Trinity Regulatory News (TRIN)

Trinity Exploration & Production plc

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

Preliminary Results

"Strong Operational and Financial Performance"

Trinity, the independent E&P company focused on Trinidad & Tobago ("T&T"), today announces its unaudited preliminary results for the 12 months ended 31 December 2019 ("the period" or "FY 2019").

2019 was a significant year for Trinity as we delivered another strong operational and financial performance as well as deploying new operating approaches, technologies and techniques, with the aim of becoming a more technologically focused operator and thereby driving optimum operational, financial and environmental performance. Despite lower oil price realisations, these efficiencies helped deliver another year of growth in our Adjusted EBITDA to USD 21.8 million, an increase in cash balances to USD 13.8 million at year end, and a further reduction in our operating break-even to USD 26.4/bbl.

Key Performance Indicators

Notes:

1. Realised price: Actual price received for crude oil sales per barrel ("bbl")

2. Adjusted EBITDA (USD million): Operating Profit before Taxes for the period, adjusted for DD&A, non-cash SOE, ILFA and hedge costs

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

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

5. Adjusted EBITDA after Supplemental Petroleum Tax ("SPT") & Property Tax ("PT") (USD million): Adjusted EBITDA after SPT & PT.

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

7. Net cash plus working capital surplus: Current Assets less Current Liabilities (other than Provisions for other liabilities).

Financial Highlights

· Revenues increased by 2% to USD 63.9 million (2018: USD 62.6 million)

· Cash operating costs down 9% to USD 15.0/bbl (2018: USD 16.9/bbl)

· Adjusted EBITDA increased 14% to USD 21.8 million (2018: USD 19.2 million)

· Adjusted EBITDA margin of 34% (2018: 31%) or USD 19.8/bbl (2018: USD 18.4/bbl)

· Adjusted EBITDA after SPT & PT up 9% to USD 13.9 million (2018: USD 12.8 million)

· Group operating break-even price reduced by 9% to USD 26.4/bbl (2018: USD 29.0/bbl)

· Cash balance of USD 13.8 million (2018: USD 10.2 million)

· Cash plus working capital surplus of USD 17.3 million (2018: USD 18.1 million)

· Working capital facility put in place (undrawn at year end but fully drawn-down effective 2 April 2020) with CIBC FirstCaribbean (Trinidad & Tobago) Limited ("CIBC") for USD 2.7 million repayable upon demand, providing further financial flexibility

Operational Highlights

· Average production volumes grew in aggregate by 5% to 3,007 bopd in 2019 (2018: 2,871 bopd)

· Operational strategy centred around preserving base production, whilst retaining flexibility with multiple options to maintain and grow production including low cost Recompletions ("RCPs"), Workovers ("WOs") and drilling new infill wells onshore

· Successfully drilled and completed six new onshore wells in H2 2019 - including the Group's first High Angle Well ("HAW")

· Supervisory Control And Data Acquisition ("SCADA") production optimisation programme commenced Onshore, with a focus on the automation of wells and operations to reduce downtime and improve productivity

· With increased activity levels in H2 2019 quarter on quarter production volumes grew 14% to 3,196 bopd for Q4 2019 (Q3 2019: 2,816 bopd) with a robust 2019 exit production rate c. 3,400 bopd

Corporate Highlights

· Strategy of maintaining robust cash balances, a low and reducing operating break-even, plus hedging initiatives and continual drives for efficiency has placed Trinity in a strong position to endure the challenging macro-environment

· Complimenting Trinity's commitment to delivering its production and financial targets safely, we are actively pursuing our Environmental Social and Governance ("ESG") responsibilities

o to ensure that our carbon footprint is reduced

o whilst facilitating further operational efficiencies and cost savings

· Continued positive dialogue with both Heritage Petroleum Company Limited ("Heritage") (Trinity's partner) and the Ministry of Energy and Energy Industries ("MEEI") (Trinity's regulator) in moving both the TGAL field development plan, and the wider Trintes Area Development forward

· Total proved reserves ("2P") and contingent resources ("2C") of 41.07 mmstb at 31 December 2019 (2018: 43.26 mmstb) based on internal Management estimates.

Post Period Highlights

· Company prioritising bottom-line free cash generation and maintaining a strong balance sheet

· Production volumes over Q1 2020 averaged 3,291 bopd (a 9% year-on-year increase)

· Cash balance of USD 14.2 million (unaudited) as at 31 March 2020 reflects cash outflows for Q4 2019 taxes (including SPT) of c. USD 1.9 million, as well as annual payments (such as insurance) and Capex of c. USD 2.2 million. Average realisation of USD 46.3/bbl for Q1 means that no SPT will be payable in respect of Q1 production

· Trinity responded rapidly and comprehensively to the unprecedented human and operational consequences of the COVID-19 pandemic with Work From Home ("WFH") arrangements for office staff effective from 13 March 2020

· The Company's field operations have not, to date, been negatively impacted from COVID-19, but we continue to monitor the evolving situation and will put further appropriate measures in place as and when required

· Continued reduction in operating breakeven - targeting an average operating break-even (inclusive of hedging income) of USD 20.5/bbl for FY 2020. Actions already taken to reduce Production Costs ("Opex") and General & Administrative ("G&A") expenditure, with further measures currently under consideration

· In addition, by only incurring essential Capex spend, the Group is confident it can maintain sufficient liquidity and cash through 2020 and H1 2021 in a protracted period of low realisations

· Hedging in place provides the Group with a degree of protection against a sustained period of lower oil prices

o 47,500 bbls/month for the first six months of 2020 (equating to approximately 46% of its 2019 exit production) and 28,333 bbls/month for the second six months of 2020 (equating to approximately 28% of its 2019 exit production)

o USD 6.0 received for each hedged barrel for each month when WTI averages below USD 50.0/bbl

o Hedge income in Q1 2020 totalled USD 0.5 million

· Production volumes for the remainder of 2020 will depend on oil prices and general market conditions supporting the economic case for the resumption of new drilling activity. However, even if prevailing oil prices do not support the case for a resumption of drilling in the near term, net average production for 2020 is still expected to increase to between 3,100 - 3,300 bopd (2019: 3,007 bopd)

2019 saw Trinity successfully drill and complete six new onshore wells in H2 2019. Results were encouraging and supported the delivery of production growth with average production volumes increasing to 3,007 bopd in 2019 (2018: 2,871 bopd). The deployment of SCADA and the drilling of our first HAW is testimony to our continual drive to get more for less and further enhance the business's operational resilience. As we ramp up these efficiency drives, we expect to see real benefits come to fruition.

