% lower than management's estimates at 31 December 2016, the Group would have an increase of $0.7 million in impairment of Oil and Gas assets (2015: nil). If the price deck used in the impairment calculation had been 10% higher than management's estimates at 31 December 2016, the Group would have had a decrease of $0.6 million in impairment of Oil and Gas assets in 2016 (2015: nil).

If the estimated cost of capital of 10% (2015: 10%) used in determining the post-tax discount rate for the CGUs had been 1% lower than management's estimates the Group would have had $0.1 million increase in its impairment for 2016 (2015: nil) against Oil and Gas assets within property, plant and equipment. If the estimated cost of capital had been 1% higher than management's estimates the Group would have had a $0.03 million decrease in its impairment charge in 2016 (2015: nil).

(ii) Slant Rig $1.3 million (2015: nil) impairment.

The Slant Rig is a unique asset specially designed to drill slanted wells on the East Coast Trintes field. The Slant Rig was last utilised by the Group in 2013-14 for offshore drilling on the Trintes field. An impairment test was carried out in 2016 and the Slant Rig was impaired as the recoverable amount was deemed lower than the carrying amount. The recoverable amount was determined using a fair value less cost to sell estimate provided by a third party.

(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 not evaluated until reserves can be appraised.

In 2016 an impairment review was carried out and there were no further impairments losses realised against the carrying values of the Group's exploration and evaluation assets (2015: $0.1 million).

(i) Provision for restructuring

In 2015, management was required to make assumptions in respect of the assessment used to arrive at the restructuring costs. The provision for restructuring of $1.9 million included the cost of severance and redundancies in accordance with the laws of Trinidad and Tobago where the restructuring was expected to take place. However, in 2016 there was a release of the provision for restructuring as the restructuring was not realised in 2016.

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 Petrotrin. All non-current assets of the Group are located in Trinidad & Tobago.

5 Property, Plant and Equipment

Note (1): An impairment loss of $2.4 million was recognised in respect of several CGUs, (see note 3 (g), (2015: $2.6 million) as a result of the carrying value being higher than the recoverable amount. The recoverable amount was determined by utilising its fair value less costs of disposal.