Annual Financial Report

RNS Number : 5135T

Serinus Energy PLC

21 March 2019

Serinus Energy plc

2018 Annual Report and Accounts

(US dollars)

2018 Highlights

Operational

· During 2018, Serinus completed the construction of the Moftinu gas plant facility in Romania with the exception of the contractor led delayed installation of the Low Temperature Separation ("LTS") unit and the Triethylene Glycol ("TEG") unit (the "Units") Given the delay in the fabrication and delivery of the Units, the Group has filed a suit for more than US$25.4 million in damages against Aval Engineering Inc. of Alberta and Kocken Energy Systems Incorporated of Nova Scotia and certain of their directors and officers

· In the period the Group drilled, completed and tested the Moftinu-1007 and Moftinu-1003 wells in Romania at stable rates of 5.66Mcf/d and 6.3Mcf/d respectively, which have been tied into the Moftinu gas facility and are ready to commence production pending access to the Transgaz pipeline system

· The Group signed a gas sales agreement with Vitol Gas and Power B.V. for Moftinu gas production that is not required to be sold on the centralised market in Romania allowing flexibility with nominating volumes each month

· Production from the Tunisian operations was 352 boe/d for 2018 (2017- 376 boe/d)

· All production in 2018 was from the Sabria field in Tunisia

· In 2019, the Group plans to reopen its Chouech Es Saida field in southern Tunisia, following it being shut in due to social issues since February 2017.

Financial

· Subsequent to year end, the Company has undertaken a placing to raise gross proceeds of $3.0 million by issuing 21,553,583 shares at a price of £0.105 per share, with the shares expected to list on or around 26 March 2019. Attached to each share issued is 0.105 warrants, with each full warrant entitling the holder to purchase one common share at an exercise price of £0.105 per share, exercisable for a period of 24 months after closing. The warrants must be approved by a special resolution of the Company's shareholders at a meeting to be convened shortly before they can be exercised.

· $8.7 million received in revenue (gross of royalties) in the period

· Realised oil price averaged $66.96 per bbl for 2018 (2017- $51.48 per bbl), an increase of 30%

· Capital expenditures of $10.8 million were incurred for the year focused on the final phase of the construction of the Moftinu gas facility and the drilling of the Moftinu-1007 and Moftinu-1003 wells

· Funds from (used in) operations was an inflow of $1.2 million in 2018 (2017- outflow of $6.6 million), with the increase due to a $3.6 million insurance recovery in 2018, relating to the well incident in December 2017, and higher revenues net of production expenses in Tunisia, partially offset by $1.4 million of transaction costs incurred in relation to the Company's continuance to Jersey and AIM listing

· On 18 May 2018, the Company listed on the Alternative Investment Market ("AIM") market of the London Stock Exchange and closed a placing of 66,666,667 new ordinary shares at 15 pence per share for total proceeds of £10 million ($13.5 million)

· Moftinu-1001 well incident costs of $4.0 million associated with the emergency operations in December 2017 on the Moftinu-1001 well were fully recognized in 2017

· Drilling of the Moftinu-1007 well was to replace the Moftinu-1001 well and the re-drill costs were covered by insurance with a claim of $3.0 million made of which $2.9 million was recognized against the costs of the asset in 2018, and for which proceeds of $3.0 million have been received subsequent to year end

2019 OUTLOOK

Corporate

Corporately 2018 was a busy year for Serinus with the re-domiciliation of the Company from Alberta to Jersey, the listing of the Company on the Alternative Investment Market of the London Stock Exchange and the raising of additional capital for the Moftinu Gas Development Project. The Group believes that it has now established a more efficient corporate structure and optimum exposure to a more sophisticated capital market for international E&P companies.

In 2019, a key area of focus for management will be establishing its position in the London market and expanding the exposure of our activities to the broader London market. The Group will also continue to focus on improving its capital structure during 2019 and will look to reduce its debt holding with the repayment of the EBRD senior debt in two tranches scheduled for March and September.

Romania

The outlook for Romania remains strong. The Moftinu Gas Development project offers a significant opportunity for the Group to materially increase both its production and its associated cashflow. 2019 is also the year where the Group focuses its eyes on future growth by performing a 3D seismic survey over portions of the Satu Mare Concession. The opportunities are significant, and this seismic program is the next step in unlocking additional opportunities equal or greater to the Moftinu project.

The Group also looks to 2019 as a year when we can further demonstrate our credentials with the drill bit by drilling the Moftinu-1004 well. This well is an appraisal well designed to provide additional gas to the Moftinu gas plant. Scheduled in the latter half of 2019, we look to this well to allow the Moftinu Gas Plant to operate at full capacity and to extend the plateau of production further.

The government of Romania introduced emergency legislation in December 2018 to cap the price at which gas producers sell their gas for purposes of household consumption. This legislation caps the price at 68 RON/Mwh (approximately $5/mcf) and is effective from 1 April 2019. The European Union Commission has formally started infringement proceedings against Romania as this law violates EU directives regarding the supply of natural gas. Due to this legislation violating EU directives, the opposition to this legislation internally in the government of Romania and industry pressure, the Group considers it highly unlikely that this legislation will come into effect.

Tunisia

Operations in Tunisia are due to ramp up after an extended period of stagnation due to the difficult social conditions in the country. Serinus is eager to reinitiate production in its southern fields with these assets being very accretive to our production levels and our cashflow. The Group has been very clear that, whilst we view these fields as very attractive, we will only allocate capital to these fields if we believe the surface risks encountered during the past two years have been sufficiently mitigated or minimized.

The Group also looks to apply additional capital to our Sabria field in the form of a re-entry into a well that was mechanically damaged during completion many years ago. The Group views activities like this as an excellent means of capital allocation with low exploration risk and technical risk that has been mitigated over the years by improving technology. The Sabria field has also been producing, since its discovery, on simple primary production. Serinus looks to 2019 as the year that we apply artificial lift to this field. We very much expect that the application of artificial lift will allow us to increase our production while also providing valuable insights into the performance of the reservoir.

SERINUS AT A GLANCE

Serinus Energy plc. is an oil and gas exploration, appraisal and development company. The Group operates all of its assets and has operations in two business units: Tunisia and Romania.

The Tunisian business unit comprises five concessions and predominantly produces oil. Associated gas and gas prospects are also part of the Tunisian portfolio. The corner stone of the Tunisian business unit is the Sabria field. Sabria is a large oilfield that has been under-developed. Serinus considers this to be an excellent asset for remedial work to increase production and in time, with proper reservoir studies, an excellent asset upon which to conduct further operations.

The Romanian Business unit is comprised of one very large (approximately 3,000km²) concession and is a highly sought after hydrocarbon province. The Moftinu Gas Development Project is what the Group hopes to be the first of many shallow gas developments. The concession is extensively covered by legacy 2D seismic and the Group considers the concession to have multiple and significant prospects available for further exploration.

WHY INVEST?

Serinus offers access to near term production increases and significant organic growth within its existing asset base.

There is a large opportunity set in both of our business units with Tunisia offering significant field development opportunities on existing and under-developed oil fields. Romania is a large contiguous asset base with significant shallow gas development opportunities in a country that is demonstrating a rapidly expanding demand for natural gas. The southern portion of our Romanian asset offers excellent exploration opportunities for large oil prospects. Just across the southern boundary of the Satu Mare concession is the Suplacu de Barcau oil field (held by OMV Petrom). This is a significant oilfield estimated to have produced in excess of 100 million barrels.

In addition to the strong asset base Serinus has a strong and experienced management team. Our local assets are managed by local teams who have worked in their regimes for an extensive time. We have significant technical and commercial experience and are able to apply that experience across our business units. Our corporate G&G team is able to rank prospects across our business units such that only the best exploration and exploitation opportunities are allocated capital.

In summary, Serinus offers a combination of near-term production growth, significant exploration opportunity and low-risk oil and shallow gas development opportunities with significant profitability at today's commodity prices.

SERINUS' STRATEGY

Vision:

The Group's goal is to transform the potential of its extensive land base in Romania and Tunisia into enhanced shareholder value through the efficient allocation of capital.

Strategy:

Serinus is focused on significant growth potential within its existing concession and license holdings in Romania and Tunisia through the development of low cost, high return projects, as follows:

1. Leverage Land Position:

· Positions in 6 exploration and production concessions in Romania and Tunisia with almost all work commitments having been met

· Extensive oil and natural gas exploration and development potential within multiple play horizons

· A significant future opportunity set that provides growth beyond existing production and development projects

2. Commitment to Shareholders

· Cohesive management team with a commitment to enhancing shareholder value

· Extensive experience and a proven track record of prudent oversight in the allocation of shareholder capital.

· Reduced corporate overhead from approximately US$15 million gross per annum in 2014 to US$5 million gross per annum 2018 with a resolute commitment to corporate efficiency

3. Manage Risks:

· Managing surface and subsurface risks through constant evaluation and the application of new technologies

· Projects that demonstrate attractive returns at relatively lower risk profiles will be strategically allocated capital

· Operate all concessions to maintain cost control

· Flexibility to bring in partners in the future once potential is de-risked

4. Focus on Growth

· Leveraging cash flow to grow through expanded exploration and development on the significant opportunities available within the existing asset base

· Seeking acquisitions that will provide synergies at a cost that is accretive to shareholders.

CHAIRMAN'S REPORT

Dear Shareholders,

2018 was a challenging year for our Group, but also one marked with a significant progress on a number of fronts.

On behalf of the Board of Directors, I would like to express my highest gratitude to all Group employees and partners for their hard work, continuous support and close cooperation. I would like to thank in particular the members of the Executive Board who, despite many challenges, continue to pursue our strategic goals in an exceptionally dedicated and professional manner.

It is through combined efforts of our employees, associates and advisors in Romania and Tunisia that we continue to move closer every day towards our goal of creating a sustainable oil & gas exploration and production company with strong growth prospects and a bright future. Their hard work, strong values and personal sacrifice are the key pillars of the future success of our Group, and our standing as an ethical member of the society and communities in which we operate.

We believe that the departure from Toronto Stock Exchange and successful introduction of Serinus on the Alternative Investment Market of London Stock Exchange will mark the turning point and enable the next promising chapter in the history of Serinus to be written by expanding the investor base and completion of all our intended investments programmes.

We look forward to the 2019 as a pivotal year for Serinus.

Yours sincerely,

Lukasz Redziniak

REPORT FROM CEO

Dear Fellow shareholders,

The year in 2018 continued the transformational path for Serinus and whilst the Group was beset by many challenges, we faced them in a professional manner and pressed forward with value creation in both of our business units.

It would be hard for the Group or its shareholders to forget that the year started with the Moftinu-1001 well incident that was placed under control on 7 January 2018. The loss of control of this well delayed the further construction of the Moftinu gas plant and the cost of controlling this well altered the Group's capital allocation plans for the whole of 2018. Thankfully there were no injuries and the Group was able to regain control of the well in a relatively short time. The Group worked closely with its Romanian partners in the local and national government, the brave firefighters of Romania who were invaluable in the well control operations, the contractors who provided valuable experience, manpower and equipment, and our own local staff who coordinated the successful response to control and remedy the situation.

Having regained control of the Moftinu-1001 well, the management of Serinus concluded that it would be far too risky to attempt to remediate this well for future production and as such made the difficult decision to abandon the well. Every cloud has a silver lining and the silver lining in this instance was that the Group immediately turned to the planning and drilling of the replacement Moftinu-1007 well. Our team in Romania did an exemplary job of planning, permitting and executing the drilling of Moftinu-1007 and on 26 June 2018, less than six months from the plugging and abandonment of Moftinu-1001, the Group announced the successful completion of Moftinu-1007. This well was drilled faster than we have previously been able to drill wells and was drilled approximately 20% under budget. The well flowed at excellent rates and is a testament to the effectiveness of our Romanian and Calgary teams.

Less than five weeks after completing the Moftinu-1007 well, the team announced the spudding of the Moftinu-1003 well. The Moftinu-1003 well was an exploration well that was targeting additional previously untested zones in the Moftinu structure. As with the Moftinu-1007 well, this well was drilled ahead of schedule and underbudget. It is particularly impressive to note that both the Moftinu-1007 well and the Moftinu-1003 well were more cost effective than previous wells drilled by the Group in 2014 and 2015, even though the Group utilized a far more sophisticated completion assembly.

At the end of June our EPC contractor mechanically completed the Moftinu gas plant and the Group was able to run gas at operating pressure through the plant. Unfortunately, the Group has been in delay since then due to the failure of the engineering sub-contractor and the fabrication sub-contractor to the EPC Contractor, with both being in breach of their contractual obligations. I can only imagine how frustrating this has been to shareholders but the Group has done its utmost to work with our EPC contractor and to step in to assume the obligations of these two defaulting parties. It is unusual to have one party fail in its contractual obligations, but to have two parties fail has been exceptional and extremely frustrating. The Group has taken all appropriate measures and is moving towards production in late Q1 2019.

In Tunisia, our local team worked diligently to resolve the social issues that whilst national in origin have had an impact on our ability to produce oil from our southern fields. Through the hard work and the knowledge of our local team, we believe we have managed to come to a place whereby we will be able to reinitiate production in our southern fields. Whilst no significant capital investments were undertaken in 2018, it was an industrious year of planning for our Tunisian business units, where plans to enhance production from our Sabria field are much advanced. The team in Tunisia is a young and energetic team that embodies all that is great in Tunisia. We are lucky to have a team that cares so much about the success of our business, its role as a model corporate citizen in Tunisia, and in striving to make Tunisia a successful place to invest. Whilst the economic and social conditions in Tunisia are difficult, it is with great pride that the energy and professionalism of our team in Tunisia offer us the best opportunity for growth and value creation.

In addition to the dramatic pace of progress in our operating areas, the Company also voluntarily de-listed from the Toronto Stock Exchange and re-listed on the Alternative Investment Market of the London Stock Exchange. This was done concurrently with the relocation of the Company from Alberta to Jersey. This move was performed to allow the Company to more appropriately access investors who recognize the value that can be created in the areas in which we operate.

Overall, 2018 was a year of tremendous development for the Group. Notwithstanding the delays created by the failure of the sub-contractors, the Group views 2018 as a transformative year where a gas plant was constructed, additional wells were drilled, resulting in the discovery of new zones in the Moftinu gas field, and those wells were tied into the gas plant in anticipation of production as soon as the plant can be completed. It was a fast-paced year full of incredible achievements by the Serinus team. The Group has had little time to reflect on all the successes but has continued to rise to the various challenges and move the business ahead. I know I speak for all the employees of Serinus when I say that we eagerly greet 2019 and the developments that will be achieved. We expect 2019 to be the year that the Group is on a firm path to growth and enhanced shareholder value.

REPORT FROM CFO

During 2018 the Group faced many changes and significant challenges, which have translated into the financial performance for the year and position of the Group as at 31 December 2018.

Liquidity, Debt and Capital Resources

The Group successfully completed the continuance of Serinus to Jersey, Channel Islands and the listing of the Company's shares on the AIM market of the London Stock Exchange in May 2018. Concurrent with the listing, we raised equity to further our development of the Moftinu field in Romania by issuing 66,666,667 common shares at £0.15 per common share for equity proceeds, before costs, of £10 million ($13.5 million). Proceeds, net of costs, were $12.7 million. Transaction costs of $1.4 million were incurred in relation to the listing.

In Romania, the Group invested $10.8 million to continue its development of the Moftinu field including the drilling of the Moftinu-1007 and Moftinu-1003 wells as well as the substantial completion of the gas plant. The capital expense of $10.8 million is net of $2.9 million of insurance proceeds attributable to the Moftinu-1007 well.

In Tunisia, production from the Sabria field remained consistent during the year and with improvements in crude oil prices in 2018, the Group generated cash flows from operations in Tunisia for deployment elsewhere in the business. Cash flow generation in Tunisia remains challenging given the current production level, though with stability of production and cost cutting measures, Tunisia was a positive cash flow generating business unit for the year. Given the focus on Romania and situation in Tunisia, there were no capital expenditures in Tunisia in 2018. Plans for 2019 include restarting the Chouech Es Saida field in southern Tunisia and undertaking a capital program in Sabria, which will enhance production and cash flow generation in Tunisia.

During 2018, funds from operations improved year over year at $1.2 million in 2018 as compared to an outflow of $6.6 million in 2017. Taking into consideration the movement in working capital, the cash flows used in operating activities in 2018 were $5.9 million (2017 - $4.2 million)

Delays with achieving first production in Romania has resulted in a tightening cash position and violation of financial covenants with the debt held with the European Bank of Reconstruction and Development ("EBRD"), as well as contributing to the delay of capital programs in Tunisia, the implications of which are further discussed below.

	Year ended 31 December
($000)	2018	2017
Current assets	13,480	15,040
Current liabilities	(28,918)	(27,540)
Working Capital deficit	(15,438)	(12,500)

The working capital deficit of the Group at 31 December 2018 was $15.4 million. Included in current liabilities at December 31, 2018 was $5.6 million of EBRD debt, accounts payable of $14.6 million and a decommissioning provision of $8.7 million. Included in accounts payable was $8.2 million relating to Brunei. Of this amount, $2.2 million relates to a dispute with a drilling company dating back to 2013 on Block L and the remaining $6.0 million relates to work commitments on the Brunei Block M production sharing agreement which expired August 2012. Current liabilities also include $2.8 million relating to decommissioning provisions in Brunei and Canada, and $5.9 million relating to Tunisia. The obligations in Canada are offset by cash held on deposit as restricted cash of $1.1 million in current assets.

Given the tight operating conditions, the Group continues to actively manage its costs.

The Group renegotiated its EBRD debt in late 2017, which provided a holiday from making principal repayments on the Senior Loan until 2019 and a holiday from covenants until September 2018, to allow a period of time to develop Romania and achieve first production. The Senior Loan is to be repaid in two instalments of $2.7 million plus interest each on 31 March and 30 September 2019.

On 21 December 2018, the Group received a waiver from the EBRD formally waiving compliance with the financial covenants for the period ended 31 December 2018.

Given the impact of delays on operating cash flows from Romania and Tunisia, the Group has a short term financing need in order to meet the debt repayment due 31 March 2019. Therefore, the Group has undertaken a placing to raise gross proceeds of $3.0 million, by issuing 21,553,583 shares at a price of £0.105 per share. Attached to each share issued is 0.105 warrants, with each full warrant entitling the holder to purchase one common share at an exercise price of £0.105 per share, exercisable for a period of 24 months after closing, the warrants must be approved by special resolution of the shareholders. In addition, given the above noted delays, our internally prepared forecast also indicates non-compliance with financial covenants in future quarters. Our future ability to meet obligations as they come due is met in our base cash forecasts which are dependent on the performance of the gas facility and wells in Romania, the ability to enhance production in Tunisia, by re-opening the Chouech Es Saida field and/or undertaking planned capital work in the Sabria field in a timely manner, and on commodity prices. We continue to closely monitor the Group's covenant compliance in respect of its debt facilities.

Despite the challenges the Group has faced, the Group is now positioned in 2019 to reap the benefits of the last two years investment in Romania, which will be transformational for the Group in increasing its production and resulting cash flows, once production commences in Romania.

A review of the financial results of the Group for the year ended 31 December 2018 follow.

Financial Review - Year ended 31 December 2018

Funds from Operations

The Group uses funds from operations as a key performance indicator to measure the ability of the Group to generate cash from operations to fund future exploration and development activities.

The following table is a reconciliation of funds from operations to cash flow from operating activities:

	Year ended 31 December
($000)	2018	2017
Cash flow used in operations	(5,913)	(4,336)
Changes in non-cash working capital	7,069	(2,278)
Funds from (used in) operations	1,156	(6,614)
Funds from (used in) operations per share	0.01	(0.05)

The additional funds from operations in 2018 were primarily attributable to $3.6 million of insurance proceeds recognized in relation to the one-time well incident in December 2017 and higher revenues net of production expenses from Tunisia, partially offset by higher transaction costs related to the continuance to Jersey and AIM listing. Funds from operations generated in Tunisia were $2.1 million, Romania $4.3 million and funds used Corporately were $5.2 million.