Despite oil prices being slightly weaker during 2019 the Group reported another year of growth in operating profitability and an increase in cash balances. The upshot is that we have a robust business with an operating break-even of USD 26.4/bbl (2018: USD 29.0/bbl). This provides a natural hedge against lower oil price environments and a strong base to build upon. Based on the current oil price environment, we have refined our business model to further lower our operating break-evens and provide further resilience to a sustained period of lower oil prices.

Our performance is not only measured in financial and operational terms, but we now also measure our business outputs in terms of our environmental and social performance. During 2019 we have strengthened our commitment to minimising our carbon footprint, benefiting the environment we work in and helping to ensure the future success of the business.

Looking ahead, we are well placed to continue to grow organically but we are also positioned to make the most of other development opportunities that may arise locally. Our toolbox of skills and procedures provides us with the means to preserve as well as grow and the resilience of our business model means we face the future with cautious optimism. We expect a return to growth once we move on from the tragedies and fall out of COVID-19 and oil prices begin to recover. In the meantime, we are committed to preserving and delivering value for all our stakeholders and with our robust finances and local, highly efficient model, we are ideally positioned to take advantage of opportunities that may arise.

Bruce Dingwall CBE, Executive Chairman of Trinity, commented: 

"2019 was a significant year for Trinity as we adopted new operating practices, along with new technologies and techniques, with a view to better securing, and then growing, our base production levels. The aim is to protect against the downside, whilst yielding better and more repeatable returns on investment in the future. We made substantive progress in 2019 towards our goal of becoming a more technologically driven operator in our effort to drive optimum financial and environmental performance, and these efforts will stand the Company in good stead when we look forward to 2021 and beyond.

The dedication, hard work and expertise to deliver continued growth from our portfolio of wells - 284 of which were active at the end of 2019 (2018: 216) - across nine licences and multiple reservoirs - has required a huge effort from those involved. The professionalism and resilience of our employees, and of the supply chain that supports our business, has continued to deliver uninterrupted operations so far this year despite the turbulent backdrop.

"Clearly the market has suffered due to the impact of the COVID-19 pandemic and the OPEC+ standoff, which together precipitated a significant decline in oil prices. Whilst the market backdrop is not as we would like, the strength of our operations and our balance sheet ensure that we remain well placed despite the challenging environment. We continue to prudently manage our operations, remain highly resilient to low oil prices and confident we can ride out the storm and be open to capture the opportunities that will inevitably exist for the more robust and low cost operators."

Analyst Briefing:

A briefing for Analysts will be held at 11.00 AM today via web conference. Analysts wishing to join should contact trinityexploration@walbrookpr.com for details.

Investor Presentation:

The Company will be hosting a presentation through the digital platform Investor Meet Company at 17.30 (BST) this afternoon. Investors can sign up to Investor Meet Company for free and add to meet Trinity Exploration via the following link https://investormeetcompany.com/trinity-exploration-production-plc/register-investor?arc=67fadd57-d5fe-4c5b-bf17-22467883feaa.

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

About Trinity

Trinity is an independent oil and gas exploration and production company focused solely on Trinidad and Tobago. Trinity operates producing and development assets both onshore and offshore, in the shallow water West and East Coasts of Trinidad. Trinity's portfolio includes current production, significant near-term production growth opportunities from low risk developments and multiple exploration prospects with the potential to deliver meaningful reserves/resources growth. The Company operates all of its nine licences and, across all of the Group's assets, management's estimate of 2P reserves as at the end of 2019 was 20.9 mmbbls. Group 2C contingent resources are estimated to be 20.1 mmbbls. The Group's overall 2P plus 2C volumes are therefore 41.1 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 the Alternative Investment Market ("AIM"). To achieve this, our strategy is simple: to retain the integrity of the core producing proved 2P reserves base, to continue to grow production safely, to efficiently deliver profitable operating returns and to prudently convert our significant 2C resources to 2P reserves and future inventory.

In delivering on our strategy, it is critical to ensure that we maintain both the quality of our asset base and our capability to monetise it. The successful execution of our strategy will deliver sustainable cash generation throughout reasonable oil price cycles and preserve and optimise value for shareholders in the short, medium and longer term.

The execution of our business plan during 2019 has ensured that we are strategically well positioned to continue monetising our assets (41.07 mmbbls of 2P reserves & 2C resources with exit production c. 3,400 bopd) whilst maintaining financial strength and flexibility with USD 13.8 million in cash balances (USD 17.3 million in cash plus working capital surplus) at 31 December 2019 and with the ability to focus on growth opportunities at a time when the oil and gas landscape in T&T remains subject to reform and is evolving quickly.

Operational Highlights

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 and drive improved operational profitability. 2019 saw Trinity successfully drill 6 new onshore wells in H2 2019, with encouraging results. Equally importantly, however, 2019 saw us deploy new approaches and technologies with our first Onshore HAW as the first step to deploying full horizontal wells and the trial and roll out of SCADA platforms on wells. Average production volumes grew by 5% to 3,007 bopd in 2019 (2018: 2,871 bopd). With the increased activity levels in H2 2019 there was a 14% quarter on quarter increase in average production volumes to 3,196 bopd for Q4 2019 (Q3 2019: 2,816 bopd) with exit production for 2019 of c. 3,400 bopd. The increase in annualised production was underpinned by a combination of the six new onshore development wells coming on stream during H2 2019, an increase in active offshore wells producing from 31 to 34 and the continuation of the Group's low-cost ongoing work programme of RCPs, WOs, reactivations and swabbing. The 2019 work programme included a total of 23 RCPs (2018: 17) and 122 WOs and well reactivations (2018: 143).

Financial Performance

The resulting production growth had a positive impact on our revenues in 2019 despite lower crude oil prices. Crucially, despite lower realisations, we yet again increased operating profitability with Adjusted EBITDA up 14% to USD 21.8 million (2018: USD 19.2 million) which represents an Adjusted EBITDA margin of 34% (2018: 31%). The upshot is a robust business with an operating break-even of USD 26.4/bbl (2018: USD 29.0/bbl) which provides a natural hedge against lower oil price environments and a strong base to build upon. Based on the current oil price environment, we have refined our business model to further lower our operating break-evens and provide further resilience to a sustained period of lower oil prices.

The like for like comparison of Adjusted EBITDA after SPT & PT was USD 13.9 million (USD 12.6/bbl) for 2019, a 9% increase vs. USD 12.8 million (USD 12.2/bbl) for 2018. Adjusted EBITDA after taxes, on a per share basis, was down 6% to US 3.4 cents per share (diluted) (2018: 3.6 cents) on account of the increased weighted average share count in FY 2019.

Operating Cash Flow ("OCF") for 2019 increased by 9% to USD 13.1 million from USD 12.1 million in 2018. Net OCF, after changes in working capital movements and income taxes, was USD 16.8 million (2018: USD 5.2 million). The increase is mainly due to USD 11.6 million year-on-year working capital movement compared to the previous year, which was largely attributable to the receivables due from Petrotrin being paid in 2019 rather than 2018. Stripping out the increase in receivables, the like for like OCF after changes in working capital would have been USD 10.6 million vs USD 11.8 million for 2018, primarily due to increased Value Added Tax ("VAT") recoverables and higher inventory balances at the 2019 year end.

