Preliminary Results

RNS Number : 5848N

Trinity Exploration & Production

10 May 2018

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 2017. Disciplined focus over the period resulted in a substantial increase in operating earnings and the continued strengthening of the balance sheet.

Key Performance Indicators

	FY 2017	FY 2016	Change (%)
Average realised oil price¹ (USD/bbl)	48.6	39.4	23
Average net production (bopd)	2,519	2,542	(1)
Operating earnings² (USD MM)	11.0	6.2	77
Operating earnings³ (USD/bbl)	12.0	6.7	77
Operating margin⁴ (%)	24.3	17.6	39
Consolidated operating break-even⁵ (USD/bbl)	30.9	29.3	6
Cash balance (USD MM)	11.8	7.6	55
Net cash/ (debt) (USD MM)⁶	0.1	(38.6)	100

1. Realised price: Actual price received for crude oil sales per bbl. A discount is normally applied to the West Texas Intermediate ("WTI") price by the Petroleum Company of Trinidad and Tobago ("Petrotrin") to derive the realised price received by Trinity

2. Operating earnings (USD MM): Revenues less Royalties less Production Costs ("Opex") less General and & Administrative Expenses ("G&A") less Other Expenses (Crude oil derivatives)

3. Operating earnings (USD/bbl): Operating earnings/ Annual production

4. Operating margin (%): Operating earnings/ Revenues

5. Consolidated operating break-even: The realised price where Operating Earnings for the entire Group is equal to zero

6. Net cash/ (debt): Current assets less Convertible Loan Notes ("CLNs") less Trade and other payables less Taxation payable less Derivative financial instrument (CLNs and Ministry of Energy and Energy Industries of Trinidad & Tobago ("MEEI") is face value of debt, including accrued interest)

Financial Highlights

· Maintenance of a low operating break-even and high operating margin production

o Highly profitable in the current oil price environment while resilient to lower oil prices

· Operating earnings increased 77% to USD 11.0 million (2016: USD 6.2 million)

· Operating margin of 24.3% (2016: 17.6%) or USD 12.0/bbl (2016: USD 6.7/bbl)

· Balance sheet significantly strengthened with increased cash and reduced debt

· Accelerated payments to the Board of Inland Revenue of Trinidad & Tobago ("BIR") and MEEI with outstanding balances of USD 5.9 million at the period end

Operational Highlights

· Work programme included a combination of; 37 Recompletions ("RCPs") (2016: nil), 97 well work overs (WOs) inclusive of the reactivation of idle wells (2016: 63) and the resumption of onshore swabbing activities

o Delivering this activity set during H2 resulted in production growth of 10% in H2 2017 (2,641 bopd) when compared to H1 2017 (2,397 bopd)

· Identified extensive RCP inventory and new infill well drilling locations across asset portfolio

· Increased Onshore 2P reserves by 50% to 5.98 mmstb (million stock tank barrels) (2016: 3.98 mmstb)

· Total Onshore and Offshore 2P reserves estimated to be 23.21 mmstb at the end of 2017, a 9% increase compared to the year-end 2016 reserve estimate of 21.25 mmstb, and 2C reserves estimated to be 23.98 mmstb at the end of 2017, a 14% increase to the year-end reserve estimate of 21.06 mmstb.

Corporate Highlights

· Completion of refinancing and share capital restructuring

· Strengthening of Board, with appointment of Jeremy Bridglalsingh (Executive), David Segel (Non-Executive), Angus Winther (Non-Executive) and James Menzies (Non-Executive)

o Complementary backgrounds and skillsets provide Trinity with appropriate industry and capital markets experience to support continuing efforts to grow the Company

Post Period End Highlights

· Production and resultant cash generation remains on an upward trajectory

o Production average of 2,721 bopd as at the end of Q1 2018

· Recommenced onshore drilling

o Two new infill development wells drilled in Q1 and on production during Q2 2018

o Plan to continue to deliver further production growth over a largely fixed operating cost base enabling sustained high netbacks with robust cash conversion

· Reduced debt and strong cash position of USD 12.2 million as at 31 March 2018

· BIR and MEEI outstanding balances payable reduced to USD 4.2 million as at 31 March 2018, USD 3.6 million less than the amount envisaged under the ratified payment plan

Bruce Dingwall CBE, Executive Chairman of Trinity, commented:

"2017 was a year that was characterised by the stabilisation of production and the building of well inventory in H1 and a return to production growth in H2. Our low-cost production model has underpinned a significant increase in operating profits, affording the Company the opportunity to accelerate debt repayment whilst also increasing cash balances. The combination of our strong balance sheet and proven ability to grow production ensures that the Company is well placed to realise further value in 2018 and beyond."

All figures for the financial year 2017 are audited. Q1 2018 figures are unaudited. The Board currently expects to publish its annual report and accounts for the year to 31 December 2017 before the end of May 2018, with the Annual General Meeting ("AGM") expected to take place during June 2018.

Enquiries:

Trinity Exploration & Production Bruce Dingwall CBE, Executive Chairman Jeremy Bridglalsingh, Chief Financial Officer	Tel: +44 (0) 131 240 3860
SPARK Advisory Partners Limited (NOMAD & Financial Adviser) Mark Brady Miriam Greenwood Andrew Emmott	Tel: +44 (0) 203 368 3550
Cantor Fitzgerald Europe (Broker) David Porter Nick Tulloch	Tel: +44 (0) 207 894 7000
Whitman Howard Limited (Equity Adviser) Nick Lovering	Tel: +44 (0) 207 659 1234
Walbrook PR Limited Nick Rome	trinityexploration@walbrookpr.com or Tel: +44 (0) 207 933 8780

About Trinity (www.trinityexploration.com)

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 2017 was 23.2 mmstb. Group 2C contingent resources are estimated to be 24.0 mmstb. The Group's overall 2P plus 2C volumes are therefore 47.2 mmstb.

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

Executive Chairman's Statement

Strategy

Trinity's aim is to position itself as the leading independent producer in T&T and on the Alternative Investment Market ("AIM"). To achieve this, our strategy is simple; to retain the integrity of the core producing proved and probable ("2P") reserves base, to continue to grow production safely and efficiently to deliver profitable returns and to prudently convert our significant contingent ("2C") resources to 2P reserves and future inventory.

Platform for growth and profitability established

Trinity's focus over the last 3 years has been on preserving the integrity of our producing asset base whilst improving operational practices and efficiencies that enabled the Company to materially re-base costs. The dramatic positive change in the cost structure of the business and the return to sustained operating profitability meant that the financial impact of the improvement in crude oil prices has been material for the financial year 2017. More importantly, as we go into 2018 and return to more proactive investment activities, the financial impact of new production growth should be even more significant.

The 2017 work programme included a combination of: 37 RCPs (2016: nil), 97 WOs inclusive of reactivations (2016: 63) and Onshore swabbing activities with the majority of activity taking place during H2. Whilst average production for 2017 was relatively flat at 2,519 bopd (2016: 2,542 bopd), the resulting production growth of 10% in H2 2017 (2,641 bopd) when compared to H1 2017 (2,397 bopd) followed a successful 2017 programme of RCPs (H1: 5 vs H2: 32) and WOs (H1: 44 vs H2: 53). In addition to the increased level of activity, H1 production was also affected by a decline during Q2 2017 as a result of production being shut-in due to the Tropical Storm Bret and the consequential electrical supply disruptions across operations for the month of June 2017.

Thus, 2017 was a year of both the preparation for and delivery of growth with H1 focused on stabilising base production whilst high-grading well based activities to begin deploying growth capital during H2. Both production and resultant cash generation remains on an upward trajectory with the overall result being that decline was arrested and a higher base level of production delivered by the successful RCP and WO programme with average production volumes of 2,777 bopd in Q4 2017.

The financial upshot of our return to growth and the improvement in oil prices has been an increase in operating earnings of 77% to USD 11.0 million (2016: USD 6.2 million) which is the equivalent of USD 12.0/bbl (2016: USD 6.7/bbl). As a result, cash balances at the year-end stood at a solid USD 11.8 million (2016: USD 7.6 million). Amounts due to the Board of Inland Revenue of Trinidad & Tobago ("BIR") and Ministry of Energy and Energy Industries of Trinidad & Tobago ("MEEI") were reduced to USD 5.9 million (H1 2017: USD 10.6 million), USD 3.0 million below the amount envisaged under the ratified repayment plan. Trinity ended the year in a net cash position of USD 0.1 million mainly due to the restructuring of debt in January 2017 and subsequent repayments to the BIR and MEEI (2016: net debt position USD 38.6 million).

While we resumed direct investment 'in the ground', 2017 was also a year when we substantially grew our 2P and 2C reserves by also refocusing resources on desktop subsurface work. This work is continuous and has been particularly successful to date with the identification of the extensive RCP inventory and new infill well drilling locations across the Onshore asset portfolio. A dedicated team worked up an incremental 16 infill drilling locations (2016:12) for reserves to be booked against, and this effort will be continued in 2018 to provide a stream of low risk and high value opportunities. As a result of this renewed focus, the Company's total 2P reserves (Onshore and Offshore) increased to 23.21 mmstb (9% increase vs 2016: 21.25 mmstb), despite total production of 0.92 mmstb, and our 2C reserves increased to 23.98 mmstb (14% increase vs 2016: 21.06 mmstb) , taking our total reserves and resources to 47.18 mmstb at 31 December 2017 (12% increase vs 2016: 42.31 mmstb).

Of particular note is the increase in Onshore 2P reserves by 45% to 5.78 mmstb (2016: 3.98 mmstb). This is all the more impressive as these reserves stand at post-production of 0.49 mmstb for 2017, which is testament to the quality of our Onshore portfolio.

The quantum and quality of the RCP inventory enabled us to grow production during H2 2017 and into 2018 via these relatively low cost/high return activities. The identification of new infill well locations will allow for further drilling and production growth during 2018.

Plans for 2018 and beyond

We see a number of options for further value creation across Trinity's asset base. Our programme of phased and risk mitigated development activities through routine RCPs, WOs, reactivations and swabbing on the current well stock has succeeded in arresting decline and provided for a return to production growth. More importantly, Trinity resumed drilling Onshore with two infill wells being drilled early in Q1 2018, production from which commenced in Q2 2018.

The current year has started positively with a year to date production average of 2,721 bopd as at the end of Q1 2018. The Company intends to build on this level of base production to reach a targeted annual average production range of 2,800 - 3,000 bopd for 2018. This is achievable under the current fiscal regime with the already completed two infill wells and the successful continuation of the RCP programme, WOs, reactivations and Onshore swabbing activities. We plan to continue to build the inventory of additional infill well locations and further investment in the Company's infrastructure is being undertaken, with the expectation of further Onshore drilling later in the year (contingent on the oil price and clarity regarding the future fiscal regime).

On the East Coast, a revised development plan for the TGAL field is being prepared with a view to reducing the capital requirements via a phased and risk-mitigated plan. Rework of the FDP commenced in Q2 2018 with the target of having an updated document resubmitted to the MEEI for approval during 2018. As part of the next stage of development, a geological, geophysical and engineering review of the Trintes infill drilling programme and the Trintes-TGAL and Galeota Ridge development plan is in progress. Well trajectory optimisation for the Trintes infill drilling programme has commenced and Trinity's drilling rig was demobilised to land for inspection and repair.

Management is continuing to examine a range of options regarding the sale of the West Coast assets. In the interim, we continue to pursue infrastructural projects to preserve asset integrity and maintain production levels. These assets continue to generate positive cash flow.

The Company's low consolidated operating break-even level (USD 30.9/bbl) and the hedging programme which was implemented in 2017 combine to provide financial resilience to low oil prices and give confidence that the Company's growth and investment plans can be delivered under a wide range of oil price scenarios. The Company continues to explore various options to strengthen its balance sheet further during 2018, with the intention of i) repaying the remaining amounts due to the BIR and MEEI; ii) redemption of the CLNs, and iii) accelerating the possibility of further Onshore drilling.

The Board of Directors ("Board") remains confident that the growth in high margin production and continued focus on strengthening the balance sheet will deliver excellent returns for shareholders in 2018 and beyond.

Overview

This time last year our aim was to stabilise base production, build well inventory and execute a limited investment programme whilst maintaining a close watch on operating costs and Health, Safety, Security and Environment ("HSSE"). The Company managed to deliver on that initial programme resulting in an increase in operating profits. This safely delivered programme also enabled the Company to accelerate repayment to the BIR and MEEI, with outstanding balances reduced to USD 4.2 million as at 31 March 2018, which is USD 3.6 million ahead of the amount envisaged under the ratified repayment plan.

During 2017 we continued to prioritise HSSE and the well-being of our people while promoting safe behaviours among all stakeholders. The dedication, hard work and expertise required to stabilise, review and return to growth on a portfolio of 1,165 wells (with 182 active wells) across 9 licences and multiple reservoirs has required a huge effort from those involved. For this we remain extremely thankful to our employees and the continued support of our suppliers with whom we look forward to working alongside as we continue to build on, and strengthen relationships with all of our stakeholders.

With a return to Onshore infill drilling in 2018, Trinity will be able to deliver further production growth over a largely fixed operating cost base, leading to improved operating earnings with robust cash conversion. Good governance remains at the core and we remain committed to meeting all of our obligations and delivering our strategy in a responsible and transparent manner.