Production

	Year ended 31 December
	2018	2017
Crude oil (bbl/d)	254	279
Natural gas (Mcf/d)	586	581
Total (boe/d)	352	376
% oil weighting	72%	74%
% gas weighting	28%	26%

Production is exclusively from the Tunisian assets. During 2018, production was only from the Sabria field whereas production was from both the Sabria and Chouech Es Saida fields during 2017. The Chouech Es Saida field has been shut-in since 28 February 2017, due to social unrest. Production resumed in Sabria in early September 2017 after being shut-in 22 May 2017. All wells returned to pre-shut in production levels except for the Win-12bis well which initially decreased by 60% from pre-shut in levels. The Win-12bis well has a history of producing at high water cuts after being shut-in and had continued to improve steadily through 2017 but has stabilized in 2018 at a rate of approximately 145 boe/d, net. The Group performed a slickline operation in 2018 to investigate the Win-12bis well and may perform a well intervention to improve performance in the future.

Production volumes of 352 boe/d were slightly down from 376 boe/d in 2017 due to the shut-in of the Chouech Es Saida field since 28 February 2017 and lower volumes from the Sabria field since resuming production in September 2017.

Oil and Gas Revenue

	Year ended 31 December
($000)	2018	2017
Oil revenue	6,216	5,242
Gas revenue	2,500	1,327
Total revenue	8,716	6,569
Oil revenue (%)	71%	80%
Gas revenue (%)	29%	20%

Oil ($/bbl)	66.96	51.48
Gas ($/Mcf)	11.69	6.25
Average realized price ($/boe)	67.85	47.88

Revenue is currently generated exclusively from Tunisia. The Group is required to sell 20% of its annual crude oil production from the Sabria concession into the local market, which is sold at an approximate 10% discount to the price obtained on its other crude sales. The remaining crude oil production is sold to the international market, through which the Group has a marketing agreement with Shell International Trading and Shipping Company Limited ("Shell agreement").

Oil and gas revenues totaled $8.7 million in 2018, as compared to $6.6 million in 2017. The increase is attributable to a 42% increase in the average realized price.

Crude oil realized prices increased to $66.96 per bbl in 2018, which reflects the increase in Brent price from $54.25 per bbl in 2017 to $71.06 per bbl in 2018. The Group realized 94% of the Brent price during 2018, as compared to 95% in 2017. There was one lifting with Shell during 2018 in September.

The average realized price for natural gas increased to $11.69 per mcf due to an increase in the reference price used to determine the sales price but also a change in the reference price basis. Natural gas prices are nationally regulated and were tied to the nine-month trailing average of low sulphur heating oil (benchmarked to Brent) prior to 2018. This changed in 2018 to reference the current month average of high sulphur heating oil (benchmarked to Brent), which nets approximately 10% higher pricing. Due to the change in the reference price basis used to determine gas prices, an adjustment was received in 2018 relating back to Q4, 2017 volumes, therefore natural gas revenues include a $0.4 million adjustment relating to this reference price change. Excluding this one-time adjustment, the realized gas price would have been $9.80 per mcf in 2018.

Royalties

	Year ended 31 December
($000)	2018	2017
Royalties	867	680
Royalties ($/boe)	6.75	4.96
Royalties (% of revenue)	9.9%	10.4%

Tunisian royalties are based on individual concession agreements. In Sabria, the royalty rate varies depending on a calculation of cumulative revenues, net of taxes, as compared to cumulative investment in the concession, known as the "R factor". As the R factor increases, so does the royalty percentage to a maximum rate of 15%. During 2018, the royalty rate in the Sabria concession was 10% for oil and 8% for gas. In the Chouech Es Saida concession, royalty rates are flat at 15%.

Royalties increased due to the increase in revenue. The effective royalty rate decreased from 10.4% in 2017 to 9.9% in 2018, primarily due to a proportionally more gas production at Sabria in 2018 relative to 2017.

Production Expenses

	Year ended 31 December
($000)	2018	2017
Production expense - Tunisia	2,990	5,207
Production expense - Canada	54	43
Production expense - Total	3,044	5,250
Tunisia production expense ($/boe)	23.27	37.96

Tunisian production expenses for 2018 decreased by 42% to $3.0 million as compared to $5.2 million in 2017. The decrease in 2018 was due to the shut-down of the Chouech Es Saida field in the third quarter of 2017, including the termination of all operating personnel in the field, resulting in lower operating costs and a decrease in Tunisian office costs, partially offset by an increase in Sabria production.

Canadian production expenses relate to the Sturgeon Lake assets, which are not producing and are incurring minimal operating costs to maintain the property.

Operating Netback

Serinus uses operating netback as a key performance indicator to assist management in understanding Serinus' profitability relative to current market conditions and as an analytical tool to benchmark changes in operational performance against prior periods. Operating netback consists of petroleum and natural gas revenues less direct costs consisting of royalties and production expenses. Netback is not a standard measure under IFRS and therefore may not be comparable to similar measures reported by other entities.

	Year ended 31 December 2018			Year ended 31 December 2017
($000)	Oil (bbl)	Gas (Mcf)	Total (boe)	Oil (bbl)	Gas (Mcf)	Total (boe)
Production volume	254	586	352	279	581	376
Realized price	66.96	11.69	67.85	51.48	6.25	47.88
Royalties	(7.13)	(0.96)	(6.75)	(5.67)	(0.49)	(4.96)
Production expense	(22.97)	(4.01)	(23.27)	(40.92)	(4.91)	(37.96)
Operating netback	36.86	6.72	37.83	4.89	0.85	4.96

The increase in operating netback to $37.83 per boe in 2018 was due to increased realized prices combined with lower production expense per boe.

General and Administrative Expense

	Year ended 31 December
($000)	2018	2017
G&A expense	3,422	3,005
G&A expense ($/boe)	26.64	21.91

General and administrative ("G&A") costs incurred by the Group are expensed, with certain costs directly related to exploration and development assets being capitalized or reported as production costs. The G&A expense reported is on a net basis, representing gross G&A costs incurred less recoveries of those costs presented as capital or production costs.

G&A costs for 2018 increased due to a decrease in G&A recoveries, partially offset by lower employee related costs.

Well Incident Recovery

On 18 December 2017, the Group suffered a well incident whereby during routine operations, to prepare the Moftinu-1001 well for future production, an unexpected gas release occurred and subsequently ignited. The costs associated with the emergency operations were recorded in 2017. During 2018, the Group submitted insurance coverage claims relating to the emergency costs and has received payment for the full amount, less an insurance deductible, of $3.6 million. These proceeds are reported as a recovery in the statement of operations.

The Group also completed the drilling of the replacement well, Moftinu-1007. The re-drill was claimed under insurance and subsequent to year end proceeds of $3.0 million have been received relating to the re-drill, of which $2.9 million was recorded as a receivable at year end with an offset to capital expenditures.

Share-Based Compensation

	Year ended 31 December
($000)	2018	2017
Stock-based compensation	820	691
Stock-based compensation ($/boe)	6.38	5.04

The increase in share-based compensation expense recognized in 2018 as compared to 2017 is primarily due to stock options issued in December 2018.

Depletion, Depreciation and Impairment

	Year ended 31 December
($000)	2018	2017
Depletion and depreciation - Tunisia	1,586	1,722
Depletion and depreciation - Romania	14	-
Depletion and depreciation - Canada	201	144
Impairment - Tunisia	-	4,981
	1,801	6,847
Tunisia depletion and depreciation ($/boe)	12.35	12.55

Depletion and depreciation expense is computed on a concession by concession basis considering the net book value of the concession, future development costs associated with the reserves as well as the proved and probable reserves of the concession.

Tunisia depletion and depreciation expense for 2018 decreased to $1.6 million, due to lower production in 2018, as compared to 2017, and a slightly lower depletion rate per boe. On a per boe basis, the depletion rate was $12.35 per boe for 2018, compared to $12.55 per boe in 2017.

Interest and Accretion Expense

	Year ended 31 December
($000)	2018	2017
Interest expense	3,493	2,919

Interest expense for 2018 increased to $3.5 million in 2018, due to higher debt balances (due to interest accrued on the convertible loan) and higher interest rates on the loans in 2018, due to an increase in LIBOR. The average debt balance included in the interest expense calculation for 2018 was $31.7 million compared to $29.8 million in 2017, therefore interest expense was slightly higher in 2018.

REVIEW OF OPERATIONS

Romania

• Satu Mare Block - 729,000 gross acres (2,949 km²) onshore Romania

• Located within the Pannonian Basin (Hajdusag sub-Basin) on trend with discovered and producing oil and gas fields and close to infrastructure

• Multiple play types that have produced or are producing along the same trend, including: shallow amplitude-supported gas reservoirs; conventional siliciclastic oil reservoirs; and fractured-basement oil and gas reservoirs

• Serinus operates with 100% deemed working interest which is owned and operated through the wholly owned subsidiary Serinus Energy Romania SA. The phase 1 & 2 exploration obligations completed in April 2015 and the phase 3 Exploration Period is currently ongoing.

Satu Mare Concession - History

• Winstar Resources farmed-in on Satu Mare in 2008 and earned 60% WI by funding 100% of work commitments for Exploration Phases 1 and 2.

• Serinus Energy acquired Winstar Resources in mid-2013.

• Serinus has completed all the phase 1 and 2 work commitments, as follows:

• Acquired two 3D seismic surveys covering a total of 260 km² (80 km² Moftinu & 180 km² Santau Surveys).

• Drilled 4 wells resulting in Moftinu gas discovery (Madaras-109, Moftinu 1000, 1001 & 1002bis wells).

• Serinus has spent approximately $52 million on the concession to date.

• Completion of Phase 2 entitled Serinus to enter a Phase 3 Exploration.

• The Phase 3 Work program includes the following commitments:

ü To drill two wells: 1 well to 1,000 metre depth and 1 well to 1,600 metre depth. Serinus has drilled Moftinu-1007 (a re-drill of Moftinu-1001) and Moftinu-1003 (1600m).

ü To acquire 120km² of 3D Seismic, to be completed in September 2019 in the Capleni- Domanesti area, north of the Moftinu discovery.

• Phase 3 has a three-year term and expires on 29 October 2019.

Serinus is in the final stage of building the Moftinu Gas Plant in Moftinu Mare Village, Satu Mare County, with first gas expected in late Q1 2019. The Moftinu Gas Project is the development of the Moftinu gas field (discovered by Serinus in 2014). This is a shallow (800-1,000metres), multi-zone gas field with relatively low drilling and completion costs, with robust initial well production rates.

The Moftinu gas plant was designed at a capacity of 15mmscf/d and can accommodate 6 flowlines from the Moftinu wells located near-by. For 2019, the initial production will comprise of the three Moftinu wells (Moftinu-1003, Moftinu-1007 and Moftinu-1000) that have been drilled and completed to date.

Serinus has also built a 3km sales lines that ties-in the major Transgaz pipe line Abramut -- Satu Mare. The infrastructure created by Serinus in the Satu Mare area represents a very important addition and investment which established the Group as one of the most significant investors in the area.

Tunisia

The Group currently holds five Tunisia concessions that comprise a diverse portfolio of development and exploration assets.

The Group produces oil and gas in Tunisia through its various working interests in one of the five Oil & Gas Concessions. This production can be sustained with low-risk development drilling, with significant growth opportunities over the medium to long term with high-impact near-field exploration within the Group's additional concession areas.

License	Serinus Working Interest	Approximate Gross Area (acres)	Outstanding Work Commitments	Expiry
Sabria	45% (ETAP 55%)	26,196	nil	Nov 2028
Chouech Es Saida	100%	42,526	nil	Dec 2027
Ech Chouech	100%	35,139	nil	Jun 2022
Sanrhar	100%	36,879	nil	Dec 2021
Zinnia	100%	17,471	nil	Dec 2020

Sabria:

· The Sabria concession (26,195 gross acres, Serinus 45% WI) comprises a large Ordovician light oil field that provides Serinus with a stable production base from its large reserve base and long reserves life index.

· The Ordovician reservoir at Sabria contains 358 MMbbl OIIP (P50), into which only eight wells (12 including re-entries) have been drilled. The reservoir comprises a large stratigraphic trap with a continuous oil column that spans the Upper Hamra, Lower Hamra and the El Atchane formations.

· For 2019, the Group plans to re-enter and workover the Sabria North-2 well (an historical well that was not completed properly) and to insert artificial lift into one of the current producing wells (West Sabria-1). These low-cost operations are expected to increase Sabria production from the current level of 320 Boe/d. Beyond 2019, the Group plans to continue to implement artificial lift into existing wells and could consider drilling new wells under the right economic conditions.

Chouech Es Saida:

· The Triassic reservoirs of the Chouech Es Saida concession (52,480 acres, Serinus 100% WI) have produced over 9.8 MM BOE to date from the TAGI Formation.

· The deeper Silurian Acacus Sands and the Tannezuft fan, which have been penetrated and successfully tested and produced hydrocarbons in two wells in the concession, hold enormous growth potential for Serinus. The Silurian Acacus sands, which are hydrocarbon-charged in the Chouech Es Saida block, are emerging in Southern Tunisia as a major new oil, condensate and gas play with exploration-well success rates of nearly 100%.

· For 2019, the Group plans to restart the Chouech Es Saida field in southern Tunisia. This field produced oil and gas until February 2017, at which time it was shut-in due to ongoing social protests in the region. The situation has since calmed significantly, providing the Group with the confidence that it can return to producing approximately 600 BOE/d with low probability of future disruption. The restart of this field will greatly enhance the profitability of the Group's Tunisian operations and provide the capital to pursue further growth opportunities. One opportunity is the completion of the 370 km, 24-inch diameter Nawarwa gas pipeline from southern Tunisia, near to the Chouech Es Saida concession, to Gabes on the Tunisia coast. This could provide the Group the impetus to explore further the gas potential of the Silurian Acacus and Tannezuft sands. Recently, in Southern Tunisia, Silurian sands have been targeted by exploration wells with very high success rates for oil, gas and condensate.

Ech Chouech

· The Ech Chouech concession (33,920 acres, Serinus 100% WI) has, since the discovery of the field in 1970, produced oil intermittently from the TAGI Formation. Adjacent to the Chouech Es Saida block, the concession similarly carries significant upside potential in Silurian exploration targets that are not yet drilled but are defined on 3D seismic (acquired in 2008). The Group has no work plans in 2019 on the Ech Chouech Concession. This asset was previously fully impaired in the accounts.

Zinnia

· The Zinnia concession (17,920 acres, Serinus 100% WI) is a currently non-producing production block with two formerly producing oil and gas wells. Discovered in 1991 by Shell, the field produced until 2008. Prospectivity lies within an undrilled fault block that requires 3D seismic to be confidently defined. The Group has no work plans in 2019 on the Zinnia concession. This asset was previously fully impaired in the accounts.

Sanghar

· The Sanghar field in located 60 kilometers northeast of the Elborma oil field in the Sahara Desert of Southern Tunisia. Three wells have been drilled on the Sanghar domal structure of the Triassic TAGI Sandstone formation. SNN-1 the sole oil historical producer in the field, began production in 1991 and was suspended in February 2016 because of economic conditions.

· In the summer of 2014, Geofizika Torun on behalf of Serinus acquired 256 square kilometers of modern full fold vibroseis 3D over the Sanghar structure. The principal objective was to image the TAGS structure and to better evaluate the hydrocarbon potential with the Silurian, Ordovician and Cambrian reservoirs for future well locations. The Group has no work plans in 2019 on the Sanghar concession. This asset was previously fully impaired in the accounts.

RESERVES

Company Gross Reserves - Using Forecast Prices

		2018			2017
		Oil/Liquids	Gas	BOE	Oil/Liquids	Gas	BOE	YoY Change
		(Mbbl	(MMcf)	(Mboe)	(Mbbl)	(MMcf)	(Mboe)	(%)
TUNISIA (Company Working Interest)
Proved
	Producing	292	687	406	438	1,028	609	-33%
	Non-Producing	570	1,358	796	692	1,544	949	-16%
	Undeveloped	750	1,765	1,044	802	1,888	1,117	-7%
Total Proved (1P)		1,611	3,810	2,246	1,932	4,460	2,675	-16%
Probable		4,421	10,542	6,179	5,044	11,670	6,989	-12%
Total Proved & Probable (2P)		6,033	14,352	8,425	6,976	16,130	9,664	-13%
ROMANIA (Company Deemed Interest)
Proved
	Producing	-	-	-	-	-	-	N/A
	Non-Producing	-	-	-	-	-	-	N/A
	Undeveloped	18	8,961	1,512	12	6,111	1,031	47%
Total Proved (1P)		18	8,961	1,512	12	6,111	1,031	47%
Probable		19	5,260	896	27	8,686	1,475	-39%
Total Proved & Probable (2P)		37	14,221	2,408	39	14,797	2,506	-4%
TOTAL COMPANY
Proved
	Producing	292	687	406	438	1,028	609	-33%
	Non-Producing	570	1,358	796	692	1,544	949	-16%
	Undeveloped	768	10,726	2,556	814	7,999	2,148	19%
Total Proved (1P)		1,629	12,771	3,758	1,944	10,570	3,706	1%
Probable		4,441	15,802	7,076	5,071	20,356	8,464	-16%
Total Proved & Probable (2P)		6,070	28,574	10,833	7,015	30,927	12,169	-11%

Serinus entered 2018 under significant external and operational challenges, although the petroleum industry in general benefited from an increasing Brent oil price from around US$60.00/bbl in January to almost US$85.00/bbl at the end of September, from which it dropped precipitously during the remainder of the year to around US55.00/bbl at the end of 2018. The Brent price for 2019 to date has again risen from the new year to around US65.00/bbl currently.

Total corporate 1P and 2P reserves in 2018 versus 2017 increased by 1% and decreased by 11%, respectively. There were positive and negative revisions, which are as follows:

Tunisia

In Tunisia, 1P reserves decreased by 16%, while 2P reserves decreased by 13%. The changes in reserves volumes are due to negative revisions as follows:

· A decline in Sabria Win12 and Win13 well production performance in 2018 resulting in a negative revision to the ultimate recovery from both wells;

· A negative revision to the ultimate recovery of the Sabria N2 well based on the Win12 revision, and;

· A shorter economic life in the Chouech Es Saida field due to higher forecasted G&A and well operating costs.

Romania

In Romania, 1P reserves increased by 47%, while 2P reserves decreased by 4%. The changes in reserves volumes are due to:

· Geological re-interpretation requiring volumes adjustments. Changes in the P50 and P10 cases reduced Gas Initially In Place (GIIP) values while the P90 case adjustment increased GIIP.

· Estimated Ultimate recovery (EUR) volumes are lower in the P50 and P10 cases due to lower GIIP.

· Increase in the P90 EUR due to improved recovery with additional development well.

Net Present Value of Future Net Revenues- After Tax, Using Forecast Prices

		2018			2017
		0%	10%	15%	0%	10%	15%	YoY Change for PV10
		(US$ millions)			(US$ millions)
TUNISIA
Proved
	Producing	(10.0)	(5.1)	(3.6)	(7.7)	(2.4)	(1.0)	-113%
	Non-Producing	(9.2)	(1.3)	0.8	(6.6)	3.6	5.4	-136%
	Undeveloped	8.5	4.4	2.8	9.3	4.3	2.5	2%
Total Proved (1P)		(10.7)	(2.0)	-	(5.0)	5.5	6.9	-136%
Probable		99.6	58.9	44.1	86.3	62.0	43.7	-5%
Total Proved & Probable (2P)		88.9	56.9	44.1	81.3	67.5	50.6	-16%
ROMANIA
Proved
	Producing	-	-	-	-	-	-	N/A
	Non-Producing	-	-	-	-	-	-	N/A
	Undeveloped	25.0	23.1	22.2	11.8	9.9	9.1	133%
Total Proved (1P)		25.0	23.1	22.2	11.8	9.9	9.1	133%
Probable		23.4	18.8	17.0	40.3	32.2	29.1	-42%
Total Proved & Probable (2P)		48.4	41.9	39.2	52.1	42.1	38.2	0%
TOTAL COMPANY
Proved
	Producing	(10.0)	(5.1)	(3.6)	(7.7)	(2.4)	(1.0)	-113%
	Non-Producing	(9.2)	(1.3)	0.8	(6.6)	3.6	5.4	-136%
	Undeveloped	33.5	27.5	25.0	21.1	14.2	11.6	94%
Total Proved (1P)		14.3	21.1	22.2	6.8	15.4	16.0	37%
Probable		123.0	77.7	61.1	126.6	94.2	72.8	-18%
Total Proved & Probable (2P)		137.3	98.8	83.3	133.4	109.6	88.8	-10%

Net present values at 10% for Serinus' reserves increased by 37% and decreased by 10% for 1P and 2P Reserves, respectively. The contributing factors to the US$5.8 million increase in the 1P PV10 valuation are the increased 1P reserves in Romania and increased oil and gas price forecasts for Tunisia and Romania, partially offset by higher operating costs, in-country G&A and capital costs in Tunisia. The reduction in the Romania NPV for 2018 versus 2017 was due to the supplemental tax on gas production introduced and made permanent by the Romanian Government in April 2018. The Group views this tax as a violation of its rights as represented in the Satu Mare Concession Agreement and the Group will undertake all efforts to defend its rights and make the supplemental tax not apply to the Group's production.