The Group's cash balances at year end stood at USD 13.8 million (2018: USD 10.2 million). The higher cash balance is as a result of a strong operating performance and movement in working capital balances more than offsetting Capex of USD 12.7 million (2018: USD 12.5 million). In aggregate, the resultant net current assets (net cash plus working capital surplus) stood at USD 17.3 million (2018: USD 18.1 million). This financial strength and flexibility was further enhanced during the year by putting in place an overdraft credit facility, payable upon demand, with CIBC for USD 2.7 million which was undrawn at the year end.

In 2019, the impact of higher production levels and more wide-scale deployment of SCADA and other technological efficiency drives started to become apparent, enabling Trinity's low operating break-even, now well established, to continue to be reduced (2018: USD 29.0/bbl, 2019: USD 26.4/bbl). The Group has evolved its operating and financial systems and processes over the last four years to enable the business to be sustainable in a lower oil price environment and in a world of global economic uncertainties.

ESG Focus

We measure our performance not only in terms of our financial and production delivery, but also in terms of our environmental and social performance. We are committed to continue to operate all of our assets in a safe and responsible manner, to ensure the safety of employees and to minimise the potential risk to the environment. During 2019, we continued to prioritise the Health Safety Security & Environment ("HSSE") and the well-being of our people while promoting safe behaviours among all stakeholders.

Complementing Trinity's commitment to delivering its production targets safely, we are assiduously pursuing our ESG responsibilities to ensure that our carbon footprint is reduced. Trinity has established its baseline for emissions since 2017 and will be embarking on an abatement plan during 2020 to ensure that we become a more efficient and cleaner business. Specific work plans in place include the development of waste inventories and established targets to reduce, reuse and recycle waste streams across the Group; progression of the Green House Gases ("GHG") Emissions Study to develop our understanding of our total emissions and subsequent targets and strategy to reduce GHG; the identification of potential impact categories which include Workplace, Industrial, Community and Environmental and the beneficial impact of the increased usage of technology.

Maximising Low Cost Production

The financial hedging supports our effective operational hedging strategy, centred on preserving base production and retaining flexibility with multiple options to sustain and grow production including low cost RCPs, WOs and drilling new infill wells onshore. To facilitate this we have created an enhanced operational management system that builds repeatability and scalability as we grow while simultaneously driving further efficiencies in terms of well uptime resulting in reduced WOs and the better allocation of human resources.

We are geared towards further reducing cost structures and optimising production following better than expected results from the initial two well trial of Weatherford's SCADA platforms with SCADA currently in place on six wells with further roll out anticipated during 2020. This is the first time this technology has been deployed in our Onshore fields in T&T and provides a low-cost means of protecting and enhancing base production levels with the full production benefits and operating cost savings expected to become more apparent over the next one to two years.

More efficient conventional vertical wells, combined with drilling more HAWs, is aimed towards increasing IP rates, well economics and ultimately cash returns. By becoming more data driven, we have a vision to digitise the business so that we can develop analytics for our 1000+ wells (across various reservoirs which have been producing for decades) and by applying a clinical approach to increasing recovery factors and maximising reserves extraction, we are further securing the business for the future.

Growing Reserves and Resources

Trinity is well placed with a full cycle portfolio of production, development, appraisal and exploration potential.

Trinity is in the opportune position of having gone through an exploration phase in the relatively recent past which yielded the successful TGAL discovery offshore on the east coast of T&T, with the TGAL-1 exploration well drilled in very close proximity (1200m) to our producing Trintes Field. There does, however, remain further exciting low risk infrastructure led exploration and appraisal potential within our offshore east coast acreage with a total Stock Tank Oil Initially In Place ("STOIIP") of c. 700 mmstb. Trinity continues to have positive dialogue with both Heritage (Trinity's partner) and the Ministry of Energy and Energy Industries ("MEEI") (T&T's oil and gas regulator) in moving forward with the TGAL Field Development Plan ("FDP") and the wider Trintes area development. The Environmental Impact Assessment ("EIA") study commenced in February 2020. This is a pre-requisite of, and on the critical path to, allowing the Group to progress the development to Final Investment Decision ("FID") when market conditions improve.

In addition, the acquisition of a 3D seismic data package over our Onshore acreage is currently pending. We are very keen to start the interpretation and analysis of this data to yield more optimum drilling locations, facilitating fully horizontal drilling, and also to identify the exploration potential of our blocks.

The Management's 2019 estimate of the Group's total 2P reserves (Onshore and Offshore) was 20.94 mmstb (2018: 24.49 mmstb), the reduction comprising total production of 1.10 mmstb and net revisions of 2.45 mmstb. This revision is largely a function of applying a more conservative oil price deck (assuming a price towards the lower end of the SPT paying range applies throughout the forecast) and reducing the number of potential infill development wells on the East Coast assets. For the third year running, more Onshore reserves were added, as the Subsurface Team continues to add locations to the Onshore drilling inventory.

Management's 2019 estimate of the Group's contingent 2C resources was 20.13 mmstb (2018: 18.77 mmstb), with the increase primarily reflecting the re-categorisation of some East Coast asset development drilling locations to 2C (previously carried as 2P in 2018) and the reallocation of TGAL shallow (G, H and M sands) resources to 2C (previously carried as 3C in 2018) with formal development solutions being finalised. This follows the high grading of a first phase development stage of the deeper TGAL reservoirs, as per the submitted FDP, targeting 10.41 mmstb (net) with more robust overall economics. These high graded 2C resources would be expected to convert to 2P following FID.

In aggregate, therefore, total 2P reserves and 2C resources amounted to 41.07 mmstb at 31 December 2019 (2018: 43.26 mmstb). So whilst we do have exploration potential across our portfolio, a clear growth trajectory is already in place with substantial existing reserves and resources to be monetised.

2020 and Beyond

Our principal priority during the global pandemic is on the safety and health of our people so we have put in place a full suite of measures to achieve this including regular and updated advisories, enhanced hygiene practices and full contingency plans should any team member be exposed to the virus. In light of the first confirmed case in T&T, Trinity implemented WFH practices for all but essential field operators and these are working well. All international travel has been suspended and minimal local travel to maintain well operations in the fields is being undertaken under the strict proviso of appropriate physical distancing measures being adhered to. The Group's operations have not, to date, been negatively impacted by COVID-19 and have, by law, been classified an essential business and therefore able to continue operations. We will continue to monitor the evolving situation and put further appropriate measures in place as and when required.

