Half-year Report

Earnings per share (expressed in dollars per share)

RNS Number : 7283L

Trinity Exploration & Production

10 September 2019

Dissemination of a Regulatory Announcement that contains inside information according to

REGULATION (EU) No 596/2014 (MAR).

Trinity Exploration & Production plc

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

Interim Results

Strong Cash Flows and Operating Margins

Trinity, the independent E&P company focused on Trinidad & Tobago ("T&T"), announces its unaudited interim results for the six month period ended 30 June 2019 ("H1 2019" or "the period").

Trinity delivered another strong operational and financial performance during the period with production volumes successfully maintained and effective cost control and strong cash generation continuing. Production averaged 3,008 bopd, a like-for-like increase of 9% versus H1 2018 and is expected to rise in the second half of the year ("H2 2019") following the resumption of onshore drilling.

During the period, Trinity continued to manage its operating costs and capital expenditures carefully. As a consequence, unaudited H1 2019 Adjusted EBITDA increased by 20% to USD 11.2 million (H1 2018: USD 9.3 million) and the Adjusted EBITDA Margin increased to 34.8% (H1 2018: 30.9%) despite a modest decline in the realised oil price. Unaudited H1 2019 cash balances increased to USD 17.8 million as at 30 June 2019 - up from USD 10.2 million at the end of 2018 - and unaudited cash plus working capital surplus increased to USD 22.0 million as at 30 June 2019 - up from USD 18.1 million at the end of 2018.

Production has already commenced from the first new infill well of the H2 2019 drilling campaign with production from the second well expected imminently. This second well is Trinity's first High Angle Well ("HAW"), which has been successfully drilled and has intersected net oil reservoir sandstone one and a half times the thickness of those expected had it been drilled as a conventional well. In addition, the third well of the H2 2019 drilling campaign has spudded.

H1 2019 Highlights

		H1 2019¹	H1 2018	% Change
Average realised oil price²	USD/bbl	59.1	60.0	(2)
Average net production	bopd	3,008	2,771	9
Revenues	USD million	32.2	30.1	7
Adjusted EBITDA³	USD million	11.2	9.3	20
Adjusted EBITDA⁴	USD/bbl	20.6	18.6	11
Adjusted EBITDA margin⁵	%	34.8	30.9	13
Adjusted EBITDA after SPT & PT⁶	USD million	6.5	5.4	20
Group operating break-even⁷	USD/bbl	26.3	28.5	(8)
Cash balance	USD million	17.8	9.1	96
Cash plus working capital surplus⁸	USD million	22.0	11.8	86

Notes:

1. Excludes the impact of adopting IFRS 16 for H1 2019 to illustrate the like-for like, period-on-period comparative with H1 2018 using IAS 17. Refer to section on Adoption of IFRS 16 for comparative representations.

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

3. Adjusted EBITDA: Operating Profit before Taxes 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/ production over the period.

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

6. Adjusted EBITDA after SPT & PT: Adjusted EBITDA less Supplementary Petroleum Taxes and Property Taxes. H1 2018 included a write back of USD 1.1 million relating to 2016 and 2017 PT which has been excluded to aid period-on-period comparison.

7. Group operating break-even: The realised price/bbl where the adjusted EBITDA/bbl for the Group is equal to zero. See Appendix 1 - Trading Summary Table.

8. See section on Cash plus working capital surplus (formerly net cash position) for additional information.

H1 2019 Highlights

Operational

· H1 2019 average production of 3,008 bopd (H1 2018: 2,771 bopd), representing a 9% increase over the corresponding period last year, underpinned by:

o 5 recompletions ("RCPs") (H1 2018: 7)

o Base production maintenance through a continuous campaign of 71 workovers ("WOs") and reactivations (H1 2018: 62)

Financial

· Opex reduced by 9% to USD 14.9/bbl (H1 2018: USD 16.5/bbl).

· Group operating break-even decreased by 8% to USD 26.3 /bbl (H1 2018: USD 28.5/bbl)

· Adjusted EBITDA increased 20% to USD 11.2 million (H1 2018: USD 9.3 million)

· Adjusted EBITDA/bbl improved by 11% to USD 20.6/bbl (H1 2018: USD 18.6/bbl) and Adjusted EBITDA Margin improved by 13% to 34.8% (H1 2018: 30.9%)

· Adjusted EBITDA after SPT and PT increased 20% to USD 6.5 million (H1 2018: USD 5.4 million)

· Capital expenditure of USD 2.5 million (H1 2018: USD 4.4 million)

· Cash plus working capital surplus at USD 22.0 million on 30 June 2019 (H1 2018: USD 11.8 million)

· The new Onshore wells drilled benefit from lower Overriding Royalties ("ORR") in Year 1 at 0% and Year 2 at 10%, compared with the base ORR rates applying under the Lease Operatorship Agreements.

Post Period End Highlights

Operational

o Onshore: First High Angle Well ("HAW") completed

· Two wells drilled and completed and third well spudded of the H2 2019 drilling programme

o First well was spudded in July 2019 and put on production after 21 days

o The second well drilled, Trinity's first HAW, FR 1807, was successfully drilled to Total Depth at 3,038 ft within 14 well days and intersected net oil reservoir sandstone one and a half times the thickness expected had it been drilled as a conventional well on this target. Completion permissions have been granted and the well has been perforated with first production expected imminently

o The third well was spudded in late August with drilling operations expected to be completed by mid-September

o Onshore: Production Optimisation Programme

· As part of an overall Supervisory Control and Data Acquisition ("SCADA") approach to production optimisation onshore and offshore Trinity and Weatherford International plc (WFTIQ) ("Weatherford") have entered a partnership onshore Trinidad:

o Piloting use of Weatherford's ForeSite® Production Optimisation Production 4.0 platform (Software and Automation) in order to maximise returns from the Company's onshore wells

o First instance where technology of this kind has been deployed in the onshore oil producing acreage of Trinidad

o Technology has been deployed on both Progressive Cavity and Sucker Rod Pumps

o By providing support for a broad array of production methods and the ability to optimise an asset from well to surface facility, it will enable Trinity to identify and prioritise production optimisation opportunities

o If deemed successful, Trinity aims to utilise continuous production optimisation on key wells in order to further reduce operating costs and increase reserves and production

o Offshore: East Coast Galeota Development progressing

· Detailed technical and commercial discussions progressing with partner Heritage Petroleum Company Limited ("Heritage") and technical providers

o Review of commercial terms initiated with Heritage and the Ministry of Energy and Energy Industries ("MEEI")

o A pre-Front End Engineering Design ("pre-FEED") study was completed on the subsea power cable, initial stability analysis completed on a new pipeline, and initial design studies are progressing on the platform. A pre-FEED study on onshore fluids handling requirements to commence during September

o Environmental permit application for field development submitted; it is expected that the relevant environmental studies will be undertaken during H2 2019 and 2020 in order to secure the environmental permit

Corporate

o Hedging

· Trinity has taken advantage of the oil price strength in July 2019 to put in place a layer of hedging which is designed to protect a portion of Group cash flows between USD 50.0 - USD 55.0/bbl thereby partially offsetting the impact of SPT whilst retaining upside exposure to rising oil prices over the majority of production

Hedge	Floor	Cap	Strike Price	Production	Effective Date	Expiry Date
	USD/bbl	USD/bbl	USD/bbl	Barrels monthly
Put Spread	50.0	55.0	N/A	12,500	01-Jul-19	31-Dec-19
3-Way Option	50.0	55.0	64.4	12,500	01-Jul-19	30-Jun-20

Operational Look Ahead

o Continued Drilling activity

· The H2 2019 drilling campaign envisages drilling up to eight onshore wells by the end of 2019

· The number of wells to be drilled will be dependent on results and prevailing market conditions

· The results from the first HAW will be closely monitored to enable the high grading of further HAW drilling candidates

· Routine production activity

· H2 2019 work programme will continue with planned RCPs, routine WOs, reactivations and swabbing

· Overriding focus on becoming sustainably and significantly free cash flow generative

· Maintain low operating break-even, providing strong operational hedging

· Further reduce opex/bbl via increased production (preserving base production and increasing individual well production rates) and leveraging via economies of scale, new technology applications and well optimisations

· Reduce capital costs of drilling new wells

· Improve commercial terms across the asset base

Bruce Dingwall CBE, Executive Chairman of Trinity, commented:

"The first half of the year delivered another strong performance as Trinity continued to increase base production levels whilst controlling costs, deriving further operating efficiencies ahead of the recommencement of our onshore drilling programme. Importantly, with our financial performance demonstrating the success of our near-term strategy, we also continued to progress longer-term objectives with regards to our offshore opportunity.