Contingent Resources

In addition to the 1P and 2P Reserves assigned to the Group's properties in Tunisia and Romania, Contingent Resources are also assigned to the Group's properties.

The Tunisian contingent resources are in the Developed Non-Producing sub-class and consist of the commercially recoverable resources in the Ech Chouech and Sanghar fields, which have been on production in the past using conventional primary recovery technology but are currently shut in due to economic and political uncertainties. The specific contingency which prevents these resources from being classified as reserves is the Group decision to not return the fields to production status at this time, given the marginal economics further exacerbated by the risk of social unrest in these areas. The Group has a 100% working interest in all properties attributed with contingent resources.

The Romanian contingent resources are in the Undeveloped sub-class and consist of the resources behind pipe in three specific reservoir sand layers and which are recoverable using conventional primary gas recovery technology. The specific contingency which would convert these resources to reserves is the Group's decision to recomplete the producing wells to access recovery of the gas resources from these sands, which is forecast to occur once production from the current producing sands have become depleted. The development costs to bring these contingent resources on to production are estimated at US$3.12 million, US$1.56 million and zero for the 1C, 2C, and 3C cases respectively.

All contingent resource volumes are presented as risked for a 90% chance of development.

Company Gross Risked Contingent - Using Forecast Prices

TUNISIA - Risked Contingent Resources (Company Working Interest)
	Resource Volumes (risked)			AT NPV (risked)
	Oil/Liquids	Gas	BOE	0%	10%	15%	Chance of Development
	(Mbbl)	(MMcf)	(Mboe)	(US$ millions)			Chance of Development
1C Contingent Resources	76	61	86	(5.9)	(4.1)	(3.5)	90%
2C Contingent Resources	223	192	254	(3.6)	0.0	0.6	90%
3C Contingent Resources	357	331	412	(0.5)	2.9	2.8	90%
ROMANIA - Risked Contingent Resources (Company Deemed Interest)
	Resource Volumes (risked)			AT NPV (risked)
	Oil/Liquids	Gas	BOE	0%	10%	15%	Chance of Development
	(Mbbl)	(MMcf)	(Mboe)	(US$ millions)			Chance of Development
1C Contingent Resources	3	1,710	288	4.2	3.4	3.1	90%
2C Contingent Resources	13	4,956	839	17.2	12.5	10.7	90%
3C Contingent Resources	26	7,860	1,336	28.3	17.9	14.5	90%
TOTAL COMPANY - Risked Contingent Resources (Company Working Interest)
	Resource Volumes (risked)			AT NPV (risked)
	Oil/Liquids	Gas	BOE	0%	10%	15%	Chance of Development
	(Mbbl)	(MMcf)	(Mboe)	(US$ millions)			Chance of Development
1C Contingent Resources	79	1,771	375	(1.7)	(0.7)	-(0.4)	90%
2C Contingent Resources	236	5,149	1,094	13.6	12.5	11.3	90%
3C Contingent Resources	383	8,191	1,7488	27.8	20.8	17.3	90%

Notes to Contingent Resources Table:

1. Contingent Resources are those quantities of petroleum estimated, as of 31 December 2018 to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.

2. There is uncertainty that any portion of the contingent resources will be commercially viable to produce.

Competent Person's Price Forecasts

The commodity price forecast used by RPS (Competent Person) in preparing is evaluation of the 2018 reserves and resources is as follows:

	Tunisia Domestic Gas			Romanian Gas Price
	Brent	Sabria	Chouech
	(US$/Bbl)	(US$/Mcf)	(US$/Mcf)	(US$/MMBtu)
2019	66.00	8.99	7.38	8.05
2020	68.30	9.30	7.64	8.15
2021	70.85	9.65	7.93	7.70
2022	73.20	9.97	8.19	7.36
2023	75.50	10.28	8.45	7.12
2024	76.50	10.42	8.56	7.12
2025	78.83	10.74	8.82	7.26
2026	80.41	10.95	9.00	7.40
2027	82.02	11.17	9.18	7.55
2028	83.66	11.39	9.36	7.69
2029	85.33	11.62	9.55	7.84
2030	87.04	11.85	9.74	7.99
2031	88.78	12.09	9.93	8.15
2032	90.55	12.33	10.13	8.31
2033	92.36	12.58	10.33	8.47
2034	94.21	12.83	10.54	8.63
2035	96.09	13.09	10.75	8.80
2036	98.02	13.35	10.97	8.97
2013	99.98	13.62	11.19	9.15

RISK MANAGEMENT STATEMENT

The Group is subject to a number of potential risks and uncertainties, which could have a material impact on the long-term performance of the Group and could cause actual results to differ materially from expectation.

The management of risk is the responsibility of the Board of Directors and the Group has developed a range of internal controls and procedures in order to manage the risks.

The following list outlines the Group's key risks and uncertainties and also provides details as to how these are managed.

Risk	Description	Mitigation
Political Risk	The Group operates in multiple jurisdictions and is therefore at risk from the political, regulatory and social environment and is exposed to risk such as social unrest, political violence, corruption, loss of licences, expropriation, changes in the fiscal regimes and non-compliance with laws and regulations.	Given this risk the Group actively monitors political developments and maintains relationships with government, authorities and industry bodies, as well as with other stakeholders. The Group manages compliance with laws and regulations and contractual obligations by employing the requisite skills or engaging consultants to supplement internal knowledge. Internal policies and procedures, as well as monitoring of performance, help mitigate risks of non-compliance.
Operational Risk	The nature of oil and gas operations means that the Group is exposed to risks such as equipment failure, well blow-outs, fire, pollution, performance of partners/contractors and suppliers, delays in commissioning or installing property, plant or equipment, unknown geological conditions and failure to achieve capital costs, operating costs, production or reserves.	In order to mitigate operational risks the Group: - Has enhanced its operating standards, in particular reflecting the well incident in late 2017; - Has extensive monitoring and review of HSE and crisis management policies and procedures; - Carries sufficient levels of insurance coverage; - Selects contractors based on a rigorous tender process that includes ensuring policies and procedures are equivalent to the Group's,; - Tightly monitors costs, compares to budget and produces monthly forecasts. - Employs geological and technical experts to review data and work programmes.
Capital Structure and availability of Financing	The delay in production in Romania indicates a need for funding. There can be no assurances that the Group can raise additional financing.	The Group closely monitors its cash position and at least monthly produces updated cash flow forecasts to help it determine its cash flow needs. Renegotiation of the EBRD debt in late 2017 to allow for development in Romania. Equity raises completed in 2017 2018 and March 2019. The Board considers different possible sources of funds and the timing of accessing the markets.
Financial Risk	The Group is subject to commodity price volatility, interest rates, foreign exchange rate volatility and credit risk of counterparties.	The Group manages these risks by actively monitoring its business, for example the gas pricing environment in Romania, including preparing monthly forecasts and cash flow forecasts based on current and forecast data. The Groups financial risk policies are set out in Note 24 to the financial statements.

BOARD OF DIRECTORS AND MANAGEMENT TEAM

BOARD OF DIRECTORS

Łukasz Rędziniak

Interim Chairman, Non-Independent Director, Chair of Remuneration Committee, Chair of the Nomination Committee Board Member and General Counsel of Kulczyk Investments SA, the largest shareholder of Serinus.

Mr. Redziniak is an Attorney and member of the District Bar Association in Warsaw. Between 1990 and 1991 he worked as an Assistant at the Faculty of Law and Administration of the Jagiellonian University. During the years 1991-1992 he was an in-house Lawyer at Consoft Consulting sp. z o.o. From 1997 to 2000 he worked as an Attorney - individual practice closely co-operating with Dewey Ballantine sp. z o.o. In the years 1993-2007 he worked in the law firm Dewey and LeBoeuf LLP and in 2001 he was appointed as a partner. Then, in the years 2007-2009 he was Undersecretary of State in the Ministry of Justice of the Republic of Poland. Since 2009 he was a Partner and Managing Partner at the Warsaw office at Studnicki, Płeszka, Ćwiąkalski, Góra sp. k. In 2013, he became a Member of the Board at Kulczyk Investments S.A. The same year he was also appointed as a member of the Supervisory Board at Firma Oponiarska Dębica S.A. and a Member of the Supervisory Board at Polenergia S.A. (Vice-Chairman of the Supervisor).

Mr. Rędziniak is a graduate of the Faculty of Law and Administration of Jagiellonian University.

Appointed: March 2016

Jeffrey Auld

President & CEO, Non-independent Director

Mr. Auld has been involved with the international oil and gas business for over 25 years. In that time he has managed companies and acted as an advisor to companies operating in the emerging markets oil and gas business. Mr. Auld has a depth of experience in corporate finance, mergers and acquisitions and strategic management.

Mr. Auld began his career in Canada and moved to the United Kingdom in 1995. He was the Commercial Manager for New Ventures for Premier Oil plc. Mr. Auld left Premier Oil and joined the Energy and Power team within the Mergers and Strategic Advisory group of Goldman, Sachs and Co. When Mr. Auld left Goldman Sachs he joined PetroKazakhstan, a NYSE listed company with assets in Kazakhstan, as a Senior Vice-President. After his time at PetroKazakhstan Mr. Auld became the Head of European Energy for Canaccord Genuity in London. Prior to joining Serinus Mr. Auld was the Head of EMEA Oil and Gas at Macquarie Capital in London.

Mr. Auld has an undergraduate degree in Economics and Political Sciences from the University of Calgary and a Masters of Business Administration with Distinction from Imperial College, London

Appointed: September 2016

Evgenij Iorich

Independent Director, Member of the Audit Committee, Member of the Remuneration Committee, Member of the Nomination Committee

Mr. Iorich is a Vice President at Pala Investments, a multi-strategy investment company dedicated to investing in, and creating value across the mining sector in both developed and emerging markets. Mr. Iorich has been with Pala Investments since 2006 and his investment experience at Pala includes oil and gas, base metal and bulk commodity investments, and his commodity experience extends across a broad range of bulk commodities, precious and base metals.

Prior to joining Pala, Mr. Iorich was a financial manager at Mechel, the Russian metals and mining company, where his responsibilities included all aspects of budgeting, forecasting and financial modeling. Mr. Iorich is currently a Director of Melior Resources Inc. and Peninsula Energy Limited (a public corporation which trades on the ASX).

Mr. Iorich graduated from the University of Zurich with a Masters of Arts degree.

Appointed: June 2013

Eleanor Barker

Independent Director, Chair of the Audit Committee, Member of the Remuneration Committee, Member of the Nomination Committee, Member of the Reserves Committee

Eleanor Barker is President of Barker Oil Strategies and from 2014 to 2017 was a Director of Sterling Resources Ltd. Since 1995, Ms. Barker has focused on international oil research. From 2012 to 2014 she was an international oil analyst with Toll Cross Securities Inc.. From 2007 to 2012 she was President of Barker Oil Strategies Inc.. Ms. Barker is a past Director of the US National Association of Petroleum Investment Analysts and a former President of the Canadian Association of Investment Analysts. From 1993 to 1995 Ms. Barker was a director of Gordon Capital. Prior to work in financial markets, she held various positions with Esso and Gulf Canada.

Ms. Barker graduated from Queen's University in Canada with an Hons. B.Sc. and from the University of Western Ontario with an MBA.

Appointed: May 2017

Jim Causgrove

Independent Director, Chair of the Reserves Committee, Member of the Audit Committee

Mr. Causgrove is an experienced Oil and Gas executive with over 35 years experience. On 14 November 2017, Mr. Causgrove was appointed Chief Operating Officer of Harvest Operation Corporation. He offers both excellent technical engineering and business experience along with a strong track record in management and leadership. Since 1979, working for first Chevron Corporation and then Pengrowth Energy Corporation, Jim has gained experience and skills in virtually all facets of the oil and gas business; with a particular technical focus on drilling, production, operations and midstream. Jim gained excellent field and technical experience with Chevron working in both the Canadian head office as well as many field offices and field sites. As well as his technical roles Jim spent time working in Joint Ventures, Human Resources, Strategic and Business Planning and in the Midstream business. Jim gained valuable business insights as first a technical leader, then as a middle manager, and finally as an executive for Chevron and Pengrowth. In his role as Vice President at Pengrowth, Jim worked as part of the senior leadership team and also worked closely with the Board of Directors.

Appointed: September 2017

Dawid Jakubowicz

Non-Independent Director

Mr. Jakubowicz is a member of the management board at Kulczyk Investments S.A., where since 2010, he has been responsible for the supervision of the investment portfolio. He is an esteemed expert with international operating experience in the building of goodwill of companies from the chemical, mining, power, automotive and new technologies sector. In the past, he worked for international company KPMG Audyt, where he was responsible for audit of unit and consolidated financial statements of entities from many sectors. Since 2014, he has been entered in the list of Chartered Accountants kept by the Polish Chamber of Chartered Accountants. r.

Mr. Dawid Jakubowicz graduated from the University of Economics in Poznań. He also holds an MBA from the University of Economics in Poznań and Georgia State University in the United States and he has completed a Program for Leadership Development at the Harvard School in Boston.

Appointed: March 2018

Tracy Heck

Chief Financial Officer, Non-independent Director

Ms Heck is a financial professional with over 25 years of experience. Her professional career started in the United Kingdom with KPMG and continued in Canada where she rose to hold the position of Associate Partner in KPMG Calgary's audit practice. Since October 2005, until joining Serinus as Director of Finance in June 2012, Ms. Heck worked in the Canadian oil and gas sector. On 1 January 2014, Ms. Tracy Heck was appointed Chief Financial Officer ("CFO") of Serinus Energy plc.

Ms. Heck is qualified as a Chartered Accountant in England & Wales and a Chartered Professional Accountant and Chartered Accountant in Canada.

Appointed: May 2018

SENIOR MANAGEMENT

Calvin Brackman

Vice President, External Relations & Strategy

Mr. Brackman has 25 years' experience in the oil & gas industry, both in the public and private sector. He started his career working for the Department of Natural Resources of the Government of Canada, before moving to a senior position in the Minerals, Oil & Gas Division of the Government of the Northwest Territories. In 2003, Mr. Brackman moved to London, UK, to join PetroKazakhstan Inc. as Director of Government Relations. In this position he developed and implemented strategies to reduce the company's surface risk. Following the sale of PetroKazakhstan to CNPC in 2005, Mr. Brackman moved back to Canada and started a successful consulting practice, providing expert advice to various international companies and governments. In December 2016, he joined Serinus in his current role, working with the company's CEO, CFO and business units to develop and implement the Group's exploration and development strategies and oversee government and stakeholder relations.

Mr. Brackman has a MA in Economics from the University of Waterloo and a BA in Economics from the University of Calgary.

Alexandra Damascan

President, Serinus Energy Romania S.A.

Ms. Damascan has been with Serinus Energy Romania since 2008 and as a senior executive with expertise in all areas of the global oil-and-gas industry, Ms. Damascan has brought the company's assets from early exploration phase to production. Prior to joining Serinus, Ms. Damascan was a partner in a medium size Romanian company which handled technical and legal translations and language interpretation for different journals and professional magazines.

Ms. Damascan graduated from the Oil and Gas Institute as a Petroleum Engineer, she also has a degree in Political Economics, an MBA in Business Transactions from the Academy of Economic Studies, a Law Degree and LLM in International Arbitration from the Romanian-American University and an MBA in Oil & Gas from the Oil and Gas Institute in Ploiesti, Romania.

Haithem Ben Hassen

President, Serinus Energy Tunisia B.V.

Mr. Ben Hassen joined Serinus Energy Tunisia in November 2014 as a Senior Project Engineer and was then promoted to Project Manager in May 2015. In January 2018, he was promoted to President of Serinus Energy Tunisia. During this time he has been responsible for the completion of numerous capital projects undertaken by Serinus Tunisia. He was also appointed to handle the technical aspect of the Moftinu Development Project.

Mr. Ben Hassen has over 16 years of experience in the oil and gas industry, power plants and renewable energies and has worked in roles involving multi-disciplined project management, engineering, construction, completions, handover and closeout and operating. Mr. Ben Hassen is equally well-versed with contract review and management, business plan development, budget estimation and bidding preparation.

Mr. Ben Hassen has a BA in Mechanical Engineering from the École Polytechnique of Montréal in Canada.

Arafet Mansali

Chief Operating Officer, Serinus Energy Tunisia B.V.

Mr. Mansali joined Winstar Tunisia in February 2014 as a Senior Production Engineer before being appointed Production Manager in May 2017. He was appointed as Chief Operating Officer of Serinus Tunisia B.V in January 2018. Prior to joining Winstar, Mr. Mansali worked in petroleum engineering, the field and operations management in Maretap Tunisia and Ecumed Petroleum Tunisia. Mr. Mansali is responsible for the daily field operations of all of the Company's assets in Tunisia.

Mr. Mansali has a Bachelor of Mechanical Engineering degree from the National Institute of Applied Science and Technology in Tunisia.

CORPORATE GOVERNANCE STATEMENT

Chairman's Introduction

The Group is managed under the direction and supervision of the Board of Directors. Among other things, the Board sets the vision and strategy for the Group in order to effectively implement the Group's business model which is the exploration and production of hydrocarbon resources from its current hydrocarbon concessions in Romania and Tunisia.

Good corporate governance creates shareholder value by improving performance while reducing or mitigating risks that the Group faces as we seek to create sustainable growth over the medium to long-term. It is the role as Chairman to lead the Board effectively and to oversee the adoption, delivery and communication of the Group's corporate governance model.

To these ends and in line with the recent changes to the AIM Rules to require all companies to adopt and comply with a recognised corporate governance code, the Board has adopted the Quoted Companies Alliance Corporate Governance Code (the "Code"). It was decided that the Code was more appropriate for the Group's size and stage of development than the more prescriptive Financial Reporting Council's UK Corporate Governance Code.

The report that follows sets out in summary terms how we comply with the Code to be read in conjunction with the Statement of Compliance with QCA Corporate Governance Code available on our website at http://serinusenergy.com/shareholder-information/

As an issuer listed on the Warsaw Stock Exchange, Poland ("WSE"), in 2018 the Company was subject and followed the recommendations and rules contained within the "Code of Best Practice for WSE Listed Companies 2016" ("Code of Best Practice WSE 2016"). These rules were adopted by the WSE Supervisory Board on 13 October 2015 (Annex to the Resolution No. 27/1414/2015) and are accessible at:

https://www.gpw.pl/best-practice

https://www.gpw.pl/pub/GPW/o-nas/DPSN2016_EN.pdf

Principle 1: Establish a strategy and business model which promotes the long term value for shareholders

· The Group's strategy is defined in the Strategic Section of this Annual Report. (page 2 to 23)

· The objective is to grow the hydrocarbon production of the Group through efficient allocation of shareholder capital to produce long-term return on investments for shareholders

· In order to capitalise on the available opportunities and to mitigate the key challenges facing the Group, the Group has assembled a high quality Board of Directors and set of advisers including a very experienced management team with substantial experience in the oil & gas exploration and production sphere. The Group has been structured to give the Board the necessary oversight of all investment decisions of the Group.

· The oil and natural gas business involves many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome. The long-term commercial success of the Group, meaning the capability to generate positive net revenues on a sustainable basis, will depend on its ability to find, acquire, develop and commercially produce oil and natural gas reserves.