This time last year, our aim was to build on our stable base production, add well inventory and execute an investment programme that included technological step-outs whilst maintaining controls on operating costs and HSSE. The Group managed to deliver on that initial programme, resulting in continued improvement in our operational performance and KPIs. We are well placed to continue to grow organically but also positioned to make the most of other development opportunities that may arise. We are assured that our locally led business model is well suited to the future based on our strong relationships with Heritage and with other partners on the ground in T&T.  

KEY PERFORMANCE INDICATORS

The Group was profitable at an operating level throughout 2019 with a 14% increase in Adjusted EBITDA to USD 21.8 million (2018: USD 19.2 million), a year-end cash balance of USD 13.8 million (2018: USD 10.2 million) and net current assets of USD 17.3 million (2018: USD 18.1 million). A summary of the year-on-year operational and financial highlights are set out below:

Notes:

1. Realised price: Actual price received for crude oil sales per barrel ("bbl").

2. Annual production (mmbbls) -- Production sold in a given year

3. Adjusted EBITDA (USD million): Operating Profit before Taxes for the period, adjusted for DD&A, non-cash SOE, ILFA and hedge costs

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 & PT (USD million): Adjusted EBITDA after SPT & PT.

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

9. Adjusted EBITDA after SPT & PT per Share -- Diluted: Adjusted EBITDA after SPT & 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. Net cash plus working capital surplus: Current Assets less Current Liabilities (other than Provisions for other liabilities).

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 by Management to assess the Group's growth and underlying operational and financial performance.

 See Note 23 to Consolidated Financial Statements - Adjusted EBITDA  

2019 Trading Summary

A 5-year historical summary of realised price, production, operating break-even, Opex and 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 SOE and FX gain/loss.

3. G&A/bbl - Consolidated: Excludes SOE and FX gain/loss.

4. Metrics post IFRS 16 adoption effective 1 January 2019 which impacted the Operating Break-Even Levels and Opex/bbl & G&A/bbl Metrics

5. Metrics pre-IFRS 16 adoption effective 1 January 2019 which impacted the Operating Break-Even Levels and Opex/bbl & G&A/bbl Metrics

2019 was a significant year as production averaged over 3,000 bopd for the first time in five years with the benefits of the drilling of new development wells during 2018 and 2019. Of particular note from a financial standpoint is that operating break-evens were reduced with an aggregate of 9% to USD 26.4/bbl (2018: USD 29.0/bbl). The consolidated operating break-even includes the Group's cash G&A costs and therefore captures the corporate costs associated with supporting the asset base.

At the corporate level, the maintenance of such a robust operating level break-even level reflects higher production volumes and lower combined expenses as detailed below:

§ Overall Opex decreased by 8% to USD 16.4 million (2018: 17.8 million). This was largely a function of a lower WO programme, production optimisation and better well uptimes, re-negotiated terms of the supply/personnel vessels and port rental and a partial reduction based on the adoption of the new leases standard IFRS 16.

§ G&A costs (which exclude non-cash SOE and FX gain/loss) increased by 8% to USD 5.6 million (2018: USD 5.2 million). This is in relation to increased staff costs, levies and corporate expenses.

OPERATIONAL REVIEW

Our People

Trinity's workforce stood at 214 (2018: 215) at the year-end December 2019 with 78% (166) male and 22% (48) 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.

HSSE

Trinity continues to place HSSE at the forefront of our operations as we strive towards further improving our safety performance by a continued focus on training, monitoring and measurement, ongoing reviews of our internal controls and implementing corrective action when necessary.

The Board is fully apprised of the Group's HSSE performance via updates at each Board meeting and from 2020 onwards this will be done on a monthly basis. The HSSE report is considered at each Board meeting and is usually the first matter considered on meeting agendas.

Management's commitment to behaviour based HSSE programmes - of which the See, Think, Act, Reinforce and Track ("START") Card programme is an example - has positively impacted our HSSE culture. During 2019, we have noted an 84% increase in participation by all employees in our START Card programme. Trinity also introduced a new initiative to report on the closure rate of all items identified in the START Card programme and routinely informed the frontline employees on their participation to further enhance their performance.

Training hours recorded also saw an increase of 24% to 3,364 hours from 2,718 hours as safety remained as a top priority to Trinity to ensure that employees are competent and confident to execute all tasks in a safe and efficient manner.

Trinity recorded 844,074-man hours in 2019 (2018: 643,400 man hours), a 31% increase, mainly due to the 2019 work programme which included onshore drilling as well as onshore and offshore RCPs and WOs. Notable improvements in our HSSE reporting were achieved due to our continued emphasis on a strong HSSE culture, facilitated by an increase in Management visits to all assets, increased feedback on lessons learned and multiple proactive initiatives implemented across all operations.

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 ("ECTT"). 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. The internal audit process for the planned recertification inspection in Q1 2020 was completed in Q3 2019. However, due to the COVID-19 pandemic, the ECTT has deferred all audits for a 3 month period effective 1 March 2020 and so Trinity is now expected to be undergoing recertification at a later date in 2020. Notwithstanding our 2019 achievements, in 2020 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 with the goal of becoming SO 45001:2018 compliant by Q2 2021.

Production

Average net production for 2019 was 3,007 bopd (2018: 2,871 bopd), an increase of 5%. A total of six new infill development wells, 23 RCPs, 122 WOs and reactivations along with swabbing activities were undertaken during 2019.

Trinity has been constantly striving towards establishing our base production at a higher level. This requires continuous improvements of our operations via the standardisation of procedures, innovative approaches in addressing emerging challenges and the application of new technologies to improve performance, reliability and efficiencies. 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 2019 net production from the Onshore assets was 1,613 bopd (3% increase from 2018 (1,563 bopd)), which accounted for 54% of total annual average production. The growth in year-on-year production averages is reflective of successfully maintaining base production and the impact of new infill development wells which were drilled during H2 and the full impact Q4 in particular (with absolute production growth higher than the annual average).

The drilling programme for 2019, which was completed on time and on budget, consisted of six Onshore wells and delivered:

1) an increase of 20% in EUR reserves above pre-drill prognosis (0.60 mmbbls vs 0.50 mmbbls)

2) an increase of 47% in estimated Net Oil Sand ("NOS") encountered over pre-drill prognosis (1653' vs 1125')

3) an increase of 54% in IP's over pre-drill prognosis (cumulative 650 bopd vs 421 bopd)

The strong performance of the 2019 drilling campaign was due to a more robust approach to sub-surface mapping and a more rigorous examination of reservoir performance which enabled more precise risking and ranking of potential reservoir targets. The drilling programme lasted 125 days and there were no Lost Time Accidents ("LTAs") over the period, a significant achievement by the drilling team and lead contractors.