"Our strong balance sheet and robust base production mean that we are delivering on our financial and production targets, and at the same time, ensuring that we can take advantage of any strategic opportunities that may arise. We remain focused on maximising output and returns for shareholders and continue to evaluate the best ways of protecting and enhancing those returns through prudent treasury management, industry leading operating practices and technical innovation. Given the strength of our business model, the ongoing work programme and visibility afforded by our balance sheet, we continue to face the future with confidence."

Management Interview

Watch management discuss today's results and future prospects by clicking on the following link: http://bit.ly/TRINH1_2019

Enquiries

Trinity Exploration & Production

Bruce Dingwall, Executive Chairman

Jeremy Bridglalsingh, Chief Financial Officer

Tracy Mackenzie, Corporate Development Manager

+44 (0)131 240 3860

SPARK Advisory Partners Limited (NOMAD & Financial Adviser)

Mark Brady

Miriam Greenwood

Andrew Emmott

+44 (0)20 3368 3550

Cenkos Securities PLC (Broker)

Joe Nally (Corporate Broking)

Neil McDonald

Derrick Lee

Pete Lynch

+44 (0)20 7397 8900

+44 (0)131 220 6939

Whitman Howard Limited (Equity Adviser)

Nick Lovering

Hugh Rich

+44 (0)20 7659 1234

Walbrook PR Limited

Nick Rome

trinityexploration@walbrookpr.com +44 (0)20 7933 8780

Competent Person's Statement

All reserves and resources related information contained in this announcement has been reviewed and approved by Graham Stuart, Trinity's Technical Adviser, who has 36 years of relevant global experience in the oil industry. Mr. Stuart holds a BSC (Hons) in Geology.

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 (9) 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 listed on the AIM market of the London Stock Exchange under the ticker TRIN.

Disclaimer

This document contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil exploration and production business. Whilst the Group believes the expectation reflected herein to be reasonable in light of the information available to it at this time, the actual outcome may be materially different owing to macroeconomic factors either beyond the Group's control or otherwise within the Group's control.

OPERATIONAL REVIEW

During H1 2019, the Company continued to build on the momentum achieved in 2018 through the continuation of the RCP programme, routine WOs, reactivations and swabbing, delivering 9% year-on-year production growth. The H2 2019 activity set will include up to eight new onshore infill wells alongside RCPs, WOs, reactivations and swabbing activities which is expected to lead to an increase in the base level of production going into 2020.

Onshore operations

· H1 2019 average net production was 1,615 bopd (H1 2018: 1,530 bopd). The 6% increase was as a result of the infill wells drilled in 2018 and continued performance from the ongoing RCPs (5) and base maintenance WOs and reactivations (56) (H1 2018: 7 RCPs, 47 WOs and reactivations).

· Technological strategies are being implemented using Supervisory Control and Data Acquisition ("SCADA") approach to:

- Reduce time to detect Electrical Shut Downs ("ESDs") from field power losses through the implementation of real time monitoring tools to potentially limit the amount of down time on wells

- Solution application for Sucker Rod Pumps and Progressive Cavity Pumps (support predicative analysis through real time surveillance and support well optimisation)

- Battery Station and Wells Site Tanks automation and monitoring

· H2 2019 planned work programme anticipates:

- Up to eight infill wells which will allow a further rebasing of production levels

- 12 RCPs and ongoing base management via WOs and reactivations and swabbing across all onshore fields

East Coast operations

· H1 2019 average production was 1,208 bopd (H1 2018: 1,046 bopd). The 15% increase in production was a result of the RCP executed in H2 2018 and the workover and reactivation campaign of 5 WOs during H1 2019 (H1 2018: 15 WOs)

· H2 2019 work programme is targeting a second RCP offshore in addition to the programme of routine WOs and reactivations

· Well optimisation strategies are being implemented using the SCADA approach to reduce current spend on real time monitoring and data aggregation of Electrical Submersible Pumps ("ESPs")

· Trinity continues to invest in maintaining production levels via better power generation management, continued pump optimisation and the review of alternative artificial lift technologies to augment production

West Coast operations

· H1 2019 average net production was 185 bopd (H1 2018: 195 bopd). The 5% decrease in production was the result of natural production decline. During H1 2019 5 WOs (H1 2018: nil) were executed to maintain base production levels

· H2 2019 planned work programme will include WOs on key wells to maintain production levels

FINANCIAL REVIEW

Income Statement Analysis

	H1 2019	H1 2018	Change
Production
Average realised oil price (USD/ bbl)	59.1	60	(1)
Average net production (bopd)	3,008	2,771	237

Statement of Comprehensive Income	USD'000	USD'000	USD'000
Operating revenues	32,216	30,098	2,118
Operating expenses (excluding DD&A)	(21,369)	(22,741)	1,372
Operating profit before DD&A	10,847	7,357	3,490
DD&A	(5,102)	(4,746)	(356)
Operating profit before SPT & PT	5,745	2,611	3,134
SPT	(4,427)	(3,650)	(777)
PT	(247)	884	(1,131)
Operating profit before exceptional items	1,071	(155)	1,226
Exceptional items	(930)	11,616	(12,546)
Operating profit/(loss)			-
after exceptional items and SPT & PT	141	11,461	(11,320)
Finance cost	(713)	(1,279)	566
Profit before Taxation	(572)	10,182	(10,754)
Taxation (charge)/credit	(154)	5,726	(5,880)
(Loss)/profit after income tax	(726)	15,908	(16,634)
Currency translation	95	(19)	114
Total comprehensive (expense)/income	(631)	15,889	(16,520)

Operating Revenues

Operating revenues of USD 32.2 million (H1 2018: USD 30.1 million). Increased production drove the USD 2.1 million increase in revenue for the period despite a modestly lower realised oil price.

Operating Expenses See Note: Adoption of IFRS 16 in relation to Operating and G&A expenses

Operating expenses of USD (26.5) million (H1 2018: USD (27.5) million) comprised of the following:

· Royalties of USD (10.1) million (H1 2018: USD (10.0) million)

· Production costs ("Opex") of USD (7.9) million (H1 2018: USD (8.3) million)

· Depreciation, Depletion and Amortisation ("DD&A") charges of USD (5.1) million (H1 2018: USD (4.7) million)

· General and administrative ("G&A") expenditure of USD (2.7) million (H1 2018: USD (2.5) million)

· Share Option expense USD (0.5) million (H1 2018: USD (0.4) million)

· Foreign Exchange loss USD (0.2) million (H1 2018: USD (0.0) million)

· Other expenses nil (H1 2018: (1.6) million relate to fair value adjustment on the oil price derivative in H1 2018)

Operating Profit Before Supplemental Petroleum Taxes ("SPT") and Property Tax ("PT")

The operating profit before SPT and PT for the period amounted to USD 5.7 million (H1 2018: USD 2.6 million) and was driven by increased production and effective cost control.

SPT & PT

The Group incurred an SPT charge of USD (4.4) million in H1 2019 (H1 2018: USD (3.7) million), on account of the realised oil price exceeding USD 50.0/bbl throughout the period. An accrual for PT of USD (0.2) million arose for the period (H1 2018: USD 0.9 million, comprising an accrual of H1 2018 of USD (0.2) million and a reversal for 2016 and 2017 of USD 1.1 million).

Operating Profit Before Exceptional items

The Operating Profit Before Exceptional items for the period amounted to USD 1.0 million (H1 2018: USD (0.2) million loss) and was mainly driven by increased production and effective cost control.