The strengthening of the Board was undertaken in January 2017, with the appointment of Jeremy Bridglalsingh (Executive) our Chief Financial Officer ("CFO") and David Segel and Angus Winther (Non-Executives). The Board was further strengthened with the appointment of James Menzies (Non-Executive) in June 2017. The result is a Board with complementary backgrounds and skillsets that provides Trinity with the appropriate industry and capital markets experience to support our ongoing efforts to grow.

Jonathan Murphy stepped down from the Board in June 2017 to focus on other interests. His contribution to Trinity has been invaluable during his tenure and we are deeply appreciative of his steadfast support during the challenges faced in previous years.

The Board is confident that the quality and profitability of our underlying assets will deliver excellent returns for shareholders from the execution of our strategy in 2018 and beyond.

KEY PERFORMANCE INDICATORS

The Group was profitable at an operating level throughout 2017 generating operating earnings of USD 11.0 million (2016: USD 6.2 million), yielding a year-end cash balance of USD 11.8 million (2016: USD 7.6 million) and a net cash position of USD 0.1 million (2016: net debt position USD 38.6 million). A summary of the year-on-year operational and financial highlights are set out below:

	FY 2017	FY 2016	Change (%)
Average realised oil price¹ (USD/bbl)	48.6	39.4	23
Average net production (bopd)	2,519	2,542	(1)
Annual production (mmbbls)	0.92	0.92	0
Revenues (USD MM)	45.2	35.3	28
Operating earnings² (USD MM)	11.0	6.2	77
Operating earnings³ (USD/bbl)	12.0	6.7	77
Operating margin⁴ (%)	24.3	17.6	39
Consolidated operating break-even⁵ (USD/bbl)	30.9	29.3	6
Cash balance (USD MM)	11.8	7.6	55
Net cash/ (debt) (USD MM)⁶	0.1	(38.6)	100

1. Realised price: Actual price received for crude oil sales per bbl. A discount is normally applied to the WTI price by Petrotrin to derive the realised price received by Trinity

2. Operating earnings (USD MM): Revenues less Royalties less Opex less G&A less Other Expenses (Crude oil derivatives)

3. Operating earnings (USD/bbl): Operating earnings/ Annual production

4. Operating margin (%): Operating earnings/ Revenues

5. Consolidated operating break-even: The realised price where Operating Earnings for the entire Group is equal to zero

6. Net cash/ (debt): Current assets less CLNs less Trade and other payables less Taxation payable less Derivative financial instrument (CLNs and MEEI is face value of debt, including accrued interest)

2017 Trading Summary

A five-year historical summary of realised price, production, operating break-evens and Opex and G&A expenditure metrics is set out below:

DETAILS	2013	2014	2015	2016	2017
Realised Price (USD/bbl)	91.6	85.8	45.5	39.4	48.6
Production (bopd)
Onshore	2,088	2,005	1,601	1,343	1,347
West Coast	493	491	312	190	212
East Coast	1,110	1,105	983	1,009	961
Consolidated	3,691	3,601	2,896	2,542	2,519

Operating Break-Even (USD/bbl)⁽¹⁾
Onshore	19.0	21.3	23.3	17.4	16.6
West Coast	21.2	24.5	40.7	37.7	26.6
East Coast	69.8	55.9	41.3	26.3	24.9
Consolidated	62.9	64.6	47.4	29.3	30.9

Metrics (USD/bbl)
Opex/bbl - Onshore	12.8	14.4	15.7	11.8	11.1
Opex/bbl - West Coast	17.4	20.2	33.8	31.6	22.1
Opex/bbl - East Coast	52.0	41.6	31.6	20.1	18.9
G&A/bbl - Consolidated	13.8	11.4	9.9	4.5	4.7

1. Operating Break-even: The realised price where Operating Earnings for the respective asset or the entire Group (Consolidated) is equal to zero

Of particular note is that the constituent asset level operating break-evens were further reduced year-on-year as follows:

Onshore	reduced by 5% in 2017 versus 2016 (2016 reduced 25% year-on-year )
West Coast	reduced by 29% in 2017 versus 2016 (2016 reduced 7% year-on-year )
East Coast	reduced by 5% in 2017 versus 2016 (2016 reduced 36% year-on-year )

At the aggregated corporate level the maintenance of such a robust consolidated operating level break-even reflects the following:

· Overall Opex reduced by 6% to USD 14.7 million (2016: USD 15.6 million). This was achieved through various cost efficiency measures including lower East Coast personnel transfer costs and reduced labour costs resulting from the restructuring.

· 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 increased by 2% to USD 4.3 million (2016: USD 4.2 million) and are on target to be sustained around this level; and

· Crude oil derivative costs of USD 1.4 million incurred for the first time.

OPERATIONAL REVIEW

OUR EMPLOYEES

Trinity's workforce stood at 188 at the year-end December 2017 with 78% (146) male and 22% (42) female employees. Our employees are positioned across the United Kingdom and T&T, with the majority (98%) based in T&T at our core operations.

HEALTH, SAFETY, SECURITY & ENVIRONMENT ("HSSE")

Trinity continues to place HSSE at the forefront of our operations as we strive towards further improving our safety performance by ongoing sensitisation, training, increased monitoring, frequent reviews of our internal controls and implementing corrective action when necessary. The Board is fully apprised of the Company's HSSE performance via quarterly updates.

Management's commitment to the See, Think, Act, Reinforce and Track ("START") card programme has positively impacted our HSSE culture. Behaviour based safety has been recognised as an integral factor in our drive to "zero" incident rates. Notable improvements in our HSSE performance were achieved due to our continued emphasis on a strong HSSE culture, facilitated by an increase in Management visits to all assets, increased communication of lessons learnt and several proactive initiatives implemented across all operations. In June 2017, our HSSE performance was recognised by Petrotrin, and we were awarded the Star of Excellence HSE Award for our contribution towards Safety Leadership Engagement.

Trinity was successfully assessed via a Safe to Work ("STOW") T&T Audit in December 2017 and our HSSE Management System was granted a 2 year certification by the Energy Chamber of T&T in February 2018. This system enhances our ability to respond, control and analyse safety events and performance data as well as allows us to be proactive in mitigating and managing risk.

Notwithstanding our 2017 achievements, in 2018 Trinity intends to continue its focus on initiatives to foster further improvement of our HSSE Management System and associated performance.

PRODUCTION

Average net production for 2017 was 2,519 bopd (2016: 2,542 bopd inclusive of GU-1/ 2,519 bopd exclusive of GU-1) (the GU-1 Lease Operatorship was disposed of in May 2016), which represents only a 1% decline in overall average production levels for the year. A total of 37 RCPs and 97 WOs and reactivations and swabbing activities were undertaken during 2017.

Onshore Assets

Current Onshore production is from Lease Operatorship Blocks: FZ-2, WD-2, WD-5/6, WD-13, WD-14 and Farmout Block: Tabaquite.

Average 2017 net production from the Onshore assets was 1,347 bopd which accounted for 54% of total annual average production. The maintenance of year-on-year production averages is reflective of the work programme beginning to impact and successfully arrest reservoir and low activity decline rates. 2016 net Onshore production exclusive of GU-1 (divested May 2016 at a 5-month average of 57 bopd) production was 1,320 bopd which represents a like-for-like increase of 2%.

The drilling programme carded for 2017 initially consisted of 4 new infill wells with the first well anticipated to spud in Q3 2017. However, after further evaluation of our inventory of opportunities, we identified over 200 up-hole resistive (not perforated) sands in the existing wells across the Onshore assets to be screened as potential RCP candidates.

Trinity opted to prioritise the acceleration of its high return on capital RCP programme whilst working to increase and high grade new infill drilling locations. To address the step-change in activities, an additional rig was contracted to target the approved RCPs, whilst our two in-house rigs facilitated both RCPs and routine WOs to arrest reservoir decline rates and grow production. In total 37 RCPs (2016: nil) and 78 WOs and reactivations (2016: 60) and were undertaken across our Onshore fields.

Going forward the Company intends to implement development activities via infill drilling, routine RCPs, WOs, reactivations and swabbing on the current well stock to maintain base production and provide for a return to production growth.

East Coast Asset

Current East Coast production is derived from the Alpha, Bravo and Delta platforms in the Trintes Field.

Average 2017 net production from the East Coast was 961 bopd which accounted for 38% of total annual average production. This represented a 5% decline in production from the 2016 average net production levels of 1,009 bopd. The decrease was largely as a result of electrical outages and subsequent delays in bringing the wells back onto production as well as a one-off production shut-down due to the Tropical Storm Bret in H1 2017.

In 2017, 18 restorative WOs were completed (2016: 2) which contributed to an upward trend in production. In June 2017 Trinity was able to install a sucker rod pumping system on a slanted wellhead in an offshore environment. This was possible through the utilisation of a Mechanical Pumping Hydraulic Unit ("MPHU") on surface and a conventional sucker rod pump downhole. An automated and real-time monitoring system along with a downhole sensor was also installed to aid in the efficient monitoring of the system and the achievement of optimum production. The unit has been operating for over 6 months. Additionally, we were able to reactivate 9 wells via the use of progressive cavity pumps.

Various infrastructure projects were undertaken during 2017 which included the Trintes cranes assessment and recertification works, replacement of the Galeota tank farm fire water pump, installation of additional diesel storage, Alpha crane boom change out, securing the 8" incoming production line and phase 1 (Front-End Engineering Design) of the installation of a new 10,000 bbl oil storage tank at the Galeota tank farm.

Trinity continues to invest in stabilising production levels via better generator maintenance strategies, continued optimisation and review of alternative artificial lift technologies to augment production rates and maintain efficiency and cost effectiveness.

The next stage of development involving an internal geological, geophysical and engineering review of the Trintes infill drilling programme and the Trintes-TGAL and Galeota Ridge development plan is in progress. Well trajectory optimisation for the Trintes infill drilling programme has commenced; and Trinity's drilling rig was demobilised to land for inspection. A revised development plan for the TGAL field is being prepared with a view to reducing the capital requirements via a phased and risk mitigated plan. Rework of the FDP began in Q2 2018 with the view to having an updated document resubmitted to the MEEI for approval during 2018.

West Coast Assets

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

Average 2017 net production from the West Coast was 212 bopd which accounted for 8% of total annual average production. This represented a 12% increase in production from 2016 average levels of 190 bopd. This increase was facilitated by a pipeline change-out programme undertaken in the latter part of Q4 2016 in BM that resulted in sustained production levels.

There were no major production related activities conducted on the West Coast assets in 2017, with the exception of 1 WO (2016: 1) in the PGB field. In 2017, infrastructural works were undertaken on the offshore platforms to maintain asset integrity and production.

On 11 August 2017, Trinity announced that it had entered into a binding Sale and Purchase Agreement ("SPA") to sell its interests in the PGB and BM Exploration and Production Licences and related fixed assets to a subsidiary of AIM quoted Range Resources Limited ("Range") for a cash consideration of USD 4.55 million. On 23 November 2017, Trinity announced that the transaction was unable to complete due to the requisite regulatory approvals not being forthcoming. Management is continuing to examine a range of options regarding the sale of the West Coast assets. In the interim, the assets continue to generate positive cash flow.

Going forward, the land based wells across both the PGB and BM fields will be targeted for reactivations in addition to minor facility upgrades to further increase production. These assets will continue to be closely monitored as progressive steps are taken to also optimise its production through swabbing and minimal well intervention at low operating costs.

RESERVES AND RESOURCES

A comprehensive Management review of all assets has been concluded and has estimated the current 2P reserves to be 23.21 million stock tank barrels ("mmstb") at the end of 2017, compared to the year-end 2016 reserve estimate of 21.25 mmstb. This represents an increase of 1.96 mmstb (9%) from 2016 levels. This increase is despite production for 2017 of 0.92 mmstb (2016: 0.92 mmstb) and is due to updated decline curve analysis on producing wells, low cost well reinstatements in 2017 and, most significantly, extensive subsurface work to generate additional infill drilling, RCP and WO candidates. Management considers this to be the best estimate of the quantity of reserves that will actually be recovered from the accumulation by the assets and represent production which is commercially recoverable, either to licence/relevant permitted extension end or sooner through the application of the economic limit test.

The subsurface review has defined investment programmes and constituent drilling targets to commercialise the reserves as detailed, by asset area, in the table below:

	Unaudited 2017 2P Reserves
Asset	31 December 2016	Production	Revisions	31 December 2017
Net Oil Production	mmstb	mmstb	mmstb	mmstb
Onshore	3.98	(0.49)	2.29	5.78
East Coast	14.68	(0.35)	0.45	14.78
West Coast	2.59	(0.08)	0.14	2.65
Total	21.25	(0.92)	2.88	23.21

The best estimate of contingent resources ("2C") due to the current economic environment and the defining technical work pending is estimated by Management at 23.98 mmstb (2016: 21.06 mmstb).

Unaudited 2017 2C Resources
	31 December 2016	Revisions	31 December 2017
Asset	mmstb	mmstb	mmstb
Onshore	1.00	1.18	2.18
East Coast	19.54	1.33	20.87
West Coast	0.52	0.41	0.93
Total	21.06	2.92	23.98

Unaudited Summary of Reserves and Resources at 31 December 2017

	2P	2C	2P+2C
	Reserves	Resources	Reserves and
Asset	mmstb	mmstb	Resources mmstb
Onshore	5.78	2.18	7.96
East Coast	14.78	20.87	35.65
West Coast	2.64	0.93	3.57
Total	23.20	23.98	47.18

East Coast Hub

On the East Coast, Trinity has an established production hub with 4 offshore marine platforms; (Alpha, Bravo, Charlie & Delta) that have a combined 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 14.78 mmstb therefore represents a low incremental recovery factor of 6%. Within contingent resources a further 6.37 mmstb relate to the Trintes field. Of the 31 conceptual infill targets generated in 2015 from the Petrel model, these have been risked during 2017 to 16 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 14.50 mmstb (gross: 22.30 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).