The drilling programme included our first HAW, FR 1807, which has continued to perform satisfactorily:

1) The well had a peak production rate of over 110 bopd vs the 50 bopd typically expected from a conventional vertical well

2) It attained a maximum daily production rate of 118 bopd prior to the planned implementation of a gravel pack, a completion technique to arrest sand production

3) Diagnostic and remediation strategy to obtain improved production is underway

Trinity executed 22 RCPs Onshore for the period (2018: 16) as well as Onshore WOs and reactivations on 104 wells (2018: 113). This intensive work campaign successfully maintained base production providing a stable platform for production growth.

Going forward, dependent on the prevailing macro environment, the Group intends to continue with development activities via additional infill development drilling (particularly of additional HAWs), the restocking of RCPs, WOs, and reactivations and swabbing on the current well stock to maintain our production and provide for further growth.

East Coast Assets

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

Average 2019 net production from the East Coast was 1,205 bopd which accounted for 40% of total annual average production. This represented a 9% increase in production from the 2018 average net production levels of 1,110 bopd. The increase was largely as a result of (i) improved power reliability, (ii) the successful execution of a just in time WO campaign that included the reactivation of four wells and continuous well optimisation.

In 2019, 13 restorative WOs were completed (2018: 23) which contributed to an upward trend in production. In 2019, production was derived from 34 of a possible 61 wellbores in the Trintes Field. The Trintes Field produces via numerous pumping technologies across our well stock including Mechanical Pumping Hydraulic Unit ("MPHU"), Hydraulic Diaphragm Electric Submersible Pump ("HDESP"), Electric Submersible Pump ("ESP") and Progressive 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 designs to overcome challenging wellbore conditions.

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.

Infrastructure investment during 2019 included the completion of significant structural upgrades without the need for any shut-ins with production sustained throughout. Essential investment to ensure structural integrity across the platforms will continue in 2020. Continued investment to increasing storage capacity will also take place with the construction of a new 10,000 barrel tank.

West Coast Assets

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

Average 2019 net production from the West Coast was 189 bopd which accounted for 6% of total annual average production. This represented a 5% decrease in production from 2018 average levels of 198 bopd and was mainly attributed to natural production decline.

There were 4 WO's (2018: 3) in the PGB field and 1 WO (2018:4) on the land-based wells in the Brighton Field which were undertaken with the intention of arresting declines and stabilising base production levels. Swabbing operations on the Brighton Marine offshore facilities commenced in Q4 adding an additional 17 bopd and chemical injection has allowed for stabilisation of production through the delay of wax formation in the wells. Minor infrastructural works were undertaken on the offshore platforms to maintain asset integrity and production.

These assets continue to generate a 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 relatively low cost.

Reserves and Resources

A comprehensive management review of all assets has been concluded and has estimated the current 2P reserves to be 20.97 mmstb at the end of 2019, compared to the year-end 2018 reserve estimate of 24.49 mmstb. This represents a 14% decrease of 3.55 mmstb from 2018 levels inclusive of production for 2019 of 1.10 mmstb (2018: 1.09 mmstb). The reduction in reserves predominantly reflects the application of an oil price forward curve which was towards the lower end of the SPT payable range, as well as updated well numbers and decline curve analysis on producing wells offshore the East Coast.

Onshore 2P reserves grew by 2% as a result of our ongoing continued investment in subsurface analysis to generate additional infill drilling, RCP and WO candidates. This follows on from a 26% increase delivered in 2018 and 45% in 2017. Management considers this to be the best estimate as at 31 December 2019 of the quantity of reserves that will actually be recovered from the assets. 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 following table:

Unaudited 2019 2P Reserves

Note(*):

i. East Coast 2P resource change primarily reflects moving 2 wells to contingent resources and changes to certain infill well decline profiles. Trinity has further risked the production profiles to reflect reservoir performance from more recent drills, RCPs and WOs which results in a more cautious assessment of initial flow rates, production profile declines and, ultimately, lower EUR.

ii. Changes to economic limit testing for the asset YE 2019 vs YE 2018 also impact the Trintes 2P position; the YE 2018 oil price deck used did not trigger SPT whereas that used in YE 2019 triggers SPT over the life of the Trintes asset.

The best estimate of 2C resources is estimated by Management at 20.13 mmstb (2018: 18.77 mmstb). The positive movement of 1.36 mmstb in 2C resources primarily reflects the re-categorisation of some infill development drilling locations to 2C (previously carried as 2P in 2018) and the reallocation of TGAL shallow (G, H and M reservoirs) resources to 2C (previously carried as 3C in 2018).

Unaudited 2019 2C Resources

Unaudited Summary of Reserves and Resources at 31 December 2019

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 STOIIP of over 700 mmstb of which only 249 mmstb of STOIIP is mapped against the Trintes Field. Trintes currently booked East Coast 2P reserves of 11.27 mmstb therefore represents an incremental recovery factor of 4.5%, with a further 2.77 mmstb (or 1.1%) booked within contingent resources. 

Galeota (TGAL) Field Development Plan (Trinity: 65% WI)

The TGAL area lies in the Galeota Licence and is Fault Block 6, an up-dip panel to the north east of Trintes, confirmed as being oil bearing in all major reservoir horizons by the TGAL-1 exploration well with an internal best estimate STOIIP of 186 mmstb. The FDP (submitted in November 2018) describes the first phase of a potential wider development across the Galeota anticline to fully develop the reserves potential from the large volumes of oil in place.

Some of the highlights of the proposed Fault Block 6 Development include:

· An unmanned platform with minimal top-side design ("Platform Echo")

· 25-year design life

· Drilling with the use of a jack-up rig

· A new pipeline from Platform Echo to shore

· Subsea power cable from shore to Platform Echo

· First oil estimated being produced by H1 2022, subject to prevailing market conditions, and peak production estimated at 5,800 bopd

· 2C resources of up to c.24.18 mmstb gross (14.51 mmstb net). The net 2C figure is inclusive of 10.41mmstb being developed by the new platform, and 4.1mmstb for the shallow resources that, after review, have moved back into 2C (was re-categorised YE 2018 from 2C to 3C)

· At Final Investment Decision ("FID") Trinity anticipates the net 2C resources developed by the Platform Echo solution would be reclassified as 2P reserves

During 2019 works progressed (and are continuing) on various pre-FEED studies to improve the topside and other aspects of the hardware design. Of equal importance, the environmental permitting process was advanced with submission of the application and all additional information requested by the Environmental Management Authority of Trinidad and Tobago ("EMA") during 2019. The Environmental Impact Assessment ("EIA"), which is a key item on the critical path to FID, is currently underway. 