Principle 2: Seek to understand and meet shareholder needs and expectations

The Group is committed to listening and communicating openly with its shareholders to ensure that its strategy, business model and performance are clearly understood. Understanding what analysts and investors think about us, and in turn, helping these audiences understand our business, is a key part of driving our business forward and we actively seek dialogue with the market by undertaking the following:

· Investor roadshows,

· Attending investor conferences,

· Hosting capital markets days,

· Timely disclosure of material information, and

· Regular reporting.

The Directors actively seek to build a relationship with institutional shareholders by making presentations to institutional shareholders and analysts from time to time in part to listen to their feedback and have a direct conversation on any areas of concern.

The Board as a whole is kept informed of the views and concerns of major shareholders by briefings from the CEO.

Any significant investment reports from analysts are also circulated to the Board.

The Non-Executive Chairman is also available to meet with major shareholders if required to discuss issues of importance to them. To request a meeting with a Director, please contact Calvin Brackman, Vice President, External Relations & Strategy by email at cbrackman@serinusenergy.com or by phone at +1 403 264 8877.

The Annual General Meeting ("AGM") is one forum for dialogue with shareholders and the Board. The results of the AGM are subsequently published on the Company's website.

Principle 3: Take into account wider stakeholder and social responsibilities and their implications for long term success

Key stakeholders are as follows:

· Shareholders

· The European Bank for Reconstruction and Development ("EBRD")

· Employees

· Communities in which we operate - landowners, local authorities, local citizens

Engaging with all of our stakeholders strengthens our relationships and helps us make better business decisions to deliver on our commitments.

The Board is regularly updated on wider stakeholder engagement.

The Company also actively engages stakeholders near our operations as follows:

· Meetings are held with the local authorities and governments in our operating jurisdictions several times a year to keep them informed, as required.

· Town hall meetings are held with local citizens as required to discuss development plans.

· We seek the input of the communities in identifying the funding needs of different community initiatives.

Principle 4: Embed effective risk management, considering both opportunities and threats, throughout the organisation

· The CFO has prepared a risk register for the Group that outlines the key financial and operational risks. All Board members have a copy of this register and it is discussed and updated at least annually. A summary of these risks is included in the Risk Management Statement of this annual report.

· The Audit Committee monitors the integrity of the financial statements of the Group including its annual and interim reports and any other formal announcement relating to financial performance.

· The Audit Committee focuses particularly on compliance with legal requirements, accounting standards and the relevant AIM Rules for Companies and Warsaw rules and ensuring that an effective system of internal financial and non-financial controls is maintained.

· The Board acknowledges that the Group's international operations may give rise to possible claims of bribery and corruption. The Board has adopted a zero tolerance policy toward bribery and has reiterated its commitment to carry out business fairly, honestly and openly.

· The Group has also adopted a share dealing code, in conformity with the requirements of Rule 21 of the AIM Rules for Companies.

· All material contracts are required to be reviewed and signed by a Director and reviewed by our external counsel.

Principle 5: Maintain the board as a well-functioning, balanced team lead by the chair

The Board comprises the Non-Executive Non-Independent Chairman, two Executive Directors, three Non-Executive Independent Directors, and one Non-Executive Non-Independent Director. The Board considers, after careful review, that the Non-Executive Directors bring an independent judgement to bear. The Board is satisfied that it has a suitable balance between independence on the one hand, and knowledge of the Group on the other, to enable it to discharge its duties and responsibilities effectively. All Directors are encouraged to use their independent judgement and to challenge all matters, whether strategic or operational.

Directors' attendance at Board and Committee meetings during 2018 was as follows:

Name of Director	Board	Audit Committee	Remuneration Committee	Nomination Committee	Reserves Committee
Total Meetings Held	9	5	9	-	1

Jeffrey Auld	9	5	3	-	1
Tracy Heck (appointed 18 May 2018)	4	3	-	-	-
Lukasz Redziniak	8	-	9	-	-
Jim Causgrove	9	5	-	-	1
Eleanor Barker	9	5	9	-	1
Evgenij Iorich	5	3	8	-	-
Dawid Jakubowicz (appointed 7 March 2018)	5	3	-	-	-
Sebastian Kulczyk (resigned 7 March 2018)	-	-	-	-	-
Helmut Langanger (resigned 7 March 2018)	1	-	-	-	-
Dominik Libicki (resigned 18 May 2018)	4	-	-	-	1

Key Board activities this year included:

· Continuance of the Company to Jersey

· Listing on AIM and concurrent equity raise

· Continued an open dialogue with the investment community

· Considered our financial and non-financial policies

· Discussed strategic priorities

· Discussed the Company's capital structure and financial strategy, including capital investments and shareholder returns

· Discussed internal governance processes

· Reviewed the Group's risk profile

· Reviewed feedback from shareholders post quarterly and full year results.

The Company has effective procedures in place to monitor and deal with conflicts of interest. Since the non-executive Directors perform their duties on a part-time basis, the Board is aware of the other commitments and interests of its Directors, and changes to these commitments and interests must be reported to and, where appropriate, agreed with the rest of the Board. The two executive directors are full time with the Company.

The Company's Board has a broad range of relevant experience suitable for issues pertaining to the oversight of a publicly-listed Oil & Gas Company. These include financial, legal, capital markets, and technical. For biographies of the Company's Directors containing their relevant experience, please refer to the Board of Directors and Management Team section of this annual report.

Principle 6: Ensure that between them the directors have the necessary up-to-date experience, skills and capabilities

Members of the Board are listed in the Board of Directors section of this Annual Report which also details their experience, skills and personal qualities. The Corporate Secretary of the Company is JTC Group.

The Board is satisfied that, between the Directors, it has an effective and appropriate balance of skills and experience, including in the areas of financial, legal, capital markets, and technical. The Company also considers it has an appropriate gender balance given its two female directors.

All Directors receive regular and timely information on the Group's operational and financial performance. All Board members receive an agenda and associated papers a few days in advance of meetings. The Group's management provides the Board with a Monthly Directors Report that contains share price performance, key financial and operating indices, cash flow forecast, capital expenditures, budget variance reports, and commentary on the opportunities and risks facing the Group and its activities.

No corporate governance matters have arisen since listing on AIM for which it was considered necessary by the directors to seek specific external advice. However, given during 2018 the Company continued to Jersey, Channel Islands and listed on AIM, the Board of directors sought advice from the Company's lawyers, nominated advisor and accounting firm (KPMG) in regards to the listing, continuance and ongoing responsibilities of directors once on AIM.

During the year there were two new board members appointed, Mr. Jakubowicz and Ms. Heck, and three board members resigned, Mr. Kulczyk, Mr. Langanger and Mr. Libicki. New directors have access to the CEO to develop an understanding of the business and also receive training from the Company's nominated advisor.

All Directors are able to take independent professional advice in the furtherance of their duties, if necessary, at the Company's expense.

In addition, the Directors have direct access to the advice and services of the Company Secretary and Chief Financial Officer and are able to solicit advice relevant to those roles.

Principle 7: Evaluate board performance based on clear and relevant objectives, seeking continuous improvement

The Company is constantly assessing the individual contributions of each of the members of the Board and executive team to ensure that:

· Their contribution is relevant and effective

· That they are committed

· Where relevant, they have maintained their independence.

Over the next 12 months the Board intends to review the performance of the team as a unit to ensure that the members of the Board collectively function in an efficient and productive manner.

Periodically the non-Executive Directors discuss relevant succession planning with the CEO. These discussions focus on key individual risk as well as broader succession issues.

Principle 8: Promote a corporate culture that is based on ethical values and behaviours

The Board believes that the promotion of a corporate culture based on sound ethical values and behaviours is essential to maximise shareholder value.

The Group maintains and annually reviews a handbook that includes clear guidance on what is expected of every employee of the Group. Adherence to these standards is a key factor in the evaluation of performance within the Group.

Principle 9: Maintain governance structures and processes that are fit for purpose and support good decision-making by the board

The Board meets at least four times each year in accordance with its scheduled quarterly meeting calendar. This may be supplemented by additional meetings as and when required. During the year to 31 December 2018, the Board met for its four scheduled meetings plus five times in addition.

The Board and its Committees receive appropriate and timely information prior to each meeting; a formal agenda is produced for each meeting, and Board and committee papers are expected to be distributed well before meetings take place. Any Director may challenge Group proposals and all decisions are taken democratically after discussion. Any Director who feels that any concern remains unresolved after discussion may ask for that concern to be noted in the minutes of the meeting, which are then circulated to all Directors. Any specific actions arising from such meetings are agreed by the Board or relevant committee and then followed up by the Company's management.

The Board is responsible for the long-term success of the Group. There is a formal schedule of matters reserved for the Board. It is responsible for overall group strategy; approval of major investments; approval of the annual and interim results; annual budgets; and Board structure. It monitors the exposure to key business risks and reviews the annual budgets and their performance in relation to those budgets. There is a clear division of responsibility at the head of the Company.

The Chairman is responsible for running the business of the Board and for ensuring appropriate strategic focus and direction. The CEO is responsible for proposing the strategic focus to the Board, implementing it once it has been approved and overseeing the management of the Group through the executive team. The terms of reference for the Chairman and CEO are on the Group's website at http://serinusenergy.com/shareholder-information.

The Board is supported by the audit, remuneration, nomination and reserves committees:

· The Audit Committee is responsible for the financial reporting and internal control principals of the Group and maintaining an appropriate relationship with the Group's auditors.

· The Remuneration Committee is responsible for the consideration, development and implementation of policy on executive remuneration and fixing remuneration packages of individual directors, so that no director shall be involved in deciding his or her own remuneration. The committee ensures remuneration is aligned to the implementation of the Group strategy and effective risk management, taking into account the views of shareholders and is also assisted by executive pay consultants as and when required.

· The Nomination Committee is responsible for establishing formal, rigorous and transparent procedures for the appointment of new directors to the Board.

· The Reserves Committee is responsible for overseeing the evaluation of the Group's petroleum and natural gas reserves, including retaining an "independent" engineering firm which is a "Competent Person" (as such term is defined in "Note for Mining and Oil & Gas Companies" issued by AIM) to prepare a report (the "Report") of an evaluation of the Group's petroleum and natural gas reserves, and of meeting with representatives of the Engineering Firm and management to discuss the Report's preparation and the conclusions contained in the Report.

Principle 10: Communicate how the company is governed and is performing by maintaining a dialogue with shareholders and other relevant stakeholders

The Company communicates with shareholders through the Annual Report and Accounts, full-year and quarterly announcements, the AGM and one-to-one meetings with large existing or potential new shareholders. A range of corporate information (including all Company announcements and presentations) is also available to shareholders, investors and the public on the Company's corporate website, www.serinusenergy.com. The Board receives regular updates on the views of shareholders through briefings and reports from the CEO, Chief Financial Officer and the Company's brokers. The Company communicates with institutional investors frequently through briefings with management. In addition, analysts' notes and brokers' briefings are reviewed to achieve a wide understanding of investors' views.

For the Company's shareholder meetings, any resolutions voted by shareholders that have a significant number of dissenting votes the Company will provide, on a timely basis, an explanation of what actions it intends to take to understand the reasons behind that vote result, and, where appropriate, any different action it has taken, or will take, as a result of the vote.

REMUNERATION COMMITTEE REPORT

This remuneration report has been prepared by the Remuneration Committee and approved by the Board. The report for 2018 sets out the details of the remuneration policy for the Directors and discloses the amounts paid during the year.

Remuneration Committee

The Remuneration Committee comprises not less than three members, two of whom are independent Non-Executive Directors (Eleanor Barker and Evgenij Iorich) with the third being a non-independent Director, that being the Chairman of the Board (Lukasz Redziniak). Other Directors are invited to attend as appropriate and only if they do not have a conflict of interest.

The aim of the Remuneration Committee is to :

· Attract, retain and motivate the executive management of the Company

· To offer the opportunuity for employees to participate in share option schemes to incentivize employees to enhance shareholder value

To achieve the above, the Committee considers the following categories of remuneration: (i) annual salary and associated benefits (ii) stock option plan and long-term share-based incentive plan, and (iii) performance based annual bonus.

The Committee met nine times during the year.

The terms of reference of the Remuneration Committee are set out below:

· To determine and agree with the Board the overall remuneration policy of the Chairman of the Board, the executive directors and such other members of the executive management as it is designated by the Board to consider

· Review the ongoing appropriateness and relevance of the remuneration policy

· Approve the design of, and determine targets for, any performance related pay schemes operated by the Company and approve the total annual payments made under such schemes

· Review the design of all share incentive plans for approval by the Board and shareholders and determine each year whether awards will be made under the share incentive plans including the amount of awards to each individual and the performance targets to be used

· To review and approve any termination payment such that these are fair to both the individual and the Company

· To review and monitor (i) the remuneration trends across the Group (ii) if required undertake a benchmarking exercise to compare against a peer group, and (iii) obtain reliable, up to date information about remuneration in other companies

Directors Remuneration

Compensation for Directors, who held office during the year, in United States dollars is as follows:

Name of Director	Salaries and fees⁽¹⁾	Benefits	Share Based Compensation ⁽²⁾	2018 Total	2017 Total
Executive Directors:
Jeffrey Auld	233,094	8,324	407,012	648,430	533,097
Tracy Heck	206,317	12,170	308,435	526,922	427,700

Non-Executive Directors:
Lukasz Redziniak	23,247	-	-	23,247	14,631
Jim Causgrove	20,922	-	10,977	31,899	6,167
Eleanor Barker	30,996	-	6,974	37,970	20,349
Evgenij Iorich	21,697	-	6,974	28,671	27,279
Dawid Jakubowicz (appointed 7 March 2018)	13,948	-	-	13,948	-
Sebastian Kulczyk (resigned 7 March 2018)	2,325	-	-	2,325	9,241
Helmut Langanger (resigned 7 March 2018)	3,100	-	-	3,100	32,641
Dominik Libicki (resigned 18 May 2018)	7,749	-	-	7,749	15,401
	563,395	20,494	740,372	1,324,261	1,086,506

Notes to Remuneration table:

1. Compensation of directors is denominated in and paid in Canadian dollars, other than for Mr. Jeffrey Auld whose pay is denominated in pounds Sterling effective 1 October 2018. The compensation is translated using the average exchange rate for the year (2018: CAD/USD 0.7749 GBP/USD 1.3322; 2017: CAD/USD 0.7701).

2. Share based compensation reflects the grant date fair value of the options amortized over the vesting period, calculated using the Black Scholes method, calculated in accordance with IFRS 2 share-based payments.

The non-executive Directors receive fees based on meetings attended as well as a monthly retainer. The monthly retainer for all non-executive Directors is C$1,000 per month and the Audit Committee Chair receives an additional retainer of C$250 per month. The fees for attending meetings are C$1,000 per meeting.

Directors Interests in Share Capital

The Group operates a share option plan pursuant which Directors and employees may be granted options to acquire ordinary shares in the Company.

Further details on the share option plan can be found in note 6 to the financial statements.

Subsequent to listing on AIM in May 2018, the Company converted its options, for Executive Directors and employees, from a TSX plan to an AIM plan and converted the exercise price on outstanding options to Pounds Sterling based on the exchange rate at the date of continuance. The AIM plan and conversion of exercise prices for non-executive directors remains to be finalized.

The following are the options outstanding and shares owned as at 31 December 2018 and changes since 31 December 2018, up to the date of this report, for all Directors:

Name of Director	Options held at 31 December 2018 and 20 March 2019	Shares held at 31 December 2017 and 2018	Change in ownership	Shares held at 20 March 2019
Executive Directors:
Jeffrey Auld	7,000,000	22,197	-	22,197
Tracy Heck	4,950,000	-	-	-

Non-Executive Directors:
Lukasz Redziniak	-	-	-	-
Jim Causgrove	100,000	-	-	-
Eleanor Barker	100,000	100,000	-	100,000
Evgenij Iorich ^(a)	100,000	3,415	-	3,415
Dawid Jakubowicz	-	-	-	-
	12,250,000	125,612	-	125,612

^(a)Mr. Iorich holds a position with Pala Investments, which is related to Pala Assets Holdings Limited ("Pala"). Pala owned 11,266,084 Shares as at 31 December 2018. By virtue of his position with Pala Investments, Mr. Iorich is deemed to have direction over such Shares in addition to those Shares that are shown above.

The Directors who held options as at 31 December 2018 and the terms of those options are as follows:

Name of Director	Options held at 31 December 2018	Options held at 31 December 2017	Exercise price	Date of Grant
Executive Directors:
Jeffrey Auld	3,500,000	3,500,000	£0.18	22 Sept 2016
Jeffrey Auld	1,000,000	1,000,000	£0.21	31 May 2017
Jeffrey Auld	2,500,000	-	$0.15	3 Dec 2018

Tracy Heck	2,750,000	2,750,000	£0.21	31 May 2017
Tracy Heck	2,200,000	-	£0.15	3 Dec 2018

Non-Executive Directors:
Jim Causgrove	100,000	100,000	C$0.37	31 May 2017
Eleanor Barker	100,000	100,000	C$0.37	31 May 2017
Evgenij Iorich ^(a)	100,000	100,000	C$0.37	31 May 2017
	12,250,000	7,550,000

Options issued 22 September 2016 have a seven-year term and vest one-third per year on the anniversary date of the grant date for the three subsequent years. Options issued 31 May 2017 have a five-year term and vest one-third per year on the anniversary date of the grant date for the three subsequent years. Options issued on 3 December 2018 have a 10-year term and vest one third immediately with the remaining two-thirds at one-third per year each on the anniversary date of the grant date for the two subsequent years.

Lukasz Redziniak, Chairman of the Remuneration Committee

20 March 2019

AUDIT COMMITTEE REPORT

This report addresses the responsibilities, the membership and the activities of the Audit Committee in 2018 up to the approval of the 2018 Annual Report and 2018 year-end Financial Statements.

Responsibilities

The main responsibilities of the Audit Committee are the following:

1. Monitor the integrity of the annual and interim financial statements;

2. Review the effectiveness of financial and related internal controls and associated risk management;

3. Manage the relationship with our external auditors including plans and findings, independence and assessment regarding reappointment.

Membership

The Audit Committee is comprised of Eleanor Barker (Chairman), James Causgrove and Evgenji Iorich, all independent non-executive Directors.

Activities in 2018

External Auditor

The Committee is responsible for the relationship with the external auditor. As a result of the move of the Company's listing to the AIM market in May 2018, it was decided that the Company should tender the external audit appointment. After a rigorous review, the decision was made to transition from KPMG to BDO in the role of external auditor and BDO was formally appointed in November 2018.

Financial Reporting

The Committee reviewed the 2018 draft interim financial statements with KPMG. The transition from KPMG to BDO was initiated in November 2018 with the significant year end audit work occurring January to March 2019.

With regard to the 2018 year end Audit, the Committee has reviewed the following key audit matters:

1. The carrying value of Development and Production Assets

2. The decommissioning provisions

3. Going concern and covenant compliance

In addition, as part of its remit the Audit Committee also reviewed Management's papers on the adoption of the new revenue recognition standard (IFRS 15) and the Financial Instruments standard (IFRS 9).

The Directors consider that the continuing availability of the existing facilities and covenant compliance at year end, and during the period taken into consideration, in respect of the going concern assessment to be a material uncertainty that may cast significant doubt with respect to the ability of the Group to continue as a going concern.. The financial statements do not reflect the adjustments which would be required if the going concern basis of preparation was not considered appropriate.

Internal Controls and Risk Management, Whistleblowing and Fraud

The Committee is vigilant regarding internal financial controls and risk management. During 2018, the Committee has undertaken anti-bribery and anti-corruption exercises and has reviewed whistle blowing arrangements.

Conclusion

In 2019 and beyond, the Committee will continue to adapt to new reporting and regulatory requirements. In addition, the evolving financial and risk management environment will inform our future decisions.

Eleanor Barker, Chairman of the Audit Committee

20 March 2019

REPORT OF THE DIRECTORS

The Directors' present their report, together with the audited consolidated financial statements of Serinus Energy plc (the "Company") and its subsidiary undertakings (together the "Group") for the year ended 31 December 2018.