Trinity decided that once it was in a position to allocate resources, the previously developed TGAL FDP would be revisited with a view to reducing the capital requirements via a more economic topside solution. Rework of the FDP commenced in Q2 2018.

With combined 2P reserves and 2C resources of 35.65 mmstb, the potential production growth from future Trintes drilling and TGAL development is substantial. Within the Galeota anticline licence area there is significant wider prospectivity with 266 mmstb STOIIP having been mapped between the Trintes field and the EG-3 and EG-4 wells.

FINANCIAL REVIEW

2017 results overview

· Growing Margins and increasing profitability

Following the Refinancing and Restructuring in January 2017, the Company focused on growing margins and increasing profitability which have contributed to a low consolidated operating break-even price of USD 30.9/bbl (2016: USD 29.3/bbl). 2017 operating expenses includes the cost of crude oil derivatives (none in 2016) and so a like-for-like comparative for 2017 would have been USD 28.9/bbl excluding crude oil derivatives. Trinity also increased its operating margin (USD/bbl) by 77% to USD 12.0/bbl (2016: USD 6.7/bbl).

· Significantly reduced net debt and strong cash position

The Statement of Financial Position has continued to strengthen at the end of the financial year with a turnaround of the net debt position into a net cash position of USD 0.1 million (2016: net debt USD 38.6 million) and an increase in the cash balance of 55% to USD 11.8 million (2016: USD 7.6 million).

· Acceleration of State creditor repayments

The Company has made repayments to its T&T state creditors ("BIR" and "MEEI") in accordance with the settlement agreements on a quarterly basis and has accelerated payments by a total of USD 3.6 million (BIR: USD 3.5 million & MEEI: USD 0.1MM) as at 31 March 2018.

· Mitigating downside price risk

Crude oil derivatives have been implemented during 2017 to mitigate against downside risk. A put option was purchased in April 2017 covering 31,645 bbls of production per month effective April 2017-March 2018 at a cost of USD 0.6 million (2016: nil) and protected against WTI falling below USD 40.0/bbl. In November 2017 a zero cost collar was entered into, effective January 2018-December 2018 on 25,000 bbls of production per month with a WTI price floor of USD 45.0/bbl and a cap of USD 59.8/bbl. A fair value loss was recognised at the end of 2017 on the zero cost collar and recognised as a derivative financial liability USD 0.8 million (2016: nil).

· Completion of Refinancing and share capital restructuring

The Refinancing 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 Refinancing with costs amounting to USD 1.2 million therefore net proceeds amounted to USD 13.8 million. In order to implement the Refinancing, 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 USD 0.01 each and one deferred share of a nominal value of USD 0.99 each.

· Supplemental Petroleum Taxes ("SPT") and Property Taxes

Q4 2017 saw average oil prices rise above USD 50.0/bbl and SPT of USD 1.5 million (2016: 1.0 million credit) incurred. When realised oil prices are higher than USD 50.0/bbl SPT is charged at a rate of 18% and 26% on Net revenues (Gross revenue - royalties - incentives) on Onshore and Offshore assets respectively. SPT reform has been earmarked by the Government of Trinidad and Tobago ("GORTT"), but has not yet been effected.

A Property Tax was introduced by the GORTT which was potentially applicable for both 2016 and 2017. As a result, a charge of USD 0.5 million (2016: USD 0.6 million) was estimated in 2017. The Property Tax (Amendment) Bill was introduced in the House of Representatives in the Parliament of Trinidad and Tobago, which seeks to make revisions to the Property Tax regime. The amendments provide for a waiver of the 2016 and 2017 property tax liabilities. If, as expected, this bill is passed and assented to in 2018 then this would result in a reduction in Property taxes accrued of USD 1.1 million.

STATEMENT OF COMPREHENSIVE INCOME ANALYSIS

Revenues

2017 crude oil sales revenues were USD 45.2 million (2016: USD 35.3 million). This 28% increase was mainly attributable to a 23% increase in the average realised oil price of USD 48.6/bbl (2016: USD 39.4/bbl).

Operating expenses

Operating expenses increased by 7% in 2017 to USD (41.2) million (2016: USD (38.6) million). Operating expenses comprised:

• Royalties of USD (13.8) million (2016: USD (9.3) million)

• Production costs of USD (14.7) million (2016: USD (15.6) million)

• Depreciation, depletion and amortisation ("DD&A") of USD (7.0) million (2016: USD (9.5) million)

· G&A expense of USD (4.3) million (2016: USD (4.2) million)

• Other expenses of USD (1.4) million (2016: nil). This includes the cost of crude oil derivatives implemented during 2017 comprising put options USD (0.6) million and zero cost collar USD (0.8) million

SPT and other taxes

· Supplemental Petroleum Tax of USD (1.5) million (2016: USD 1.0 million credit)

• Property Tax of USD (0.5) million (2016: USD (0.6) million)

Exceptional items

Exceptional items of USD 25.7 million (2016: USD (1.7) million) comprised:

• Restructuring USD 26.3 million credit (2016: USD (1.5) million)

• Impairments USD (0.6) million (2016: USD (3.6) million)

• Provisions USD nil (2016: USD 2.4 million)

• Gain on disposal of GU-1 asset USD nil (2016: USD 1.0 million)

See Note 7 to Consolidated Financial Statements - Exceptional items for further details.

The Group's operating profit after exceptional items was USD 27.6 million (2016: USD 4.6 million loss).

Net Finance Costs

In 2017, finance costs amounted to USD (2.3) million (2016: USD (4.7) million) and comprised:

• Unwinding of the decommissioning liability USD (1.6) million (2016: USD (1.6) million)

· Interest on taxes nil (2016: USD (2.2) million)

· Interest on loans: USD (0.7) USD million: (2016: USD (0.9) million)

- Interest accrued on the convertible loan note USD (0.6) million (2016: nil)

- Interest expense on loan facilities from Citibank (Trinidad & Tobago) Limited USD (0.04) million (2016: USD (0.9) million)

- Effective interest on financial liability USD (0.04 million) (2016: nil)

See Note 8 to Consolidated Financial Statements - Finance Costs for further details

Income Tax Expense

Taxation credit for 2017 of USD 0.03 million (2016: USD 1.9 million), and its components are described below.

• Petroleum Profits Tax ("PPT") credit USD 0.9 million (2016: (1.5) million)

• Reduction in Deferred Tax Asset ("DTA") for the year was as a result of tax losses de-recognised USD (1.3) million (2016: credit of USD 3.0 million DTA recognised)

· Reduction in Deferred Tax Liabilities ("DTL") for the year was as a result of accelerated tax depreciation credit of USD 0.4 million (2016: credit of USD 0.4 million)

• Unemployment levy ("UL") USD credit of 0.03 million (2016: USD nil)

See Note 9 to Consolidated Financial Statements - Income Tax Expense for further details

CONSOLIDATED STATEMENT OF CASH FLOWS ANALYSIS

Cash inflow from operating activities

Cash inflows from operating activities were USD 9.6 million (2016: USD 9.0 million) following adjustments for:

• Operating activities resulted in an adjusted profit before tax of USD 8.7 million (2016: USD 8.0 million)

• Changes in working capital comprised of a net cash inflow of USD 0.9 million (2016: USD 2.6 million inflow) excluding amounts paid to unsecured creditors of USD (3.9) million and T&T state creditors of (8.8) million under the Restructuring

• Taxation paid nil (2016: USD (1.6) million outflow)

Cash outflow; change in working capital relating to the Restructuring

Working capital cash outflows relating to the Restructuring amounted to USD (12.7) million comprising:

• Payments T&T State Creditors: USD (7.7) million to the BIR and USD (1.1) million to MEEI

• Payments of USD (3.9) million to the Group's Unsecured Creditors

Cash outflow from investing activities

Cash outflow from investing activities was USD (3.1) million (2016: USD (0.3) million), which was comprised of:

• Expenditure on Property, Plant and Equipment for the year was USD (2.8) million (2016: USD (0.3) million) which mainly included recompletions and infrastructure upgrades

• Purchase of Intangible assets (0.3 million) (2016: USD nil) in the form of a new finance software package

Cash inflow from financing activities

Cash inflow from financing activities was USD 10.4 million (2016: USD (6.2) million outflow) as a result of the Refinancing and Restructuring:

• Proceeds from the issue of shares (net of costs) USD 10.9 million (2016: nil)

• Proceeds from the issue of convertible loan note (net of costs) USD 3.0 million (2016: nil)

• Settlement of the compromised Citibank loan of USD (3.5) million (2016: USD (3.1) million)

• Finance costs nil (2016: USD (3.2) million)

See Note 25 to the Consolidated Financial Statements - Borrowings for further details.

See Note 8 to the Consolidated Financial Statements - Finance Costs for further details.

NET CASH/ (DEBT) CALCULATION

At 31 December 2017 the Group showed a net cash position of USD 0.1 million (audited 2016: USD 38.6 million net debt position) based on Management's view. The turnaround from the net debt position on a year-on-year basis to a net cash position was a result of the Refinancing and Restructuring of the Group's Statement of Financial Position and the Group's strong cash flow generation during the year which have enabled it to accelerate repayments under the ratified payment plan.

Statement of Financial Position Extract	FY 2017	FY 2017	FY 2016	FY 2016
Statement of Financial Position Extract	USD MM	USD MM	USD MM	USD MM
	Unaudited	Audited²	Unaudited	Audited
	Mgmt. View¹	Audited²	Pro forma	Audited
Current Assets
Cash and cash equivalents	11.8	11.8	11.9	7.6
Trade and other receivables	5.2	5.2	4.8	5.5
Inventories	3.8	3.8	3.8	3.8
A: Total Current Assets	20.8	20.8	20.5	16.9

Liabilities
Non-current
Trade and other payables	1.0	0.9	9.4	-
Convertible loan note	7.0	3.0	6.6	-
Total Non-Current Liabilities³	8.0	3.9	16.0	-

Current
Trade and other payables	10.2	10.1	6.7	42.8
Taxation payable	1.7	1.7	2.7	2.7
Derivative Financial Instrument	0.8	0.8	-	-
Borrowings	-	-	-	10.0
Total Current Liabilities⁴	12.7	12.6	9.4	55.5
B: Total Liabilities^3,4	20.7	16.5	25.4	55.5

(A-B): Net cash/(debt)	0.1	4.3	(4.9)	(38.6)

Notes:

1. Based on the face value of the CLN and MEEI liabilities (including accrued interest) as opposed to amortised cost stated in the Financials

2. Based on the amortised cost of the CLN and MEEI liabilities as stated in the Financials (see Notes 27 and 24 to the Financial Statements)

3. Non-Current Liabilities excludes DTL & Provision for other liabilities

4. Current Liabilities excludes Provision for other liabilities

During 2017, the Group made payments of USD 3.5 million to Citibank, USD 7.7 million to the BIR, USD 1.1 million to the MEEI and USD 3.9 million to unsecured creditors in accordance with the various settlement agreements forming part of the Restructuring and Refinancing.

As at 31 December 2017, the remaining amounts outstanding to the BIR and MEEI under the ratified repayment plans were USD 5.0 million and USD 0.9 million respectively.