FINANCIAL REVIEW

Trinity and its subsidiaries ("the Group's") consolidated financial information has been prepared on a going concern basis, in accordance with International Financial Reporting Standards ("IFRS") Interpretations Committee ("IFRS IC") interpretations as adopted by the European Union ("EU") and those parts of the Companies Act ("CA") 2006 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 1 of the Financial Statements. The Group has adopted additional accounting policies in the year ended 31 December 2019 as set out in the notes to Financial Statements.

Throughout this report reference is made to adjusted results and measures. The Board 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 underlying cash earnings achieved in the year. In exercising this judgment, the Board 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 impact of SOE, ILFA and oil price hedges and these are summarised on the face of the Consolidated Income Statement as well as being described in the notes to the financial statements.

Results for the year

· Revenue growth from increased production despite lower oil price realisations: The combination of a 5% increase in production to 3,007 bopd (2018: 2,871 bopd) and a 3% decrease in average oil price realisations to USD 58.1/bbl (2018: USD 59.8/bbl) resulted in a 2% increase in revenues to USD 63.9 million (2018: USD 62.6 million).

· Successful Capex work programme: USD 12.7 million (2018: USD 12.5 million) incurred in predominantly production related and infrastructure expenditure. 2019 saw the Group complete 6 Onshore development wells, 22 Onshore RCP's and the second RCP on the East Coast since acquiring the asset in 2013. Infrastructure Capex were also conducted across the assets to support the production initiatives. Capex included:

· USD 7.4 million New Wells (6 wells, of which 1 HAW and 5 conventional)

· USD 2.8 million Infrastructure Capex

· USD 1.3 million 23 RCP's

· USD 0.6 million Subsurface time-writing costs

· USD 0.6 million Exploration and Evaluation ("E&E") assets

· Further growth in operating margins and increased operating profitability: The Group maintained its focus on growing margins and increasing operating profitability which is evident in a 14% increase in Adjusted EBITDA to USD 21.8 million (2018: USD 19.2 million) and 9% lower consolidated operating break-even price of USD 26.4/bbl (2018: USD 29.0/bbl), while increasing Adjusted EBITDA Margin to 34% in 2019 (2018: 31%). On a per barrel basis this represents an 8% increase in Adjusted EBITDA to USD 19.8/bbl (2018: USD 18.3/bbl) and a 2% decrease in Adjusted EBITDA per share (diluted) to 5.3 cents (2018: 5.4 cents) due to the increased average share count. 

· SPT & PT: 2019 and 2018 saw average oil price realisations above USD 50.0/bbl, thereby being in the SPT paying range. As a result, SPT of USD 7.4 million was incurred in 2019 (2018: USD 7.1 million).

· Impairment losses (non-cash): during the year the Group recorded property, plant and equipment impairment losses on its oil and gas assets of USD 15.2 million (2018: USD 2.6 million) within exceptional items. The carrying values of certain of the Group's cash generating units were deemed to be higher than their recoverable amount measured utilising a discounted cash flow approach to fair value less cost of disposal. This was largely driven by the application of a more conservative oil price forward curve at 31 December 2019, on account of it falling towards the lower end of the SPT payment range. The Group also recognised USD 0.6 million (2018: nil) of impairment losses on carrying values held within trade and other receivables due to expected credit loss following the adoption of IFRS 9 financial instruments.

· Increased Operating Cash Flows: OCF for 2019 increased by 9% to USD 13.1 million (2018: USD 12.1 million). Net OCF, after changes in working capital movements and income taxes, was USD 16.8 million (2018: USD 5.2 million). The increase is mainly a function of a USD 11.6 million year-on-year working capital movement from the prior year, which was largely attributable to the receivables due from Petrotrin being paid in 2019 rather than 2018. Stripping out the increase in receivables, the like-for-like OCF after changes in working capital would have been USD 10.6 million vs. USD 11.8 million for 2018. Decreases in working capital were attributed to lower trade and other payables by USD (1.0) million and increased inventory of USD (1.5) million and increased VAT receipts due (USD 2.9 million vs 2018: USD 1.6 million).

· Increased Financial Strength: The Group's cash balances at year end stood at USD 13.8 million (2018: USD 10.2 million). The higher cash balance is as a result of a strong operating performance and movement in working capital balances more than offsetting Capex of USD 12.7 million (2018: USD 12.5 million). In aggregate, the resultant net cash plus working capital surplus stood at USD 17.3 million (2018: USD 18.1 million). This financial strength and flexibility was further enhanced during the year by putting in place an overdraft credit facility with CIBC for USD 2.7 million which was undrawn at the 2019 year end.

Revenues

Crude oil sales revenues of USD 63.9 million (2018: USD 62.6 million).

Operating expenses

Operating expenses decreased by 4% in 2019 to USD (53.6) million (2018: USD (56.7) million) and comprised:

· Cash Expenses: USD (42.1) million (2018: (45.3) million):

· Royalties of USD (20.0) million (2018: USD (20.4) million) have decreased due to the new wells from the 2018 and 2019 drilling campaign attracting 0%-10% ORR.

· Opex of USD (16.4) million (2018: USD (17.8) million) have decreased due to lower costs in relation to WOs, production optimisation and vessel and equipment.

· G&A expense of USD (5.6) million (2018: USD (5.2) million) have increased due to an increase in staff and corporate costs. 

· Other expenses of USD (0.1) million (2018: USD (1.1) million) includes the impact of hedge costs in relation to the zero cost collar/ put options implemented during 2019.

· Non-Cash Expenses: USD (11.5) million (2018: USD (11.4) million):

· DD&A of USD (9.8) million (2018: USD (10.7) million).

· SOE of USD (1.0) million (2018: USD (0.7) million).

· ILFA: USD (0.6) million (2018: nil).

· FX (loss)/gain of USD (0.1) million (2018: USD 0.0 million). 

Note (*): the relatively modest impact on Opex and G&A of the adoption of IFRS 16 for leases is set out in the following section.

SPT & PT

SPT & PT were USD (7.9) million (2018: USD (6.4) million) and comprised:

· SPT of USD (7.4) million (2018: USD (7.1) million) due to realised oil prices being above the USD 50.01/bbl SPT threshold.

· PT charge of USD (0.5) million (2018: USD 0.6 million credit). There is still no official guidance on the PT valuation method as it relates to oil and gas entities. The 2017 and prior obligations were waived during 2018 but the Group is still providing for the potential obligations arising in 2018 and 2019.

The Group's reported operating profit before exceptional items was USD 2.4 million (2018: USD 0.2 million). Adjusting for non-cash expenses, the Group's Adjusted EBITDA after SPT & PT was USD 13.9 million (2018: USD 12.8 million) (further details below).

Exceptional items

Exceptional items were USD (15.2) million (2018: USD (2.3) million) related to Impairment of property, plant and equipment

See Note 6 to Consolidated Financial Statements

Finance Income

Finance income is solely related to interest income derived on short term investments USD 0.1 million (2018: 0.1 million).