Principal Activities

The principal activity of the Group is oil and gas development.

Directors and Directors Interests

Directors who held office during the year, their remuneration and interests held in the Company are detailed in the Remuneration Report.

Directors biographies for those holding office at the end of the year are detailed in the Board and Management Team section of this annual report.

Substantial Shareholders

As of the date of issuing this report, management is aware of the following shareholders holding more than 5% of the common shares of the Company, as reported by the shareholders to the Company:

Kulczyk Investments S.A. 38.77%

James Caird Investments Ltd 9.11%

Marlborough Fund Managers 7.67%

City Financial 6.03%

Pala Assets Holdings Limited 5.18%

Results and Dividends

The results for the year are set out in the Consolidated Statement of Comprehensive Income. The results are further discussed in the CFO Report.

The Directors do not recommend payment of a dividend in respect of these financial statements (2017: $nil)

Going Concern

The Group is required to have sufficient resources to cover the expected running costs of the business for a period of at least 12 months after the issue of these financial statements. At the end of the year, the Group had a cash balance of $2.3 million, a working capital deficit of $15.4 million and generated a loss before income tax of $3.1 million for the year.

The Directors have prepared cash flow forecasts for the Group covering the period to June 2020. Due to the delay in achieving production in Romania an equity raise with gross proceeds of $3.0 million was undertaken in order to meet a scheduled debt repayment under the EBRD Senior Loan, due 31 March 2019. With this equity raise the forecast indicates that that the Group will be able to operate within the existing loan facilities, as currently available. Should the base case forecasts be negatively impacted by a downward revision in key assumptions in the cash flow forecast, there is the possibility that the Group will not be able to meet obligations as they come due. In addition, the cash flow forecast indicates that quarterly financial covenants related to its debt with EBRD will not be met in future quarters. The Group notes that it was not in compliance with the consolidated debt service coverage ratio for the three months ended 31 December 2018. However, on 21 December 2018, the Group received a waiver from the EBRD formally waiving compliance with both financial covenants for the period ended 31 December 2018. The implication of this waiver is that the debt will follow their original scheduled repayment terms and the bank will not be acting on its security as a result of the breach.

The Directors consider that the continuing availability of the existing facilities but, with the acknowledgement that the potential that the covenants may not be met during the going concern review period is a material uncertainty that may cast significant doubt with respect to the ability of the Group to continue as a going concern.

The consolidated financial statements do not reflect the adjustments and classification of assets, liabilities, revenues and expenses which would be necessary of the Group were unable to continue as a going concern.

Statement of Directors Responsibilities in Respect of the Financial Statements

The Directors are responsible for preparing the Directors' Report and the financial statements in accordance with applicable law and regulations.

Jersey Company law requires the Directors to prepare financial statements for each financial year. Under that law the Directors have elected to prepare the financial statements in accordance with International Financial Reporting Standards as adopted by the European Union (IFRS) and applicable law. Under Company law the Directors must prepare financial statements that give a true and fair view of the state of affairs of the Group and of the profit or loss of the Group for that period. In preparing these financial statements, the Directors are required to:

· Select suitable accounting policies and apply them consistently;

· Make judgements and accounting estimates that are reasonable and prudent;

· State whether the financial statements have been prepared in accordance with IFRS as adopted by the European Union; and

· Prepare the financial statements on the going concern basis unless it is inappropriate to presume that the Group will continue in business.

The Directors are responsible for keeping proper accounting records that are sufficient to show and explain the Group's transactions and disclose with reasonable accuracy at any time the financial position of the Group and enable them to endure that the financial statements comply with Companies (Jersey) Law 1991.

The Directors are also responsible for safeguarding the assets of the company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.

The Directors are responsible for the maintenance and integrity of the corporate and financial information included on the Group's website. The Group's website is maintained in accordance with AIM Rule 26.

Legislation in Jersey governing the preparation and dissemination of financial information may differ from legislation in other jurisdictions.

The Directors confirm that they have complied with all the above requirements in preparing these financial statements.

Statement of Disclosure to Auditors

As far as the Directors are aware, there is no relevant audit information of which the Group's auditor is unaware and each Director has taken all the steps that he ought to have undertaken as a director order to make himself aware of any relevant audit information and to establish that the Group's auditor is aware of that information.

Auditors

BDO LLP has indicated its willingness to continue in office, and a resolution that they are reappointed will be proposed at the next annual general meeting.

On behalf of the Board

Jeffrey Auld

Chief Executive Officer

20 March 2019

SERINUS ENERGY PLC

Serinus Energy plc (the "Company") is a Jersey incorporated company that holds investments in wholly owned subsidiaries, which hold the rights to oil and gas assets in the Group's countries of operation. The Group operates in Romania and Tunisia. The Company also holds investments in two directly held management companies, in Canada and the UK that provide management service to the Company and the Group and has a branch in Warsaw Poland that provides investor services.

The Company's shares were admitted to trading on the AIM market on May 18, 2018 and are listed on the Warsaw Stock Exchange ("WSE").

The following notes in the consolidated financial statements are of particular relevance to the Company:

· Note 15 and 3(l) - Share capital of the Company.

· Note 2 - Going concern

· Note 24 - Risk management

· Note 26 - Commitments

The Company does not have any significant operating transactions and as such the previous sections of this annual report, in particular the Outlook, Operations, Serinus' strategy sections and the CFO report, which details liquidity, capital resources, going concern and a financial review for 2018, all relate to the Company.

INDEPENDENT AUDITOR'S REPORT TO THE MEMBERS OF SERINUS ENERGY PLC

Opinion

We have audited the financial statements of Serinus Energy Plc (the 'Company) and its subsidiaries (the 'Group') for the year ended 31 December 2018 which comprise the consolidated statement of comprehensive income, the consolidated statement of financial position, the consolidated statement of cash flows, the consolidated statement of changes in equity and notes to the financial statements, including a summary of significant accounting policies.

The financial reporting framework that has been applied in the preparation of the group financial statements is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the European Union.

In our opinion:

• the financial statements give a true and fair view of the state of the Group's affairs as at 31 December 2018 and the Group's loss for the year then ended;

• the Group's financial statements have been properly prepared in accordance with IFRSs as adopted by the European Union; and

• the financial statements have been prepared in accordance with the requirements of the Companies (Jersey) Law 1991.

Basis for opinion

We conducted our audit in accordance with International Standards on Auditing UK (ISA (UK)) and applicable law. Our responsibilities under those standards are further described in the Auditor's responsibilities for the audit of the financial statements section of our report. We are independent of the Company and the Group in accordance with the ethical requirements that are relevant to our audit of the financial statements in the UK, including the FRC's Ethical Standard as applied to listed entities, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Material uncertainty related to going concern

We draw attention to Note 2 of the financial statements concerning the Group's ability to continue as a going concern. The matters explained in Note 2 relating to the waiver of compliance with loan covenants and the continued availability of existing loan facilities indicate the existence of a material uncertainty which may cast significant doubt over the Group's ability to continue as a going concern. These financial statements do not include the adjustments that would result if the Group is unable to continue as a going concern. Our opinion is not modified in respect of this matter.

We have highlighted going concern as a key audit matter based on our assessment of the significance of the risk and the effect on our audit strategy.

Our audit procedures in response to this key audit matter included:

· Assessing and sensitising key costs and income streams included in the Group cash flow forecast which have been prepared by Management for a period of twelve months from the date of approval of these financial statements

· Challenging and critiquing Managements' assumptions included in the cash flow forecast to evidence obtained during the course of our audit work and to publically available third party information in order to benchmark Managements' assessment

· Discussing with Management and the Board the Group's strategy to continue to ensure funds are available to the Group to fund its operations and fulfil the repayments under its debt obligations. Confirming statements made to publically available information and third party documentation where available

· Obtaining and reading documents which support the March 2019 fund raise

· Assessing, re-performing calculations and reviewing correspondence in respect of the terms and covenants relating to the Group's debt facilities including historical compliance and expected future compliance with covenants, and

· Reviewing and considered the adequacy of the disclosure within the financial statements relating to the Directors' assessment of the going concern basis of preparation.

Key audit matters

Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the financial statements of the current period and include the most significant assessed risks of material misstatement (whether or not due to fraud) we identified, including those which had the greatest effect on the overall audit strategy, the allocation of resources in the audit and directing the efforts of the engagement team. These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters.

In addition to the matter described in the Material uncertainty related to going concern section, we identified the following key audit matters:

• Carrying value of Development and Production assets, and

• Accounting for Decommissioning provisions.

Carrying value of Development and Production assets (see note 12)

Accounting standards require Management and the Directors to undertake an annual impairment review of the carrying value of development and production assets for any indicators of impairment. If indicators of impairment are identified Management and the Directors' must undertake a full impairment review to ensure the potential recoverable value of the assets is higher than the carrying value of the assets recorded on the balance sheet. Management have determined that there are no indicators of potential impairment were present. Given the materiality of the assets in the context of the Group's balance sheet, and the judgements involved we consider this to be a key audit matter.

Our response

Our specific audit testing in this regard included:

· Performing onsite visits to both the Tunisian and Romanian projects post year-end in order to gain a detailed understanding of the nature of the Group's operations

· Holding meetings with operational management whilst on site in order to be able to assess the operating activity and development of the assets undertaken in the year

· Considering Managements' and the Boards' conclusion that the Group continued to have two cash generating units ('CGU') against the requirements of the accounting standard

· Examining licence concession agreements and supporting documentation in order to assess that appropriate legal and beneficial ownership percentages had been considered by Management in their CGU assessment.

· Reviewing Management's impairment indicators assessment for each CGU against the criteria in the accounting standard in order to determine whether their assessment was complete and in accordance with the requirements of the accounting standard, and

· Performing an independent assessment of financial and non-financial data for potential impairment indicators.

As Management and the Board had identified that there were no impairment triggers present for either CGU we;

· Compared the actual operating performance for each CGU for the year back to Management's historic forecasts in order to assess whether the CGUs were operating in line with forecasts and in order to assess the Group's ability to forecast reliably

· Assessed the competence of Management's reserves report expert by reviewing the latest reserves report provided and comparing key model inputs to data obtained elsewhere during the course of the audit, third party publically available information in order to benchmark the assumptions applied by the expert.

· Discussed the experts report and our findings direct with Management's reserve report expert

· Obtained, reviewed and sensitised the key inputs in Management's Discounted Cash Flow (DCF) models, checking that the key inputs included in the models such as oil prices, reserves, capex, interest rates and discount rates were reasonable and within an acceptable range. Our work was undertaken in order to assess whether there were any potential impairment triggers highlighted in the models which had not previously been identified. Our work was undertaken using third party publically available and benchmark data to which we subscribe

· Tested the mathematical integrity of Management's model and ensured that the basis of preparation of the model was in line with our expectations and accepted valuation methodology for a discounted cashflow, and

· Reviewed and assessed the adequacy of the disclosures in the financial statements to ensure that they were prepared in accordance with the requirements of the accounting standard.

Accounting for Decommissioning provisions (see note 16)

Management have calculated and prepared the decommissioning provisions from available historic cost reports generated by third party experts. Such reports have been updated and related to asset specific events by Managements' internal expert who is considered to hold the relevant qualifications, knowledge and industry expertise for both of the Group's CGUs to ensure a reliable estimate of the Group's decommissioning provision is made.

Given the level of judgement and number of estimates which are required to be applied in estimating the Group's decommissioning liabilities we consider this to be a key audit matter.

Our response

Our specific audit testing in this regard included:

· Visiting both the Romanian and Tunisian operations and sighting the areas that form part of the Group's obligations to decommission their assets

· Discussing the future plans for decommissioning with operational management in order to assess whether the required works were appropriately reflected in the Group's decommissioning models

· Reviewing the historic, third party, reports on the decommissioning of the Group's assets in order to benchmark to publically available data the key inputs applied by the third party in determining the historic assessment made

· Assessing whether Management's internal expert had the expertise to perform the underlying calculations for the decommissioning provision included in the financial statements.

We also performed the following work:

o Confirm that the basis of the planned decommissioning work was in line with our understanding of the assets gained from our on-site visits

o Discussed with the internal expert the methodologies applied in the calculation and re-performed testing of calculations included within the model

o Read the licences for each asset and considered whether the Group's decommissioning plans adhered to the Tunisian and Romanian regulation, laws and licence requirements

o Verified unit costs included in the decommissioning provision calculation to supporting documentation where available

o Verified other key estimates such as inflation and discount rates back to empirical market data

o Verified the underlying mechanics of the decommissioning provision to ensure that movements related to work performed, unwinding of the discount rate and that changes in underlying estimates have been accounted for in the appropriate financial statement area.

Our application of materiality

Materiality

Basis for materiality

FY 2018

Group: $1.6m

1.3% of Total Assets

Total Assets was determined as an appropriate basis as the principal focus of the Group remains fundamentally focused on the development of its oil and gas assets within Romania and Tunisia.

We apply the concept of materiality both in planning and performing our audit and in evaluating the effect of misstatements. We consider materiality to be the magnitude by which misstatements, including omissions, could influence the economic decisions of reasonable users that are taken on the basis of the financial statements. Importantly, misstatements below these levels will not necessarily be evaluated as immaterial as we also take account of the nature of identified misstatements, and the particular circumstances of their occurrence, when evaluating their effect on the financial statements as a whole.

Performance materiality is the application of materiality at the individual account or balance level set at an amount to reduce to an appropriately low level the probability that the aggregate of uncorrected and undetected misstatements exceeds materiality for the financial statements as a whole. Performance materiality was set at 65% of the above materiality levels.

We agreed with the Audit Committee that we would report to the Committee all individual audit differences identified during the course of our audit in excess of $32,000.

Whilst materiality for the financial statements as a whole was $1.6 million, each significant component of the Group was audited to a lower level of materiality ranging from $0.2 million to $0.3 million which was used to determine the financial statement areas that were included within the scope of the Component audits and the extent of sample sizes used during the audit.

There were no misstatements identified during the course of our audit that were individually, or in aggregate, considered to be material in terms of their absolute monetary value or on qualitative grounds.

An overview of the scope of our audit

Our Group audit scope focused on the Group's principal operating locations being the projects based in Tunisian and Romanian. As a result we determined that there were two significant components and both of these were subject to a full scope audit. Together with the Group consolidation, which was also subject to a full scope audit, these represent the significant components of the Group.

The remaining components of the Group were considered non-significant and these components were principally subject to analytical review procedures, together with additional substantive testing over the risk areas detailed above where applicable to that component.

The audits of each of the significant components were principally performed in the geographical location of the project (Tunisia and Romania) by BDO member firms, the location of the Group head office (Canada) where Group work was performed as well as in the United Kingdom. All of the audits were conducted by BDO LLP and BDO member firms.

As part of our audit strategy, the Responsible Individual, component key audit partner and senior members of the audit team visited each of the principal operating locations and reviewed the detailed underlying work papers of the BDO Member Firms in Tunisia and Romania.

Other information

The Directors are responsible for the other information. The other information comprises the information included in the annual report, other than the financial statements and our auditor's report thereon. Our opinion on the financial statements does not cover the other information and, except to the extent otherwise explicitly stated in our report, we do not express any form of assurance conclusion thereon.

In connection with our audit of the financial statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained in the audit or otherwise appears to be materially misstated. If we identify such material inconsistencies or apparent material misstatements, we are required to determine whether there is a material misstatement in the financial statements or a material misstatement of the other information. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.

Opinion on other matters prescribed by the regulations of the Warsaw Stock Exchange

In our opinion, the information contained in the Directors' Report on the Group's activities complies with the requirements of the regulations of the Warsaw Stock Exchange issuers and is consistent with the information presented in the accompanying consolidated financial statements.

Based on our knowledge obtained during the audit about the Group and its environment we have identified no material misstatements in the Directors' Report on the Group's activities.

The Company's Management and members of its Audit Committee are responsible for the preparation of a declaration on the application of corporate governance in accordance with regulations of the Warsaw Stock Exchange.

In connection with our audit of the consolidated financial statements it was our responsibility to read the declaration on the application of corporate governance, constituting a separate section of the Annual Report.

In our opinion, the declaration on the application of corporate governance contains all information specified in paragraph 70 section 6 point 5 of the Minister's of Finance Decree of 29 March 2018 on the current and periodic information provided by the issuers of securities and on the conditions for recognising as equally valid the information required by the regulations of a state that is not a member state (2018 Journal of Laws, item 757).

Information provided in paragraph 70 section 6 point 5 letters c-f, h and i of the regulations contained in the statement on the application of corporate governance are in accordance with the applicable regulations and information contained in the annual consolidated financial statements.

Matters on which we are required to report by exception

We have nothing to report in respect of the following matters in relation to which the Companies (Jersey) Law 1991 requires us to report to you if, in our opinion:

• adequate accounting records have not been kept, or returns adequate for our audit have not been received from branches not visited by us; or

• the Company's financial statements are not in agreement with the accounting records and returns; or

• we have not received all the information and explanations we require for our audit.

Responsibilities of Directors

As explained more fully in the Directors' responsibilities statement, the Directors are responsible for the preparation of the financial statements and for being satisfied that they give a true and fair view, and for such internal control as the Directors determine is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, the Directors are responsible for assessing the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the group or the parent company or to cease operations, or have no realistic alternative but to do so.

Auditor's responsibilities for the audit of the financial statements

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs UK will always detect a material misstatement when it exists.

Misstatements can arise from fraud or error and are considered material if, individually or in the

aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements.

A further description of our responsibilities for the audit of the financial statements is located on the Financial Reporting Council's website at: www.frc.org.uk/auditorsresponsibilities. This description forms part of our auditor's report.

Use of our report

This report is made solely to the Company's members, as a body, in accordance Article 113A of the Companies (Jersey) Law 1991. Our audit work has been undertaken so that we might state to the Company's members those matters we are required to state to them in an auditor's report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the Company and the Company's members as a body, for our audit work, for this report, or for the opinions we have formed.

Anne Sayers

For and on behalf of BDO LLP, Chartered Accountants

London, UK

20 March 2019

BDO LLP is a limited liability partnership registered in England and Wales (with registered number OC305127).