Exceptional items

Exceptional items charge of USD (0.9) million (H1 2018: USD (11.6) million credit) relate to:

· Impairment of property plant and equipment USD 0.8 million (H1 2018: nil)

· Impairment of receivables and inventory USD 0.1 million (H1 2018: nil)

· Fees relating to corporate restructuring and unsecured creditor compromise USD 0.0 million (H1 2018: nil)

· Gain on fair value of financial instrument nil (H1 2018: USD 11.6 million credit). In 2018 a revaluation of the embedded call option associated with the Convertible Loan Notes ("CLNs") incurred a non-cash gain. The embedded call option associated with the CLN was revalued as at 30 June 2018 which resulted in a fair value gain arising on the financial instrument. This gain was eliminated when the CLNs were converted or repaid subsequent to the period end, and as such did not appear in the 2018 full year results.

Net Finance Cost

Finance costs for the period totalled USD (0.7) million (H1 2018: USD (1.3) million), comprised of:

· Unwinding of the discount rate on the decommissioning provision of USD (0.6) million (H1 2018: USD (0.8) million)

· Accrued interest on CLN- nil (H1 2018: USD (0.5) million)

· Interest income - USD 0.1 million (H1 2018: USD 0.0 million)

· Interest on taxes - USD (0.1) million (H1 2018: nil)

· Interest on leases - USD (0.1) million (H1 2018: nil)

Taxation

Taxation (charge)/credit for the period was USD (0.2) million charge (H1 2018: USD 5.7 million credit), comprised of:

· Reduction in deferred tax assets recognised of USD (0.8) million (H1 2018: USD 5.8 million)

· Reduction in deferred tax liability of USD 0.7 million (H1 2018: USD (0.0) million)

· Unemployment Levy of USD (0.1) million (H1 2018: (0.1) million)

As at 30 June 2019, the Group had unrecognised tax losses of USD 234.8 million (H1 2018: 213.0 million) which have no expiry date.

Total Comprehensive (Expense)/ Income

Total Comprehensive Expense for the period was USD (0.6) million (H1 2018: 15.9 million income, as a result of non-cash exceptional items).

Cash Flow Analysis

Opening Cash Balance

Trinity began the year with an initial cash balance of USD 10.2 million (2018: USD 11.8 million).

Summary of Statement of Cash Flows
	H1 2019	H1 2018	FY 2018
	USD'000	USD'000	USD'000
Opening cash balance	10,201	11,792	11,792
Cash movement
Net cash inflow from operating activities	10,394	4,996	5,207
Net cash outflow from Unsecured and T&T State Creditor payments	-	(3,254)	(5,835)
Net cash outflow from investing activities	(2,541)	(4,403)	(12,460)
Net cash outflow from financing activities	(288)	-	11,497
Increase/ (decrease) in cash and cash equivalents	7,565	(2,661)	(1,591)
Closing cash balance	17,766	9,131	10,201

Net cash inflow from operating activities

Cash inflow from operating activities was USD 10.4 million (H1 2018: USD 5.0 million).

· Operating activities for H1 2019 resulting in an adjusted profit before changes in working capital and tax of USD 6.4 million (H1 2018: USD 5.7 million)

· Changes in working capital resulted in a net increase of USD 3.9 million (H1 2018: USD (0.7) million)

· Trade and other receivables in relation to Petroleum Company of Trinidad and Tobago ("Petrotrin") restructuring:

- Trinity received USD 5.3 million from Petrotrin in H1 2019 for crude oil volumes delivered for the period October to November 2018 in H1 2019

- At 30 June 2019 the outstanding balance from Petrotrin was USD 1.4 million. Post 30 June 2019 Trinity received a further USD 0.9 million which leaves a remaining outstanding balance of USD 0.5 million. Management anticipates full payment by the end of Q3 2019

· Taxation paid USD (0.0) million (H1 2018: USD (0.1) million )

Restructuring related payments

There were no working capital cash outﬂows relating to the restructuring during H1 2019 as these debts were fully repaid in H2 2018. In H1 2018: payments of USD (3.3) million were made to T&T State Creditors (BIR and MEEI)

Cash outflow from investing activities

Trinity incurred capital expenditures mainly on production related investment on its onshore assets and infrastructure investment on its East Coast assets totaling USD (2.5) million in aggregate (H1 2018: USD (4.4) million)

Net cash outflow from financing activities

Cash payment on leases of USD (0.2) million (H1 2018: nil). See note adoption of IFRS 16

Closing Cash Balance

Trinity's cash balance at 30 June 2019 was USD 17.8 million (H1 2018: USD 9.1 million)

Adoption of IFRS 16 Leases

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 IFRIC 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 Condensed Consolidated Statement of Comprehensive Income

(a) Impact on Net Profit and Earnings per share:	IFRS 16	IAS 17	Difference
	USD'000	USD'000	USD'000
Expenses
Production costs ("Opex")	(7,903)	(8,116)	213
General & Administrative Expenses ("G&A")	(2,665)	(2,739)	74
Depreciation, Depletion and Amortisation	(5,102)	(4,867)	(235)
Finance costs	(713)	(632)	(81)
	(16,383)	(16,354)	(29)

Total Comprehensive (Expense)/Income for the period	(631)	(602)	(29)
Earnings Per Share	0.00	0.00	0.00

(b) Impact on non-IFRS measures used by the Group:

		IFRS 16	IAS 17	Difference
Opex	USD '000	(7,903)	(8,116)	213
G&A	USD '000	(2,665)	(2,739)	74
Total	USD '000	(10,568)	(10,855)	287

H1 2019 Metrics
Opex	USD/bbl	14.5	14.9	(0.4)
G&A	USD/bbl	4.9	5.0	(0.1)
Adjusted EBITDA	USD '000	11,506	11,219	287
Adjusted EBITDA	USD/bbl	21.1	20.6	0.5
Adjusted EBITDA After SPT & PT	USD '000	6,832	6,545	287
Adjusted EBITDA After SPT & PT	USD/bbl	12.5	12.0	0.5
Group operating break-even	USD/bbl	25.6	26.3	(0.7)

2. Impact on Condensed Consolidated Statement of Financial Position

ROU and Lease Liabilities recognised in Balance Sheet:	1-Jan-19	Depreciation	Lease Payment	30-Jun-19
	USD'000			USD '000
ROU recognised
Non- current assets	1,739	(235)	-	1,504
	1,739	(235)	-	1,504

Lease Liabilities recognised as at 1 January 2019
Current lease liabilities	529		(207)	322
Non-current lease liabilities	1,210			1,210
	1,739	-	(207)	1504

Cash Plus Working Capital Surplus (Formerly Net Cash/Debt Position)

Statement of Financial Position Extract	H1 2019	H1 2018
Statement of Financial Position Extract	USD MM	USD MM
	Unaudited	Unaudited
	Unaudited	Unaudited
A: Current Assets
Cash and cash equivalents	17.8	9.1
Trade and other receivables	9.6	6.3
Inventories	5.3	3.9
Derivative financial asset	-	11.6
Total Current Assets	32.7	30.9

B: Liabilities
Non-current
Convertible loan note¹	-	7.3
Total Non-Current Liabilities²	-	7.3

Current
Trade and other payables	10.7	9.9
Taxation payable	0.0	0.2
Derivative Financial Instrument	-	1.7
Total Current Liabilities³	10.7	11.8
Total Liabilities	10.7	19.1

(A-B): Cash plus working capital surplus	22.0	11.8

Notes:

1. States the Face Value of the 2018 CLN and MEEI liabilities as opposed to amortised cost stated in the Financials

2. Non-Current Liabilities excludes Lease Liabilities, Deferred Tax Liability & Provision for other liabilities

3. Current Liabilities excludes Lease Liabilities and Provision for other liabilities

APPENDIX 1: TRADING SUMMARY

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

Trading Summary Table

Details	H1 2019¹	H1 2018	% Change

Realised price (USD/bbl)	59.1	60.0	-2
Production (bopd)
Onshore	1,615	1,530	6
West Coast	185	195	(5)
East Coast	1,208	1,046	15
Group Consolidated	3,008	2,771	9

Operating break-even (USD/bbl)
Onshore	15.9	15.7	2
West Coast	33.5	24.4	37
East Coast	19.4	27.8	(30)
Group Consolidated²	26.3	28.5	(8)

Metrics (USD/bbl)
Opex/bbl - Onshore	11.7	11.4	3
Opex/bbl - West Coast	27.6	20.3	36
Opex/bbl - East Coast	15.4	21.5	(29)
Opex/bbl - Group Consolidated	14.9	16.5	(9)
G&A/bbl	5.0	5.0	-

Notes:

1. Metrics does not include the impact of IFRS 16 for H1 2019 so as to illustrate the like-for like, period -on-period comparative with H1 2018. Refer to section on Adoption of IFRS 16 Leases for additional explanations

2. Group operating break-even: The realised price/bbl for which the adjusted EBITDA/bbl for the Group is equal to zero.

Independent review report to Trinity Exploration & Production Plc

Report on the Condensed Consolidated Interim Financial Statements

Our conclusion

We have reviewed Trinity Exploration & Production Plc's Condensed Consolidated Interim Financial Statements (the "interim financial statements") in the interim results of Trinity Exploration & Production Plc for the 6 month period ended 30 June 2019. Based on our review, nothing has come to our attention that causes us to believe that the interim financial statements are not prepared, in all material respects, in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union and the AIM Rules for Companies.