Finance Costs

In 2019, finance costs amounted to USD (1.4) million (2018: USD (2.2) million) and comprised:

· Unwinding of the decommissioning liability USD (1.2) million (2018: USD (1.6) million).

· Interest on Leases USD (0.2) million (2018: nil).

· Interest accrued on the CLNs nil (2018: (0.6) million).

See Note 7 to Consolidated Financial Statements

Income Taxation

Income Taxation credit for 2019 of USD 4.4 million (2018: USD (1.3) million charge), and its components are described below.

· Increase in DTA of USD 3.4 million based on the increase in taxable profits expected in the next three years (2018: USD 1.8 million).

· Decrease in Deferred Tax Liabilities ("DTL") USD 1.4 million as the temporary difference between the accounting values of property, plant and equipment, intangible assets and tax values decreased compared to 2018 (2018: USD (3.1) million charge).

· Increase in Unemployment Levy ("UL") USD (0.4) million (2018: USD 0.0 million credit).

See Note 8 to Consolidated Financial Statements

The Group's comprehensive post-tax loss for the period was therefore USD (9.6) million (2018: USD (5.3) million loss).

Adjusted EBITDA

Adjusted EBITDA is a non-IFRS measure used by the Group to measure business performance. It is calculated as Operating Profit before SPT & PT for the period, adjusted for non-cash DD&A, SOE, ILFA, FX gain/loss and fair-valuing of oil price hedges.

The Group presents Adjusted EBITDA at USD 21.8 million and Adjusted EBITDA after SPT & PT at USD 13.9 million as it is used in by Management to assess the Group's growth and underlying operational and financial performance. 

Statement of Cash Flows

Cash inflow/ (outflow) from operating activities

OCF was USD 16.8 million (2018: USD 5.2 million):

· Operating cash flow (pre-working capital movements and income tax) of USD 13.1 million (2018: 12.1 million) reflected a reported Operating Loss before income tax of USD (14.1) million (2018: USD (4.1) million) less non-cash items totalling USD 27.2 million (2018: USD 16.2 million) principally comprising DD&A, impairment of Oil & Gas asset valuations, unwinding of Decommissioning provisions and SOE.

· Changes in working capital of USD 3.9 million inflow (2018: USD 6.8 million outflow), primarily as a result of the decrease in trade receivables compared to the 2018 year end.

· Current income taxation paid USD (0.3) million outflow (2018: USD (0.1) million outflow).

Cash (outflow) from investing activities

Cash outflow from investing activities was USD (12.7) million (2018: USD (12.5) million):

· Expenditure on property, plant and equipment for the year was USD (12.1) million (2018: USD (12.3) million) which mainly included 6 onshore development wells, 23 RCPs and infrastructure upgrades.

· Expenditure on exploration and evaluation assets and computer software USD (0.6) million (2018: USD (0.2) million).

Cash (outflow)/inflow from financing activities

Cash outflow from financing activities was USD (0.4) million (2018: USD 11.5 million inflow):

· Cash payment on leases USD (0.6) million (2018: nil)

· Finance income of USD 0.1 million (2018: USD (0.1) million in Finance costs.

· Repayment of CLN nil (2018: USD (0.8 million).

· Issuance of shares nil (2018: USD 12.4 million inflow).

Net Cash Plus Working Capital Surplus

Note (*): Current Liabilities excludes Provision for other liabilities

Adoption of IFRS 16 Leases

IFRS 16 is a new accounting standard effective 1 January 2019. This accounting standard supersedes IAS 17 Leases and results in almost all leases being recognised on the balance sheet, as the distinction between operating and finance leases is removed. Under the new standard, Right of Use Assets ("ROU") and a financial liability to pay rentals are recognised. The only exceptions are short-term (less than 12 months) and low-value leases (less than USD 5,000).

The Group has adopted IFRS 16 from 1 January 2019, but has not restated comparatives for the 2018 reporting period, as permitted under the simplified transitional approach. On transition the Group elected to apply the practical expedient to grandfather the assessment of which transactions are leases. It applied IFRS 16 only to contracts that were previously identified as leases. Contracts that were not identified as leases under IAS 17 and IFRS IC 4 were not reassessed. Therefore, the definition of a lease under IFRS 16 has been applied only to contracts entered into or changed on or after 1 January 2019.

On adoption of IFRS 16, the Group has recognised ROU assets and lease liabilities in relation to Motor vehicles, Office buildings, Staff houses and Office Equipment. The following table sets forth the impact of the adoption of IFRS 16 on the condensed consolidated financial statements as well as non-IFRS measures.

1. Impact on Consolidated Statement of Comprehensive Income

2. Impact on Consolidated Statement of Financial Position

Events Since the Year End

1. Hedging

The Company implemented two additional crude hedge options over the Group's monthly production on 3 January 2020 as follows:

2. Petrotrin Legacy Receipts

There remains an outstanding payment due from Petrotrin for October and November 2018 crude oil revenues, with an amount outstanding of USD 0.5 million at the end of 2019 for which an Expected Credit Losses ("ECL") of USD 0.2 million was recognised. The Group received USD 0.1 million of these delayed payments on 7 February 2020, with the remaining USD 0.4 million still outstanding.

3. COVID-19 Pandemic and Oil Price Decline

The impact of the COVID-19 virus on the demand end for oil, and the inability of OPEC and Russia to agree sufficient supply curbs in a timely manner, has led to a significant decline in the oil price. WTI traded as high as USD 63.0/bbl in early January 2020, declining to USD 45.0/bbl as a result of reduced demand from COVID-19 in early March 2020, prior to the oil price war which subsequently drove prices lower than USD 20.0/bbl. On 12 April 2020, OPEC and Russia announced plans to reduce production output by nearly 10.0 mmbbls. However, concerns about storage capacity being exceeded led to oil-market history being made on 20 April 2020 when WTI prices dropped below zero for the first time (to minus USD 37.63/bbl). Although prices have since recovered somewhat, they remain below USD 30.0/bbl as at the last practicable date prior to approval of this announcement on 12 May 2020, and there remains considerable uncertainty regarding oil price levels during the remainder of 2020, and possibly beyond.

The World Health Organisation ("WHO") officially declared COVID-19 as a pandemic on 11 March 2020. Effective 22 March 2020, the Government of the Republic of Trinidad and Tobago ("GORTT") closed T&T's borders to all international and national travelers via the air bridge and sea ports. Subsequently, the operations of only essential services were approved by the GORTT (which includes oil and gas companies within T&T).