Trinity Exploration & Production Plc

Consolidated Statement of Comprehensive Income

For the year ended 31 December 2017

(Expressed in United States Dollars)

	Note	2017	2016
			(Restated¹)
		$'000	$'000
Operating Revenues
Crude oil sales		44,957	35,303
Other income		210	--
		45,167	35,303

Operating Expenses
Royalties		(13,755)	(9,326)
Production costs		(14,737)	(15,569)
Depreciation, depletion and amortisation	12	(7,055)	(9,539)
General and administrative expenses		(4,326)	(4,154)
Other expenses		(1,362)	--
		(41,235)	(38,588)

Operating Profit/(Loss) Before SPT and Property Taxes		3,932	(3,285)

Supplemental petroleum taxes		(1,533)	951
Property taxes		(497)	(603)


Operating Profit/(Loss) Before Exceptional Items		1,902	(2,937)

Exceptional Items	7	25,718	(1,675)


Operating Profit/(Loss)		27,620	(4,612)

Net finance costs	8	(2,300)	(4,733)

Profit/(Loss) Before Taxation		25,320	(9,345)

Taxation credit	9	28	1,878

Profit/(Loss) for the period		25,348	(7,467)

Other Comprehensive Income/(Expense)
Items that may be subsequently reclassified to profit or loss
Currency translation		74	(112)

Total Comprehensive Income/(Expense) For The Year		25,424	(7,579)

Earnings per share (expressed in dollars per share)
Basic	10	0.09	(0.08)
Diluted	10	0.06	(0.08)

^{1 see note 5 for restatement}

Trinity Exploration & Production Plc

Consolidated Statement of Financial Position

at 31 December 2017

(Expressed in United States Dollars)

	Note	2017	2016
			(Restated¹)
ASSETS		$'000	$'000

Non-current Assets
Property, plant and equipment	12	52,450	59,632
Intangible assets	13	25,591	25,406
Abandonment fund	14	1,650	1,072
Performance bond	15	253	--
Deferred tax assets	16	4,179	5,496
		84,123	91,606
Current Assets
Inventories	17	3,766	3,787
Trade and other receivables	18	5,155	5,449
Cash and cash equivalents	19	11,792	7,615
		20,713	16,851
Total Assets		104,836	108,457

Equity and liabilities

Capital and Reserves Attributable to Equity Holders
Share capital	20	96,676	94,800
Share premium	20	125,362	116,395
Share warrants	21	--	71
Other equity	24	590	--
Share based payment reserve	22	12,553	12,244
Merger reserves	23	75,467	75,467
Reverse acquisition reserve	23	(89,268)	(89,268)
Translation reserve		(1,678)	(1,997)
Accumulated losses		(171,112)	(196,460)
Total Equity		48,590	11,252

Non-current Liabilities
Trade and other payables	27	881	--
Convertible loan notes	24	3,019	--
Deferred tax liabilities	16	2,538	2,927
Provision for other liabilities	26	37,151	38,318
		43,589	41,245
Current Liabilities
Trade and other payables	27	10,092	42,799
Provision for other liabilities	26	115	470
Derivative financial instruments	29	762	--
Borrowings	25	--	9,950
Taxation payable	30	1,688	2,741
		12,657	55,960
Total Liabilities		56,246	97,205
Total Equity and Liabilities		104,836	108,457

^{1 see note 5 for restatement}

Trinity Exploration & Production Plc

Company Statement of Financial Position

at 31 December 2017

(Expressed in United States Dollars)


	Note	2017	2016
ASSETS		$'000	$'000

Non-current Assets
Investment in subsidiaries	11	51,416	44,802

Current Assets
Trade and other receivables	18	89	813
Intercompany	18	2,447	1,857
Cash and cash equivalents	19	6,024	758
		8,560	3,428
Total Assets		59,976	48,230

Equity and liabilities
Capital and Reserves Attributable to Equity Holders
Share capital	20	96,676	94,800
Share premium	20	125,362	116,395
Other equity		590	--
Share based payment reserve		1,853	1,544
Merger reserves		56,652	56,652
Accumulated losses		(225,459)	(222,235)
Total Equity		55,674	47,156


Non - Current Liabilities
Convertible loan notes	24	3,019	--


Current Liabilities
Trade and other payables	27	521	739
Derivative financial instruments	29	762	--
Intercompany		--	335
		1,283	1,074
Total Liabilities		4,302	1,074
Total Equity and Liabilities		59,976	48,230

Trinity Exploration & Production Plc

Consolidated Statement of Changes in Equity

for the year ended 31 December 2017

(Expressed in United States Dollars)

Year ended 31 December 2016	Share Capital	Share Premium	Other Equity	Share Warrants	Share Based Payment Reserve	Reverse Acquisition Reserve	Merger Reserves	Translation Reserve	Accumulated Losses	Total Equity
	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000

At 1 January 2016	94,800	116,395	--	71	12,178	(89,268)	75,467	(557)	(188,993)	20,093
Share based payment charge (Note 22)	--	--	--	--	66	--	--	--	--	66
Restated ( See Note 5)	--	--	--	--	--	--	--	--	(603)	(603)
Translation difference	--	--	--	--	--	--	--	(1,328)	--	(1,328)
Total comprehensive expense for the period	--	--	--	--	--	--	--	(112)	(6,864)	(6,976)

At 31 December 2016 restated	94,800	116,395	--	71	12,244	(89,268)	75,467	(1,997)	(196,460)	11,252

At 1 January 2017	94,800	116,395	--	71	12,244	(89,268)	75,467	(1,997)	(196,460)	11,252
Other equity net of transaction cost	--	--	590	--	--	--	--	--	--	590
Issue of shares	1,876	8,967	--	--	--	--	--	--	--	10,843
Share based payment charge (Note 22)	--	--	--	--	309	--	--	--	--	309
Share warrants expired	--	--	--	(71)	--	--	--	--	--	(71)
Translation difference	--	--	--	--	--	--	--	246	--	246
Total comprehensive income for the period	--	--	--	--	--	--	--	73	25,348	25,421

At 31 December 2017	96,676	125,362	590	--	12,553	(89,268)	75,467	(1,678)	(171,112)	48,590

Trinity Exploration & Production Plc

Company Statement of Changes in Equity

for the year 31 December 2017

(Expressed in United States Dollars)

	Share Capital	Share Premium	Other Equity	Share Based Payment Reserve	Merger Reserves	Accumulated Losses	Total Equity
	$'000	$'000	$'000	$'000	$'000	$'000	$'000
Year ended 31 December 2016

At 1 January 2016	94,800	116,395	--	1,505	56,652	(218,234)	51,118
Share based payment charge	--	--	--	39	--	--	39
Total comprehensive expense for the year	--	--	--	--	--	(4,001)	(4,001)
At 31 December 2016	94,800	116,395	--	1,544	56,652	(222,235)	47,156

At 1 January 2017	94,800	116,395	--	1,544	56,652	(222,235)	47,156
Other equity net of transaction costs	--	--	590	--	--	--	590
Issue of ordinary shares	1,876	8,967	--	--	--	--	10,843
Share based payment charge	--	--	--	309	--	--	309
Total comprehensive expense for the year	--	--	--	--	--	(3,224)	(3,224)

At 31 December 2017	96,676	125,362	590	1,853	56,652	(225,459)	55,674

Trinity Exploration & Production Plc

Consolidated Statement of Cash Flows

for the year ended 31 December 2017

(Expressed in United States Dollars)

	Note	2017	2016
		$'000	$'000
Operating Activities			(Restated)
Profit/(Loss) before taxation		25,320	(9,345)
Adjustments for:
Translation difference		(663)	2,275
Finance cost - loans and interest	8	579	3,156
Share based payment charge	22	235	66
Finance cost - decommissioning provision	26	1,643	1,577
Depreciation, depletion and amortisation	12	7,055	9,539
Gain on disposal of assets		--	(954)
Impairment of property, plant and equipment	12	--	2,420
Release of provision for restructuring		--	(1,870)
Release of provision for claim		--	(1,218)
Provisions recorded		--	712
Impairment of receivables		348	1,071
Impairment of inventory		264	--
Impairment of payables		--	(157)
Gain on extinguishment of financial liabilities		(210)	--
Unsecured creditors' claims		--	697
Fair value zero cost collar		762	--
Compromised creditor balances		(26,672)	--
		8,661	7,969
Changes In Working Capital
Inventories	17	(243)	26
Available for-sale non-financial assets		--	1,896
Trade and other receivables	18	(887)	(746)
Trade and other payables	27	2,023	1,393
Restructuring (Unsecured Creditors)		(3,857)	--
State creditors (BIR and MEEI)		(8,775)	--
		(11,739)	2,569
Taxation paid		--	(1,551)
Net Cash (Outflow)/Inflow From Operating Activities		(3,078)	8,987

Investing Activities
Purchase of computer software	13	(250)	--
Purchase of property, plant and equipment	12	(2,868)	(266)
Net Cash Outflow From Investing Activities		(3,118)	(266)

Financing Activities
Finance costs		--	(3,156)
Issue of shares (net of costs)	20	10,843	--
Issue of Convertible loan notes (net of costs)	24	3,030	--
Repayment of borrowings	25	(3,500)	(3,050)
Net Cash Inflow/ (Outflow) From Financing Activities		10,373	(6,206)
Increase in Cash and Cash Equivalents		4,177	2,515
Cash And Cash Equivalents
At beginning of year		7,615	8,200
Less funds held for abandonment		--	(3,100)
Increase in cash and cash equivalents		4,177	2,515
At end of year	19	11,792	7,615

Trinity Exploration & Production Plc

Company Statement of Cash Flows

for the year ended 31 December 2017

(Expressed in United States Dollars)

	Note	2017	2016
		$'000	$'000

Operating Activities
Loss before taxation		(3,161)	(4,259)
Adjustments for:
Translation differences		69	78
Finance income		(270)	(289)
Finance cost		579	12
Share based payment charge		91	39
Fair value zero cost collar		762	--
Impairment intragroup loan		--	4,014
Compromised creditor balances		446	--
		(1,484)	(405)

Changes In Working Capital
Trade and other receivables		134	5,246
Trade and other payables		(553)	(2,958)
		(419)	2,288

Taxation Paid		--	(1,402)

Net Cash (Outflow)/Inflow from Operating Activities		(1,903)	481

Financing Activities
Finance income		270	289
Finance cost		(579)	(12)
Capital contributed to subsidiary	11	(6,395)	--
Issue of shares (net of costs)	20	10,843	--
Issue of Convertible loan notes (net of costs)	24	3,030	--

Net Cash Inflow from Financing Activities		7,169	277

Increase In Cash And Cash Equivalents		5,266	758

Cash And Cash Equivalents
At beginning of year		758	--
Increase in cash and cash equivalents		5,266	758


At end of year	19	6,024	758

Trinity Exploration & Production Plc

Notes to the Consolidated Financial Statements

31 December 2017

(Expressed in United States Dollars)

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 ("TEPUKL"), a Company incorporated in Scotland, through a reverse acquisition. Bayfield changed its name to Trinity Exploration & Production plc and the enlarged group was re-admitted to trading on AIM. 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 $3.2 million (2016 $4.0 million loss).

Going Concern

In making their going concern assessment, the Board 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 overheads. At the 31 December 2017, the Group had net current assets of $8.1 million, compared to 2016, where the Group had a net current liability of $39.1 million.

On the 11 January 2017, the Group was able to secure a refinancing solution enabling the Company to retire its existing senior debt facility, reduce outstanding payables to unsecured trade creditors, significantly modify repayment terms to state creditors namely the Board of Inland Revenue ("BIR") and the Ministry of Energy and Energy Industries ("MEEI") and raise additional capital through the issuing of ordinary shares and Convertible Loan Notes ("CLNs"). As part of the refinancing, significant balances were compromised with the senior debt holder and with the Group's unsecured creditors in accordance with the senior debt settlement and unsecured creditor settlement agreements.

Subsequent to the refinancing the Group meets its day-to-day working capital requirements through revenue generation and positive operating cash flows. The Group's forecast and projections, taking account of reasonable possible changes in oil price and sales volume, show that the Group should be able to operate within the level of its current cash resources. Should there be a down turn in the oil prices within the industry the Board of Directors and Management have a number of actions within control that can be effected. These include deferral of its capital expenditure spend and further reducing operating costs to manageable levels. For these reasons, the Board of Directors have a reasonable expectation that the Group has adequate resources to continue operational existence for the foreseeable future. The Group therefore continues to adopt the going concern basis of preparing the financial statements.

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 has carefully considered and formed a reasonable judgement that, at the time of approving these financial statements, the Group and Company are in a stable position, the Group is able to pay its debts as they fall due in the foreseeable future and is poised for continued growth. 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 2017:

IAS 12

Income Taxes

The amendment to the standard deals with the recognition of Deferred Tax Assets for Unrealised Losses. The diversity in practice around the recognition of a deferred tax asset that is related to a debt instrument measured at fair value is mainly attributable to uncertainty about the application of some of the principles in IAS 12. The adoption of the amendment did not have any impact on the amounts recognised in prior periods.

Periods beginning on / after 1 January 2017

IAS 7

Statement of Cash Flows

The amendments are intended to clarify IAS 7 to improve information provided to users of financial statements about an entity's financing activities. The adoption of the amendment did not have any impact on the amounts recognised in prior periods.

Periods beginning on / after 1 January 2017

New and amended standards not yet adopted by the Group:

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2017 reporting periods and have not been early adopted by the Group. The Group's assessment of the impact of these new standards and interpretations is set out below.

IFRS 15 Revenue from Contracts with Customers

The new standard for revenue replaces IAS 18, and will have a significant impact on some entities. The changes could have an impact on the timing of when revenue is recognised and the period over which it is recognised as well as on the financial statement disclosures. The Group does not expect this standard to have a material impact on revenue.

Periods beginning on / after 1 January 2017

IFRS 9 Financial Instruments

The standard addresses the classification, measurement and de-recognition of financial assets and financial liabilities, introduces new rules for hedge accounting and a new impairment model for financial assets. The Group does not expect the new guidance to affect the classification and measurement of these financial assets. The Group doesn't expect a material impact in accounting for financial liabilities that are designated at fair value through profit or loss.

Periods beginning on / after 1 January 2018

IFRS 16 Leases

This is a new accounting standard which will result in almost all leases being recognised on the balance sheet, as the distinction between operating and finance leases is removed. Under the new standard, an asset (the right to use the leased item) and a financial liability to pay rentals are recognised. The only exceptions are short-term and low-value leases. The accounting for lessors will not significantly change. Although its impact is still being assessed, the Group doesn't expects there to be a material impact as the majority of leases are short term and low value.

Periods beginning on / after 1 Jan 2019

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 share options and Long Term Incentive Plans ("LTIPs") 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 payments is recognised as an expense. The total amount to be expensed is determined by reference to the fair value of the options or LTIP awards 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 or LTIP awards 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.

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

Company: The functional and presentation currency of the Company is United States Dollars ("USD" or "$").