Serinus Energy plc

Consolidated Statement of Comprehensive Income for the year ended 31 December 2018

(US 000s)

	Note	2018	2017

Revenue, net of royalties	5	7,849	5,889

Cost of sales
Production expenses		(3,044)	(5,250)
Depletion and depreciation	12	(1,801)	(1,866)
Total cost of sales		(4,845)	(7,116)

Gross profit (loss)		3,004	(1,227)

Total administrative expenses		(3,422)	(3,005)
Share-based payment expense	6	(820)	(691)
Impairment of oil and gas assets	12	-	(4,981)
Decommissioning provision recovery (expense)	16	316	(1,155)
Well incident recovery (expense)	7	3,602	(4,047)
Gain on disposal of subsidiary	7	-	2,179
Gain on disposal of property, plant and equipment	12	117	-
Listing costs	7	(1,377)	(705)

Operating profit (loss)		1,420	(13,632)

Finance expense	8	(4,567)	(3,667)

Loss before tax		(3,147)	(17,299)

Taxation	9	(1,743)	(1,493)

Loss for the year		(4,890)	(18,792)

Loss per share:
Basic and diluted	10	(0.03)	(0.13)

The accompanying notes on pages 45 to 74 form part of the consolidated financial statements

Serinus Energy plc

Consolidated Statement of Financial Position as at 31 December 2018

(US 000s)

	Note	2018	2017

Non-current assets
Property, plant and equipment	12	107,541	99,578

Current assets
Restricted cash	13	1,054	1,098
Trade receivables and other	14	10,143	6,690
Cash and cash equivalents		2,283	7,252
		13,480	15,040

Total assets		121,021	114,618

Equity
Share capital	15	375,208	362,534
Share-based payment reserve		23,307	22,487
Accumulated deficit		(385,173)	(381,317)

Total equity		13,342	3,704

Liabilities
Non-current liabilities
Decommissioning provision	16	36,573	36,866
Deferred tax liability	17	13,154	13,500
Long-term debt	18	27,667	31,261
Other provisions	19	1,367	1,747
		78,761	83,374

Current liabilities
Decommissioning provision	16	8,696	8,815
Current portion of long-term debt	18	5,624	-
Accounts payable and accrued liabilities	20	14,598	18,725
		28,918	27,540

Total liabilities		107,679	110,914

Total equity and liabilities		121,021	114,618

The accompanying notes on pages 45 to 74 form part of the consolidated financial statements

These consolidated financial statements were approved by the Board of Directors and authorized for issue on 20 March 2019 and were signed on its behalf by:

ELEANOR BARKER

DIRECTOR, CHAIR OF THE AUDIT COMMITTEE

JEFFREY AULD

DIRECTOR, PRESIDENT AND CEO

Serinus Energy plc

Consolidated Statement of Shareholder's Equity for the year ended 31 December 2018

(US 000s)

	Note	Share capital	Share-based payment reserve	Accumulated deficit	Total
Balance at 31 December 2016		344,479	21,796	(362,525)	3,750
Comprehensive loss for the year		-	-	(18,792)	(18,792)
Transactions with equity owners
Share issue, net of issue costs	15	18,055	-	-	18,055
Share-based payment expense	6	-	691	-	691
Balance at 31 December 2017		362,534	22,487	(381,317)	3,704
Comprehensive loss for the year		-	-	(4,890)	(4,890)
Adjustment on initial application of IFRS 9	3	-	-	1,034	1,034
Transactions with equity owners
Share issue, net of issue costs	15	12,674	-	-	12,674
Share-based payment expense	6	-	820	-	820
Balance at 31 December 2018		375,208	23,307	(385,173)	13,342

The accompanying notes on pages 45 to 74 form part of the consolidated financial statements

Serinus Energy plc

Consolidated Statement of Cash Flows for the year ended 31 December 2018

(US 000s)

	Note	2018	2017
Operating activities
Loss for the year		(4,890)	(18,792)
Items not involving cash:
Depletion and depreciation	12	1,801	1,866
Impairment	12	-	4,981
Decommissioning provision (recovery) expense	16	(316)	1,155
Gain on disposal of subsidiary	7	-	(2,179)
Gain on disposal of property, plant and equipment	12	(117)	-
Accretion expense	8	1,030	684
Share-based payment expense	6	820	691
Shares issued as compensation		-	7
Unrealized loss on investments		-	13
Foreign exchange loss unrealized		211	12
Change in other provisions	19	(49)	599
Current tax expense	9	2,089	1,303
Deferred tax (recovery) expense	9	(346)	190
Interest expense	8	3,493	2,919
Income taxes paid		(2,540)	(63)
Expenditures on decommissioning liabilities	16	(30)	-
Funds from (used in) operations		1,156	(6,614)
Changes in non-cash working capital	23	(7,069)	2,389
Cashflows (used in) operating activities		(5,913)	(4,225)

Financing activities
Ordinary shares issued	15	13,475	19,105
Share issue costs	15	(801)	(1,057)
Repayment of long-term debt	23	-	(1,667)
Interest and financing fees	23	(436)	(754)
Cashflows from (used in) financing activities		12,238	15,627

Investing activities
Exploration and development expenditures	12	(11,396)	(8,551)
Change in restricted cash	13	(44)	64
Proceeds on disposal of property, plant and equipment	12	117	-
Proceeds on disposal of investment		-	54
Cashflows used in investing activities		(11,323)	(8,433)

Impact of foreign currency translation on cash		29	(14)

Change in cash and cash equivalents		(4,969)	2,955
Cash and cash equivalents, beginning of year		7,252	4,297
Cash and cash equivalents, end of year		2,283	7,252

The accompanying notes on pages 45 to 74 form part of the consolidated financial statements

Notes to the Consolidated Financial Statements

For the years ended 31 December 2018 and 2017

(US 000s, unless otherwise noted)

1. General information

Serinus Energy plc (the "Company") and its subsidiaries ("Serinus" or the "Group") is principally engaged in the exploration for and development of oil and gas properties in Tunisia and Romania. The Company is incorporated under the Companies (Jersey) Law 1991. The Company's head office and registered office is located at 28 Esplanade, St. Helier, Jersey, JE1 8SB.

Effective 3 May 2018 the Company continued from Alberta, Canada, to Jersey, Channel Islands. In connection with the continuance, the Company changed its name from Serinus Energy Inc. to Serinus Energy plc and adopted new charter documents. On 18 May 2018, the Company listed on the Alternative Investment Market ("AIM") of the London Stock Exchange. The Company then delisted from the Toronto Stock Exchange ("TSX") on 22 May 2018, retaining its listings on the Warsaw Stock Exchange ("WSE") and AIM.

Serinus is a publicly listed company whose ordinary shares are traded under the symbol "SENX" on AIM and "SEN" on the WSE. Kulczyk Investments, S.A. ("KI") holds a 38.77% investment in Serinus as of 31 December 2018.

The consolidated financial statements for Serinus include the accounts of the Company and its subsidiaries for the years ended 31 December 2018 and 2017.

2. Basis of presentation

The principal accounting policies adopted in the preparation of the consolidated financial statements are set out below. The policies have been consistently applied to all years presented, unless otherwise stated. The consolidated financial statements have been prepared on a historical cost basis except as noted in the accompanying accounting policies.

The consolidated financial statements of the Group for the 12 months ended 31 December 2018 have been prepared in accordance with International Financial Reporting Standards ("IFRS") and their interpretations issued by the International Accounting Standards Board ("IASB") as adopted by the European Union ("EU").

These consolidated financial statements are expressed in U.S. dollars unless otherwise indicated. All references to US$ are to U.S. dollars. All financial information is rounded to the nearest thousands, except per share amounts and when otherwise indicated.

Going concern

These consolidated financial statements have been prepared on a going concern basis, which assumes that Serinus will continue its operations for the foreseeable future and will be able to realize its assets and discharge its liabilities and commitments in the normal course of operations.

The Group meets its day-to-day working capital requirements from net operating cash flows, cash balances, equity, and fully drawn debt facilities (Senior and Convertible loans from the EBRD of $5.5 million and $29.1 million respectively (see note 18). As at 31 January 2019 the group had cash balances of $3.5 million.

The Group is faced with financial difficulties stemming from the delay in commencing production in Romania. Due to the continued focus on finalization of the gas plant, the Group has not yet been in a position to undertake planned work in Tunisia, including the reopening of the Chouech Es Saida field in southern Tunisia. The resulting impact of the delay in the Romanian production and the delay in Tunisian plans has severely impacted the Group's planned cash flows.

Equity was issued in May 2018 raising net proceeds of $12.7 million to enable the Group to complete construction of a gas plant in Romania, into which two existing wells would be tied in and produced. To date, these proceeds have primarily been used to fund the completion of the gas plant, drill the Moftinu-1007 well, which replaced the Moftinu-1001 well which suffered a blow out in December 2017, and drill the Moftinu-1003 well. The Group has claimed insurance proceeds in relation to the Moftinu-1007 well and has received $3.0 million subsequent to 31 December 2018.

The Group's $5.5 million Senior loan is due to be repaid in two equal instalments of $2.7 million each on 31 March 2019 and 30 September 2019. The Group's $29.1 million convertible loan accumulates interest to 30 June 2020 at which point the outstanding amount is repayable in four equal instalments on 30 June 2020, 2021, 2022 and 2023 and interest after 30 June 2020 is to be paid annually on the loan repayment dates. Both loans are subject to covenants. Those covenants were not tested at 31 December 2017 as they were not in effect at that date due to a covenant holiday obtained on debt renegotiation. As at 31 December 2018, the Company was not in compliance with the debt service coverage ratio for the three months ended 31 December 2018. On 21 December 2018, the Company received a waiver from the EBRD formally waiving compliance with this covenant for the period ended 31 December 2018. The implication of this waiver is that the debt repayments will follow their original scheduled repayment terms and the bank will not be acting on its security as a result of the breach.

In assessing the Group's ability to continue as a going concern, the Directors have prepared base and sensitized cash flow forecasts for a period in excess of 12 months from the date of authorization of these financial statements.

Base case forecasts indicate that the Group will breach the EBRD covenants at 31 March 2019 and for the foreseeable future, the result of which is that the Senior and Convertible loans will become repayable on demand at the discretion of the bank. The Directors intend to seek waiver of those covenants and the continued availability of those existing loan facilities represents a material uncertainty.

The Group has secured equity of $3.0 million in March 2019 to bridge a short term financing need to fund a scheduled debt repayment due 31 March 2019.

The key assumptions in the base case forecasts are the timing of the start of commercial production in Romania, the field's post-commissioning performance and the ability to reopen the Chouech Es Saida field in Tunisia, as set out above, and commodity prices. The base case forecasts indicate that the Group will be able to operate within the existing loan facilities, should they remain available. Should the base case forecasts be negatively impacted by a downward revision in key assumptions, there is the possibility that the Group will not be able to meet obligations as they come due.

The Directors consider that the continued availability of the existing facilities, but with forecast potential breaches of loan covenants represents a material uncertainty that may cast significant doubt on the ability of the Group to continue as a going concern. These consolidated financial statements do not reflect the adjustments and classifications of assets, liabilities, revenues and expenses which would be necessary if the Group were unable to continue as a going concern.

3. Significant accounting policies

(a) Principles of consolidation

The consolidated financial statements include the results of the Company and all subsidiaries. Subsidiaries are entities over which the Company has control. All intercompany balances and transactions, and any unrealized gains or losses arising from intercompany transactions are eliminated upon consolidation. Serinus has four directly held subsidiaries, Serinus Energy Canada Inc. ("Serinus Canada"), Serinus Holdings Limited ("Serinus Holdings"), Serinus Petroleum Consultants Limited ("Serinus Petroleum") and Serinus B.V. ("Serinus B.V.). Through Serinus Holdings, the Company has the following indirect wholly-owned subsidiaries, Kulczyk Oil Brunei Limited and AED South East Asia Ltd., which held the Company's interests in Brunei Block L, and KOV Borneo Limited, which held the Company's interest in Brunei Block M. Through Serinus B.V., Serinus has one wholly-owned subsidiary Serinus Tunisia B.V. ("Serinus Tunisia") and 99.9995% of Serinus Energy Romania S.A. ("Serinus Romania"). Serinus Tunisia owns the remaining 0.0005% of Serinus Romania.

Some of the Group's activities are conducted through jointly controlled assets. The consolidated financial statements therefore include the Group's share of these assets, associated liabilities and cashflows in accordance with the term of the arrangement. The Group's associated share of revenue, cost of sales and operating costs are recorded within the statement of comprehensive income.

Basis of consolidation

Where the Group has control over an investee, its classified as a subsidiary. The Group controls an investee if all three of the following elements are present: power over the investee, exposure to variable returns from the investee and the ability of the investor to use its power to affect those variable returns. Control is reassessed whenever facts and circumstances indicate that there may be a change in any of these elements of control.

De-facto control exists in situations where the Group has the practical ability to direct the relevant activities of the investee without holding the majority of the voting rights. In determining whether de-facto control exists the Group considers all relevant facts and circumstances, including:

· The size of the Group's voting rights relative to both the size and dispersion of other parties who hold voting rights;

· Substantive potential voting rights held by the Group and by other parties;

· Other contractual arrangements;

· Historic patterns in voting attendance.

The consolidated financial statements present the results of the Group is if they formed a single entity. Intercompany transactions and balances between group companies are therefore eliminated in full.

The consolidated financial statements incorporate the results of business combinations using the acquisition method. In the statement of financial position, the acquiree's identifiable assets, liabilities and contingent liabilities are initially recognized at their fair values at the acquisition date. The results of acquired operations are included in the consolidated statement of comprehensive income from the date on which control is obtained. They are deconsolidated from the date on which control ceases.

(b) Segment information

Operating segments have been determined based on the nature of the Group's activities and the geographic locations in which the Group operates and are consistent with the level of information regularly provided to and reviewed by the Group's chief operating decision makers.

i. Foreign currency transactions

Transactions in foreign currencies are translated to the Group's functional currency at exchange rates at the dates of the transactions. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency at the year-end exchange rate. Non-monetary assets and liabilities denominated in foreign currencies that are measured at fair value are translated to the functional currency at the exchange rate at the date that the fair value was determined. Foreign currency differences arising on translation are recognized in profit or loss.

ii. Foreign currency translation

In preparing the Group's consolidated financial statements, the financial statements of each entity are translated into U.S. dollars, the presentational currency of the Group. The assets and liabilities of foreign operations that do not have a functional currency of US dollars, are translated into US dollars using exchange rates at the reporting date. Revenues and expenses of foreign operations are translated into US dollars using foreign exchange rates that approximate those on the date of the underlying transaction. Significant foreign exchange differences are recognized in Other Comprehensive Income.

(d) Revenue recognition

The Group earns revenue from the sale of crude oil, natural gas and natural gas liquids, with a portion of crude oil sales required to be sold to local markets in Tunisia. Royalties are recorded at the time of production.

i. Crude oil, natural gas and natural gas liquids recognition

Revenue from the sale of crude oil, natural gas and natural gas liquids is recorded when performance obligations are satisfied. Performance obligations associated with the sale of crude oil are satisfied at the point in time when the products are delivered to the loading terminal and the volumes and prices have been agreed upon with the customer, which is considered to be the point at which the Group transfers control of the product to the customer. Performance obligations associated with the sale of natural gas and natural gas liquids are satisfied upon delivery at the respective concession delivery points, which is where the purchasers obtain control.

Crude oil sales prices are determined by benchmarking to the Brent crude oil price index less a fixed discount per bbl when the performance obligation is satisfied. Revenue is stated net of royalties.

ii. Local crude oil recognition

The Tunisian government has the right to purchase up to a maximum 20% of the crude oil production from the Sabria concession, to be sold into the local market at an approximate 10% discount to the price obtained on other crude oil sales. This arrangement is considered to be outside the scope of IFRS 15 due to failing the commercial substance criteria test in the standard. The risks and rewards associated with this revenue are transferred when the product is delivered to the customer. There are no minimum or maximum volume requirements, only that 20% of the volume delivered for lifting is required to be sold to the local market.

(e) Share-based compensation

The Company reflects the economic cost of awarding share options to employees and Directors by recording an expense in the Consolidated Statement of Comprehensive Income equal to the fair value of the benefit awarded. The expense is recognized in the Consolidated Statement of Comprehensive Income over the vesting period of the award. Fair value is measured by use of a Black-Scholes model which takes into account conditions attached to the vesting and exercise of the equity instruments. The expected life used in the model is adjusted, based on management's best estimate, for the effects of non-transferability, exercise restrictions and behavioral considerations.

(f) Taxes

Current and deferred income taxes are recognized in profit (loss), except when they relate to items that are recognized directly in equity or other comprehensive income, in which case the current and deferred taxes are also recognized directly in equity or other comprehensive income, respectively. When current income tax or deferred income tax arises from the initial accounting for a business combination, the tax effect is included in the accounting for the business combination.

Current income taxes are measured at the amount expected to be paid to or recoverable from the taxation authorities based on the income tax rates and laws that have been enacted at the end of the reporting period.

The Group follows the balance sheet method of accounting for deferred income taxes, where deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates expected to apply when the assets are realized, or the liabilities are settled. Deferred income tax balances are adjusted for any changes in the enacted or substantively enacted tax rates and the adjustment is recognized in the period that the rate change occurs.

Deferred income tax liabilities are generally recognized for all taxable temporary differences. Deferred income tax assets are recognized to the extent that it is probable future taxable profits will be available against which the temporary differences can be utilized. The carrying amount of deferred income tax assets is reviewed at the end of each reporting period and reduced to the extent that it is no longer probable that sufficient taxable income will be available to allow all or part of the asset to be recovered. Deferred income tax assets and liabilities are only offset where they arise within the same entity and tax jurisdiction. Deferred income tax assets and liabilities are presented as non-current.

(g) Cash and cash equivalents and Restricted cash

Cash and cash equivalents include short-term investments such as term deposits held with banks or similar type instruments with a maturity of three months or less. Restricted cash is comprised of cash held in trust by a financial institution for the benefit of a third party as a guarantee that certain work commitments will be met. Once the work commitments are met, the restricted cash is released from the trust and returned to cash.

(h) Financial instruments

Financial instruments are recognized when the Group becomes a party to the contractual provisions of the instrument and are subsequently measured at amortized cost. The Group characterizes its fair value measurements into a three-level hierarchy depending on the degree to which the inputs are observable, as follows:

Level 1 inputs are quoted prices in active markets for identical assets and liabilities;

Level 2 inputs are inputs, other than quoted prices included within Level 1, that are observable for the asset or liability either directly or indirectly; and

Level 3 inputs are unobservable inputs for the asset or liability.

Classification and measurement of financial assets

The initial classification of a financial asset depends upon the Group's business model for managing its financial assets and the contractual terms of the cash flows. There are three measurement categories into which the Group classified its financial assets:

i. Amortized costs: includes assets that are held within a business model whose objective is to hold assets to collect contractual cash flows and its contractual terms give rise on specified dates to cashflows that represent solely payments of principal and interest;

ii. Fair value through other comprehensive income ("FVOCI"): includes assets that are held within a business model whose objective is achieved by both collecting contractual cash flows and selling the financial assets, where its contractual terms give rise on specified dates to cash flows that represent solely payments of principal and interest; or

iii. Fair value through profit or loss ("FVTPL"): includes assets that do not meet the criteria for amortized cost or FVOCI and are measured at fair value through profit or loss.

The Group's cash and cash equivalents, restricted cash, and trade receivables and other receivables are measured at amortized cost.

Trade receivables and other receivables are initially measured at fair value. The Group holds trade receivables and other receivables with the objective to collect the contractual cash flows and therefore measures them subsequently at amortized cost. Trade receivables and other receivables are presented as current assets as collection is expected within 12 months after the reporting period.

The Group has no financial assets measured at FVOCI or FVTPL.

Impairment of financial assets

The Group recognizes loss allowances for expected credit losses ("ECLs") on its financial assets measured at amortized cost. Due to the nature of its financial assets, the Group measures loss allowances at an amount equal to the lifetime ECLs. Lifetime ECLs are the anticipated ECLs that result from all possible default events over the expected life of a financial asset. ECLs are a probability-weighted estimate of credit losses.

Classification and measurement of financial liabilities

A financial liability is initially classified as measured at amortized cost or FVTPL. A financial liability is classified as measured at FVTPL if it is held-for-trading, a derivative or designated as FVTPL on initial recognition.

The Group's accounts payable and accrued liabilities and long-term debt are measured at amortized cost.

Accounts payable and accrued liabilities are initially measured at fair value and subsequently measured at amortized cost. Accounts payable and accrued liabilities are presented as current liabilities unless payment is not due within 12 months after the reporting period.

Long-term debt is initially measured at fair value, net of transaction costs incurred. The contractual cash flows of the long-term debt are subsequently measured at amortized cost. Long-term debt is classified as current when payment is due within 12 months after the reporting period.

The Group has no financial liabilities measured at FVTPL.

(i) Exploration and evaluation and Property, plant and equipment

i. Exploration and evaluation ("E&E") expenditures

Pre-license costs are costs incurred before the legal rights to explore a specific area have been obtained. These costs are expensed in the period in which they are incurred.

Exploration and evaluation costs, including the costs of acquiring licenses and directly attributable general and administrative costs, are capitalized as exploration and evaluation assets. The costs are accumulated in cost centers by well, field or exploration area pending determination of technical feasibility and commercial viability.

Exploration and evaluation assets are assessed for impairment when (i) facts and circumstances suggest that the carrying amount exceeds the recoverable amount, or (ii) sufficient data exists to determine technical feasibility and commercial viability, and the assets are to be reclassified. For purposes of impairment testing, exploration and evaluation assets are grouped by concession or license area.

The technical feasibility and commercial viability of extracting a resource is considered to be determinable based on several factors including the assignment of proved or probable reserves. A review of each exploration license or field is carried out, at least annually, to ascertain whether the project is technically feasible and commercially viable. Upon determination of technical feasibility and commercial viability, exploration and evaluation assets attributable to those reserves are first tested for impairment and then reclassified from exploration and evaluation assets to a separate category within property, plant and equipment referred to as oil and natural gas interests.

ii. Development and production costs

Items of property, plant and equipment, which include oil and gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Development and production assets are grouped into cash generating units ("CGU") for impairment testing and categorized within property and equipment as oil and natural gas interests. Property, plant and equipment is comprised of drilling and well servicing assets, office equipment and other corporate assets. When significant parts of an item of property, plant and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (major components).