What we have reviewed

The interim financial statements comprise:

● the Condensed Consolidated Statement of Financial Position as at 30 June 2019;

● the Condensed Consolidated Statement of Comprehensive Income for the period then ended;

● the Condensed Consolidated Cashflow Statement for the period then ended;

● the Condensed Consolidated Statement of Changes in Equity for the period then ended; and

● the explanatory notes to the interim financial statements.

The interim financial statements included in the interim results have been prepared in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union and the AIM Rules for Companies.

As disclosed in note 1 to the interim financial statements, the financial reporting framework that has been applied in the preparation of the full annual financial statements of the Group is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the European Union.

Responsibilities for the interim financial statements and the review

Our responsibilities and those of the directors

The interim results, including the interim financial statements, is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the interim results in accordance with the AIM Rules for Companies which require that the financial information must be presented and prepared in a form consistent with that which will be adopted in the company's annual financial statements.

Our responsibility is to express a conclusion on the interim financial statements in the interim results based on our review. This report, including the conclusion, has been prepared for and only for the company for the purpose of complying with the AIM Rules for Companies and for no other purpose. We do not, in giving this conclusion, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

What a review of interim financial statements involves

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures.

A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and, consequently, does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

We have read the other information contained in the interim results and considered whether it contains any apparent misstatements or material inconsistencies with the information in the interim financial statements.

PricewaterhouseCoopers LLP

Chartered Accountants

Aberdeen

10 September 2019

STATEMENT OF DIRECTORS' RESPONSIBILITY

The Directors confirm that this condensed consolidated interim financial information has been prepared in accordance with International Accounting Standards ("IAS") 34 as adopted by the European Union and that the interim management report includes a fair review of the information required by DTR 4.2.7 and DTR 4.2.8, namely:

· an indication of important events that have occurred during the first six (6) months and their impact on the condensed set of financial statements, and a description of the principal risks and uncertainties for the remaining six (6) months of the financial year; and

· the management report, which is incorporated into the directors' report, includes a fair review of the development and performance of the business and the position of the Company and the undertakings included in the consolidation taken as a whole, together with a description of the principal risks and uncertainties that they face; and

· material related party transactions in the first six (6) months and any material changes in the related-party transactions described in the last annual report.

A list of the current Directors is maintained on the Trinity Exploration & Production plc website www.trinityexploration.com.

By order of the Board

Bruce Dingwall, CBE

Executive Chairman

Trinity Exploration & Production plc Condensed Consolidated Statement of Comprehensive Income for the period ended 30 June 2019 (Expressed in United States Dollars)
	Notes	6 months to 30 June 2019	6 months to 30 June 2018	Year ended 31 December 2018
		$'000	$'000	$'000
		(unaudited)	(unaudited)	(audited)
Operating Revenues
Crude oil sales		32,205	30,085	62,578
Other income		11	13	15
		32,216	30,098	62,593

Operating Expenses
Royalties		(10,142)	(10,013)	(20,390)
Production costs		(7,903)	(8,259)	(17,754)
Depreciation, depletion and amortisation	1,7,8	(5,102)	(4,746)	(10,694)
General and administrative expenses		(2,665)	(2,510)	(5,240)
Share option expense	11	(494)	(369)	(737)
Foreign exchange (loss)/gain		(165)	(4)	17
Other operating expenses		--	(1,586)	(1,075)
		(26,471)	(27,487)	(55,873)

Operating Profit Before Supplemental Petroleum Taxes ("SPT") and Property Tax ('PT")		5,745	2,611	6,720

SPT		(4,427)	(3,650)	(7,050)
PT	4	(247)	884	607

Operating Profit/ (Loss) Before Exceptional Items		1,071	(155)	277

Exceptional items	3	(930)	11,616	(2,312)

Operating Profit/ (Loss) After Exceptional Items		141	11,461	(2,035)

Net finance cost	6	(713)	(1,279)	(2,056)

(Loss)/Profit Before Income Taxation		(572)	10,182	(4,091)

Income Taxation (expense)/credit	5	(154)	5,726	(1,270)

(Loss)/Profit for the period		(726)	15,908	(5,361)

Other Comprehensive Income/(Expense)
Currency Translation		95	(19)	40

Total Comprehensive (Expense)/Income for the period		(631)	15,889	(5,321)

Trinity Exploration & Production plc Condensed Consolidated Statement of Financial Position for the period ended 30 June 2019 (Expressed in United States Dollars)
	Notes	As at 30 June 2019	As at 30 June 2018	As at 31 December 2018
ASSETS		$'000	$'000	$'000
		(unaudited)	(unaudited)	(audited)
Non-current Assets
Property, plant and equipment	7	50,112	52,552	53,599
Right-of-use assets	1	1,504	--	--
Intangible assets	8	26,082	25,708	25,757
Abandonment fund		3,124	2,185	2,979
Performance bond (Investment held to maturity)		253	253	253
Deferred tax asset	12	5,217	9,948	5,973
		86,292	90,646	88,561
Current Assets
Inventories		5,255	3,940	3,738
Trade and other receivables	9	9,570	6,254	13,343
Derivative financial assets		--	11,616	--
Cash and cash equivalents		17,766	9,131	10,201
		32,591	30,941	27,282
Total Assets		118,883	121,587	115,843

Equity
Capital and Reserves Attributable to Equity Holders
Share capital	10	97,692	96,676	97,692
Share premium	10	139,879	125,362	139,879
Other equity		--	590	--
Share based payment reserve	11	13,784	12,922	13,290
Reverse acquisition reserve		(89,268)	(89,268)	(89,268)
Merger reserves		75,467	75,467	75,467
Translation reserve		(1,649)	(1,532)	(1,638)
Accumulated deficit		(177,104)	(155,204)	(176,473)
Total Equity		58,801	65,013	58,949

Non-current Liabilities
Lease liabilities	1	1,210	--	--
Convertible loan note ("CLN")		--	3,378	--
Deferred tax liability	12	4,911	2,508	5,598
Provision for other liabilities	13	42,569	38,772	41,802
		48,690	44,658	47,400
Current Liabilities
Trade and other payables	14	10,711	9,862	9,147
Lease liabilities	1	322	--	--
Taxation payable	5	41	198	--
Derivative financial liabilities		--	1,703	--
Provision for other liabilities	13	318	153	347
		11,392	11,916	9,494
Total Liabilities		60,082	56,574	56,894
Total Shareholders' Equity and Liabilities		118,883	121,587	115,843

Trinity Exploration & Production plc

Condensed Consolidated Statement of Changes in Equity

for the period ended 30 June 2019

(Expressed in United States Dollars)

	Share Capital	Share Premium	Other Equity	Share Based Payment Reserve	Reverse Acquisition Reserve	Merger Reserve	Translation Reserve	Accumulated Deficit	Total
	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000	$'000

Balance at 1 January 2018	96,676	125,362	590	12,553	(89,268)	75,467	(1,678)	(171,112)	48,590
Share based payment charge	--	--	--	369	--	--	--	--	369
Translation difference	--	--	--	--	--	--	146	--	146
Total comprehensive income for the period	--	--	--	--	--	--	--	15,908	15,908
Balance at 30 June 2018 (unaudited)	96,676	125,362	590	12,922	(89,268)	75,467	(1,532)	(155,204)	65,013

