Trinity Regulatory News (TRIN)

RNS ANNOUNCEMENT: The information communicated in this announcement contains inside information for the purposes of Article 7 of Regulation 596/2014.

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 unaudited preliminary results for the 12 months ended 31 December 2018.

2018 was a significant year for Trinity with the recommencement of onshore drilling activities, continuation of our low-cost work programme and strengthening of our balance sheet. The maintenance of our high operating margins and increase in production propelled us to exit the year in a strong financial and operational position as evidenced by our Q4 2018 production levels being in excess of 3,000 bopd and our Adjusted EBITDA margin for the year exceeding 30%.

Key Performance Indicators

1. Realised price: Actual price received for crude oil sales per barrel ("bbl"). A discount is normally applied to the West Texas Intermediate ("WTI") price by The Petroleum Company of Trinidad and Tobago Limited ("Petrotrin") (1 January 2018 - 30 November 2018) and Heritage Petroleum Company Limited ("Heritage") (effective 1 December 2018 to present) to derive the realised price received by Trinity.

2. Adjusted EBITDA (USD MM): Operating Profit before Supplemental Petroleum Tax ("SPT") and Property Tax ("PT") for the period, adjusted for Depreciation, Depletion & Amortisation ("DD&A"), non-cash share option expenses and Other Expenses (derivative hedge instruments)

3. Adjusted EBITDA (USD/bbl): Adjusted EBITDA/Annual production

4. Adjusted EBITDA Margin (%): Adjusted EBITDA/Revenues

5. Adjusted EBITDA SPT and PT (USD MM): Adjusted EBITDA less Supplementary Petroleum Taxes and Property Taxes

6. Consolidated operating break-even: The realised price where Adjusted EBITDA for the entire Group is equal to zero

7. Cash plus working capital surplus: Current assets less Convertible Loan Notes ("CLN") less Trade and other payables less Taxation payable less Derivative financial instrument (CLN and Ministry of Energy and Energy Industries of T&T ("MEEI") is face value of debt, including accrued interest)

Financial Highlights

· Revenues increased by 38% to USD 62.6 million (2017: USD: 45.2 million)

· Adjusted EBITDA increased 51% to USD 19.2 million (2017: USD 12.7 million)

· Adjusted EBITDA margin of 31% (2017: 28%) or USD 18.3/bbl (2017: USD 13.8/bbl)

· Adjusted EBITDA after SPT and PT up 21% to USD 12.8 million (2017: USD 10.6 million)

· Maintained a group operating break-even price below USD 30.0/bbl

· Cash balance of USD 10.2 million (2017: USD 11.8 million) impacted by one-off increase in trade receivables of USD 6.7 million relating to the Petrotrin restructuring. Post the period-end, USD 4.1 million of these outstanding receivables have been collected and full collection of the remaining USD 2.6 million is expected by the end of H1 2019

· Cash plus working capital surplus of USD 18.1 million (2017: USD 0.1 million)

Corporate Highlights

· Balance sheet significantly strengthened with all outstanding debt fully repaid following USD 20 million fundraise which also provided funds for ongoing onshore drilling programme

· Strengthening of Board, with appointment of Nicholas Clayton as Senior Independent Director

Operational Highlights

· The Company's total 2P reserves (Onshore and Offshore) increased to 24.49 million stock tank barrels ("mmstb") (6% increase vs 2017: 23.21 mmstb)

· Driven primarily by 26% increase in onshore reserves following on from a 45% increase in 2017

· Total 2P reserves and 2C resources of 43.26 mmstb at 31 December 2018 (2017: 47.19 mmstb)

· Average production of 2,871 bopd (2017: 2,519 bopd), representing a 14% increase, underpinned by:

o Drilling of eight new onshore wells efficiently and cost effectively on a turnkey basis

o 17 recompletions ("RCPs") (2017: 37) including first offshore RCP

o Increase in active offshore wells producing to 31 (2017: 17)

o Base production maintenance through a continuous campaign of 143 workovers ("WO") and reactivations (2017: 97).

· Resulted in exit production rate in excess of 3,000 bopd (Q4 2018: 3,205 bopd)

· Contingent upon the prevailing oil price environment, and subsequent investment, net average production for 2019 is expected to be in the range of 3,000 - 3,300 bopd

 2018 was a significant year for Trinity with the recommencement of onshore drilling activities, continuation of our low-cost work programme and strengthening of our balance sheet. The maintenance of our high operating margins and increase in production propelled us to exit the year in a strong financial and operational position as evidenced by our Q4 2018 production levels being in excess of 3,000 bopd and our Adjusted EBITDA margin for the year exceeding 30%.

The Fundraise which we completed in July 2018 means that we are fully funded and debt free. Equally importantly, the sustained generation of strong operating cash flows and a consolidated operating break-even below USD 30.0/bbl provides significant downside protection in the event of a decline in the oil price.

We continue to focus on delivering our planned work programme, with our fully funded drilling operations providing near-term production upside, targeting year-on-year production growth of at least 10%. Added to this, as the development effort continues to mature on our TGAL Area development plan, the Company is increasingly excited the project. The TGAL development has the potential to achieve a step change in production and value for the Company as we target our medium-term production goal of 7,500 bopd. Furthermore, we believe there are a number of inorganic growth opportunities that the Company could pursue, and we are well placed to take advantage of any suitable opportunities that may arise.

The broader environment in T&T remains extremely promising. Whilst there have been some one-off challenges in the transition from Petrotrin to Heritage, we are confident that our locally led business model is well suited to the future based on our incumbent position and strong relationships on the ground in T&T.

With average realisations being above USD 50.0/bbl for 2018, the regressive Supplemental Petroleum Tax ("SPT") impacted cash conversion levels. SPT in its current structure is a global anomaly and disadvantages oil producers when compared to gas producers. Trinity, alongside other crude oil producers in T&T, continue to lobby for its reform as was promised by the current Government. We believe that reform would re-calibrate the economics for all crude oil operators in the region while potentially opening up new investment opportunities.

Alongside working towards a more equitable fiscal environment for oil producers, Trinity continues to strive to optimise the economic returns from its asset base; with a determined focus on subsurface analysis, using the best data available and adopting new technological approaches to include high angle or horizontal drilling.

Given the strength of our ongoing work programme and visibility afforded by our balance sheet, we face the future with a growing confidence. We anticipate further strategic opportunities arising in 2019 and are committed to delivering value for all our stakeholders and with our local model, we are ideally positioned to take advantage of such changes.

Bruce Dingwall, CBE, Executive Chairman of Trinity, commented:

"2018 was a significant year for Trinity with the recommencement of onshore drilling activities, continuation of our low-cost work programme and strengthening of our balance sheet. We face the future with a growing confidence, ideally positioned to take advantage of strategic opportunities arising in 2019 for the benefit of all our stakeholders."

All figures for the financial year 2018 are unaudited. The Board of Directors ("The Board") currently expects to publish its annual report and accounts for the year to 31 December 2018 before the end of April 2019, with the Annual General Meeting ("AGM") expected to take place during May 2019.