Gains and losses on disposal of an item of property, plant and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and are recognized within profit or loss.

iii. Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are capitalized only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized costs generally represent costs incurred in developing proved and/or probable reserves and bringing in or enhancing production from such reserves and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in profit or loss as incurred.

iv. Depletion and depreciation

The net carrying value of development or production assets is depleted using the unit-of-production method based on estimated proved and probable reserves, taking into account future development costs, which are estimated costs to bring those reserves into production. For purposes of the depletion assessment, petroleum and natural gas reserves are converted to a common unit of measurement on the basis of their relative energy content where six thousand cubic feet of natural gas equates to one barrel of oil.

Certain of the Group's assets are not depleted based on the unit of production method as they relate to infrastructure, corporate and other assets. Such plant and equipment items are recorded at cost and are depreciated over the estimated useful lives of the asset using the declining balance basis at rates ranging from 20% to 45%. The expected lives of other plant and equipment are reviewed on an annual basis and, if necessary, changes in expected useful lives are accounting for prospectively.

v. Impairment

The carrying amounts of the Group's property, plant and equipment are reviewed whenever events or changes in circumstances indicate that that the carrying value of an asset may not be recoverable and at a minimum at each reporting date. For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (the cash generating unit or "CGU"). The Group's CGU's generally align with each concession or production sharing contract. The recoverable amount is then estimated. The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell.

Value-in-use is generally computed as the present value of the future cash flows, discounted to present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset, expected to be derived from production of proved and probable reserves.

An impairment loss is recognized if the carrying amount of an asset or a CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGU's are allocated first to reduce the carrying amount of any goodwill allocated to the unit and then to reduce the carrying amounts of the other assets in the unit on a pro rata basis.

An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization if no impairment loss had been recognized.

vi. Corporate assets

Corporate assets consist primarily of office equipment, computer hardware and leasehold improvements. Depreciation of office equipment and computer hardware is provided over the useful life of the assets on the declining balance basis between 20% and 45% per year. Leasehold improvements are depreciated on a straight-line basis over the term of the lease.

(j) Provisions

i. General

A provision is recognized if, as a result of a past event, the Group has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

ii. Decommissioning provisions

Decommissioning provisions include legal or constructive obligations where the Group will be required to retire tangible long-lived assets such as well sites and processing facilities. The amount recognized is the present value of estimated future expenditures required to settle the obligation using the risk-free interest rate associated with the type of expenditure and respective jurisdiction. A corresponding asset equal to the initial estimate of the liability is capitalized as part of the related asset and depleted to expense over its useful life. The obligation is accreted until the date of expected settlement of the retirement obligation and is recognized within financial costs in the statement of comprehensive income (loss).

Changes in the estimated liability resulting from revisions to the estimated timing or amount of undiscounted cash flows or the discount rates are recognized as changes in the decommissioning provision and related asset. Actual expenditures incurred are charged against the provision to the extent the provision was established.

(k) Long-term debt

Long-term debt is classified as a financial liability or equity instrument in accordance with the substance of the contractual arrangement. In determining whether a financial instrument is a financial liability rather than an equity instrument, the following conditions must both be met:

i. The instrument includes a contractual obligation to deliver cash or another financial asset, or to exchange financial assets and financial liabilities under conditions that are potentially unfavourable.

ii. If the instrument will or may be settled in equity instruments it is a non-derivative that includes a contractual obligation to deliver a variable number of equity instruments, or a derivative that will be settled by exchanging a fixed amount of cash or another financial asset for a fixed number of equity instruments.

Long-term debt that contains a conversion feature is assessed using the criteria above. If the conversion feature fails to meet the definition of an equity instrument it is classified as a derivative liability. Derivative liabilities are recorded at their fair value each reporting period with changes recognized in profit or loss.

(l) Share capital

Ordinary shares are classified as equity. Incremental costs directly attributable to the issuance of ordinary shares and share options are recognized as a deduction from equity, net of any tax effects.

(m) Dividends

To date the Company has not paid a dividend and does not anticipate paying dividends in the foreseeable future. Should the Company decide to pay dividends in the future, it would need to satisfy certain liquidity tests as established in the Companies (Jersey) Law 1991.

(n) Changes to accounting policies

i. IFRS 15 Revenue from Contracts with Customers

Serinus has adopted IFRS 15 Revenue from Contracts with Customers ("IFRS 15") on 1 January 2018, using the modified retrospective transition approach. Management has reviewed its revenue streams and major contracts with customers, using the IFRS 15 principles-based five step model. The adoption of this standard did not have a material impact on the Group's consolidated financial statements.

Disclosure requirements prescribed under IFRS 15 are provided in note 5.

ii. IFRS 9 Financial Instruments

Serinus adopted IFRS 9 Financial Instruments ("IFRS 9") on 1 January 2018. IFRS 9 sets out requirements for recognizing and measuring financial assets, financial liabilities and some contracts to buy or sell non-financial items. This standard replaces IAS 39 Financial Instruments: Recognition and Measurement ("IAS 39").

Serinus applied IFRS 9 retrospectively but elected not to restate comparative information. As such the comparative information provided continues to be accounted for in accordance with the Group's previous accounting policy as disclosed in the annual consolidated financial statements for the year ended 31 December 2017.

On 1 January 2018, the Group:

· Identified the business model used to manage its financial assets and classified its financial instruments into the appropriate IFRS 9 category;

· Applied the 'expected credit loss' ("ECL") model to financial assets classified as measured at amortized cost.

The following table shows the original measurement categories under IAS 39 and the new measurement categories under IFRS 9 as at 1 January 2018 for each class of the Group's financial assets and financial liabilities.

	Measurement Category
Financial Instrument	IAS 39	IFRS 9
Cash and cash equivalents	Loans and receivables	Amortized cost
Accounts receivable	Loans and receivables	Amortized cost
Restricted cash	Loans and receivables	Amortized cost
Accounts payable and accrued liabilities	Financial liabilities measured at amortized cost	Amortized cost
Long-term debt	Financial liabilities measured at amortized cost	Amortized cost

The classification and measurement of financial instruments under IFRS 9 did not result in any adjustments to the Group's opening retained earnings as at 1 January 2018 except for an adjustment for debt modifications as the Group renegotiated the repayment terms on its long-term debt, effective 31 October 2017. Under IFRS 9, the amortized cost of the financial liability must be recalculated as the present value of the estimated future contractual cash flows that are discounted at the original effective interest rate. The difference in the carrying amount and the calculated amount is recognized in profit and loss.

The Group calculated a modification loss of $0.4 million on the Senior Loan, and a modification gain of $1.4 million on the Convertible Loan. A net $1.0 million modification gain was recorded as a decrease to long-term debt and an increase to opening retained earnings as at 1 January 2018. The impact on the consolidated statement of financial position is shown below:

As at:

31 December 2017

Adjustments

1 January

2018

Long-term debt

31,261

(1,034)

30,227

Accumulated deficit

(381,317)

1,034

(380,283)

iii. IFRS 2 Share-based Payment

The IASB issued amendments to IFRS 2 Share-based payment, effective 1 January 2018, relating to classification and measurement of particular share-based payment transactions. The adoption of this revision did not have a material impact on the Group's consolidated financial statements.

iv. IFRIC 22 Foreign Currency Transactions and Advance Consideration

The IASB issued IFRIC 22 Foreign Currency Transactions and Advance Consideration, effective 1 January 2018, to provide requirements about which exchange rate to use in reporting foreign currency transactions when payment is made or received in advance. The adoption of this standard did not have a material impact on the Group's consolidated financial statements.

(o) Accounting standards issued but not yet applied

IFRS 16 Leases

In January 2016, the IASB issued IFRS 16 "Leases" ("IFRS 16"), which requires entities to recognize assets and lease obligations on the statement of financial position. For lessees, IFRS 16 removes the classification of leases as either operating leases or finance leases, effectively treating all leases as finance leases. Certain short-term leases (less than 12 months) and leases of low-value assets are exempt from the requirements and may continue to be treated as operating leases. Lessors will continue with a dual lease classification model. Classification will determine how and when a lessor will recognize lease revenue and what assets would be recorded.

IFRS 16 is effective for years beginning on or after 1 January 2019 with early adoption permitted if IFRS 15 "Revenue From Contracts With Customers" has been adopted. The standard shall be applied retrospectively to each period presented or using a modified retrospective approach where the Group recognizes the cumulative effect as an adjustment to the opening retained earnings and applies the standard prospectively. The Group plans to adopt IFRS 16 effective 1 January 2019, using the modified retrospective approach, and apply several of the practical expedients available such as low-value and short-term exemptions.

The Group has completed identifying and gathering contracts that fall into the scope of the standard and has completed analyzing and calculating the impact of these contracts. The impact on the consolidated statement of financial position is shown below:

As at:

31 December 2018

Adjustments

1 January

2019

Non-current assets

107,541

852

108,393

Non-current liabilities

(78,761)

(852)

(79,613)

As at 31 December 2018, the Group had operating lease commitments of $1.4 million (see note 26). Of these commitments, approximately $0.4 million relate to short-term and low-value leases which will be recognized on a straight-line basis in profit or loss.

On 1 January 2019, for the remaining lease commitments, the Group expects to recognize a lease liability of $0.9 million for leases previously classified as operating leases. The Group will recognize a right-of-use asset of $0.9 million, electing to measure the right-of-use assets at an amount equal to the lease liability as prescribed in the modified retrospective approach.

The right-of-use assets will be included in property, plant and equipment, and will be depreciated on a straight-line basis over the lease term. The lease liability will be included in other provisions at its net present value and will be accreted until the end of the lease term. The Group anticipates that profit (loss) before tax will decrease by approximately $0.2 million for 2019 as a result of adopting the new rules.

Cashflows from operating activities will increase by approximately $0.5 million for 2019 due to the principal repayments of the lease liability being classified as cash flows used in financing activities.

4. Use of estimates and judgments

The preparation of financial statements in conformity with IFRS requires management to make judgements, estimates and assumptions based on currently available information that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Estimates and judgements are evaluated and are based on managements' experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. However actual results could differ from these estimates. By their very nature, these estimates are subject to measurement uncertainty and the effect on the financial statements of future periods could be material. Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.

Significant estimates and judgments made by management in the consolidated financial statements are described below:

(a) Oil and gas reserves

Measurements of depletion, depreciation, impairment, decommissioning provisions and business acquisitions are determined in part based on the Group's estimate of oil and gas reserves and resources. The process of determining reserves is complex and involves the exercise of professional judgement. All reserves have been evaluated at 31 December 2018 by independent qualified reserves evaluators. All significant judgments are based on available geological, geophysical, engineering, and economic data. These judgments are based on estimates and assumptions that may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserve estimates are based on current production forecasts, prices and economic conditions. As circumstances change and additional data becomes available, reserve estimates also change. Estimates made are reviewed and revised, either upward or downward, as warranted by the new information. Revisions are often required due to changes in well performance, prices and economic conditions. Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and gas prices and reservoir performance. Such revisions could be material and result in either positive or negative amounts.

The cash flow model used to value oil and gas properties incorporates estimates of future commodity prices. Generally, the pricing assumptions used are those of the external reserve engineer adjusted for differentials specific to the Group. Commodity prices can fluctuate for a variety of external reasons including supply and demand fundamentals, inventory levels, exchange rates, weather, and economic and geopolitical factors as well as internal reasons including quality differentials.

(b) Assumed 100% interest in the Satu Mare concession

The Group currently holds a deemed 100% interest in the Satu Mare concession.

The defaulted partner, who held a 40% interest in the Satu Mare concession declined to participate in future exploration or development phases under the concession and as such has not contributed their share of expenditures to the joint venture. The Group therefore issued a notice of default to the partner in December 2016 under the terms of the joint operating agreement ("JOA"). The partner did not have the necessary means or intention to remedy the situation and as such the partner is not entitled to participate in joint venture operations and has no right to transfer their interest to a third party. The partner is currently in a tax dispute with the government of Romania, the results of which is that the Romanian fiscal authorities have placed a protective seizure order on an account of the partner relating to their past activities on the Satu Mare concession. The primary goal of this seizure order is to prevent the unauthorized flight of capital by the partner out of Romania whilst the tax dispute is adjudicated. The seizure order also has the effect of preventing the transfer of the partner's 40% interest in the Satu Mare concession without the approval of the Romanian fiscal authorities. The Group is not involved in any manner with this tax dispute and the dispute only relates to the partner. However, the dispute means that any transfer of the partner's interest to the Group necessarily involves conversations with the Romanian fiscal authorities. In August 2017, the Group provided the partner with a Notice of Deemed Transfer pursuant to the JOA. This Notice of Deemed Transfer states that the Group has claimed this interest without any obligation to the partner going forward and that the partner must without delay, do any act required to render the transfer of the participating interest legally valid, including obtaining all governmental consents and approvals, and shall execute any document and take such other actions as may be necessary in order to affect a prompt and valid transfer of the interest in the Satu Mare Concession. The Group fully expects the Partner to fulfil this obligation to transfer its interest in the Satu Mare Concession to the Group in an expedited manner, subject to the approval of the Romanian Fiscal Authorities.

Under the terms of the JOA and pursuant to the notice of default and notice of deemed transfer, the Group has commercially assumed 100% of the joint venture. The Group has notified the National Agency for Mineral Resources ("NAMR") of the default of the partner and has provided the requisite guarantees to NAMR for 100% of the project. The Group has also communicated the position to the fiscal authorities in Romania. The Group continues to pursue the Partner's adherence to its obligation to transfer the interest, and should this not be forthcoming, pursue any and all legal remedies that would formally see the rightful transfer of the defaulting 40% working interest to the Group. The Group maintains its right to 100% of the obligations and benefits of commercial activities conducted within the Satu Mare concession.

Given the defaulted partners legal dispute with fiscal authorities in Romania, it is as yet unclear whether the Partner has the ability to transfer its interest in the Satu Mare Concession to the Group. There is a risk with respect to the timing of the transfer as it is dependent on the Partner in resolving its legal dispute with the fiscal authorities

The Group is required to apply judgment whether it is likely that future economic benefit exists when activities have not reached a stage where technical feasibility and commercial viability can be reasonably determined (exploration and evaluation) and when technical feasibility and commercial viability have been reached (development and production). The Group is required to make judgments about future events and circumstances and applies estimates to assess the economic viability of extracting the underlying resources.

(d) Cash generating units

The determination of CGUs requires judgment in defining a group of assets that generate cash inflows that are largely independent of the cash inflows from other assets or groups of assets. CGUs are determined by similar geological structure, shared infrastructure, geographical proximity, commodity type, similar exposure to market risks and materiality.

(e) Impairment and reversals

Judgment in assessing the existence of impairment and impairment reversal indicators is based on various internal and external factors. The recoverable amount of CGUs and individual assets is determined on the greater of fair value less cost of disposal or value in use. Key estimates in determining the recoverable amount normally include proved and probable reserves, forecasted commodity prices, expected production, future operating and development costs, discount rates and tax rates. In determining the recoverable amount, management may also need to make assumptions regarding the likelihood of an event. Changes to these estimates and judgements will impact the recoverable amounts of CGUs and individual assets and may require a material adjustment to their carrying value.

(f) Decommissioning provisions

The Group recognizes liabilities for the future decommissioning and restoration of exploration and evaluation assets and property, plant and equipment. Management applies judgment in assessing the existence and extent as well as the expected method of reclamation of the Group's decommissioning and restoration obligations at the end of each reporting period. Management also uses judgment to determine whether the nature of the activities performed is related to decommissioning and restoration activities or normal operating activities. In addition, these provisions are based on estimated costs, which take into account the anticipated method and extent of restoration and the possible future use of the site. Actual costs are uncertain, and estimates can vary as a result of changes to relevant laws and regulations, the emergence of new technology, operating experience, prices and closure plans. The estimated timing of future decommissioning and restoration may change due to certain factors, including reserve life. Changes to estimates related to future expected costs, discount rates and timing could result in a significant adjustment to the provisions established which would affect future financial results.

(g) Deferred income taxes

Estimates and assumptions are used in the calculation of deferred income taxes. Judgments include assessing whether tax assets can be recognized is based on expectations of future cash flows from operations and the application of existing tax laws and terms of concession agreements. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Group to realize the deferred tax assets and liabilities recorded at the balance sheet date could be impacted by a material amount. Additionally, changes in tax laws could limit the ability of the Group to obtain tax deductions in the future.

The determination of the Group's taxable income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. Estimates that require significant judgments are also made with respect to the timing of temporary difference reversals, the realizability of tax assets and in circumstances where the transaction and calculations for which the ultimate tax determination are uncertain. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

(h) Uncertain tax positions

The Group makes interpretations and judgements on the application of tax laws for which the eventual tax determination may be uncertain. To the extent that interpretations change, there may be a significant impact on the consolidated financial statements.

(i) Share-based compensation

Stock options issued by the Company are recorded at fair value using the Black-Scholes option pricing model. The calculation of share-based payment expense requires estimates which involve assumptions about the share price volatility, forfeiture rates, option life, dividend yield and risk-free rate at the initial grant date. Changes to these estimates impact the share-based compensation expense and contributed surplus and may have a material impact on the amounts presented.

5. Revenue, net of royalties

Year ended 31 December	2018	2017
Petroleum and natural gas revenues	8,716	6,569
Royalties	(867)	(680)
Revenue, net of royalties	7,849	5,889

In 2016, the Group entered into a marketing agreement with Shell International Trading and Shipping Company Limited ("Shell") for the sale of its Tunisian oil production. The terms of this agreement are such that crude oil accumulates in storage until lifting and prepayments of cash are received monthly for a proportion of this accumulated crude oil.

The Group sells its production pursuant to variable-price contracts with customers. The transaction price for these variable priced contracts is based on underlying commodity prices, adjusted for quality, location, or other factors depending on the contract terms. Under the contracts, the Group is required to deliver a variable volume of crude oil and natural gas to the contract counterparty. A total of 20% of the Group's annual oil production from the Sabria concession in Tunisia is required to be sold in the local market at an approximate 10% discount to the prices obtained under other crude oil contracts in Tunisia. The disaggregation of revenue by major products and geographical market is included in the segment note (see note 11).

The Group's revenue was entirely generated in Tunisia for the years ended 31 December 2018 and 2017 and was based on Brent crude oil index pricing. For the years ending 31 December 2018 and 2017 the Group had three customers, refer to credit risk discussion in note 24. The Group's contract with Shell is for a period of five years beginning 2016, while the Group's contracts for local sales in Tunisia are generally for the period of the concession.

As at 31 December 2018, the receivable balance related to contracts with customers, included within "accounts receivable" is $1.9 million (1 January 2018 - $1.6 million).

Upon adoption of IFRS 15 the comparative period accounting for the Shell contract was reviewed. There was no impact on the total revenue recorded under the contract identified, however, the comparative split disclosure within revenue noted as arising from a change in oil inventory ($298,000) was reclassified to Petroleum and natural gas revenues.

6. Share-based payment expense

The Company has granted ordinary share purchase options to directors and employees with exercise prices equal to or greater than the fair value of the ordinary shares on the grant date. Upon exercise, the options are settled in ordinary shares. For options issued prior to 2016, each tranche of the share purchase options had a five-year term and vested one-third immediately with the remaining two-thirds at one-third per year each anniversary of the grant date. In 2016, options were granted with a seven-year term and vested one-third per year on the anniversary of the grant date for the three subsequent years. In 2017, options were granted with a five-year term, which vested one-third per year on the anniversary date for the three subsequent years. In 2018, options were granted with a ten-year term, which vested one-third immediately with the remaining two-thirds at one-third per year each anniversary of the grant date for the two subsequent years.

During the fourth quarter of 2018, the Company converted all executive directors and employee options from a TSX plan to an AIM plan and converted the exercise price on all outstanding options to Pound Sterling based on the exchange rate at the date of continuance. The options granted to non-executive directors have not yet been repriced or converted to an AIM plan.