Balance at 1 January 2019	97,692	139,879	--	13,290	(89,268)	75,467	(1,638)	(176,473)	58,949
Share based payment charge	--	--	--	494	--	--	--	--	494
Translation difference	--	--	--	--	--	--	(11)	--	(11)
Total comprehensive loss for the period	--	--	--	--	--	--	--	(631)	(631)
Balance at 30 June 2019 (unaudited)	97,692	139,879	--	13,784	(89,268)	75,467	(1,649)	(177,104)	58,801

Trinity Exploration & Production plc Condensed Consolidated Cashflow Statement for the period ended 30 June 2019 (Expressed in United States Dollars)
	Notes	6 months to 30 June 2019	6 months to 30 June 2018	Year ended 31 December 2018
		$'000	$'000	$'000
		(unaudited)	(unaudited)	(audited)
Operating Activities
Profit before taxation		(572)	10,182	(4,091)
Adjustments for:
Translation difference		(93)	(675)	330
Finance Income		78	31	--
Finance cost	6	--	359	499
Share option expense		494	368	737
Finance cost - decommissioning provision	6	586	778	1,557
Depreciation, depletion and amortisation	1,7,8	5,102	4,746	10,694
Loss on disposal of assets	7	--	(6)	(6)
Impairment of property, plant and equipment	7	835	--	2,561
Impairment of inventory		50	--	--
Impairment of receivables		54	--	--
Fair value zero cost collar		--	1,586	--
Gain recognised on embedded derivative		--	(11,616)
Unsecured creditors claim	3	(19)	--	(192)
Compromised creditor balances		--	(18)	--
		6,515	5,735	12,089

Changes In Working Capital
(Increase)/Decrease in Inventory		(1,567)	(163)	28
Decrease/(Increase) in Trade and other receivables		3,687	(843)	(9,513)
Increase/(Decrease) in Trade and other payables		1,802	395	2,731
Taxation paid		(43)	(128)	(128)

Net Cash Inflow From Operating Activities		10,394	4,996	5,207

Restructuring related payments
T&T State creditors (BIR and MEEI)		--	(3,254)	(5,835)

Investing Activities
Purchase of computer software		--	--	(26)
Exploration and Evaluation Assets	8	(332)	(46)	(170)
Purchase of property, plant & equipment	7	(2,209)	(4,357)	(12,264)
Net Cash Outflow From Investing Activities		(2,541)	(4,403)	(12,460)

Financing Activities
Finance cost		--	--	(94)
Cash payment on lease (ROU)		(288)	--	--
Issue of shares (net of costs)		--	--	12,361
Repayment of CLNs		--	--	(770)
Net Cash (Outflow)/Inflow From Financing Activities		(288)	--	11,497

Increase/(Decrease) in Cash and Cash Equivalents		7,565	(2,661)	(1,591)
Cash And Cash Equivalents
At beginning of period		10,201	11,792	11,792
Increase/(Decrease)		7,565	(2,661)	(1,591)
At end of period		17,766	9,131	10,201

Trinity Exploration & Production plc

Notes to the Condensed Consolidated Financial Statements for the period ended 30 June 2019

1 Background and Accounting Policies

Background

Trinity Exploration & Production plc ("Trinity") is incorporated and registered in England and trades on the Alternative Investment Market ("AIM"), a market operated by London Stock Exchange plc. Trinity ("the Company") and its subsidiaries (together "the Group") are involved in the exploration, development and production of oil reserves in Trinidad.

Basis of Preparation

These condensed interim financial statements for the six months ended 30 June 2019 have been prepared in accordance with IAS 34, 'Interim financial reporting', as adopted by the European Union ("EU"), on a going concern basis. The condensed interim financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2018, which have been prepared in accordance with International Financial Reporting Standards ("IFRS") as adopted by the EU.

The results for the six months ended 30 June 2019 and 30 June 2018 are unaudited and do not comprise statutory accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 December 2018 were approved by the board of directors and delivered to the Registrar of Companies. The report of the independent auditors on those accounts was unqualified.

Going Concern

In making their going concern assessment, the Directors have considered the Group's budget and cash flow forecasts taken together with its performance during the first half of the financial year.

During the period, the Group continued to control its operating costs and capital expenditures carefully. As a consequence, unaudited cash balances increased to $17.8 million as at 30 June 2019, an increase of $7.6 million compared to the cash balance at the end of 31 December 2018 ($10.2 million), which is available to support the recommencement of the Group's drilling campaign in H2 2019.

The Group continues to work hard on all facets of its business by maintaining close attention to base production, growing production through new infill drilling, progressing the TGAL development, and being well positioned to capitalise on the changing local market. 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 of Directors have a reasonable expectation that the Group has adequate resources to continue operational existence for the foreseeable future. The Group therefore continues to adopt the going concern basis of preparing the interim financial statements.

Accounting policies

The accounting policies adopted are consistent with those of the previous financial year, and corresponding interim reporting period, except for the estimation of income tax (note 5a) and the adoption of new and amended standards as set out below.

New and amended standards adopted by the group

A number of new or amended standards became applicable for the current reporting period, and the Group had to change its accounting policies as a result of adopting IFRS 16 Leases.

The impact of the adoption of the leasing standard and the new accounting policies are disclosed in note "Changes in accounting policies" below. The other standards did not have any impact on the Group's accounting policies and did not require retrospective adjustments.

Changes in accounting policies

· Adoption of IFRS 16 Leases ("IFRS 16")

The Group adopted IFRS 16, effective 1 January 2019. This is a new accounting standard resulting in almost all leases being recognised on the balance sheet, as the distinction between operating and finance leases is removed. Under the new standard, an asset (the right to use the leased item) and a financial liability to pay rentals are recognised. The only exceptions are short-term (less than 12 months) and low-value leases (less than $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 adoption of IFRS 16, the Group has recognised right of use assets and lease liabilities, but under the practical expedient permitted by the standard, elected not to reassess whether a contract is, or contains a lease at the date of initial application. Instead, for contracts entered into before the transition date the Group relied on its assessment made applying IAS 17 and IFRIC 4 determining whether an arrangement contains a Lease.

a) Adjustments recognised on adoption of IFRS 16

Right of Use Assets ("ROU") and Lease Liabilities recognised in Balance Sheet

	30 June 2019	01 January 2019
	$'000	$'000
ROU recognised
Non- current assets	1,504	1,739

Lease Liabilities recognised
Current lease liabilities	322	529
Non-current lease liabilities	1,210	1,210
	1,504	1,739

The ROU assets relate to Motor vehicles, Office building, Staff house and Office equipment leases that met the recognition criteria of a Lease under IFRS 16.

i. Impact on Earnings per share

	IFRS 16	IAS 17	Difference
	$'000	$'000	$'000
Expenses
Production costs	(7,903)	(8,116)	213
General and administrative expenses	(2,665)	(2,739)	74
Depreciation, depletion and amortisation	(5,102)	(4,867)	(235)
Finance cost	(713)	(632)	(81)
	(16,383)	(16,354)	(29)

Total Comprehensive (Expense)/Income for the period	(631)	(602)	(29)
Earnings per Share	(0.00)	(0.00)	(0.00)

ii. Practical expedients applied

In applying IFRS 16 for the first time, the Group has used the following practical expedients permitted by the standard:

· the use of a single discount rate to a portfolio of leases with reasonably similar characteristics

· reliance on previous assessments on whether leases are onerous

· the accounting for operating leases with a remaining lease term of less than 12 months as at January 2019 as short-term leases

· the exclusion of initial direct costs for the measurement of the right-of-use asset at the date of initial application, and the use of hindsight in determining the lease term where the contract contains options to extend or terminate the lease.

The Group has also elected not to reassess whether a contract is, or contains a lease at the date of initial application. Instead, for contracts entered into before the transition date the Group relied on its assessment made applying IAS 17 and IFRIC 4 Determining whether an Arrangement contains a Lease.

b) The Group's leasing activities and how these are a accounted for:

The Group has lease agreements for various types of assets; Motor vehicles, Office buildings, Staff house and Office equipment leases are typically made for fixed terms ranging between 1-3 years but may have extension options.