Enquiries

For further information please visit www.trinityexploration.com or contact:

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 2018 was 24.5 mmbbls. Group 2C contingent resources are estimated to be 18.8 mmbbls. The Group's overall 2P plus 2C volumes are therefore 43.3 mmbbls.

Trinity is quoted 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 on market. 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, to efficiently deliver profitable returns and to prudently convert our significant contingent ("2C") resources to 2P reserves and future inventory.

Delivering production growth whilst sustaining a low operating break-even

Trinity's focus in recent years has been on preserving the integrity of our producing asset base whilst improving operational practices and efficiencies to materially re-base costs. 2018 was the first year since 2013 that Trinity undertook new onshore drilling, with two new wells in H1 and six new wells in H2. The resulting production growth, and improved crude oil prices, had a positive impact on our revenues in 2018. As we progress into 2019, the financial impact of higher base production and new production growth from our continuing drilling programme should become even more apparent.

Average production volumes grew in aggregate by 14% to 2,871 bopd in 2018 (2017: 2,519 bopd). With increased activity levels during H2 2018 there was a 15% quarter on quarter increase in average production volumes to 3,205 bopd for Q4 2018 (Q3 2018: 2,734 bopd). The increase in annualised production was underpinned by a combination of eight new onshore development wells coming on stream during 2018, an increase in active offshore wells producing from 17 to 31 and the continuation of the Group's low-cost ongoing work programme of RCPs, WOs, reactivations and swabbing. The 2018 work programme included a total of 17 RCPs (2017: 37), and 143 WOs and reactivations (2017: 97). On the East Coast, the first offshore RCP on the Trintes field was undertaken by Trinity since assuming operatorship in 2013. It was successfully completed during Q4 2018 and put on production at a rate ahead of management's expectations.

Financial Performance

The result of the 14% growth in production volumes and 23% improvement in oil prices was a 38% increase in revenues to USD 62.6 million (2017: USD 45.2 million). This resulted in a strong operating performance with a 51% increase in Adjusted EBITDA to USD 19.2 million (2017: USD 12.7 million) which is the equivalent of USD 18.3/bbl (2017: USD 13.8/bbl) and US 5.4 cents per share (diluted) (2017: US 3.2 cents) representing a 69% year-on-year increase.

However, bottom-line profitability and cash conversion was negatively affected by the application of SPT which is a regressive tax on net revenues when realised oil prices are above USD 50.0/bbl (2018 average realisations of USD 59.8/bbl vs 2017 of USD 48.6/bbl). The like-for-like comparison of Adjusted EBITDA after SPT and PT was USD 12.8 million (USD 12.2/bbl) for 2018, a 21% increase versus USD 10.6 million (USD 11.6/bbl) for 2017, which equated to a 33% year-on-year increase in Adjusted EBITDA after Taxes of US 3.6 cents per share (diluted) (2017: 2.7 cents).

Operating Cash Flow ("OCF") for 2018 was USD 12.1 million (2017: USD 8.7million). Net OCF after changes in working capital movements and income taxes was USD 5.2 million (2017: USD 9.6 million). The reduction is mainly a function of a USD 4.4 million year-on-year increase in cash taxes paid (largely related to SPT) and an increase in trade receivables totalling USD 6.7 million. The increase in trade receivables was due to delayed revenue receipts of USD 6.7 million as a result of the Petrotrin restructuring (see details below). Post the year end, USD 4.1 million of the outstanding receivables from Petrotrin have been collected and full collection of the remaining USD 2.6 million is expected to occur by the end of H1 2019. Stripping out the increase in receivables, the like for like OCF after changes in working capital would have been USD 11.8 million versus USD 9.6 million for 2017.

The Group's cash balances at the year-end stood at USD 10.2 million (2017: USD 11.8 million). The lower cash balance is as a result of capital expenditures of USD 12.5 million (2017: USD 3.1 million) and the repayment of all outstanding debts to Board of Inland Revenue of T&T ("BIR") and Ministry of Energy and Energy Industries of T&T ("MEEI") (together "T&T State Creditors") and Convertible Loan Notes ("CLN") holders (USD 5.8 million and USD 7.2 million respectively). However, importantly, the Company is now debt free, with no dilutive CLN overhang, and has the financial flexibility required to grow by the most effective means. In aggregate, the resultant cash plus working capital surplus (cash plus net operating working capital) stood at an impressive USD 18.1 million (2017: USD 0.1 million)

Reserve base continues to grow

Management's estimate of the Company's total 2P reserves (Onshore and Offshore) increased by 6% to 24.49 million stock tank barrels ("mmstb") (2017: 23.21 mmstb), despite total production of 1.04 mmstb. This increase is testament to the quality of our onshore and offshore producing assets and the benefits of the return to robust subsurface evaluation to identify additional infill drilling, RCP and WO candidates. Onshore reserves grew significantly by 26%, following on from a 45% increase in 2017 as the subsurface team continued to add locations to the onshore drilling inventory.

2C resources decreased by 22% to 18.77 mmstb (2017: 23.98 mmstb). The movement in 2C resources primarily reflects moving some 5.98 mmstb (net) of TGAL resources to 3C until a formal development solution is finalised. This follows the high grading of a first phase development stage targeting 10.41 mmstb (net) with more robust overall economics. In aggregate, total 2P reserves and 2C resources amounted to 43.26 mmstb at 31 December 2018 (2017: 47.19 mmstb). 

Corporate

Funded and Debt Free

In July 2018 the Company raised gross proceeds of USD 20.0 million through a Fundraising exercise comprising a placing and an open offer. Of this, USD 6.4 million comprised a non-cash rollover by holders of 88% of the CLNs electing to convert the value of their CLNs into new ordinary shares at the issue price. This enabled the full and final repayment of all outstanding debts to the T&T State Creditors as well as redemption of the remaining CLNs which were outstanding. The Fundraise has enabled the Company to accelerate its onshore drilling programme and production, with a planned 8-10 wells per year going forward subject to a conducive landscape and economic environment.

East Coast Asset Development

In November 2018 the Company, as operator of the Galeota licence, submitted the first phase of its revised Field Development Plan ("FDP") for the TGAL Area to the MEEI. Work is now ongoing on pre- Front End Engineering Design ("FEED") studies and environmental approvals as we move towards a Final Investment Decision ("FID") during H1 2020.

This FDP is the first phase of a potential wider development strategy moving across the Galeota anticline to fully develop the reserves potential from the large volumes of oil in place (c. 700 mmbbls). The first phase currently contemplates the installation of a low cost, 10 well conductor supported platform, the installation of a new generation thermoplastic composite subsea export pipeline, the laying of a subsea power cable to provide power to the offshore facilities, and the drilling of horizontal production wells. The development of these assets would underpin our medium-term group onshore and offshore production target of over 7,500 bopd.