Group: The functional currency of the Group operating entities is Trinidad & Tobago Dollars ("TTD") as this is the currency of the primary economic environment in which the entities operate. The presentation currency is USD which better reflects the Group's business activities and improves the 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 from both USD and Great British Pound ("GBP" or "£") currencies. The following exchange rates have been used in the preparation of these financial statements:

	2017		2016
	$	£	$	£
Average rate TTD= $/£	6.751	8.831	6.626	9.143
Closing rate TTD= $/£	6.771	9.207	6.754	8.401

(b) Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation of monetary assets and liabilities denominated in foreign currencies at year end exchange rates are generally recognised in profit or loss. They are deferred in equity if they relate to qualifying cash flow hedges and qualifying net investment hedges or are attributable to part of the net investment in a foreign operation.

Foreign exchange gains and losses that relate to borrowings are presented in the statement of profit or loss, within finance costs. All other foreign exchange gains and losses are presented in the statement of profit or loss on a net basis within administrative expenses.

Non-monetary items that are measured at fair value in a foreign currency are translated using the exchange rates at the date when the fair value was determined. Translation differences on assets and liabilities carried at fair value are reported as part of the fair value gain or loss. For example, translation differences on non-monetary assets and liabilities such as equities held at fair value through profit or loss are recognised in profit or loss as part of the fair value gain or loss and translation differences on non-monetary assets such as equities classified as available-for-sale financial assets are recognised in other comprehensive income.

The results and financial position of foreign operations (none of which has the currency of a hyperinflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

· assets and liabilities for each balance sheet presented are translated at the closing rate at the date of that balance sheet

· income and expenses for each statement of profit or loss and statement of comprehensive income are translated at average exchange rates (unless this is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions), and

· all resulting exchange differences are recognised in other comprehensive income.

On consolidation, exchange differences arising from the translation of any net investment in foreign entities, and of borrowings and other financial instruments designated as hedges of such investments, are recognised in other comprehensive income. When a foreign operation is sold or any borrowings forming part of the net investment are repaid, the associated exchange differences are reclassified to profit or loss, as part of the gain or loss on sale.

(d) Translation differences

Differences arising from retranslation of the financial statements at the year-end are 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:

· Licence and property acquisition costs

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

· 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.

ii) 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 ("VIU"). 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.

Computer software is initially recognised at cost, once it is purchased. Internally generated software is capitalised once it is proven technological feasibility, probable future benefits, intent and ability to use the software, resources to complete the software, and ability to measure cost. It is amortised over its useful life, based on pattern of benefits (straight-line is the default).

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 meet the definition of a business (therefore do not apply business combination accounting) 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 are 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 VIU. 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 and 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, recompletions and workovers are stated at lower of cost and net realisable value. Cost is determined using the average cost method.

Cash and cash equivalents

For the purpose of presentation in the statement of cash flows, cash and cash equivalents includes cash on hand, deposits held at call with financial institutions, other short-term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value, and bank overdrafts. Bank overdrafts are shown within borrowings in current liabilities in the balance sheet.

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.

Income tax

The income tax expense or credit for the period is the tax payable on the current period's taxable income based on the applicable income tax rate for each jurisdiction adjusted by changes in deferred tax assets and liabilities attributable to temporary differences and to unused tax losses.

The current income tax charge is calculated on the basis of the tax laws enacted or substantively enacted at the end of the reporting period 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 provided in full, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the consolidated financial statements. However, deferred tax liabilities are not recognised if they arise from the initial recognition of goodwill. Deferred income tax is also 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 end of the reporting period and are expected to apply when the related deferred income tax asset is realised or the deferred income tax liability is settled.

The deferred tax liability in relation to investment property that is measured at fair value is determined assuming the property will be recovered entirely through sale.

Deferred tax assets are recognised only if it is probable that future taxable amounts will be available to utilise those temporary differences and losses.

Deferred tax liabilities and assets are not recognised for temporary differences between the carrying amount and tax bases of investments in foreign operations where the Company is able to control the timing of the reversal of the temporary differences and it is probable that the differences will not reverse in the foreseeable future.

Deferred tax assets and liabilities are offset when there is a legally enforceable right to offset current tax assets and liabilities and when the deferred tax balances relate to the same taxation authority. Current tax assets and tax liabilities are offset where the entity has a legally enforceable right to offset and intends either to settle on a net basis, or to realise the asset and settle the liability simultaneously.

Current and deferred tax is recognised in profit or loss, except to the extent that it relates to items recognised in other comprehensive income or directly in equity. In this case, the tax is also recognised in other comprehensive income or directly in equity, respectively.

Property taxes

Property taxes are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method. Assessments are based on the Annual Rental Value ("ARV") of property. The Annual Taxable Value ("ATV") is the ARV subject to deductions and allowances in respect of voids and loss of rent multiplied by the respective Property tax rate. The Property tax rate applicable to the Group are industrial with building rates at 6% and industrial without building 3%.

Revenue recognition

Revenue is measured at the fair value of the consideration received or receivable. Amounts disclosed as revenue are net of returns, trade allowances, rebates and amounts collected on behalf of third parties.

The Group recognises revenue when the amount of revenue can be reliably measured, it is probable that future economic benefits will flow to the entity and specific criteria have been met for each of the Group's activities as described below. The Group bases its estimates on historical results, taking into consideration the type of customer, the type of transaction and the specifics of each arrangement. The specific accounting policies for the Group's main types of revenue are explained in Note 3.

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.

Compound Financial Instruments

Compound financial instruments issued by the Group comprise convertible loan notes that can, in certain circumstances, be converted to share capital at the option of the holder, and the number of shares to be issued does not vary with changes in their fair value. The liability component of a compound financial instrument is recognised initially at the fair value of a similar liability that does not have an equity conversion option. The equity component is recognised initially as the difference between the fair value of the compound financial instrument as a whole and the fair value of the liability component. Any directly attributable transaction costs are allocated to the liability and equity components in proportion to their initial carrying amounts. Subsequent to initial recognition, the liability component of a compound financial instrument is measured at amortised cost using the effective interest rate method. The equity component of a compound financial instrument is not re-measured subsequent to initial recognition except on conversion or expiry.

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.

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.

Derivatives and hedging activities

Derivatives are initially recognised at fair value on the date a derivative contract is entered into and are subsequently re-measured to their fair value at the end of each reporting period. The accounting for subsequent changes in fair value depends on whether the derivative is designated as a hedging instrument, and if so, the nature of the item being hedged.

The Group has not applied hedge accounting and all derivatives are measured at fair value through profit and loss.

Financial assets at fair value through profit or loss are financial assets held for trading. A financial asset is classified in this category if acquired principally for the purpose of selling in the short term. Derivatives are also categorised as held for trading unless they are designated as hedges. Assets in this category are classified as current assets if expected to be settled within 12 months, otherwise they are classified as non-current. Financial assets are derecognised when the rights to the cash flows expire, risks and rewards are transferred or control of the asset is transferred.

A financial liability is removed from the balance sheet only when it is extinguished - that is, when the obligation specified in the contract is discharged or cancelled - or expires.

Operating segment information

The steering committee is the Group's chief operating decision-maker. Management has determined the operating segments which are Onshore, West Coast and East Coast 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 Executive Chairman, Country Manager, Chief Operating Officer and Chief Financial Officer, that makes strategic decisions in accordance with Board policy.

Investments

Investments are shown at cost less provision for any impairment in value. The Company performs impairment reviews in respect of investments whenever events or changes in circumstances indicate that the carrying amount of the investment may not be recoverable. An impairment loss is recognised when the higher of the investment's net realisable value and fair value less cost of disposal is less than the carrying amount.

Exceptional Items

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

2 Financial Risk Management

Financial risk factors

The Group's activities expose it to a variety of financial risks. The Group's overall risk management 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 2017, if the functional currency of the main operating subsidiary had weakened/strengthened by 10% against the US dollar with all other variables held constant, post-tax profit/(loss) for the year would have been $2.1 million (2016: $0.8 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 2017, if commodity prices had been 20% higher/lower with all other variables held constant, post-tax profit/(loss) for the year would have been $8.7million (2016: $7.0million) lower/higher. The sensitivity doesn't take into consideration the impact of the put options and zero cost collar in place over commodity prices.

(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 2017, there were no loan commitments to attract interest rates on foreign currency-denominated borrowings. However in 2016 if the interest had been 1% higher/lower with all other variables held constant, post-tax (loss)/profit for the year would have been $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 - the Petroleum Company of Trinidad & Tobago ("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.

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 held cash at bank of $11.8 million (2016:$7.6 million).

Management monitors rolling forecasts of the Group's cash and cash equivalents on the basis of expected cash flows. This is carried out at the Group level in accordance with practice and limits set by the Group, refer to the disclosures in Note 1 "Going Concern" for more information regarding the factors considered by the Company in managing liquidity risk.

The tables below analyse the Group's financial liabilities into relevant maturity groupings based on their contractual maturities for:

(a) All non-derivative financial liabilities, and

(b) Net and gross settled derivative financial instruments for which the contractual maturities are essential for an understanding of the timing of the cash flows.

The amounts disclosed in the table are the contractual undiscounted cash flows. Balances due within 12 months equal their carrying balances as the impact of discounting is not significant.

	Less than 1 year	Between 1-2 years	Between 2-5 years	Total Contractual Cash flows	Carrying amount
At 31 December 2017	$'000	$'000	$'000	$'000	$'000
Non-derivatives
Trade and other payables	10,092	881	--	10,973	10,973
Convertible loan notes (including interest)	--	7,547	3,290	10,837	3,019
Total Non-derivatives	10,092	8,428	3,290	21,810	13,992

Derivatives
Trading derivatives	762	--	--	762	762

At 31 December 2016
Non-derivatives
Trade payables	42,799	--	--	42,799	42,799
Borrowings (including interest)	10,766	--	--	10,766	10,766
Total Non-derivatives	53,565	--	--	53,565	53,565

(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. 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.

	2017	2016
	$'000	$'000
Convertible loan notes and borrowings*	3,019	9,950
Less: cash and cash equivalents	(11,792)	(7,615)
Net (cash)/debt	(8,773)	2,335
Total equity	48,590	11,252
Total capital	39,817	13,587

Gearing ratio	(22.0)%	17.2%

_{Note (*): 2017 relates to the fair value of the CLN at 31 December 2017. The face value of the CLN's principal plus interest was $7.0 million at 31 December, 2017. 2016 relates to the outstanding principal balance on the (Citibank Trinidad & Tobago) Limited loan.}

(e) Fair value estimation

The table below analyses financial instruments carried at fair value, by valuation method.

The different levels have been defined as follows:

- Quoted prices (unadjusted) in active markets for identical assets or liabilities (Level 1).

- Inputs other than quoted prices included within level 1 that are observable for the asset or liability, either directly (that is, as prices) or indirectly (that is, derived from prices) (Level 2).

- Inputs for the asset or liability that are not based on observable market data (that is, unobservable inputs) (Level 3).

The following table presents the Group's financial assets and liabilities that are measured at fair value at 31 December 2017.

	Level 1	Level 2	Level 3	Total
	$'000	$'000	$'000	$'000
Liabilities
Zero cost collar	--	--	762	762
Total liabilities	--	--	762	762

The Group had no financial assets and liabilities measured at fair value at 31 December 2016.

Fair value measurements using significant unobservable inputs (Level 3)

	Put options	Zero cost collar
	$'000	$'000
1st January 2017	--	--
Purchased	600	--
Losses recognised	(600)	(762)

31 December 2017	--	(762)

Put Options / Zero Cost Collar - For put/call options at fair value through the profit or loss, an assessment of oil price movement in terms of the volatility at 31 December 2017 was done recognising a charge of $1.4 million (2016: nil). The charge was included within 'Other expenses' in the consolidated statement of comprehensive income.

Group's valuation processes

The Group's finance department includes a team that performs the valuations of financial assets required for financial reporting purposes, including Level 3 fair values. For valuations requiring the use of experts the Group outsources this function to qualified experts. This team reports directly to the Chief Financial Officer ("CFO") who in turn reports to the Audit Committee ("AC"). Discussions of valuation processes and results are held between the CFO and AC at least twice per year, in line with the Group's year end reporting dates.

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 in which the deferred tax asset arose.

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 specific risk free rates for each asset ranging between 3.09%-4.65% (2016: 3.9%) and a core inflation rate of 3% (2016: 3%), See Note 26. The impact in 2017 of a 1% change in these variables is as follows:

	Statement of Financial Position Obligation	Statement of Comprehensive Income/Expense
	2017	2017
	$'000	$'000
	(Decrease)/Increase	(Decrease)/Increase
Discount rate
1% increase in assumed rate	(5,614)	120
1% decrease in assumed rate	6,785	(205)

Inflation rate
1% increase in assumed rate	6,804	330
1% decrease in assumed rate	(5,725)	(275)

(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 becomes available. The Group's reserve estimates are also evaluated when required by independent external reserve evaluators, The last independent external reserve valuation was done in 2012. Since 2012 up to and including 2017 the Group estimated its own commercial reserves based on information compiled by appropriately qualified persons relating to the geological and technical data on the size, depth, shape and grade of the hydrocarbon body and suitable production techniques and recovery rates.

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.

As at 31 December 2017 all subsidiaries onshore and offshore proved and probable ("2P") reserve estimates were re-evaluated by management and approved by the Board.

(e) Farm outs and lease operatorship agreements

The Group financial statements are prepared on the assumption that it's Farmout and Lease Operatorship agreements ('LOAs") will be renewed upon expiry. If any of these Farmout or LOAs 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 CGU. A CGU represents an individual field or asset held by the Group.