Until the 2018 financial year, leases of property, plant and equipment were all classified as operating leases as the Group had no finance leases. Payments made under operating leases (net of any incentives received from the lessor) were charged to profit or loss on a straight-line basis over the period of the lease.

From 1 January 2019, leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Group. Each lease payment is allocated between the liability and finance cost. The finance cost is charged to profit or loss over the lease period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period. The right-of-use asset is depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis.

Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of fixed payments (including in-substance fixed payments), less any lease incentives receivable.

The lease payments are discounted using a 9.25% incremental borrowing rate, being the rate that the Group believes it would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions.

Right-of-use assets are measured at cost comprising the following:

· the amount of the initial measurement of lease liability

· any lease payments made at or before the commencement date less any lease incentives received

· any initial direct costs, and

· restoration costs.

Payments associated with short-term leases and leases of low-value assets are recognised on a straight-line basis as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less. Low-value assets comprise of assets value less than $5,000.

Estimates

The preparation of interim financial statements requires management to make judgements, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expenses. Actual results may differ from these estimates.

In preparing these condensed interim financial statements, the significant judgements made by management in applying the Group's accounting policies and the key sources of estimation uncertainty were the same as those that applied to the Condensed Consolidated Financial Statements for the year ended 31 December 2018.

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 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.

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.

Trade and other payables

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

Derivative financial Instruments and hedging activities

The company 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 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.

2 Financial risk management

Financial risk factors

The Group's activities expose it to a variety of financial risks: market risk (including currency risk, fair value interest rate risk, cash flow interest rate risk and price risk), credit risk and liquidity risk. The Group's overall risk management program seeks to minimise potential adverse effects on the Group's financial performance

The condensed interim financial statements do not include all financial risk management information and disclosures required in the annual financial statements; they should be read in conjunction with the Group's annual financial statements for 2018, which can be found at www.trinityexploration.com.

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 June 2019 the Group held cash at bank of $17.8 million (2018:$10.2 million).

Credit risk

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

All sales are made to a state-owned entity - the Petroleum Company of Trinidad & Tobago ("Petrotrin") Limited and, from 1 December 2018, Heritage Petroleum Company Limited ("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 30 June 2019 and 31 December 2018.

3 Exceptional Items

Items that are material either because of their size, 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 in the Condensed Consolidated Statement of Comprehensive Income. An analysis of the amounts presented as exceptional items in these financial statements are highlighted below.

	30 June 2019	30 June 2018	31 December 2018
	$'000	$'000	$'000
Reversal of bad debt written off	--	--	(205)
Unsecured creditor compromise	19	--	(70)
Impairment of property, plant and equipment (Note 8)	(835)	--	2,561
Impairment of receivables and inventory	(104)	--	--
Fees relating to corporate restructuring	(10)	--	26
Gain on fair value of financial instrument	--	11,616	--


Exceptional (charge)/credit	(930)	11,616	2,312

· Unsecured creditor compromise - ($0.0 million): Gain under the creditor settlements arising from compromised balances with suppliers.

· Impairment on Property, Plant and Equipment - ($0.8 million): Charge resulting from impairment losses in Onshore Assets.

· Impairment of receivables and inventory - ($0.1 million): Charge for impairment of debtor balance no longer recoverable and charge resulting from impairment of inventory.

· Fees relating to corporate restructuring - ($0.0 million): Charge in relation to trustee fees incurred in H1 2019.

4 Property Tax ("PT")

	30 June 2019	30 June 2018	31 December 2018
	$'000	$'000	$'000
PT charges	(247)	(216)	(493)
Reversal of 2016 and 2017 charges	--	1,100	1,100
	(247)	884	607

On 8 June 2018 the Property Tax Amendment Act 2018 was assented to by the Government of Trinidad and Tobago. The Act effectively waived the obligation to pay PT up to December 2017. The Company continues to accrue for PT in 2019.

5 Income taxation (expense)/ credit

a. Taxation	30 June 2019	30 June 2018	31 December 2018
Current tax	$'000	$'000	$'000
- Current period
Petroleum profits tax	--	--	(5)
Unemployment levy	(84)	(62)	--

Deferred tax
- Current period
Movement in asset due to tax losses	(757)	5,750	1,794
Movement in liability due to accelerated tax depreciation	650	5	(2,991)
Unwinding deferred tax on FV uplift	37	33	(68)
Income tax expense/(credit)	(154)	5,726	(1,270)

Current tax: The Group's effective tax rate varies from the statutory rate for UK companies of 19.0% (2018: 19.0%) mainly as a result of tax losses set off against future taxable profits, allowable and disallowable expenses.

Deferred tax: The Group has a deferred tax asset of $5.2 million on its Condensed Consolidated Statement of Financial Position which it expects to recover in more than 12 months based on the expected taxable profits generated by Group companies.

	30 June 2019	30 June 2018	31 December 2018
	$'000	$'000	$'000
b. Taxation payable current
Petroleum Profits Tax("PPT")/ Unemployment Levy("UL")	41	--	--
Due to BIR (PPT,CT and UL)	--	198	--
Taxation payable	41	198	--

The $0.04 million relates to Unemployment Levy incurred for the period.

6 Net finance cost

	30 June 2019	30 June 2018	31 December 2018
	$'000	$'000	$'000
Unwinding of discount on Decommissioning	(586)	(778)	(1,557)
Interest on loans	--	(390)	(592)
Interest unwind on liabilities	--	(142)	--
Interest on taxes	(125)	--	--
Interest on leases	(80)	--	--
Interest income	78	31	93
	(713)	(1,279)	(2,056)

7 Property, Plant and Equipment

	Plant & Equipment	Land & Buildings	Oil & Gas Property	Other	Total
	$'000	$'000	$'000	$'000	$'000
Opening net book amount at 1 January 2019	962	1,705	50,932	--	53,599
Additions	389	52	1,768	--	2,209
Impairment	--	--	(835)	--	(835)
Depreciation, depletion and amortisation charge for period	(209)	(82)	(4,569)	--	(4,860)
Translation difference	--	--	(1)	--	(1)
Closing net book amount 30 June 2019	1,142	1,675	47,295	--	50,112

Period ended 30 June 2019
Cost	11,309	3,297	290,448	336	305,390
Accumulated depreciation, depletion, amortisation and impairment	(10,167)	(1,622)	(243,152)	(336)	(255,277)
Translation difference	--	--	(1)	--	(1)
Closing net book amount 30 June 2019	1,142	1,675	47,295	--	50,112
	Plant & Equipment	Land & Buildings	Oil & Gas Property	Other	Total
	$'000	$'000	$'000	$'000	$'000
Opening net book amount at 1 January 2018	3,767	1,726	46,957	--	52,450
Additions	205	2	4,434	--	4,641
Disposal	--	(6)	--	--	(6)
Reclassification of DDA	(2,470)	--	2,470	--	--
Depreciation, depletion and amortisation charge for period	(784)	(70)	(3,892)	--	(4,746)
Translation difference	--	(1)	214	--	213
Closing net book amount 30 June 2018	718	1,651	50,183	--	52,552

Period ended 30 June 2018
Cost	10,643	3,111	279,353	336	293,443
Accumulated depreciation, depletion, amortisation and impairment	(9,925)	(1,459)	(229,384)	(336)	(241,104)
Translation difference	--	(1)	214	--	213
Closing net book amount 30 June 2018	718	1,651	50,183	--	52,552
	Plant & Equipment	Land & Buildings	Oil & Gas Assets	Other	Total
	$'000	$'000	$'000	$'000	$'000
Year ended 31 December 2018
Opening net book amount at 1 January 2018	3,767	1,726	46,957	--	52,450
Additions	483	135	11,646	--	12,264
Disposal	--	(6)	--	--	(6)
Adjustment for decommissioning estimate	--	--	2,076	--	2,076
Impairment	--	--	(2,561)	--	(2,561)
Reclassification of assets between categories	(2,470)	--	2,470	--	--
Depreciation, depletion and amortisation charge for year	(818)	(150)	(9,696)	--	(10,664)
Translation difference	--	--	40	--	40
Closing net book amount 31 December 2018	962	1,705	50,932	--	53,599
At 31 December 2018
Cost	13,391	3,245	286,172	336	303,144
Accumulated depreciation, depletion, amortisation and impairment	(12,429)	(1,540)	(235,280)	(336)	(249,585)
Translation difference	--	--	40	--	40
Closing net book amount	962	1,705	50,932	--	53,599

Note: An impairment loss of $0.8 million was recognised in respect of several Oil and Gas assets as a result of carrying value being higher than the recoverable amount. The recoverable amount was determine by utilising its fair value less costs of disposal.