Petrotrin Restructuring and Heritage Update 

On 28 August 2018 Petrotrin announced its intention to discontinue refining operations to focus on its upstream exploration and production activities following a restructuring. To that end the new national oil company, Heritage began trading on 1 December 2018. Whilst the transition has been relatively seamless with regards to production, supply and distribution, there have been delays in the timing of payments for October and November oil production from Petrotrin. As a result, Trinity's receivables increased by USD 6.7 million at the year end. To date, USD 4.1 million of the USD 6.7 million delayed revenues have been collected and under Heritage's stewardship since December 2018 all payments have been received according to the agreed payment terms. The management of both Petrotrin and Heritage have been in close contact with Trinity's management team and have provided the requisite comfort that all outstanding revenues will be received in full during H1 2019.

Trinity currently accounts for approximately 5% of all crude oil production in T&T and we are optimistic of our ability to deliver continued production growth in the short-term. Having established a locally driven, efficient and low-cost operating model, Trinity will work alongside Heritage wherever possible to help facilitate efficiency drives and production growth in T&T with the resultant economic benefits for all citizens and stakeholders.

Overview

This time last year our aim was to stabilise base production, build well inventory and execute a limited investment programme whilst maintaining controls on operating costs and Health, Safety, Security and Environment ("HSSE"). The Company managed to deliver on that initial programme resulting in a significant improvement in our operational performance and a successful year in terms of our key performance indicators ("KPIs").

During 2018, we continued to prioritise HSSE and the well-being of our people, promoting safe behaviours among all stakeholders whilst undertaking a step-change in activity levels. The dedication, hard work and expertise to deliver this growth on a portfolio of 1,094 wells with 216 active wells at the end of 2018 (2017:182) across nine licences and multiple reservoirs has required a huge effort from those involved. As such, we remain extremely thankful to our employees and the continued support of the supply chain, with whom we look forward to working alongside as we continue to build on, and strengthen relationships with all of our stakeholders.

We are ideally placed to continue to grow organically but also very well positioned to make the most of the significant number of other development opportunities that may arise locally. Whilst we work with the Petrotrin restructuring and transition changes with Heritage, we are assured that our locally led business model is well suited to the future based on our strong relationships on the ground in T&T.

Good governance remains at the core and we remain committed to delivering our strategy in a responsible and transparent manner. In November 2018, the Company expanded its Board with the appointment of Nicholas Clayton as a Senior Independent Director. The breadth and depth of his sector specific advisory experience will provide the Board with additional perspective and, combined with our existing Board members, strengthens our collective industry, merger and acquisitions ("M&A") and capital markets expertise as we continue to grow and develop Trinity's business.

Plans for 2019 and beyond

We are ideally placed to continue to grow organically but also very well positioned to make the most of the significant number of other development opportunities that may arise locally. Whilst we look forward to working with Heritage going forward, we are assured that our locally led business model is well suited to the future based on our strong relationships on the ground in T&T.

The Company's successful drilling programme completed during Q4 means that it fulfilled stated >10% per annum ("p.a.") production growth target for 2018 and, subject to the scheduling of the drilling programme, Trinity is targeting similar growth in 2019. The fully funded onshore drilling programme will continue, but given recent oil price volatility, the timing and scale of the programme will be determined with a view to optimising capital allocation.

We see a number of options for further value creation across Trinity's asset base both organically and from wider portfolio management. Our programme of phased and risk mitigated development activities through infill development wells onshore, routine RCPs, WOs, reactivations and swabbing on the current well stock has succeeded in arresting decline and provided for a step-change in base production on which to further grow.

The Company intends to build on base production to reach a targeted annual average production range of 3,000 - 3,300 bopd for 2019. The absolute level of growth from production will be determined by oil price and activity levels which will be set with a view to optimising profitability and cash flows, and not just top-line production growth.

The Company's strengthened balance sheet and low operating break-even provides financial resilience to low oil prices and gives confidence that the Company's growth and investment plans can be optimised according to the prevailing macro and fiscal environment.

On behalf of the Board, I must thank all our staff and suppliers in T&T for their diligence, commitment and support which has allowed Trinity to focus on growth whilst maintaining a safe working environment. The Board would additionally like to take this opportunity to thank existing shareholders and other stakeholders, notably Petrotrin, Heritage, BIR, and the MEEI, for their support and to welcome new shareholders as we move forward debt free and strongly positioned to add value from future opportunities in the changing environment in T&T.

2018 was a notable year for Trinity and the Board is confident that the quality and low cost nature of our underlying assets will deliver sustainable cash generation throughout oil price cycles and excellent returns for shareholders from the execution of our strategy in 2019 and beyond.

KEY PERFORMANCE INDICATORS

The Group's performance was profitable at an operating level throughout 2018 with a 51% increase in Adjusted EBITDA of USD 19.2 million (2017: USD 12.7 million), year-end cash balance of USD 10.2 million (2017: USD 11.8 million) and a cash plus working capital surplus of USD 18.1 million (2017: USD 0.1 million).

A summary of the year-on-year operational and financial highlights are set out below:

1. Realised price: Actual price received for crude oil sales per barrel ("bbl"). A discount is normally applied to the West Texas Intermediate ("WTI") price by Petrotrin (1 January 2018 - 30 November 2018) and Heritage (effective 1 December 2018 to present) to derive the realised price received by Trinity.

2. Annual production (mmbbls)- Production from a reserves perspective is what is produced from the reservoir in a given year - which is 1.04 mmbbls (2,855 bopd) in 2018. For cash flow purposes it is the sold production in a given year which for 2018 is 1.05 mmbbls (2,871 bopd). These minor differences occur at year end due to stock sales in December and carry forward to subsequent year. See Reserves and resources section for further details.

3. Adjusted EBITDA (USD MM): Operating Profit before SPT and PT for the period, adjusted for Depreciation, Depletion & Amortisation ("DD&A"), non-cash share option expenses and Other Expenses (derivative hedge instruments)

4. Adjusted EBITDA (USD/bbl): Adjusted EBITDA/Annual production

5. Adjusted EBITDA Margin (%): Adjusted EBITDA/Revenues

6. Adjusted EBITDA Per Share - Diluted: Adjusted EBITDA / Weighted average ordinary shares outstanding - diluted 

7. Adjusted EBITDA after SPT and PT (USD MM): Adjusted EBITDA less Supplementary Petroleum Taxes ("SPT") and Property Taxes ("PT")

8. Adjusted EBITDA after SPT and PT (USD/bbl): Adjusted EBITDA after SPT and PT/Annual production

9. Adjusted EBITDA after SPT and PT Per Share - Diluted: Adjusted EBITDA after SPT and PT / Weighted average ordinary shares outstanding - diluted

10. Consolidated operating break-even: The realised price where Adjusted EBITDA for the entire Group is equal to zero

11. Cash plus working capital surplus: Current assets less CLN less Trade and other payables less Taxation payable less Derivative financial instrument (CLN and MEEI is face value of debt, including accrued interest)

ADJUSTED EBITDA CALCULATION

Adjusted EBITDA is a non-IFRS measure used by the Group to measure business performance. The Group presents Adjusted EBITDA metrics as they are used in assessing the Group's growth and operational efficiencies as they better illustrate the underlying performance of the Group's business by excluding items not considered by management to reflect the underlying operations of the Group.