During 2017 no impairment charge was recognised on the Group's property, plant and equipment (2016: $2.4 million) see Note 12. In 2016 the impairment charge resulted in the carrying amount of the respective CGUs being written down to their recoverable amount.

(i) Oil and Gas Assets nil (2016: $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 VIU. The FVLCOD is the amount that a market participant would pay for the CGU less the cost of disposal or utilising a discounted cash flow approach to FVLCOD. The FVLCOD approach utilised a discounted cash flow based on the 2P reserve estimates of the CGU's of the Group. The period over which management has projected its cash flow forecast, ranges between 8-25 year economic lives based on the field economic 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 2P reserves which are estimated using standard recognised evaluation techniques on a fully funded basis; future revenues and estimated development costs pertaining to the CGU's; and a discount rate utilised for the purposes of deriving a recoverable value.

The forward price curve used was as follows:

Price Strip	2018	2019	2020	2021	2022
USD/bbl	56.7	58.9	62.5	64.2	58.0

If the price deck used in the impairment calculation had been 10% lower than management's estimates at 31 December 2017, the Group would have nil impairment on the Oil and Gas assets (2016: $0.7 million increase). If the price deck used in the impairment calculation had been 10% higher than management's estimates at 31 December 2017, the Group would have nil impairment on the Oil and Gas assets in 2017 (2016: $0.6 million decrease).

If the estimated cost of capital of 10% (2016: 10%) used in determining the post-tax discount rate for the CGU's had been 1% lower than management's estimates the Group would have had no changes to its impairment position for 2017 (2016: $0.1 million decrease) 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 no impairment changes in 2017 (2016: $0.03 million increase).

(ii) Slant Rig nil (2016:$1.3 million) impairment.

In 2017 there were no impairments on Rigs. The impairment of the Slant Rig occurred in 2016, since it was last utilised by the Group in 2013-2014 for offshore drilling on the Trintes field and was not used afterwards. 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 of disposal estimate provided by a third party.

(h) Impairment of intangible exploration and evaluation assets

In 2017 a review for impairment triggers was carried out and there were no further impairment losses realised against the carrying values of the Group's Exploration and Evaluation assets.

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

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

5 Correction of error in accruing for Property Taxes

Adjustments to the 2016 issued financial statements have been made as a result of the correction of a prior period omission.

During 2016, the Government of Trinidad and Tobago announced that property tax, under the Property Tax Act 2009, was to be reintroduced with effect from 1 January 2016. There were no clear guidelines provided in terms of the estimation of the annual rental value upon which the liability was calculated. The Group omitted to accrue an estimate for 2016 and as a consequence the Property Taxes had been underestimated.

	31 December
	2016 $'000	2016 $'000	2016 $'000
Equity and Liabilities	Previous	Adjustment	Restated
Accumulated Losses	(195,857)	(603)	(196,460)

Current Liabilities
Trade and other payables	42,196	603	42,799

The error of omission has been corrected by restating each of the affected financial statement line items for the prior period as follows in the Statement of Financial Position extract and Statement of Comprehensive Income extract below:

	31 December
	2016 $'000	2016 $'000	2016 $'000
Operating expenses	Previous	Adjustment	Restated
Property taxes	--	603	603

Basic and diluted earnings per share for 2016 have also been restated. The amount for the correction for both basic and diluted earnings per share was a decrease of $0.01 cents per share.

6 Operating Profit Before Exceptional Items

	2017 $'000	2016 $'000
Operating profit before exceptional items is stated after taking the following items into account:
Depreciation, depletion and amortisation (Note 12)	7,055	9,539
Employee costs (Note 33 )	7,475	7,938
Operating lease rentals	675	779
Inventory recognised as expense, charged to operating expenses	67	67

Auditors' remuneration

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

	2017 $'000	2016 $'000
- Fees payable to the Company's auditors' and its associates for the audit of the parent Company and consolidated financial statements	192	197
- Fees payable to the Company's auditors' and its associates for other services: - The audit of Company's subsidiaries	58	58
- Audit related assurance services - interim review	30	20
Total assurance	280	275
- Tax advisory	--	50
- Other advisory	54	--
Total auditors' remuneration	334	325

All fees are in respect of services provided by PricewaterhouseCoopers LLP (PwC). The independence and objectivity of the external auditors are considered on a regular basis by the Audit Committee, with particular regard to the level of non-audit fees incurred.

7 Exceptional Items

Items that are material either because of their size or their nature, or that are non-recurring are considered as exceptional items and are presented within the line items to which they best relate. During the current period, exceptional items as detailed below have been included as exceptional expenses below operating profit in the Income Statement. An analysis of the amounts presented as exceptional items in these financial statements are highlighted below.

	2017	2016
Exceptional items:	$'000	$'000
Secured creditor compromise	(6,472)	--
Unsecured creditor compromise	(15,639)	--
Interest on tax compromise	(5,247)	--
Foreign exchange loss on compromised balance	687	--
Impairment of property, plant and equipment (Note 12)	--	2,420
Impairment of receivables	234	1,071
Impairment of recompletions	135	--
Impairment of inventory	264	--
Fees relating to corporate restructuring	532	940
Gain on extinguishment of liability	(210)	--
Release of provision - potential claim	--	(1,218)
Release provision for restructuring	--	(1,870)
Other provisions	--	712
Unsecured creditor claims	--	545
Gain on disposal of GU-1	--	(954)
Translation difference	(2)	29
Exceptional (credit)/charge	(25,718)	1,675

Exceptional items 2017:

Secured creditor compromise - $6.5 million gain under the senior debt settlement agreement where the unpaid balance was compromised

Unsecured creditor compromise - $15.6 million gain under the creditor settlements arising from compromised balances with suppliers

Interest on tax compromise - $5.2 million gain under the creditor settlement where interest outstanding was waived with the Board of Inland Revenue ("BIR")

Foreign exchange loss on compromised balances - $0.7 million charge under the creditor settlements arising from compromised balances with suppliers

Impairment on receivables - $0.2 million charge resulting from impairment of deal cost VAT recoverable from 2013

Impairment of recompletions - $0.1 million charge resulting from impairment of recompletions

Impairment of inventory - $0.3 million charge resulting from impairment of inventory

Fees relating to corporate restructuring - $0.5 million in fees relating to the corporate restructuring of the Group include the Formal Sales Process ("FSP"), the Proposal process, the cost of advisors, as well as field restructuring

Gain on extinguishment of liability - $0.2 million in gain as a result of accounting for the liability due to the Ministry of Energy and Energy Industries ("MEEI") at fair value

Exceptional items 2016:

Impairment - $2.4 million charge for impairment. In 2016 impairment reviews were carried out over the non-current and current assets on the Statement of Financial Position with impairment losses being recognised on property, plant and equipment, receivables and payables

Fees relating to corporate restructuring - $0.9 million in fees relating to the corporate restructuring of the Group include the Formal Sales Process ("FSP"), the Proposal process and the cost of advisors incurred in relation to both in 2016

Release of provision: potential claim - In December 2015, a provision was created in the sum of $1.2 million for a potential claim, against Trinity Exploration and Production (Galeota) Limited, for a matter that arose before the merger with the Bayfield Group. However, due to the elapse in time (4 years ended September, 2016) for NIKO to make a 'call' for payments under the Limitations of Certain Actions Act Chapter 7:09, the provision was reversed in 2016

Other Provisions: restructuring - At the end of 2015 management held a provision for restructuring totalling $1.9 million which wasn't utilised because the intending restructuring did not occur in 2016. Accordingly in line with the Group's policy the restructuring provision was released at the end of 2016

Other Provisions - $0.7 million

• $0.5 million provision recognised based on litigation obligations raised under the Proposal and;

• $0.2 million revision to the provision recognised for Oilbelt Services Limited retirement benefit

Unsecured creditor claims - An amount of $0.5 million has been recognised following a reconciliation to the Proposal filed and accepted under the Notice of Intention

Gain on disposal of GU-1 - This asset held for sale was disposed in 2016 for a gain of $1.0 million

8 Finance Costs

	2017	2016
	$'000	$'000
Decommissioning (Note 26)	1,643	1,577
Interest on taxes	--	2,215
Interest on loans	657	941
	2,300	4,733

9 Income Tax Expense

	2017	2016
Current tax	$'000	$'000
Petroleum profits tax	(926)	1,533
Corporation tax	--	27
Unemployment levy	(26)	--
Deferred tax
- Current year
Movement in asset due to tax losses (Note 16)	1,317	(3,036)
Movement in liability due to accelerated tax depreciation (Note 16)	(389)	(381)
Translation difference	(4)	(21)
Income tax credit	(28)	(1,878)

The Group's effective tax rate varies from the statutory rate for UK companies of 19.25% as a result of the differences shown below:

	2017	2016
	$'000	$'000
Profit/ (Loss) before taxation	25,320	(9,345)
Tax charge at expected rate of 19.25% (2016: 20%)	4,874	(1,869)
Effects of:
Higher overseas tax rate	10,722	(1,783)
Disallowable expenses	(8,635)	(745)
Deferred tax asset not recognised	(8,960)	(5,979)
Tax loss generated not recognised	--	(1,197)
Tax losses utilised	7,630	9,993
Tax losses previously recognised	(5,496)	(2,420)
Green fund levy	149	151
Other differences	(312)	1,971
Tax credit	(28)	(1,878)

Taxation losses at 31 December 2017 available for set off against future taxable profits amounts to approximately $226.1 million (2016: $217.6 million), with tax losses recognised of $7.6 million in 2017. These losses do not have an expiry date and have not yet been confirmed by the BIR.

10 Earnings Per Share

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

	Earnings $'000	Weighted Average Number Of Shares '000'	Earnings Per Share $
Year ended 31 December 2017
Basic	25,348	276,746	0.09
Diluted	25,348	395,054	0.06

Year ended 31 December 2016
Basic	(7,467)	94,800	(0.08)
Diluted	(7,467)	94,800	(0.08)

Impact of dilutive ordinary shares:

Diluted earnings per share is calculated by adjusting the weighted average number of ordinary shares outstanding to assume conversion of all potentially dilutive potential ordinary shares. The Company has two categories of dilutive ordinary shares: CLNs and share based payments. The CLNs issued during the year are considered to be potential ordinary shares and have been included in the determination of diluted earnings per share. This is calculated as the CLN nominal value of $6.55 million plus accrued interest after the second anniversary of $1.0 million divided by the conversion price of $0.08125. Long term incentives of 24,415,998 are considered potential ordinary shares. They have been included in the determination of the diluted earnings per share. Share options of 1,975,084 are considered potential ordinary shares and have not been included as the exercise hurdle would not have been met.

11 Investment In Subsidiaries

	Company
	2017	2016
	$'000	$'000

Opening balance	44,802	44,775
Capital contributed to subsidiary	6,395	27
Share based payment	219	--
Closing balance	51,416	44,802

The investment in Group undertakings is recorded at cost less impairments which is the fair value of the consideration paid.

Listing of Subsidiaries

The Group's principal subsidiaries at 31 December 2017 are listed below:

Name	Registered Address/Country of Incorporation	Nature of Business	% Shares held by the Group
Bayfield Energy Limited	c/o Pinsent Masons LLP, 1 Park Row, Leeds, England, LS1 5AB, United Kingdom	Holding Company	99.99998 %
Trinity Exploration & Production (UK) Limited	13 Queen's Road, Aberdeen, AB15 4YL, United Kingdom	Holding Company	100 %
Trinity Exploration and Production Services (UK) Limited	c/o Pinsent Masons LLP, 1 Park Row, Leeds, England, LS1 5AB, United Kingdom	Service Company	100 %
Bayfield Energy do Brasil Ltda	Av. Presidente Vargas 509, Rio de Janeiro, 20071-003, Brazil	Dormant	100 %
Trinity Exploration & Production (Barbados) Limited	Ground Floor, One Welches, Welches, St. Thomas BB22025, Barbados	Holding Company	100 %
Trinity Exploration and Production (Trinidad and Tobago) Limited	3^rd Floor Southern Supplies Limited Building, 40 -44 Sutton Street, San Fernando, Trinidad & Tobago ("Trinidad address")	Holding Company	100 %
Galeota Oilfield Services Limited	Trinidad address	Oil and Gas	100 %
Trinity Exploration and Production (Galeota) Limited	Trinidad address	Oil and Gas	100 %
Oilbelt Services Limited	Trinidad address	Oil and Gas	100 %
Ligo Ven Resources Limited	Trinidad address	Oil and Gas	100 %
Trinity Exploration and Production Services Limited	Trinidad address	Service Company	100 %
Tabaquite Exploration & Production Company Limited	Trinidad address	Oil and Gas	100 %
Trinity Exploration and Production (GOP) Limited	Trinidad address	Oil and Gas	100 %
Trinity Exploration and Production (GOP-1B) Limited	Trinidad address	Oil and Gas	100 %

12 Property, Plant and Equipment

	Plant & Equipment	Leasehold & Buildings	Oil & Gas Assets	Other	Total
Year ended 31 December 2017	$'000	$'000	$'000	$'000	$'000

Opening net book amount at 1 January 2017	4,201	1,890	53,541	--	59,632
Disposal	--	(9)	--	--	(9)
Additions	42	2	2,824	--	2,868
Adjustment to decommissioning estimate (Note 17)	--	--	(2,868)	--	(2,868)
Depreciation, depletion and amortisation charge for year	(483)	(147)	(6,425)	--	(7,055)
Translation difference	7	(10)	(115)	--	(118)