8 Intangible Assets

	Computer Software	Exploration and evaluation assets	Total
	$'000	$'000	$'000
At 1 January 2019	246	25,511	25,757
Additions	--	332	332
Amortisation	(7)	--	(7)
At 30 June 2019	239	25,843	26,082

At 1 January 2018	250	25,341	25,591
Additions	--	46	46
Translation difference	--	71	71
At 30 June 2018	250	25,458	25,708

At 1 January 2018	250	25,341	25,591
Computer software	26	--	26
Exploration and evaluation assets	--	170	170
Amortisation	(30)	--	(30)
At 31 December 2018	246	25,511	25,757

Exploration and evaluation assets: related to the TGAL exploration well and field development plan.

9 Trade and Other Receivables

	30 June 2019	30 June 2018	31 December 2018
Due within one year	$'000	$'000	$'000
Trade receivables - net	5,020	3,264	10,408
Prepayments	1,389	1,217	846
VAT recoverable	2,584	1,372	1,610
Other receivables	577	401	479
	9,570	6,254	13,343

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

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.

Trade receivables - Having reviewed past payment performance combined with the credit rating of Petrotrin/Heritage in order to assess the potential for impairment, the Group has concluded this to be insignificant as there has been no history of default or disputes arising on invoiced amounts in the past 5 years and as such the credit loss percentage is assumed to be almost zero.

There was a delay in collecting trade receivables for October and November 2018 amounting to $6.7 million due to the restructuring of the Group's sole customer Petrotrin/ Heritage at the end of December 2018. However, $5.3 million of these have been collected with a remaining $1.4 million outstanding as at 30 June 2019.

VAT recoverable - VAT recoverable is due from the Trinidad and Tobago Board of Inland Revenue ("T&T BIR"). In reviewing past payment performance combined with credit rating of the T&T BIR, the Group has concluded the ECL to be insignificant as there has been no history of default arising on the amount collectable and the timing of recovery is consistent with past outstanding amounts.

10 Share capital

Number of shares

Ordinary shares

$'000

Share premium

$'000

Total

$'000

As at 1 January 2019

384,049,246

97,692

139,879

237,571

As at 30 June 2019

384,049,246

97,692

139,879

237,571

11 Share Based Payment Reserve

The share-based payments reserve is used to recognise over the vesting period:

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

- The grant date fair value of shares issued to employees

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

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

During 2019 the Group granted share-based payment arrangements to certain of its employees and Executive Directors under the Long Term Incentive Plan ('LTIP'). The charge in relation to these arrangements is shown below, with further details of the new LTIP grants following:

	30 June 2019	30 June 2018	31 December 2018
	$'000	$'000	$'000
At 1 January	13,290	12,553	12,553
Share based payment expense:
Long term incentive plan	494	369	737
At 31 December	13,784	12,922	13,290

Long Term Incentive Plan

In January 2019 Options over 2,824,000 ordinary shares and in May 2019 Options over 3,832,824 ordinary shares were granted under the LTIP in accordance with the policy announced to the market on 25 August 2017. The LTIP awards are designed to provide long-term incentives for Senior Managers and Executive Directors to deliver long-term shareholder returns. Under the plan, participants were granted options which only vest if certain performance standards are met. Participation in the plan is at the Board's discretion and no individual has a contractual right to participate in the plan or to receive any guaranteed benefits.

The 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 and 31 December 2021 respectively. TSR is the increase in share price plus the value of any dividends paid over a period of time and captures the full return shareholders see on an investment. Relative TSR is the comparison of these returns against peer companies over a set period of time.

The January 2019 LTIP awards will vest on 1 January 2021, while the May 2019 awards will vest on 2 January 2022 subject to meeting the performance criteria set out in the table below and continued employment with the Company. The Options are exercisable at nil cost by the participants.

Performance targets	January 2019 LTIPs	May 2019 LTIPs

Below the Median	None of the award will vest	None of the award will vest
Median (50th percentile)	30% of the maximum award will vest	30% of the maximum award will vest
Between Median and Upper Quartile	Straight Line basis between these points	Straight Line basis between these points
Upper Quartile (75%)	100% of the maximum award will vest	100% of the maximum award will vest
Above the Upper Quartile	100% of the maximum award will vest	100% of the maximum award will vest

The total fair value at grant date of the 2019 LTIP awards was $0.9 million and this will be pro-rated and expensed over the vesting period. The fair value at grant date was determined using a Monte Carlo simulation model that takes into account the exercise price, the term of the option, the share price at grant date and expected price volatility of the underlying share, the expected dividend yield, the risk free interest rate for the term of the option and the correlations and volatilities of the peer group companies. The model inputs for the 2019 LTIP awards granted during the period ended 30 June 2019 included:

	January 2019 LTIPs	May 2019 LTIPs
Grant Dates	2 January 2019	9 May 2019
Share price at grant dates	GBp16.77	GBp14.66
Exercise price	GBP0.00	GBP0.00
Expected volatility	113.9%	113.9%
Risk-free interest rates	0.73%	0.73%
Expected dividend yields	0%	0%
Vesting dates	1 January 2021	2 January 2022

12 Deferred Income Taxation

The analysis of deferred income taxes is as follows:

	30 June 2019	30 June 2018	31 December 2018
	$'000	$'000	$'000
Deferred tax assets:
-Deferred tax assets to be recovered in more than 12 months	(5,217)	(9,948)	(5,973)
-Deferred tax assets to be recovered in less than 12 months	--	--	--
Deferred tax liabilities:
-Deferred tax liabilities to be settled in more than 12 months	4,911	2,508	5,598
Net deferred tax (assets)/liability	(306)	(7,440)	(375)

The movement on the deferred income tax is as follows:

	30 June 2019	30 June 2018	31 December 2018
	$'000	$'000	$'000
At beginning of year	(375)	(1,641)	(1,641)
Movement for the year	106	(5,799)	1,334
Unwinding of deferred tax on fair value uplift	(37)	--	(68)
Net deferred tax (asset)/liability	(306)	(7,440)	(375)

The deferred tax balances are analysed below:

	1 January 2018	Movement	30 June 2018	Movement	31 December 2018	Movement	30 June 2019
	$'000	$'000	$'000	$'000	$'000	$'000	$'000
Deferred tax assets
Acquisition	(33,436)	--	(33,436)	--	(33,436)		(33,436)
Tax losses recognised	(34,293)	(5,760)	(40,053)	3,966	(36,087)	(1,195)	(37,282)
Tax losses derecognised	63,550	(9)	63,541	9	63,550	1,951	65,501
	(4,179)	(5,769)	(9,948)	3,975	(5,973)	756	(5,217)
Deferred tax liabilities	1 January 2018	Movement	30 June 2018	Movement	31 December 2018	Movement	30 June 2019
Accelerated tax depreciation	14,043	--	14,043	3,127	17,170	(651)	16,619
Non-current asset impairment	(33,214)	--	(33,214)	--	(33,214)	--	(33,214)
Acquisitions	19,580	--	19,580	--	19,580	--	19,580
Fair value uplift	2,129	(30)	2,099	(37)	2,062	(36)	2,025
	2,538	(30)	2,508	3,090	5,598	(687)	4,911

Deferred income tax assets are recognised for tax loss carry-forwards to the extent that the realisation of the related tax benefit through future taxable profits is probable. The Group recognises deferred tax assets over a 3 year outlook which is consistent with prior periods. Deferred tax assets of $0.8 million have been de-recognised (2018: $1.8 million was recognised). Deferred tax liabilities have reduced by $0.7 million (2018: $3.0 million increase) based on the carrying values of property, plant and equipment and intangible assets which gave rise to the temporary differences. The Group has unrecognised tax losses amounting to $234.8 million which have no expiry date (2018: $233.3 million).