See Note 22 to Consolidated Financial Statements - Adjusted EBITDA for further details

2018 TRADING SUMMARY

A 5-year historical summary of realised price, production, operating break-evens and Production Costs ("Opex") and General & Administrative ("G&A") expenditure metrics is set out below:

Notes:

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

2. Consolidated Operating Break-even: Includes G&A but excludes share option expenses

3. G&A/bbl - Consolidated: Excludes share option expenses

The above production trends show clearly the impact that returning to drilling has had with Onshore production up over 16% year-on-year despite the new drilling mainly impacting in the final quarter of the financial year. Similarly, the impressive impact of active production and well management offshore the East Coast has been to deliver a five year average volume of 1,033 bopd and a very stable platform from which to grow when development recommences on the East Coast.

Of particular note from a financial standpoint is that robust constituent asset and corporate level operating break-evens were sustained with an aggregate increase of only 2% in the Group consolidated operating break-even to USD 29.0/bbl (2017: USD 28.4/bbl). The consolidated operating break-even includes the Group's G&A costs and therefore captures the corporate costs associated with supporting the asset base.

At the aggregated corporate level the maintenance of such a robust consolidated operating level break-even reflects higher production volumes offsetting higher expenses as detailed below:

• Overall Opex increased by 21% to USD 17.8 million (2017: USD 14.7 million). This variance was largely a function of a larger WO programme, production optimisation and increased vessel and equipment rental from higher activity levels.

• G&A costs increased by 40% to USD 6.0 million (2017: USD 4.3 million). This is predominately a function of non-cash related expenses (unrealised foreign exchange gain USD (0.0) million (2017: USD (0.5) million) and share option expenses USD 0.7 million (2017: USD 0.3 million)) as well as increased staff costs, levies and corporate expenses.

Operating netback (Revenues minus Royalties and Production costs) increased 47% to USD 24.4 million (2017: USD 16.7 million). On a per barrel basis this represents a 33% increase in operating netback to USD 23.4/bbl (2017: 17.6/bbl).

OPERATIONAL REVIEW

OUR PEOPLE

Trinity's workforce stood at 215 (2017: 188) at the year-end December 2018 with 79% (170) male and 21% (45) female employees. Our employees are located both in the United Kingdom ("UK") and T&T, with the majority (97%) 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. The HSSE report is considered at each Board meeting and is one of the first matters considered on the agenda.

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 an incident free environment. 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 learned and several proactive initiatives implemented across all operations. Trinity recorded 643,400 man hours in 2018 (2017: 486,200 man hours), a 32% increase, mainly due to the 2018 work programme which included onshore drilling as well as onshore and offshore RCPs and workovers. Training hours recorded also saw an increase of 14% to 2,718 hours from 2,384 hours as safety remained as a top priority to Trinity to ensure that employees are competent to execute all tasks in a safe and efficient manner.

Trinity continues to build its HSSE management system as per our Safe to Work ("STOW") T&T certification attained in February 2018 from the Energy Chamber of T&T. The renewal process and audit commences in Q3 2019 in preparation for recertification in February 2020. Trinity was able to attain a two year certification within a four month period which surpassed the 6-12 month standard process. This is considered a great achievement since new companies to the STOW T&T certification process rarely achieve a two year certification. This certification provides the assurance that our HSSE management system is developed in such a form to allow us to have the ability to respond, control and analyse safety events and performance data as well as allowing us to be proactive in mitigating and managing risk. Notwithstanding our 2018 achievements, in 2019 Trinity intends to continue its focus on sustaining and improving our HSSE management system to ensure that we deliver our production targets safely and efficiently.

PRODUCTION

Average net production for 2018 was 2,871 bopd (2017: 2,519 bopd), an increase of 14%. A total of eight new infill development wells, 17 RCPs, 143 WOs and reactivations along with swabbing activities were undertaken during 2018.

We are constantly striving towards re-setting base production upwards. This requires continuous efforts, good acreage and the application of new technologies. An overview of these activities by asset is given below.

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 2018 net production from the Onshore assets was 1,563 bopd which accounted for 54% of total annual average production. This represented a 16% increase in production from the 2017 average net production levels of 1,347 bopd. The growth in year-on-year production averages is reflective of the step-change in investment activities beginning to impact in adding new production whilst simultaneously successfully maintaining base production.

The drilling programme carded for 2018 initially consisted of four new infill wells. The first two wells were drilled in H1 2018 before expanding the campaign by drilling a further six wells in H2 2018.

Trinity's RCP campaign contemplated the completion of 12 RCPs onshore. The programme was executed in the first 10 months of the year, eventually recompleting 16 wells (2017: 37) across all Onshore blocks. The RCPs and WOs were executed utilising Trinity's internal rigs through H1, while contracting two rigs for the remainder of the year. The internal rigs were removed from service during H2 for upgrades and overhaul.

The Onshore WO and reactivations campaign contemplated the completion of 84 WO's onshore. For 2018, 113 were completed (2017: 78).

Going forward, the Company intends to continue with development activities via infill development drilling, RCPs, WOs, reactivations and swabbing on the current well stock and identified drilling locations to maintain base production and provide for further production growth.

East Coast Assets

Current East Coast production is derived from the Alpha, Bravo and Delta platforms in the Trintes Field which sits within the Galeota Block.

Average 2018 net production from the East Coast was 1,110 bopd which accounted for 39% of total annual average production. This represented a 16% increase in production from the 2017 average net production levels of 961 bopd. The increase was largely as a result of the successful execution of a rigorous workover and reactivation campaign. Alongside these activities the successful completion of the first RCP undertaken by Trinity since assuming operatorship in 2013 was undertaken during Q4 2018 and put on production at a rate ahead of Management's expectations.

In 2018, 23 restorative WOs were completed (2017: 18) which contributed to an upward trend in production. In 2018 production was derived from 32 of a possible 61 wellbores in the Trintes field. The Trintes field produced by deploying numerous pumping technologies across our well stock including; Mechanical Pumping Hydraulic Unit ("MPHU"), Hydraulic Diaphragm Electric Submersible Pump ("HDESP"), Electric Submersible Pump ("ESP") and Progressing Cavity Pumps ("PCP"). The team continues to explore further means of optimising production through the utilisation of downhole remote monitoring, chemical treatment for the prevention of scale formation and modified artificial lift technologies. 

Various infrastructure projects were undertaken during 2018 which included crane assessment and recertification works, the acquisition of four new generators, accommodation upgrades and the commencement of phase 1 Front-End Engineering Design ("FEED") process for 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 and continued optimisation of alternative artificial lift technologies to augment production rates and maintain efficiency and cost effectiveness.

West Coast Assets

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

Average 2018 net production from the West Coast was 198 bopd which accounted for 7% of total annual average production. This represented a 6% decrease in production from 2017 average levels of 212 bopd and was mainly as a result of natural production decline.