The COVID-19 pandemic's impact on demand for oil, the subsequent fall in oil prices, and the potential operating disruption to oil and gas companies is an extremely challenging and evolving situation. Given the fluidity and significant volatility of these events, it is extremely difficult to predict their impact on the Group at this stage as the oil price environment is dependent on the interplay between global demand and supply, both of which are changing significantly. Nevertheless, having assessed the current impact of these various factors, and the potential impact of a prolonged economic downturn triggered by the COVID-19 pandemic, the Directors currently believe the Group can maintain sufficient liquidity and a positive cash balance, and remain in operational existence, for at least the next twelve months (see Going Concern refer to Note 1 to Financial Statements).

4. CIBC Full Overdraft Credit Facility Drawdown

Trinity fully drew down its USD 2.7 million overdraft credit facility with CIBC effective 2 April 2020 as part of its strategy of maximising available cash during the short-medium term. The facility is a revolving overdraft credit available to Trinity which is repayable upon demand to CIBC. Interest is required to be paid monthly on the principal and currently attracts an interest rate charge of 2.7% (US Prime minus 6.3% per annum). 

Consolidated Statement of Comprehensive Income

For the year ended 31 December 2019

(Expressed in United States Dollars)

Consolidated Statement of Financial Position

at 31 December 2019

(Expressed in United States Dollars)

Company Statement of Financial Position

at 31 December 2019

(Expressed in United States Dollars)

Consolidated Statement of Changes in Equity

for the year ended 31 December 2019

(Expressed in United States Dollars)

[1] On 11 January 2017 the Company issued at a 50% discount 6.6 million USD 1.00 dollar, unsecured CLNs.  

Company Statement of Changes in Equity

for the year 31 December 2019

(Expressed in United States Dollars)

Consolidated Statement of Cash Flows

for the year ended 31 December 2019

(Expressed in United States Dollars)

1 Trinidad & Tobago ("T&T")

2 Ministry of Energy and Energy Industries of Trinidad & Tobago ("MEEI")

3 Board of Inland Revenue of Trinidad & Tobago ("BIR")

Company Statement of Cash Flows

for the year ended 31 December 2019

(Expressed in United States Dollars)

Notes to the Consolidated Financial Statements

31 December 2019

(Expressed in United States Dollars)

1 Background and Summary of significant 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. The financial statements are for the Group of Trinity Exploration & Production plc and its subsidiaries.

Background

Trinity Exploration & Production plc ("Trinity" or "the Company" or "Parent") is an independent energy company limited by shares and listed on the Alternative Investment Market ("AIM") of the London Stock Exchange ("LSE"). The Company is incorporated and domiciled in England and the address of the registered office is C/o Pinsent Masons LLP 1 Park Row, Leeds LS1 5AB, United Kingdom ("UK"). Trinity and its subsidiaries (together "the Group") are involved in the exploration, development and production of oil reserves in 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, except certain financial assets and liabilities (including derivative financial instruments) and certain classes of property, plant and equipment - which are measured at fair value through the Consolidated Statement of Comprehensive Income. Accounting policies have been applied consistently, other than where a new accounting policy has been adopted.

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 $1.7 million (2018: $2.7 million loss).

Going Concern

The Directors have adopted the going concern basis in preparing the Financial Statements.

In making their going concern assessment, the Board of Directors ("Board") have considered the Group's, and therefore the Company's, current financial position, budget and various cash flow forecast scenarios. The Directors have attempted to consider the potential impact of the COVID-19 pandemic on the Group's operational capabilities, liquidity and financial position over the next twelve month period and beyond. This going concern assessment has taken into account the current measures being put in place by the Group to preserve cash and reduce discretionary expenditure during a period when the Group is having to rapidly adapt to a significantly lower oil price environment.

The Group started 2020 with a strong operating and financial position, a 2019 average production rate of 3,007 bopd (Q1 2020 3,291), cash in hand and at bank of $13.8 million (Q1 2020 $14.2 million (unaudited)), no outstanding debt, crude oil hedges in place and undrawn credit facilities of $2.7 million, repayable on demand, which are available for general working capital purposes).

In making their going concern assessment, the Directors have considered what they consider to be a wide range of plausible scenarios for future oil prices, production volumes and discretionary expenditure reductions which could be implemented in response to differing oil price and production scenarios.

In making their going concern assessment the Board has looked at a number of forecast scenarios, the principal two of which are summarised below:

1. Base Case

The Base Case forecast assumes:

· Future oil prices are in line with the forward curve prevailing as at the end of April 2020, with an average realised oil price of $26.8/bbl in the period to May 2021. The forward price curve applied in the Base Case starts at $15.4/bbl in May 2020, increasing each month up to $31.37/bbl in May 2021;

· Average 2020 forecast production of 3,271 bopd and average 2021 forecast to May production of 3,123 bopd, with production being maintained by RCPs, WOs and swabbing activities but no new drilling (Q1 2020 actual average production rate of 3,291 bopd);

· The benefit of cost reduction measures across Opex, G&A and Capex which have already been implemented by the Group;

· The Group receives the benefit of the crude oil price hedges currently in place; and

· The Group repays the CIBC FirstCaribbean International Bank (Trinidad & Tobago) Limited ("CIBC") $2.7 million bank facility in October 2020 and does not receive any cash in relation to the $2.7 million VAT Bonds for which the Group has applied to the BIR.

The Base Case forecast showed that the Group will remain in a relatively strong financial position for the next twelve months, being able to pay its debts as they fall due, with available cash in May 2021 of approximately $16.0 million. Management considers this is a reasonable scenario that reflects its best estimate of the future oil price, production profile and cost savings which have already been implemented.

2. Risked Case

The Risked Case forecast is essentially a stress test which assumes:

· A flat oil price of $10.0/bbl over the period May 2020 to May 2021. This assumption represents a 63% decline on the forward curve assumed in the Base Case;

· Average 2020 forecast production of 2,829 bopd and average 2021 forecast production to May of 2,566 bopd, with production stressed to reflect the potential impact of reduced operational capability due to COVID-19. These represents a 15% decline in the production assumptions used in the Base Case in the period from January 2020 to May 2021, equivalent to a loss of an average 475 bopd over that period;

· Additional cost reductions of $2.8 million can be implemented across Opex and G&A, reflecting the reduced activity associated with the lower forecast production profile, and other cost saving measures which Management are confident can be implemented; and

· All other assumptions remain the same as the Base Case above.

The Board considers that these assumptions represent a relatively severe scenario but, given the difficulty of predicting the impact of the COVID-19 pandemic, they are not entirely implausible. The Risked Case forecast showed that, whilst the Group would still be able to pay its debts as they fall due over the next twelve months, the Group's financial position would deteriorate significantly with ending cash in May 2021 of approximately $4.0 million. This scenario relies on the ability of Management to implement the planned cost reduction measures, and it is also important to note that the Group's financial position would deteriorate further were these severe conditions to continue beyond the twelve month going concern forecast period. Should such a severe scenario arise and persist during the next twelve months, the Board will consider various means by which to adapt the business model in order to create additional financial headroom.