Deferred tax assets and liabilities can only be offset in the Statement of Financial Position if an entity has a legal right to settle current tax amounts on a net basis and Deferred Tax amounts are levied by the same tax authority (as per IAS 12).

13 Provisions and Other Liabilities

Non-Current:	Decommissioning cost	Total
	$'000	$'000
6 months ended 30 June 2019
Opening amount as at 1 January 2019	41,802	41,802
Unwinding of discount	586	586
Decommissioning provision	--	--
Translation differences	181	181
Closing balance as at 30 June 2019	42,569	42,569

6 months ended 30 June 2018
Opening amount as at 1 January 2018	37,151	37,151
Unwinding of discount	778	1,062
Decommissioning provision	739	455
Translation differences	104	104
Closing balance as at 30 June 2018	38,772	38,772

Year ended 31 December 2018
Opening amount as at 1 January 2018	37,151	37,151
Increase in provision for new wells	1,164	1,164
Unwinding of discount	1,557	1,557
Revision to estimates	867	867
Decommissioning provision	1,074	1,074
Translation differences	(11)	(11)
Closing balance at 31 December 2018	41,802	41,802
Current:	Litigation claims	Closure of pits	Total
	$'000	$'000	$'000
6 months ended 30 June 2019
Opening amount as at 1 January 2019	115	232	347
Litigation claims settled	(29)	--	(29)
Closing balance as at 30 June 2019	86	232	318

6 months ended 30 June 2018
Opening amount as at 1 January 2018	115	--	115
Provision for litigation claims	6	--	6
Litigation claims settled	(38)	--	(38)
Provision for drill pit closure	--	70	70
Closing balance as at 30 June 2018	83	70	153

Year ended 31 December 2018
Opening amount as at 1 January 2018	115	--	115
Increase in provision	--	232	232
Closing balance at 31 December 2018	115	232	347

14 Trade and Other Payables

	30 June 2019	30 June 2018	31 December 2018
	$'000	$'000	$'000

Current:
Trade payables	2,009	1,085	3,076
Accruals	3,548	3,009	3,454
VAT payable	--	170	--
Other payables	951	783	701
SPT & PT	4,203	2,436	1,916
Due to BIR Interest on taxes¹	--	1,749	--
Due to MEEI²	--	630	--
	10,711	9,862	9,147

Notes 2018:

1. Due to the BIR is interest on taxes totaling $1.7 million. These were fully repaid by year end 2018

2. Financial liabilities due to the MEEI of $2.1 million were substantially modified based on the new terms of repayment. This transaction was accounted for as an extinguishment of the original financial liability and the recognition of a new financial liability of $1.9 million based on its fair value. In 2018 $0.3 million was repaid with a nominal value of $0.6 million outstanding at 30^th June 2018 and fully repaid by year end 2018

15 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 and PT for the period, adjusted for depreciation, depletion and amortisation, share option expenses, foreign exchange loss/(gain) and the impact of derivative hedge instruments (other expenses).

The Group presents Adjusted EBITDA as it is used in assessing the underlying performance of the Group's business by excluding items not considered by management to reflect the underlying performance of the Group.

Adjusted EBITDA is calculated as follows:

	6 months to 30 June 2019	6 months to 30 June 2018	Year ended December 2018
	$'000	$'000	$'000
Operating Profit Before SPT & PT	5,745	2,611	6,720

Depreciation, depletion and amortisation	5,102	4,746	10,694
Share option expenses	494	369	737
Loss on oil derivative hedge instruments	--	1,586	1,075
Foreign exchange loss/ (gain)	165	4	(17)
Adjusted EBITDA	11,506	9,316	19,209

	$'000	$'000	$'000
Weighted average ordinary shares outstanding - basic	384,049	282,400	330,579
Weighted average ordinary shares outstanding - diluted	416,123	400,708	355,995
	$	$	$
Adjusted EBITDA per share - basic	0.030	0.033	0.058
Adjusted EBITDA per share - diluted	0.028	0.023	0.054

Adjusted EBITDA after the impact of SPT and PT is calculated as follows:

	6 months to 30 June 2019	6 months to 30 June 2018	Year ended December 2018
	$'000	$'000	$'000
Adjusted EBITDA	11,506	9,316	19,209
SPT	(4,427)	(3,650)	(7,050)
PT¹	(247)	(216)	(493)
Adjusted EBITDA after SPT and PT	6,832	5,450	11,666

	$'000	$'000	$'000
Weighted average ordinary shares outstanding - basic	384,049	282,400	330,579
Weighted average ordinary shares outstanding - diluted	416,123	400,708	355,995
	$	$	$
Adjusted EBITDA per share - basic	0.018	0.019	0.035
Adjusted EBITDA per share - diluted	0.016	0.014	0.033

^{1 PT - 30 June and Year ended December 2018 excludes the reversal of 2016 and 2017 waiver of $1.1 million}

16 Earnings per Share

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

	Weighted Average Number Of Shares '000	Total Comprehensive (Expense)/ Income For The Period $'000	Earnings Per Share $	Exceptional Items $	Adjusted Comprehensive Income/ (Expense) For The Period $'000¹	Adjusted Earnings Per Share $
Period ended 30 June 2019
Basic	384,049	(631)	(0.00)	930	299	0.00
Diluted	384,049	(631)	(0.00)	930	299	0.00

Period ended 30 June 2018
Basic	282,400	15,889	0.06	(11,616)	4,273	0.02
Diluted	400,708	15,889	0.04	(11,616)	4,273	0.01

Year ended 31 December 2018
Basic	330,579	(5,321)	(0.02)	2,312	(3,009)	(0.01)
Diluted	330,579	(5,321)	(0.02)	2,312	(3,009)	(0.01)

^{1 Adjusted Comprehensive income - Total Comprehensive (Expense)/Income before Exceptional items}

Impact of dilutive ordinary shares:

Diluted earnings per share is calculated by adjusting the weighted average number of ordinary shares outstanding to assume conversion of all dilutive potential ordinary shares. The awards issued under the Company's LTIP comprising 32,072,822 are considered potential ordinary shares. Share options of 1,975,084 are considered potential ordinary shares and have not been included as the exercise hurdle would not have been met.

There was no impact on the weighted average number of shares outstanding during period ended 30 June 2019 as all share options and LTIP's were excluded from the weighted average dilutive share calculation because their effect would be anti-dilutive and therefore both basic and diluted earnings per share are the same.

17 Contingent Liabilities

i) The farm-out agreement for the Tabaquite Block (held by Coastline International Inc.) has expired. The Coastline entity had a sub licence (farm out) with Petrotrin for the Tabaquite Block in relation to Petroleum operating activities. The last sub licence agreement dated March 2000 had various renewal options which expired on 28 February 2010. The terms of a renewed sub licence have been agreed with Heritage but the agreement has not been executed pending renewal of the exploration and production head licence between Heritage and the Government of the Republic of Trinidad and Tobago. There may be additional liabilities arising when a new agreement is finalised, but these cannot be presently quantified until a new agreement is available.

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

iii) On 3 June 2017 a performance bond was established by the Group's Lease Operatorship Assets ("LOA"). A performance bond in the form of a cash deposit of $0.3 million in the name of the beneficiary Petrotrin/ Heritage was established for due and punctual observance of the matters under the LOA effective until 31 December 2020.

18 Events after the Reporting Period

· Subsequent to the period end in the month of July 2019 the Company put in certain oil price derivatives which are intended to help mitigate the impact of SPT on its cash flows. The derivatives comprise of the following.

- Put spread with a WTI price floor of $50.0/bbl and a cap of $55.0/bbl for 12,500 bbls per month over the period from 1 July 2019 to 31 December 2019.

- 3 way option with a WTI price floor of $ 50.0/bbl and a cap of $55.0/bbl and with a call strike price of $ 64.4/bbl for 12,500 bbls per month over the period from 1 July 2019 to 30 June 2020.

· At the end of June 2019 Trinity had $1.4 million outstanding from Petrotrin in relation to crude oil receivables relating to October and November 2018. Subsequent to 30 June 2019 $0.9 million of the outstanding amount has been received by Trinity, with remaining balance of $0.5 million expected to be repaid in the coming months.

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