There were no major production related activities conducted on the West Coast assets in 2018, with the exception of three WOs (2017: one) in the PGB field and four WO (2017: one) on the land-based wells in the Brighton Field which were undertaken with the intention of reducing natural production decline and stabilising base production levels. Minor infrastructural works were undertaken on the offshore platforms to maintain asset integrity and production.

Management are continuing to keep the potential sale of the West Coast assets under review. In the interim, the assets continue to generate positive cash flow and 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 increase production. These assets will continue to be closely monitored as progressive steps are taken to further optimise 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 24.49 mmstb at the end of 2018, compared to the year-end 2017 reserve estimate of 23.21 mmstb. This represents a 6% increase of 1.28 mmstb from 2017 levels, despite production for 2018 of 1.04 mmstb (2017: 0.92 mmstb). This increase reflects contributions from new wells, sustained RCP production, updated decline curve analysis on producing wells, low cost well reinstatements and, most significantly, extensive subsurface work to generate additional infill drilling, RCP and WO candidates.

Onshore reserves grew by 26% as a result of our ongoing continued investment in subsurface analysis. This follows on from a 45% increase delivered in 2017. Management considers this to be the best estimate of the quantity of reserves that will actually be recovered from the assets at the end of 2018. It represents production which is commercially recoverable, either to licence/relevant permitted extension end or earlier via 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 2018 2P Reserves

Note (*): Production from a reserves perspective is what is produced from the reservoir in a given year-in this case 2,855 bopd. For cash flow purposes it is the sold production in a given year and this figure is given elsewhere as 2,871 bopd. These minor differences occur at year end due to stock sales in December and carry forward to subsequent year.

The best estimate of 2C resources due to the current economic environment and the defining technical work pending is estimated by management at 18.77 mmstb (2017: 23.98 mmstb).

Unaudited 2018 2C Resources

Unaudited Summary of Reserves and Resources

at 31 December 2018

EAST COAST

Trintes (Trinity: 100% WI)

On the East Coast, Trinity has an established production hub on the Trintes field with 4 offshore marine platforms; (Alpha, Bravo, Charlie & Delta) that have an aggregate of 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 14.8 mmstb therefore represents a low incremental recovery factor of 6%. Within contingent resources a further 5.96 mmstb relates to the Trintes field.

TGAL Field Development Plan (Trinity: 65% WI)

The TGAL area carries an internal best estimate STOIIP of 186 mmstb. The TGAL updip fault panel was confirmed as oil bearing in all major reservoir horizons by the TGAL-1 discovery well and is now incorporated in the 2018 FDP. In November 2018 the first phase of the FDP for the TGAL Area, located on the Galeota Block (updip from and on the same anticline as the Trintes field), was submitted to the MEEI. This FDP is the first phase of a potential wider step-out development moving across the Galeota anticline to fully develop the reserves potential from the large volumes of oil in place (see Reserves & Resources review for further details).

Work is progressing on FEED studies and environmental approvals as we move towards a FID during H1 2020, at which time the optimal scheme for financing the development will have been selected and agreed between all stakeholders. The 2018 FDP envisages 10 wells and is a lower development cost solution targeting the deeper sands using vertical conductors when compared to scheme outlined in the 2015 FDP which previously outlined 17 wells and the following key features:

· Conductor Support Platform ("CSP") designed to accommodate a platform rig

· 25 year design life

· A 6" ID Thermoplastic Composite Pipeline ("TCP") from the TGAL platform to shore

· Subsea power cable from shore to the platform

· First oil estimated being produced by H1 2022 and peak production estimated at 5,800 bopd

· 2C resources c.16.02 mmstb gross (10.41 mmstb net)

· At FID Trinity anticipate the net 2C resources would be reclassified as 2P reserves

This 2018 FDP is viewed as the first phase of a potential broader development moving across the Galeota anticline to commercialise the reserves potential from the large volumes of oil in place (c. 700 mmstb). The shallow sands (which were to be accessed via 7 wells in the 2015 FDP) but necessitate drilling slanted conductors/drilling have been moved to the 3C category (9.20 mmstb gross, 5.98 mmstb net) pending the integration of a technical solution into the current vertical conductor CSP platform concept. The current TGAL total 2C+3C volumes are therefore 25.22 mmstb (16.4 mmstb net). Within the Galeota anticline licence area there is also significant additional prospectivity with 266 mmstb STOIIP having been mapped over and above the Trintes and TGAL areas. Even excluding this further upside potential, with current combined 2P reserves and 2C resources of 32.68 mmstb, the potential growth from future Trintes drilling and TGAL development is substantial.

FINANCIAL REVIEW

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 Group's accounting policies and details of accounting judgements and critical accounting estimates are disclosed within Note 3 of the Financial Statements. The Group has adopted additional accounting policies in the year ended 31 December 2018 as set out in Note 3 of the Financial Statements.

Throughout this report reference is made to adjusted results and measures. The directors believe that the selected adjusted measures allow management and other stakeholders to better compare the normalised performance of the Group between the current and prior year, without the effects of one-off or non-operational items and better reflects the normalised underlying cash earnings achieved in the year. In exercising this judgment, the directors have taken appropriate regard of International Accounting Standards ("IAS") 1 "Presentation of financial statements". For the reasons stated above, Adjusted EBITDA excludes the impact of DD&A, non-cash share option expenses, and the impact of derivative hedge instruments ("adjustment items") and these are summarised on the face of the Consolidated Income Statement as well as being described in Note 22 to the financial statements.

Results for the year

Trinity and its subsidiaries ("the Group") recorded an Adjusted EBITDA of USD 19.2 million (2017: USD 12.6 million), a reported loss for the year of USD (5.3) million (2017: USD 25.4 million profit), an ending cash balance of USD 10.2 million (2017: USD 11.8 million) and a net cash plus working capital surplus position of USD 18.1 million (2017: USD 0.1 million).

· Revenue growth from increased production and oil price realisations: The combination of a 14% increase in production to 2,871 bopd (2017: 2,519 bopd) and a 23% increase in average oil price realisations to USD 59.8/bbl (2017: USD 48.6/bbl) resulted in a 38% increase in revenues to USD 62.6 million (2017: USD 45.2 million).

· Successful capital expenditure work programme: USD 12.5 million (2017: USD 3.1 million) incurred in predominately production related and infrastructure expenditure. 2018 saw the company return to drilling, with 8 Onshore development wells, 16 Onshore RCP's and the first RCP on the East Coast since acquiring the asset in 2013. Infrastructure capital expenditure were also conducted across the assets to support the production initiatives.

· Further growth in operating margins and increased operating profitability: The Company maintained its focus on growing margins and increasing operating profitability which is evident in a 51% increase in Adjusted EBITDA to USD 19.2 million (2017: USD 12.7 million) and maintaining a robust consolidated operating break-even price of USD 29.0/bbl (2017: USD 28.5/bbl), while increasing Adjusted EBITDA Margin to 31% in 2018 (2017: 28%). On a per barrel basis this represents a 33% increase in Adjusted EBITDA to USD 18.3/bbl (2017: USD 13.8/bbl) and Adjusted EBITDA per share - diluted increased 69% to 5.4 cents (2017: 3.2 cents).