Closing net book amount at 31 December 2017	3,767	1,726	46,957	--	52,450
At 31 December 2017
Cost	12,901	3,126	272,565	336	288,928
Accumulated depreciation, depletion, amortisation and impairment	(9,141)	(1,390)	(225,493)	(336)	(236,360)
Translation difference	7	(10)	(115)	--	(118)

Closing net book amount	3,767	1,726	46,957	--	52,450

	Plant & Equipment	Leasehold & Buildings	Oil & Gas Assets	Other	Total
Year ended 31 December 2016	$'000	$'000	$'000	$'000	$'000

Opening net book amount at 1 January 2016	3,966	1,629	40,548	--	46,143
Disposal	(16)	--	--	--	(16)
Additions	19	--	247	--	266
Impairment^*	--	--	(2,420)	--	(2,420)
Transferred to available for sale	831	399	26,361	--	27,591
Depreciation, depletion and amortisation charge for year	(641)	(176)	(8,722)	--	(9,539)
Translation difference	42	38	(2,473)	--	(2,393)

Closing net book amount at 31 December 2016	4,201	1,890	53,541	--	59,632
At 31 December 2016
Cost	12,815	3,095	275,081	336	291,327
Accumulated depreciation, depletion, amortisation and impairment	(8,656)	(1,243)	(219,067)	(336)	(229,302)
Translation difference	42	38	(2,473)	--	(2,393)

Closing net book amount	4,201	1,890	53,541	--	59,632

^{Note (*): An impairment loss of $2.4 million was recognised on Oil and Gas Assets and Slant Rig (see Note 3 (g (i) (ii)), 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.}

13 Intangible Assets

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

	Computer Software $'000	Exploration and evaluation assets $'000	Total $'000

At 1 January 2017	--	25,406	25,406
Computer software	250	--	250
Translation difference	--	(65)	(65)
At 31 December 2017	250	25,341	25,591

At 1 January 2016	--	26,751	26,751
Translation difference	--	(1,345)	(1,345)
At 31 December 2016	--	25,406	25,406

· Computer Software: In 2017, a new accounting software was purchased

· Exploration and evaluation assets: Includes the TGAL-1 exploration well and development costs. The Group tests whether E&E has suffered any impairment on an annual basis and there were no impairment triggers (2016: nil)

14 Abandonment Fund

	2017	2016
	$'000	$'000
At 1 January	1,072	--
Additions	578	--
Reclassified	--	1,072
At 31 December	1,650	1,072

Abandonment funds are restricted cash put aside in escrow for abandonment and environmental purposes in accordance with contractual obligations to be used in accordance with the contract.

15 Performance Bond

	2017	2016
	$'000	$'000
At 1 January	--	--
Additions	253	--
At 31 December	253	--

A performance bond was put in place on 3 July 2017 for the Group's Lease Operatorship Assets ("LOA") effective until 31 December 2020. The performance bond is a requirement under the Lease Operatorship Agreement.

16 Deferred Income Taxation

Group

The analysis of deferred tax assets is as follows:

	2017	2016
	$'000	$'000
Deferred tax assets:
-Deferred tax assets to be recovered in more than 12 months	(4,179)	(5,496)
Deferred tax liabilities:
-Deferred tax liabilities to be settled in more than 12 months	2,538	2,927
Net deferred tax assets	(1,641)	(2,569)

The movement on the deferred income tax is as follows:

	2017	2016
	$'000	$'000
At beginning of year	(2,569)	848
Movement for the year	928	(3,417)
Net deferred tax asset	(1,641)	(2,569)

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

	2015	Movement	2016	Movement	2017
	$'000	$'000	$'000	$'000	$'000
Deferred tax assets
Acquisition	(33,436)	--	(33,436)	--	(33,436)
Tax losses recognised	(31,257)	(3,036)	(34,293)	--	(34,293)
Tax losses derecognised	62,233	--	62,233	1,317	63,550
	(2,460)	(3,036)	(5,496)	1,317	(4,179)

	2015	Movement	2016	Movement	2017
Deferred tax liabilities	$'000	$'000	$'000	$'000	$'000
Accelerated tax depreciation	14,374	--	14,374	(331)	14,043
Non-current asset impairment	(33,214)	--	(33,214)	--	(33,214)
Acquisitions	19,580	--	19,580	--	19,580
Fair value uplift	2,568	(381)	2,187	(58)	2,129
	3,308	(381)	2,927	(389)	2,538

- Deferred tax assets are recognised for tax loss carry-forwards to the extent that the realisation of the related tax benefit through future taxable profits are probable. Deferred tax assets of $1.3 million has been derecognised (2016: $3.0 million was recognised) based on future taxable profits. The Group has unrecognised deferred tax asset amounting to $119.6 million which have no expiry date.

- Deferred tax liabilities have reduced by $0.4 million as the carrying values of property, plant and equipment and intangible assets which gave rise to the temporary differences have been written down to their recoverable amount.

17 Inventories

	Crude oil	Materials and supplies	Total
	$'000	$'000	$'000
At 1 January 2017	120	3,667	3,787
Inventory movement	10	233	243
Impairment	--	(264)	(264)
At 31 December 2017	130	3,636	3,766

At 1 January 2016	160	3,802	3,962
Inventory movement	(40)	(135)	(175)
At 31 December 2016	120	3,667	3,787

(i) Assigning costs to inventories

The costs of individual items of inventory within the category material and supplies are determined using weighted average costs. The cost assigned for crude oil is based on the lower of cost and net realisable value.

(ii) Amounts recognised in profit or loss

Inventories recognised as an expense during the year ended 31 December 2017 amounted to $0.1 million (2016: $0.1 million); these were included in production costs.

At the end of 2017 an impairment loss of $0.3 million (2016: nil) was recognised against the materials and supplies inventory. Write-downs of inventories to net realisable value amounted to $0.0 million (2016: nil). These were recognised within exceptional items during the year ended 31 December 2017.

18 Trade and Other Receivables

	Group		Company
	2017 $'000	2016 $'000	2017 $'000	2016 $'000
Due after more than one year
Amounts due from Group companies (Note 28 (d))	--	--	--	--
Due within one year
Amounts due to related parties (Note 28 (d))	--	--	2,447	1,857
Trade receivables	3,272	2,849	--	--
Less: provision for impairment of trade receivables	--	--	--	--
Trade receivables - net	3,272	2,849	2,447	1,857
Prepayments	631	1,140	58	334
VAT recoverable	807	1,315	31	479
Other receivables	445	145	--	--
	5,155	5,449	2,536	2,670

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

At 31 December 2017, trade receivables of $3.3 million (2016: $2.9 million) were fully performing. Trade receivables that are less than six months past due are not considered impaired. At the end of 2016 there was an impairment of $1.1 million relating to a recoverable amount from the former owners of the WD2 and FZ2 assets. At the end of 2017 there was an impairment of $0.3 million relating to VAT on invoices that were no longer recoverable.

Ageing analysis of these trade receivables is as follows:

2017

$'000

2016

$'000

Up to 30 days

3,272

2,849

3,272

2,849

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

	Group		Company
	2017 $'000	2016 $'000	2017 $'000	2016 $'000
USD	2,631	2,249	2,464	2,167
GBP	60	1,033	72	503
TTD	2,464	2,167	--	--
	5,155	5,449	2,536	2,670

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

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

	Group		Company
	2017	2016	2017	2016
	$'000	$'000	$'000	$'000
Trade receivables
Counterparties without external credit rating:
Existing customers with no defaults in the past	3,272	2,849	--	--

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

19 Cash and Cash Equivalents

	Group		Company
	2017	2016	2017	2016
	$'000	$'000	$'000	$'000

Cash and cash equivalents	11,792	7,615	6,024	758
	11,792	7,615	6,024	758

Cash and cash equivalents disclosed above and in the statement of cash flows exclude restricted cash and are available for general use by the Group.

20 Share Capital and Share Premium

	Number of shares No.	Ordinary shares $'000	Share premium $'000	Total $'000
As at 1 January 2017	94,799,986	94,800	116,395	211,195
Share Capital Reorganisation	187,600,000	1,876	8,967	10,843
As at 31 December 2017	282,399,986	96,676	125,362	222,038

As at 1 January 2016	94,799,986	94,800	116,395	211,195
Movement	--	--	--	--
As at 31 December 2016	94,799,986	94,800	116,395	211,195

The Company effected a Share Capital Reorganisation ("SCR") on the 11 January 2017 whereby each existing Ordinary Share was divided and converted into one new Ordinary Share of a nominal value of $0.01 each and one Deferred Share of a nominal value of $0.99 each. The deferred shares have no voting or dividend rights and on a return of capital on a winding up has no valuable economic rights. Subsequent to the SCR the Company raised $11.7 million before expenses by issuing 187,600,000 new ordinary shares at a placing price of £0.0498. The nominal value of the new ordinary shares are $0.01 each issued at a premium of $0.05 per share.

Share Capital and Share Premium		No. of Shares	Ordinary Shares	Deferred Shares	Share Premium	Total
			$'000	$'000	$'000	$'000
At 1 January 2017	1.00	94,799,986	94,800	--	116,395	211,195
Share capital reorganisation	1.00	(94,799,986)	(94,800)	--	--	(94,800)
New ordinary shares following the SCR	0.01	94,799,986	948	--	--	948
Deferred ordinary shares following SCR	0.99	--	--	93,852	--	93,852
New ordinary shares issued	0.01	187,600,000	1,876	--	--	1,876
Ordinary share premium	0.05	--	--	--	9,849	9,849
Cost of raising equity		--	--	--	(882)	(882)
At 31 December 2017		282,399,986	2,824	93,852	125,362	222,038
Note: $:GBP rate 1.255:1

21 Share Warrants

The Group's policy with respect to equity-settled share-based payment transactions is to measure the value of the good or service received with the corresponding increase in equity at the fair value of the services received. If the Group cannot estimate reliably the fair value of the good or services received it then shall measure their value and the corresponding increase in equity indirectly by reference to the fair value of the equity instrument.

	2017	2016
	$'000	$'000
Oriel Securities Limited	--	71
	--	71

Oriel Securities Limited warrants

The warrants over 62,027 shares which had originally been granted to Oriel Securities Limited in connection with a 2011 private placing lapsed on the 22 November 2017 in accordance with the warrant conditions.

22 Share Based Payment Reserve

The share-based payments reserve is used to recognise:

- The grant date fair value of options issued to employees but not exercised

- The grant date fair value of shares issued to employees

- The grant date fair value of deferred shares granted to employees but not yet vested

- The issue of shares held by the Employee Share Trust to employees.

During 2017 the Group had in place share-based payment arrangements for its employees and Executive Directors, the Share Option Plan and the Long Term Incentive Plan ('LTIP'). The charge in relation to these arrangements is shown below, with further details of each scheme following:

	2017	2016
	$'000	$'000
At 1 January	12,244	12,178
Share based payment expense:
Share option expense	--	30
Long term incentive plan	306	36
At 31 December	12,550	12,244

Share Option Plan

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

At 31 December 2017, the Group had two employee share option plans which were fully vested.

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

		2017		2016
Grant-Vest	Expiry Date	Exercise price per share options	Number of Options	Exercise price per share options	Number of Options
2012-2015	2022	GBP0.86	1,685,540	GBP0.86	1,685,540
2013-2016	2023	GBP1.20	289,544	GBP1.20	289,544

			1,975,084		1,975,084

The inputs into the Black-Scholes model for options granted in prior periods were as follows:

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

Long Term Incentive Plan

Long Term Incentive Plan awards were was granted in August 2017 over 25,415,998 ordinary shares ('2017 LTIP Award"). The 2017 LTIP Award is designed to provide long-term incentives for Senior Managers and Executive Directors to deliver long-term shareholder returns. Under the plan, participants were granted options which only vest if certain performance standards are met. Participation in the plan is at the Board's discretion and no individual has a contractual right to participate in the plan or to receive any guaranteed benefits.

The 2017 LTIP Awards will normally vest on 30 June 2022, although they may vest in full or in part on 30 June 2020 or 2021 subject to meeting performance targets relating to:

· In respect of 70 per cent of the award, the Company's share price growth from the 2017 placing price of 4.98 pence per share. If the 3 month volume-weighted price ("VWAP") at the testing date is 35 pence or more per share, this part of the award will vest in full. If the VWAP at the testing date is 4.98 pence per share or less, this part of the award will not vest at all. If the VWAP at the testing date is between 4.98 pence and 35 pence per share, this part of the award will vest on a pro-rated straight-line basis;

· In respect of 20 per cent of the award, repayment of the amount due to the Board of Inland Revenue of Trinidad and Tobago ("BIR") in accordance with the terms of the Creditors Proposal approved in 2017. The final payment under the Creditors Proposal is due on 30 September 2019; and

· In respect of 10 per cent of the award, redemption of all the CLNs issued in January 2017 before the second anniversary of their issue.

All remaining awards under the LTIP (which were granted in 2013) lapsed during 2017 as the performance targets were not satisfied.