· Supplementary Petroleum Taxes ("SPT") and Property Taxes ("PT"): 2018 saw average oil price realisations rise above USD 50.0/bbl (2018: USD 59.8/bbl) into the SPT paying range. As a result, SPT of USD 7.1 million was incurred in 2018 (2017: USD 1.5 million). For each quarter that realised oil prices are higher than USD 50.01/bbl SPT is charged at a rate of 18% and 26% on net revenues (gross revenue - royalties - incentives) on Onshore and Offshore assets respectively. The headline SPT rates are, however, partially mitigated by investment tax credits of 20%. SPT is seen by many commentators as being a regressive tax, which negatively impacts on investment and unfairly penalises oil (as opposed to gas) companies. SPT reform has been earmarked by the Government of Trinidad and Tobago ("GORTT"), but has not yet been effected.

The passing of the Property Tax Amendment Bill by the T&T House of Representatives resulted in a PT credit of USD 0.7 million (2017: USD (0.5) million charge) with the USD 1.1 million reversal for 2016 and 2017 offsetting a USD 0.4 million charge for the current year.

· Impairment loss: During the year the Group recorded an impairment loss of USD 2.6 million (2017: nil) within exceptional items on its oil and gas assets held within property plant and equipment. The carrying values of certain of the Group's cash generating units were higher than their recoverable amount measured utilising discounted cash flow approach to Fair Value less Cost of Disposal. This was largely driven by the lower oil price forward curve at 31 December 2018, and a more conservative cost of capital assumption being applied.

· Reported Profitability and Cash conversion: Bottom-line profitability and cash conversion was negatively impacted by SPT. The like for like comparison of Adjusted EBITDA after SPT and PT is USD 12.8 million (USD 12.2/bbl and 3.6 cents per share - diluted) for 2018 versus USD 10.6 million (USD 11.5/bbl and USD 2.7 cents per share - diluted) for 2017.

The inclusion of DD&A, hedging costs, other non-cash items, exceptional items and net finance costs yielded a reported post tax loss for the period of USD 5.3 million (2017: USD 25.4 million profit). Notably, in 2017 there was an exceptional non-cash credit of USD 26.7 million, which related to the restructuring that occurred in January of that year.

Operating Cash Flow ("OCF") for 2018 was USD 12.1 million (2017: USD 8.7million). Net OCF after changes in working capital movements and income taxes was USD 5.2 million (2017: USD 9.6 million). The reduction is mainly a function of a USD 4.4 million year-on-year increase in cash taxes paid (largely related to SPT) and an increase in trade receivables totalling USD 6.7 million. The increase in trade receivables was due to delayed revenue receipts of USD 6.7 million as a result of the Petrotrin restructuring (see details below). Post the year end, USD 4.1 million of the outstanding receivables from Petrotrin have been collected and full collection of the remaining USD 2.6 million is expected to occur by the end of H1 2019. Stripping out the increase in receivables, the like for like OCF after changes in working capital would have been USD 11.8 million versus USD 9.6 million for 2017.

· Strong net cash plus working capital surplus: The lower OCF after changes in working capital combined with higher capital expenditure of USD 12.5 million (2017: USD 3.1 million) and the repayment of all outstanding debts to T&T state creditors and CLN holders (USD 5.8 million and USD 7.2 million respectively) pushed down cash balances at year end. Cash balances at the year-end stood at USD 10.2 million (2017: USD 11.8 million). Nevertheless, Trinity had a strong net cash plus working capital surplus of USD 18.1 million (versus USD 0.1 million in 2017). Crucially, the Company is now debt free, with no dilutive CLN overhang, and has the financial flexibility to grow by the most effective means.

· Mitigating downside price risk: In 2018, a USD 1.0 million loss was incurred on the crude oil derivative instrument and recorded within Other Expenses which protected against downside oil prices below USD 45.0/ bbl utilising a Zero Cost Collar. For 2018 the WTI price ranged from USD 62.3/bbl to USD 70.7/bbl between January and October 2018. The WTI price traded in a range of USD 59.8/bbl to USD 56.7/bbl in November and USD 49.1/bbl for December 2018, hence no settlements were incurred in those months. This hedge expired on 31 December 2018 and so no hedge valuations are included for the year end financials.

STATEMENT OF COMPREHENSIVE INCOME ANALYSIS

Revenues

2018 crude oil sales revenues were USD 62.6 million (2017: USD 45.2 million). This 38% increase was attributable to a 14% increase in production volumes to 2,871 bopd (2017: 2,519 bopd) and a 23% increase in the average realised oil price to USD 59.8/bbl (2017: USD 48.6/bbl).

Operating expenses

Operating expenses increased by 24% in 2018 to USD (55.9) million (2017: USD (41.2) million). Operating expenses comprised:

• Royalties of USD 20.4 million (2017: USD 13.8 million) have increased due to a combination of increased sales volume and price.

• Production costs of USD (17.8) million (2017: USD (14.7) million) have increased due to more workovers, production optimisation and vessel and equipment costs complimenting the increased activity levels.

• G&A expense of USD (6.0) million (2017: USD (4.3) million), increased mainly due to non-cash share option expense of USD (0.7) million (2017: USD (0.3) million) and unrealised foreign exchange gain USD 0.0 million (2017: USD 0.5 million)

• Depreciation, depletion and amortisation ("DD&A") of USD (10.7) million (2017: USD (7.0) million).

• Other Expenses of USD (1.0) million (2017: (1.4) million) includes the impact of derivative hedge instruments in relation to the Zero Cost Collar in effect during 2018 USD (1.0) million (2017: USD (0.8) million) and Put Options nil (2017: USD (0.6) million).

Supplemental Petroleum Tax and Property Tax

SPT and PT were USD (6.5) million (2017: USD (2.0) million) and comprised:

• SPT of USD (7.1) million (2017: USD (1.5) million) due to realised oil prices being above USD 50.01/bbl.

• PT credit of USD 0.6 million (2017: USD (0.5) million) which included the current year charge of USD (0.4) million and the reversal of the 2016 and 2017 accrual of USD 1.1 million.

Exceptional items

Exceptional items were USD (2.3) million (2017: USD 25.7 million credit) and comprised:

• Impairment of plant property, equipment, receivables, recompletions and inventory USD (2.6) million (2017: USD (0.6) million).

• Reversal of bad debt USD 0.2 million credit (2017: nil) for recovered VAT refunds in relation to 2013 previously written off.

• Restructuring USD (0.0) million (2017: USD 26.3 million credit).

• Unsecured creditors compromised USD 0.1 million credit (2017: nil) relating to write off of remaining creditor balances compromised.

See Note 6 to Consolidated Financial Statements - Exceptional items for further details. The Group's operating loss after exceptional items was USD (2.0) million (2017: USD 27.6 million profit).

Net Finance Costs

In 2018, finance costs amounted to USD (2.1) million (2018: USD (2.3) million) and comprised:

• Unwinding of the decommissioning liability USD (1.6) million (2017: USD (1.6) million).

• Interest accrued on the CLNs USD (0.5) million (2017: (0.7) million).

See Note 7 to Consolidated Financial Statements - Finance Costs for further details.

Income Tax Expense

Taxation charge for 2018 of USD (1.3) million (2017: USD 0.03 million credit), and its components are described below.

• Increase in Deferred Tax Asset ("DTA") for the year with tax losses recognised of USD 1.8 million credit (2017: USD (1.3) million).

• Increase in Deferred Tax Liabilities ("DTL") for the year resulting from accelerated tax depreciation USD (3.1) million (2017: credit of USD 0.4 million).

• Unemployment levy ("UL") USD (0.0) million (2017: USD 0.03 million credit).

See Note 8 to Consolidated Financial Statements - Taxation (expense)/credit for further details.

CONSOLIDATED STATEMENT OF CASH FLOWS ANALYSIS

Cash inflow from operating activities

Operating Cash Flow ("OCF") was USD 12.1 million (2017: USD 8.7 million):

• Loss before income tax of USD (4.1) million (2017: USD 25.3 million profit) included non-cash items amounting to USD 16.2 million (2017: USD (16.7) million). 

• Changes in working capital of USD (6.8) million (2017: USD 0.9 million inflow), primarily as a result of the increased level of trade receivables at the year end.

• Current income taxation paid USD (0.1) million outflow (2017: nil).

Cash outflow relating to the restructuring

Cash outflow relating to full and final repayment of T&T State Creditors amounted to USD (5.8) million (2017: USD (12.6) million).

Cash outflow from investing activities

Cash outflow from investing activities was USD (12.5) million (2017: USD (3.1) million):

• Expenditure on Property, Plant and Equipment for the year was USD (12.3) million (2017: USD (2.8) million) which mainly included 8 Onshore development wells, 17 recompletions and infrastructure upgrades.

• Expenditure on exploration and evaluation assets USD (0.2 million) (2017: nil).

· Expenditure on new software USD (0.0) million (2017: USD (0.3) million).

Cash inflow from financing activities

Cash inflow from financing activities was USD 11.5 million (2017: USD 10.3 million):

• Issue of shares (net of costs and conversion of CLN) USD 12.4 million (2017: 10.8 million).

• Repayment of CLN USD (0.9) million (2017: nil.).

• Issue of CLN (net of costs) nil (2017: USD 3.0 million).

• Settlement of the compromised Citibank loan nil (2017: USD (3.5) million).

See Note 23 to the Consolidated Financial Statements - Convertible loan notes for further details and see Note 19 to the Consolidated Financial Statements - Issue of shares for further details.

CASH PLUS WORKING CAPITAL SURPLUS

Events since the Year End

1. On 2 January 2019 the Company issued awards under its Long-Term Incentive Plan ("LTIP"). The Company awarded the grant of Options over 2,824,000 ordinary shares (representing 0.735% of the Company's issued share capital) under the LTIP.

The LTIP Awards are subject to the achievement of relative Total Shareholder Return ("TSR") performance targets measured over a three year performance period ending on 1 January 2021. These awards have been made in accordance with the policy announced to the market on 25 August 2017 and have been made to certain individuals in respect of the performance of the Group for the financial year ended 31 December 2017.

2. On 15 January 2019, the Group announced that the effective transition date to the new national oil company, Heritage, was 1 December 2018 and the restructuring process with Petrotrin was ongoing. There have been some delays in the receipt of payments for October and November crude oil revenues from Petrotrin with an amount outstanding of USD 6.7 million at year end. The Group has to date received USD 4.1 million of these delayed payments, with the remaining USD 2.6 million which is outstanding expected to be collected by the end of H1 2019. 

Consolidated Statement of Comprehensive Income

For the year ended 31 December 2018

Company Statement of Financial Position

at 31 December 2018

Company Statement of Financial Position

at 31 December 2018

Consolidated Statement of Changes in Equity

for the year ended 31 December 2018

Company Statement of Changes in Equity

for the year 31 December 2018

Consolidated Statement of Cash Flows

for the year ended 31 December 2018

Company Statement of Cash Flows

for the year ended 31 December 2018

Trinity Exploration & Production Plc

Notes to the Consolidated Financial Statements

1 Background and Accounting Policies

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

Background

Trinity Exploration & Production plc ("Trinity" or "the Company") 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 and its subsidiaries (together "the Group") are involved in the exploration, development and production of oil reserves in Trinidad & Tobago ("T&T").

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, with the exception of certain financial assets, financial liabilities (including derivative instruments and the CLN) and classes of property, plant and equipment which are measured at fair value.

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: Critical Accounting Estimates and Assumptions.

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 $2.7 million (2017: $3.2 million loss).

Going Concern

In making their going concern assessment, the Board of Directors (the "Board") have considered the Group's budget and cash flow forecasts. The Group's main objective in 2018 was to grow production, through a fully funded onshore drilling programme and a low cost work programme of Recompletions ("RCPs"), Workovers ("WOs"), reactivations and swabbing.

In July 2018, gross proceeds of $20.0 million were raised through the Fundraising. The Fundraising allowed the Group to repay all outstanding debt to its Board of Inland Revenue of T&T ("BIR") and Ministry of Energy and Energy Industries of T&T ("MEEI") (together the "T&T State Creditors"). Subsequent to this repayment, on 15 August 2018 Trinity settled the remaining balance of the redeemable CLN plus accrued interest. Through the settlement of all outstanding debts, the Group improved on its prior year net current asset position. At 31 December 2018, the Group held net current assets of $17.8 million (2017: $8.1 million).

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 will be able to operate within the level of its current cash resources. Should there be a decline in the oil price, the Board believe there are a number of actions within their control that can be effected. These include deferral of capital expenditure and further reducing operating costs to manageable levels. For these reasons, the Board have a reasonable expectation that the Group has adequate resources to continue operational existence 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 for a period of at least 12 months post approval of the financial statements and is poised for continued growth. For this reason, the Board continues to adopt the going concern basis when 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 2018:

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 2018 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.

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.

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:

(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 G&A 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.

(c) Group companies

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 of disposal 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 has lapsed.

- 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 exists 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.

(c) Computer software

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 ("G&G") costs. Acquisitions of oil and gas properties are accounted for under the acquisition 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 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 of disposal 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 & Amortisation("DD&A")

The provision for DD&A 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 asset

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:

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 of disposal 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. They are generally due for settlement within 30 days and therefore are all classified as current. Trade receivables are recognised initially at the amount of consideration that is unconditional unless they contain significant financing components, when they are recognised at fair value.

The Group applies the simplified approach to determine impairment of trade receivables. The simplified approach requires expected lifetime losses to be recognised from initial recognition of the receivables. This involves determining expected loss rates using a provision matrix that is based on the Group's historical default rates observed over the expected life of the receivable and adjusted forward-looking estimates. This is then applied to the gross carrying amount of the receivable to arrive at the loss allowance for the period.