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


	2017 Average exercise price per share option	Number of Options	2016 Average exercise price per share option	Number of Options
At 1 January	GBP 0.00	189,600	GBP0.00	189,600
Lapsed	GBP 0.00	(189,600)	GBP0.00	--
Granted during the year	GBP 0.00	25,415,998	--	--
At 31 December	GBP 0.00	25,415,998	GBP0.00	189,600

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

Grant-Vest	Expiry date	Exercise price	2017	2016
2017-2022	2022	GBP 0.00	25,415,998	189,600

The fair value at grant date of the 2017 LTIP awards recognised during the year ended 31 December 2017 was $0.3 million. The total fair value of the 2017 LTIP Award will be $2.6 million and this will be expensed over the vesting period with the full charge pro-rated over the period up to 30 June 2022. However the LTIP award may vest in full or in part on 30 June 2020 or 2021 with the appropriate charge being taken. The fair value at grant date is independently determined using an adjusted form of the Black Scholes Model which includes a Monte Carlo simulation model that takes into account the exercise price, the term of the option, the share price at grant date and expected price volatility of the underlying share, the expected dividend yield, the risk free interest rate for the term of the option and the correlations and volatilities of the peer group companies. The model inputs for the 2017 LTIP Awards granted during the year ended 31 December 2017 included:

Grant Date	24 August 2017
Share price at grant date	GBP10.75
Exercise price	GBP0.00
Expected volatility	73.3%
Risk-free interest rates	0.44%
Expected dividend yields	0%
Vesting period 1	30 June 2020
Vesting period 2	30 June 2021
Vesting period 3	30 June 2022

23 Merger and Reverse Acquisition Reserves

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

At 1 January 2017	(89,268)	75,467	(13,801)
Movement	--	--	--
Translation differences	--	--	--
At 31 December 2017	(89,268)	75,467	(13,801)

At 1 January 2016	(89,268)	75,467	(13,801)
Movement	--	--	--
Translation differences	--	--	--
At 31 December 2016	(89,268)	75,467	(13,801)

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

The insertion of the Company as the new parent to the Group has been accounted for using business combination accounting as described in Note 1. The reverse acquisition difference recorded in the consolidated financial statements represents the difference in accounting for reverse acquisition transactions.

24 Convertible Loan Notes

On 11 January 2017 the Company issued at a 50% discount 6,550,000 one dollar, unsecured Convertible Loan Notes ("CLNs"). The notes mature 7 years from the issue date at their nominal value of $6.55 million plus quarterly accrued, aggregated and compounded interest. Repayments or conversion prior to the maturity date can be made in certain circumstances:

• Early Redemption

Subject to the settlement of the debts owed to the BIR and the MEEI (see Note 27) the Company can before the second anniversary of the CLNs' issue date, redeem all or a portion of the CLNs giving 5 business days' written notice to the Noteholder. The Noteholders do not have the option to convert under this arrangement.

• Redemption

The Company can, after satisfying the debts owed to the BIR and the MEEI or after two years from the issue dates (whichever is the latter), elect to redeem all the CLNs before the maturity date. The redemption date in this scenario must not be less than 20 days from the Early Redemption Notice. The Noteholders can serve a Conversion Notice.

• Conversion

Each Noteholder can after the second anniversary of the issue date serve a Conversion Notice. The principal amount plus the outstanding interest shall be converted into new fully paid ordinary shares at a Conversion Price of $0.08125.

The fair values of the CLNs' liability and equity component were determined at the issuance of the Loan note instrument. The CLNs were recognised in the Statement of Financial Position as follows:

	2017	2016
	$'000	$'000
Nominal value of convertible loan notes issued¹	6,550	--
Issued at a 50% discount	(3,275)	--
Fair value of convertible loan notes	3,275	--
Expenses incurred	(245)	--
Fair value of convertible loan notes (net of costs)	3,030	--
Equity component	(590)	--
Liability component at initial recognition	2,440	--
Effective interest	105	--
Interest accrued²	474	--
Closing balance	3,019	--

Notes:

¹The face value amount repayable on the CLN is the nominal value of $6.6 million plus accrued interest of $0.5 million.

² Interest is calculated by applying the effective interest rate of 23.7% to the liability component.

25 Borrowings

	2017	2016
	$'000	$'000
Non-current portion:
Citibank (Trinidad & Tobago) Limited	--	--
Total	--	--
Current portion:
Citibank (Trinidad & Tobago) Limited	--	9,950
Total	--	9,950

On the 23 January 2017 the borrowings from secured lender Citibank (Trinidad & Tobago) Limited was repaid in full via the senior debt settlement agreement whereby an amount of $3.5 million plus interest was paid in lieu of full settlement on the outstanding balance owed of $10.0 million and the entire financial liability was extinguished. The compromised balance of $6.5 million was recognised within exceptional items through the Consolidated Statement of Comprehensive Income.

26 Provision for Other Liabilities

(a) Non-current:	Potential Claim	Decommissioning cost	Employee Retirement Benefit	Total
	$'000	$'000	$'000	$'000
Year ended 31 December 2017
Opening amount as at 1 January 2017	--	37,970	348	38,318
Unwinding of discount (Note 8)	--	1,643	--	1,643
Restructuring provision settled	--	--	(348)	(348)
Revision to estimates	--	(2,868)	--	(2,868)
Decommissioning contribution	--	497	--	497
Translation differences	--	(91)	--	(91)
Closing balance at 31 December 2017	--	37,151	--	37,151

Year ended 31 December 2016
Opening amount as at 1 January 2016	1,270	18,561	--	19,831
Transferred from other payables	--	--	118	118
Transferred from liabilities held for sale	--	21,810	--	21,810
Revision to employee retirement benefit	--	--	230	230
Unwinding of discount (Note 8)	--	1,577	--	1,577
Release of provision	(1,218)	--	--	(1,218)
Decommissioning contribution	--	(1,939)		(1,939)
Translation differences	(52)	(2,039)	--	(2,091)
Closing balance at 31 December 2016	--	37,970	348	38,318

Decommissioning cost

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

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

a. Core inflation rate - 3% (2016: 3%)

b. Risk free rate - 3.09% - 4.65% (2016: 3.95%)

c. Estimated market value/decommissioning cost

d. Estimated life of each asset

See Note 3(c) for the rates used and sensitivity analysis.

Employee Retirement benefit

In 2017 the employee retirement benefit provision was extinguished under the restructuring process.

(b) Current:

	Litigation claims
	$'000
Year ended 31 December 2017
Opening amount as at 1 January 2017	470
Creditor compromise	(355)
Closing balance at 31 December 2017	115

Year ended 31 December 2016
Opening amount as at 1 January 2016	--
Provision for litigation claims	470
Closing balance at 31 December 2016	470

Litigation claims

In 2016 following the creditors' proposal certain claims were made under the proposal for which the outcome was uncertain and will be decided by the Court of Trinidad and Tobago. Following the creditor compromised settlements the Group has provided for the specific claims made. In 2017 the claims were written down to the compromised amount.

27 Trade and Other Payables

	Group		Company
(a) Non- Current:	2017 $'000	2016 $'000	2017 $'000	2016 $'000

Due to BIR Interest on taxes¹	417	--	--	--
Due to MEEI²	231	--	--	--
Other Payables	233	--	--	--
	881	--	--	--

	Group		Company
(b) Current:	2017 $'000	2016 $'000	2017 $'000	2016 $'000

Trade payables	555	18,984	67	544
Accruals	2,547	1,880	454	152
VAT payable	272	187	--	--
Other payables	701	3,927	--	43
Supplemental petroleum and property taxes	2,626	603	--	--
Amounts due to related parties (Note 28 (d))	--	--	--	335
Due to BIR Interest on taxes and SPT¹	2,865	15,181	--	--
Due to MEEI²	526	2,037	--	--
	10,092	42,799	521	1,074

Notes:

1. Due to the BIR under the settlement agreement is interest on taxes totaling $1.7million and SPT of $1.6million.

2. Financial liabilities due to the MEEI of $2.0 million were substantially modified based on the new terms of repayment. This transaction was accounted for as an extinguishment of the original financial liability and the recognition of a new financial liability of $1.9 million based on its fair value. During the period $1.1 million was repaid with a nominal value of $0.9 million outstanding at 31 December 2017

On 6 January 2017 the High Court of Trinidad and Tobago approved the unsecured creditors' proposal allowing the Group to settle its outstanding liabilities with unsecured creditors in accordance with the unsecured creditor settlement agreement. A total of $15.5 million in unsecured creditors and $5.2 million in interest on taxes due to the BIR were compromised in accordance with the unsecured creditor settlements see note 7 Exceptional items.

28 Related Party Transactions

Group

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

(a) Sales of services and loans issued to subsidiaries	Group		Company
	2017 $'000	2016 $'000	2017 $'000	2016 $'000
Group subsidiaries:
Trinity Exploration and Production Services (UK) Limited	--	--	347	(8,620)
Trinity Exploration and Production (Galeota) Limited	--	--	(498)	(494)
Trinity Exploration and Production (Trinidad and Tobago) Limited	--	--	910	--
Trinity Exploration and Production Services Limited	--	--	(168)	158
	--	--	591	(8,956)

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

(b) Purchases of services

	Group		Company
	2017 $'000	2016 $'000	2017 $'000	2016 $'000

Related party:
Trinity Exploration and Production Services (UK) Limited	--	--	(335)	--
	--	--	(335)	--

Key Management includes Directors (Executive & Non-Executive) and the Country Manager. The compensation paid or payable to Key Management for employee services is shown below:

	Group
	2017 $'000	2016 $'000

Salaries and short-term employee benefits	643	806
Post-employment benefits	53	23
Share-based payment (Note 22)	239	67
	935	896

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

	Group		Company
	2017 $'000	2016 $'000	2017 $'000	2016 $'000

Receivables from related parties:
Trinity Exploration and Production Services Limited	--	--	688	856
Trinity Exploration and Production (Galeota) Limited	--	--	--	498
Trinity Exploration and Production (Trinidad) Limited	--	--	909	--
Trinity Exploration and Production Services (UK) Limited	--	--	850	503
	--	--	2,447	1,857

Payables to related parties:
Trinity Exploration and Production Services (UK) Limited	--	--	--	335
	--	--	--	335

Group and Company

The receivables from related parties arise mainly from sales. The receivables are unsecured and bear no interest. No provisions are held against receivables from related parties (2016: nil).

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

29 Derivative financial instruments

	31 December 2017	31 December 2016
	$'000	$'000
Zero cost collar	762	--
	762	--

Derivatives are classified as held for trading and accounted for at fair value through profit or loss unless they are designated as hedges. They are presented as current assets or liabilities if they are expected to be settled within 12 months after the end of the reporting period.

30 Taxation Payable

	Group		Company
	2017	2016	2017	2016
	$'000	$'000	$'000	$'000
Taxation payable
PPT/ UL	66	--	--	--
Due to BIR (PPT, CT and UL)¹	1,622	2,741	--	--
	1,688	2,741	--	--

Notes:

^1.Due to the BIR under the settlement agreement is PPT; CT and UL taxes of $1.6 million.(2016: $2.7 million)

31 Financial Instruments by Category

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

	Group		Company
	2017	2016	2017	2016
	$'000	$'000	$'000	$'000
Trade and other receivables - current	5,155	5,449	2,536	2,670
Abandonment fund - non current	1,650	1,072	--	--
Cash and cash equivalents	11,792	7,615	6,024	758
	18,597	14,136	8,560	3,428

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

	Group		Company
	2017	2016	2017	2016
	$'000	$'000	$'000	$'000
Borrowings	--	9,950	--	--
Amounts due to related companies	--	--	--	335
Derivative financial instrument	762	--	762	--
Accounts payable and accruals	10,092	42,799	521	739
	10,854	52,749	1,283	1,074

The only category of financial liabilities held by the Group is liabilities at amortised cost.

32 Commitments and Contingencies

a) Commitments

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

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

	Group
	2017	2016
	$'000	$'000
Not later than 1 year	518	675
Later than 1 year and no later than 5 years	130	691
	648	1,366

b) Contingent Liabilities

i) The farm-out agreement for the Tabaquite Block (held by Coastline International Inc.) has expired. There may be additional liabilities arising when a new agreement is finalised, but these cannot be presently quantified until a new agreement is available.

ii) Parent company guarantee. A Letter of Guarantee has been established over the Point Ligoure, Guapo Bay & Brighton ("PGB") Block where a subsidiary of Trinity is obliged to carry out a Minimum Work Programme to the value of $8.4 million. The guarantee shall be reduced at the end of each twelve month period upon presentation of all technical data and results of the Minimum Work Programme performed.

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

33 Employee Costs


Employee costs for the Group during the year	2017 $'000	2016 $'000

Wages and salaries	6,778	7,588
Other pension costs	391	284
Share based payment expense (Note 22)	306	66
	7,475	7,938

Average monthly number of people (including Executive and Non-Executive Directors') employed by the Group	2017 number	2016 number

Executive and Non-Executive Directors	5	2
Administrative staff	64	93
Operational staff	122	126
	191	221

34 Events after the Reporting Year

On 2 February 2018 the Property Tax (Amendment) Bill was introduced in the House of Representatives in the Parliament of Trinidad and Tobago, which seeks to make revisions to the Property tax regime. The amendments provide for a waiver of the 2016 and 2017 property tax liabilities. This bill is expected to be passed and assented to in 2018. The potential impact of this would result in a reduction in Property taxes accrued of $1.1 million.

This information is provided by RNS

The company news service from the London Stock Exchange

END

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Trinity Exploration & Production (TRIN)

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