Trade payables

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

Impairment of financial assets

Financial assets recognition of impairment provisions under IFRS 9 is based on the expected credit losses ("ECL") model. The ECL model is applicable to financial assets classified at amortised cost and contract assets under IFRS 15: Revenue from Contracts with Customers. The measurement of ECL reflects an unbiased and probability weighted amount that is available without undue cost or effort at the reporting date, about past events, current conditions and forecasts of future economic conditions. The Group applied the simplified approach to determine impairment of its trade and other receivables. The simplified approach requires expected lifetime losses to be recognised from initial recognition of the receivables. This involves determining the expected loss rates using a provision matrix that is based on the Group's historical default rates observed over the expected life of the receivables and adjusted for forward looking estimates. This is then applied to the gross carrying amount of the receivables to arrive at the loss allowance for the period.

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 ("PT")

PT 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 PT rate. The PT rate applicable to the Group are industrial with building rates at 6% and industrial without building 3%.

Revenue recognition

IFRS 15 Revenue from Contracts with Customers replaces IAS 18 and IAS 11 with effect from accounting periods commencing 1 January 2018. The new standard requires that revenue is recognised by performance obligation, as or when each performance obligation is satisfied, and that variable elements of pricing are recognised, to the extent that is it not highly probable they will be reversed.

The Group has evaluated its customer contract with the Petroleum Company of Trinidad & Tobago Limited ("Petrotrin") and, from 1 December 2018, Heritage Petroleum Company Limited ("Heritage") to identify performance obligations, timing of revenue recognition and treatment of variable elements of pricing. Sales revenue represents the sales value of the Group's oil sold in the year.

Oil revenue is recognised when title of the crude has passed to the buyer by means of a sales ticket document. Typically, payment for the sale of the oil is received by the end of the month following the month in which the sale is recognised.

Prices are determined by Petrotrin/Heritage, with agreed contractual adjustments based on oil quality. Revenue is measured at the fair value of the consideration received or receivable, and represents amounts receivable for oil and gas products in the normal course of business.

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 comprised the CLN that could, in certain circumstances, have been converted to share capital at the option of the holder, and the number of shares to be issued did 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 Operations 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 2018, 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 $2.9 million (2017: $2.1 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 2018, if commodity prices had been 20% higher/lower with all other variables held constant, post-tax profit/(loss) for the year would have been $12.5 million (2017: $8.7 million) lower/higher. The sensitivity doesn't take into consideration the impact of the derivative instruments 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 2018, there were no loan commitments to attract interest rates on foreign currency-denominated borrowings, (2017: nil).

(b) Credit risk

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

All sales are made to a state-owned entity - Petrotrin/Heritage.

The Group applies the IFRS 9 simplified model for measuring ECL which uses a lifetime expected loss allowance and are measured on the days past due criterion. Having reviewed past payments combined with the credit profile of its existing trade debtors in order to assess the potential for impairment, the Company has concluded that this is insignificant as there has been no history of default or disputes arising on invoiced amounts since inception and as such the credit loss percentage is assumed to be almost zero. No provision for doubtful accounts against these sales has been recorded as at 31 December 2018 and 31 December 2017.

(c) Liquidity risk

Prudent liquidity risk management implies maintaining sufficient cash and short-term funds and the availability of funding through an adequate amount of committed credit facilities. Management monitors rolling forecasts of the Group's liquidity and cash and cash equivalents on the basis of expected cash flow. At the end of the year the Group held cash at bank of $10.2 million (2017: $11.8 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: Background and accounting policies-Going Concern for more information regarding the factors considered by the Company in managing liquidity risk.

The tables below analyses 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.

(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 cash/ (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 cash/ (debt).

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. In August 2018, the CLN was fully settled.

(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).

Fair value measurements using significant unobservable inputs (Level 3)

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 recognised 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.

(c) Provision for decommissioning costs

This provision is significantly affected by changes in technology, laws and regulations which may affect the actual cost of decommissioning to be incurred at a future date. The estimate is also impacted by the discount rates used in the provisioning calculations. The discount rates used are the Group's risk-free rate and the core inflation rate applicable. The provision has been estimated using specific risk free rates for each asset ranging between 2.69%-2.90% (2017: 3.09%-4.65%) and a core inflation rate at 2% (2017: 3%), See Note 24: Provision for other liabilities. The impact in 2018 of a 1% change in these variables is as follows:

(d) Estimation of reserves

All reserve estimates involve some degree of uncertainty, which depends chiefly on the amount of reliable geological and engineering data available at the time of the estimate. Generally, reserve estimates are revised as additional data 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 2018 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 2018 all subsidiaries onshore and offshore proved and probable ("2P") reserve estimates were re-evaluated by management and approved by the Board.

(e) 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.

(f) 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: Background and Accounting policies. In order to test for impairment, the higher of fair value less costs of disposal 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 2018 an impairment charge of $2.6 million was recognised on the Group's property, plant and equipment (2017: no impairment) see Note 11: Property, Plant & Equipment. The impairment charge resulted in the carrying amount of the respective CGUs being written down to their recoverable amount.

(g) Oil and Gas Assets $2.6 million (2017: nil) impairment

As part of this assessment, management has carried out an impairment test on the oil and gas assets classified as property, plant and equipment. This test compares the carrying value of the assets at the reporting date with the recoverable amount for each CGU. The recoverable amount is the higher of the Fair Value less Costs of Disposal ("FVLCOD") and Value In Use ("VIU"). The FVLCOD is the amount that a market participant would pay for the CGU less the cost of disposal utilising a discounted cash flow approach to FVLCOD. The FVLCOD approach utilised a discounted cash flow based on the 2P reserve estimates of the CGUs of the Group. VIU is the present value of the future cash flows expected to be derived from an asset or CGU in its current condition. The period over which management has projected its cash flow forecast, ranges between 9-24 year economic lives based on the field economic life 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.

If the price deck used in the impairment calculation had been 10% lower than management's estimates at 31 December 2018, the group would have $3.4 million increase on impairment of Oil and Gas assets (2017: nil). If the price deck used in the impairment calculation had been 10% higher than management's estimates at 31 December 2018, the group would $0.2 million decrease on impairment of the Oil and Gas assets (2017: nil).

For the year ended 31 December 2018, management's estimate of the Group's cost of capital was 13% (2017:10%). If the estimated cost of capital in determining the post-tax discount rate for the CGU's had been 1% lower than management's estimates the Group would have $0.6 million decrease on impairment position for 2018 (2017: nil) against Oil and Gas assets within property, plant and equipment. If the estimated cost of capital had been 1% higher than management's estimates the Group would have $0.6 million increase on impairment for 2018 (2017: nil).

(h) Impairment of intangible exploration and evaluation assets

In 2018 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: Background. 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/Heritage. All non-current assets of the Group are located in T&T.

5 Operating Profit Before Exceptional Items

Auditors' remuneration

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

All fees are in respect of services provided by PricewaterhouseCoopers LLP. 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.

6 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.