The conversion of the exercise price to Pound Sterling represents a modification to the share-based payment arrangement. The Company assessed the fair value of the converted options and determined that there was no change in fair value based on the modification.

The weighted average fair value of options granted during the year ended 31 December 2018 was £0.12 per option (31 December 2017 - $0.21 per option) using the following assumptions:

Inputs used in the Black-Scholes model	2018	2017
Risk-free interest rate	1.33%	0.97%
Expected dividend yield	nil	nil
Expected volatility	77%	78%
Forfeiture rate	5%	0.00%
Expected option life (in years)	10.0	5.0

A summary of the changes to the option plans during the year ended 31 December 2018, are presented below:

(a) USD denominated options

	2018		2017
	Number of options	Weighted average exercise price (USD)	Number of options	Weighted average exercise price (USD)
Balance, beginning of year	67,000	3.68	79,000	3.90
Expired	(67,000)	3.68	(12,000)	5.10
Balance, end of year	-	-	67,000	3.68

(b) CAD denominated options

	2018		2017
	Number of options	Weighted average exercise price (CAD)	Number of options	Weighted average exercise price (CAD)
Balance, beginning of year	9,933,000	0.36	3,611,000	0.38
Granted	-	-	6,995,000	0.37
Expired	-	0.37	(58,000)	2.43
Forfeited	(1,043,000)	-	(615,000)	0.37
Converted to GBP	(8,590,000)	0.36	-	-
Balance, end of year	300,000	0.37	9,933,000	0.36

As at 31 December 2018 there are 300,000 options outstanding to non-executive directors with a weighted average contractual life of 3.6 years and a weighted average exercise price of $0.37.

	2018		2017
	Number of options	Weighted average exercise price (GBP)	Number of options	Weighted average exercise price (GBP)
Balance, beginning of year	-	-	-	-
Granted	6,203,000	0.15	-	-
Converted from CAD	8,590,000	0.20	-	-
Balance, end of year	14,793,000	0.18	-	-

Exercise price (GBP)	Options outstanding	Options exercisable	Weighted average contractual life (years)
£0.14 - £1.00	14,743,000	6,081,001	6.5
£1.01 - £2.00	50,000	50,000	0.9
	14,793,000	6,131,001	6.5

7. Other expenses and income

(a) Well incident

Year ended 31 December	2018	2017
Well incident recovery	3,926	-
Well incident expense	(324)	(4,047)
	3,602	(4,047)

In December 2017, during routine operations to bring the Moftinu 1001 well out of suspension in preparation for future production, an unexpected gas release occurred and subsequently ignited. The costs associated with bringing the well under control were recorded in 2017.

The Group has submitted insurance claims during 2018 relating to the emergency costs and has received payment for the full amount of costs incurred, less an insurance deductible, of $3.9 million.

The Group also submitted insurance claims for the cost of redrilling a replacement well, Moftinu-1007. An interim claim of $2.9 million was recognized as a receivable at 31 December 2018, and as an offset to capital additions (note 12) for the year ended 31 December 2018. Subsequent to 31 December 2018, the Group submitted a further claim of $0.1 million and has received the full $3.0 million relating to the redrill.

(b) Listing costs

Listing costs include costs associated with the continuance of the Company from Alberta, Canada, to Jersey, Channel Islands, and includes the legal, accounting and due diligence costs associated with listing its shares for trading on the AIM.

During 2017, the Group sold all of its shares in an indirectly wholly-owned subsidiary, which held the Syrian production sharing agreement, for a nominal amount. The disposed subsidiary had net liabilities of $2.2 million, comprised of accounts payable, which on disposal were presented net of proceeds as a gain on disposal in the statement of comprehensive income.

8. Finance expense

Year ended 31 December	Note	2018	2017
Interest expense on debt	18	3,201	2,761
Accretion on decommissioning provision	16	1,030	684
Amortization of debt costs	23	255	222
Amortization of debt modification	23	44	-
Bank charges		23	-
Interest income		(30)	(64)
Foreign exchange loss		44	51
Unrealized loss on investments		-	13
		4,567	3,667

9. Taxation

Year ended 31 December	Note	2018	2017
Current income tax expense		2,089	1,303
Deferred income tax (recovery) expense	17	(346)	190
		1,743	1,493

Reconciliation of the effective tax rate:

Year ended 31 December	2018	2017
Loss before income taxes	(3,147)	(17,299)
Federal and provisional statutory rate	18.5%	27.0%
Expected income tax reduction	(582)	(4,671)
Non-deductible expenditures	4,802	1,153
Tax rate differences	(711)	1,594
Net change in tax attributes not recognized	(1,766)	3,417
Income tax expense (recovery)	1,743	1,493

The blended corporate income tax rate effective during 2018 in Tunisia is approximately 50.0% (2017 - 50%).

As a result of the Company's continuance from being a Canadian incorporated entity to a Jersey incorporated entity, the effective tax rate of the Group has reduced. The corporate tax rate in Jersey is 0%. Historically, the tax rate applicable to the Company had been 27%. As a consequence, the overall effective tax rate of the Group has been reduced from 27% in 2017 to 18.5% in 2018.

A significant portion of the non-deductible expenditure total in the 2018 reconciliation relates to a tax loss arising on the merger of Winstar Resources and the Company which occurred prior to the continuance.

10. Loss per share

Year ended 31 December
(000s, except per share amounts)	2018	2017
Loss for the year	(4,890)	(18,792)

Weighted average shares outstanding Basic and dilutive ⁽¹⁾	192,113	139,797
Loss per share - basic and dilutive	(0.03)	(0.13)

⁽¹⁾ For the year ended 31 December 2018, there were 6.1 million weighted average stock options exercisable that were excluded from the calculation as the impact was anti-dilutive (for the year ended 31 December 2017 - 1.3 million).

Basic earnings or loss per share is calculated by dividing the profit or loss attributable to ordinary shareholders of the Group by the weighted average number of ordinary shares outstanding during the year. Diluted earnings per share is determined by adjusting the income attributable to ordinary shareholders and the weighted average number of ordinary shares outstanding for the effects of dilutive instruments such as options granted. In a loss year, potentially dilutive ordinary shares are excluded from the loss per share calculation as the effect would be anti-dilutive.

11. Segment information

The Group's reportable segments are organized by geographical areas and consist of the exploration, development and production of oil and natural gas in Romania and Tunisia. The Corporate segment includes all corporate activities and items not allocated to reportable operating segments and therefore includes Brunei.

	Romania	Tunisia	Corporate	Total
As at 31 December 2018
Total assets	44,095	71,473	5,453	121,021
For the year ended 31 December 2018
Petroleum and natural gas revenues
Crude oil	-	6,216	-	6,216
Natural gas	-	2,500	-	2,500
	-	8,716	-	8,716
Royalties	-	(867)	-	(867)
Revenue, net of royalties	-	7,849	-	7,849
Cost sales
Production expenses	-	(2,990)	(54)	(3,044)
Depletion and depreciation	(14)	(1,586)	(201)	(1,801)
Total cost of sales	(14)	(4,576)	(255)	(4,845)
Gross profit (loss)	(14)	3,273	(255)	3,004
General and administrative	-	-	(3,422)	(3,422)
Share-based payment expense	-	-	(820)	(820)
Decommissioning provision recovery	-	316	-	316
Well incident recovery	3,602	-	-	3,602
Gain on disposition of property, plant and equipment	-	117	-	117
Listing costs	-	-	(1,377)	(1,377)
Operating profit (loss)	3,588	3,706	(5,874)	1,420
Finance expense	668	(1,413)	(3,822)	(4,567)
Profit (loss) before income taxes	4,256	2,293	(9,696)	(3,147)
Current income tax expense	-	(2,086)	(3)	(2,089)
Deferred income tax recovery	-	346	-	346
Profit (loss) for the year	4,256	553	(9,699)	(4,890)
Capital expenditures ⁽¹⁾	10,905	(233)	86	10,758

As at 31 December 2017
Total assets	32,353	75,499	6,766	114,618
For the year ended 31 December 2017
Petroleum and natural gas revenues
Crude oil	-	5,242	-	5,242
Natural gas	-	1,327	-	1,327
	-	6,569	-	6,569
Royalties	-	(680)	-	(680)
Revenue, net of royalties	-	5,889	-	5,889
Cost sales
Production expenses	-	(5,207)	(43)	(5,250)
Depletion and depreciation	(5)	(1,722)	(139)	(1,866)
Total cost of sales	(5)	(6,929)	(182)	(7,116)
Gross loss	(5)	(1,040)	(182)	(1,227)
General and administrative	-	-	(3,005)	(3,005)
Share-based payment expense	-	-	(691)	(691)
Impairment	-	(4,981)	-	(4,981)
Decommissioning provision expense	-	(1,155)	-	(1,155)
Well incident expense	(4,047)	-	-	(4,047)
Gain on disposition of subsidiary	-	-	2,179	2,179
Listing costs	-	-	(705)	(705)
Operating loss	(4,052)	(7,176)	(2,404)	(13,632)
Finance expense	(49)	(880)	(2,738)	(3,667)
Loss before income taxes	(4,101)	(8,056)	(5,142)	(17,299)
Current income tax expense	-	(1,301)	(2)	(1,303)
Deferred income tax expense	-	(190)	-	(190)
Loss for the year	(4,101)	(9,547)	(5,144)	(18,792)
Capital expenditures ⁽¹⁾	8,450	402	-	8,852

⁽¹⁾ Capital expenditures exclude the impact of changes in non-cash working capital.

12. Property, plant and equipment

	Oil and gas interests	Corporate assets	Total
Cost or deemed cost:
Balance as at 31 December 2016	221,404	2,527	223,931
Capital expenditures	449	(28)	421
Transfers from exploration and evaluation	29,302	-	29,302
Change in decommissioning provision	2,935	-	2,935
Disposals	-	(10)	(10)
Balance as at 31 December 2017	254,090	2,489	256,579
Capital expenditures	10,668	90	10,758
Change in decommissioning provision	(994)	-	(994)
Disposals	(3,500)	-	(3,500)
Balance as at 31 December 2018	260,264	2,579	262,843

Accumulated depletion and depreciation:
Balance as at 31 December 2016	(148,654)	(1,507)	(150,161)
Depletion and depreciation	(1,670)	(196)	(1,866)
Disposals	-	7	7
Impairment	(4,981)	-	(4,981)
Balance as at 31 December 2017	(155,305)	(1,696)	(157,001)
Depletion and depreciation	(1,560)	(241)	(1,801)
Disposals	3,500	-	3,500
Balance as at 31 December 2018	(153,365)	(1,937)	(155,302)

Net book value
Balance as at 1 January 2017	72,750	1,020	73,770
Balance as at 31 December 2017	98,785	793	99,578
Balance as at 31 December 2018	106,899	642	107,541

Exploration and evaluation assets

As at 31 December	2018	2017
Balance, beginning of the year	-	20,271
Additions	-	8,431
Changes in decommissioning provision	-	600
Transfers to property, plant and equipment	-	(29,302)
Balance, end of year	-	-

The following table reconciles capital expenditures to the property, plant and equipment expenditures in the cash flow statement:

Year ended 31 December	2018	2017
Property, plant and equipment expenditures	10,758	421
Exploration and evaluation expenditures	-	8,431
Exploration and development expenditures	10,758	8,852
Changes in non-cash working capital	638	(301)
Exploration and development, cash payments	11,396	8,551

Future development costs associated with the proved plus probable reserves of $55.6 million (2017 - $53.0 million) were included in the depletion calculation for the Tunisia operating segment.

As at 31 December 2018, $2.9 million of insurance proceeds were recognized as a receivable relating to the cost of redrilling Moftinu-1007. The proceeds were offset against the capital additions relating to the Moftinu-1007 well as this is where the redrill costs had been capitalized.

During the year ended 31 December 2018, proceeds of $117 thousand were received for the disposal of raw materials inventory in Tunisia with a zero net book value.

As at 31 December 2018, there were no impairment indicator triggers or triggers for reversals indicating the need for an impairment test, or a reversal, as such, no additional impairment or reversals have been recorded.

During 2017, as a result of negative technical revisions due to prolonged shut-ins of fields in Tunisia, decreased performance and sustained low commodity prices, the Group recorded an impairment of $5.0 million using a fair value less costs to sell methodology. The following summarized the recoverable amount and the total impairment recorded for each Tunisia CGU:

2017	Recoverable amount	Impairment
Sabria	17,013	-
Chouech Es Saida	7,262	4,981
Ech Chouech	-	-
Sanrhar	-	-
Zinnia	-	-
	24,275	4,981

The fair value less costs of disposal values used to determine the recoverable amount of the Tunisia CGU's were classified as Level 3 fair value measures as they are based on the Group's estimate of key assumptions that are not based on observable market data. The fair values were based on proved plus probable reserves and 2C contingent resources assessed by external reserves engineers, risk-adjusted discount rates of 20-27% and the following benchmark reference prices adjusted for commodity differentials specific to the Group.

		Gas (US$/mcf)
Year	Oil (US$/bbl) All fields	Sabria	Chouech
2017	53.19	6.21	5.95
2018	55.00	6.42	6.15
2019	57.50	6.71	6.43
2020	59.00	6.89	6.60
2021	62.80	7.33	7.03
2022	66.50	7.76	7.44
2023	69.00	8.06	7.72
2024	72.00	8.41	8.06
2025	76.30	8.91	8.54
2026	79.00	9.22	8.84
2027	85.33	9.96	9.55
2028	87.04	10.16	9.74
2029	88.78	10.37	9.93
2030	90.55	10.57	10.13
2031	92.36	10.78	10.33
2032	94.21	11.00	10.54
2033	96.10	11.22	10.75
2034	98.02	11.44	10.97
Remaining	99.98	11.67	11.19

The estimates of recoverable values were sensitive to discount rate and future commodity prices. Changes to these assumptions would have had the following impact on the impairment of PP&E:

2017	Discount rate 1% change	Future commodity prices 10% change
Sabria	1,310	12,628
Chouech Es Saida	98	2,893
Ech Chouech	-	-
Sanrhar	-	-
Zinnia	-	-
	1,408	15,521

13. Restricted cash

The Group has cash on deposit with the Alberta Energy Regulator of $1.1 million, as required to meet future abandonment obligations existing on certain oil and gas properties in Canada (see note 16) (31 December 2017 - $1.1 million). The fair value of restricted cash approximates the carrying value.

14. Trade receivables and other

As at 31 December	Note	2018	2017
Trade receivables	24	2,930	2,118
Commodity tax receivable		2,701	2,001
Insurance receivable	7	2,881	-
Corporate tax receivable		1,357	2,216
Prepaids and other		274	355
		10,143	6,690

Upon adoption of IFRS 15 the comparative period accounting for the Shell contract was reviewed resulting in comparatives for commodity inventory and advances for crude oil sales being reclassified to trade receivables to conform to current year presentation. This impacted comparative balances by reducing current assets and current liabilities by $353,000.

15. Shareholder's capital

Authorized

The Company is authorized to issue an unlimited number of ordinary shares without nominal or par value.

Changes in issued ordinary shares are as follows:

Year ended 31 December	2018		2017
	Number of shares	Amount ($000s)	Number of shares	Amount ($000s)
Balance, beginning of the year	150,652,138	362,534	78,629,941	344,479
Issued for cash	66,666,667	13,475	72,000,000	19,105
Issued for non-cash	-	-	22,197	7
Issuance costs, net of tax	-	(801)	-	(1,057)
Balance, end of the year	217,318,805	375,208	150,652,138	362,534

The Company has a total of 217,318,805 ordinary shares outstanding at 31 December 2018 (31 December 2017 - 150,652,138).

On 18 May 2018, the Company issued 66,666,667 ordinary shares at £0.15 per ordinary share, for gross equity proceeds of £10 million. Proceeds, net of issuance costs of $0.8 million, totaled $12.7 million.

Subsequent to year end, the Company has undertaken a placing to raise gross proceeds of $3.0 million by issuing 21,553,583 shares at a price of £0.105 per share. Attached to each share issued is 0.105 warrants, with each full warrant entitling the holder to purchase one common share at an exercise price of £0.105 per share, exercisable for a period of 24 months after closing. The warrants must be approved by a special resolution of the Company's shareholders at a meeting to be convened shortly before they can be exercised.

16. Decommissioning provision

As at 31 December	Note	2018	2017
Balance, beginning of year		45,681	40,236
Liabilities incurred		1,101	676
Liabilities settled		(30)	-
Accretion	8	1,030	684
Change in estimate ⁽¹⁾		(2,411)	4,014
Foreign currency translation		(102)	71
Balance, end of year		45,269	45,681
Due within one year ⁽²⁾⁽³⁾		8,696	8,815
Long-term liability ⁽³⁾		36,573	36,866
		45,269	45,681

⁽¹⁾ Changes in the discount rate, inflation rate and cost estimates are significant factors contributing to a change in estimate.

⁽²⁾ Reported as current liabilities as they relate to local environmental requirements, non-producing properties or expired production sharing contracts.

⁽³⁾ A re-analysis of decommissioning provisions resulted in a reclass of $5.9 million from long-term to current in the comparative period in order to reflect the legal obligations of the Group to decommission certain assets

The Group's decommissioning provisions are based on its net ownership in wells and facilities in Tunisia, Romania, Brunei and Canada. Management estimates the costs to abandon and reclaim the wells and facilities using existing technology and the estimated time period during which these costs will be incurred in the future.

The Group has estimated the decommissioning provisions of Brunei's Block L, Block M and the wells in Canada to be $2.8 million (31 December 2017 - $2.9 million). These obligations are reported as current liabilities as they relate to non-producing properties or expired production sharing contracts. The Group has estimated the decommissioning provisions for local environmental requirements in Tunisia to be $5.9 million (31 December 2017 - $5.9 million) and these obligations are reported as current liabilities.

The decommissioning provision in Canada of $1.0 million is provided for with the cash on deposit with the Alberta Energy Regulator (see note 13).

The significant assumptions underlying the calculation of the decommissioning provision are as follows:

As at 31 December	2018			2017
	Net present value	Risk-free rate	Inflation rate	Net present value	Risk-free rate	Inflation rate
Tunisia	39,929	2.7% - 3.1%	1.9%	41,685	2.0% - 2.8%	2.1%
Romania	2,560	4.3%	2.5%	1,114	3.8%	2.5%
Brunei ⁽¹⁾	1,801	-	-	1,801	-	-
Canada ⁽¹⁾	979	-	-	1,081	-	-
	45,269	-	-	45,681	-	-

⁽¹⁾ Provisions for Brunei and Canada are recorded at their undiscounted amount as they are current liabilities.

Management expects to incur the long-term obligations between 2020 and 2057.

The undiscounted amount of estimated future cashflows required to settle obligations is $47.7 million (31 December 2017 - $48.0 million) as follows:

As at December 31	2018	2017
Tunisia	42,163	43,953
Romania	2,775	1,204
Brunei	1,801	1,801
Canada	979	1,081
	47,718	48,039
Due within one year	8,456	8,558
Long-term liability	39,262	39,481
	47,718	48,039

A change in decommissioning provision recovery of $0.3 million (31 December 2017 - $1.2 million expense) was recognized in the statement of comprehensive income for the year ended 31 December 2018 for changes in decommissioning provision estimates related to concessions that have previously been fully impaired and have no value.

17. Deferred income tax

Movement in deferred income tax balances:

	31 December 2017	Recovery/ (expense)	Other	31 December 2018
PP&E	(19,370)	1,082	-	(18,288)
Decommissioning provision	4,570	(468)	-	4,102
Other	1,300	(268)	-	1,032
Deferred income tax liability	(13,500)	346	-	(13,154)

	31 December 2016	Recovery/ (expense)	Other	31 December 2017
PP&E	(19,650)	280	-	(19,370)
Decommissioning provision	4,564	6	-	4,570
Losses carried forward	458	(458)	-	-
Other	1,318	(18)	-	1,300
Deferred income tax liability	(13,310)	(190)	-	(13,500)

Unrecognized deferred tax assets

Deferred tax assets have not been recognized in respect of the following deductible temporary differences:

As at 31 December	2018	2017
PP&E and E&E assets	5,588	13,071
Decommissioning provision	10,198	9,995
Share issue costs	-	845
Non-capital losses carried forward and other	36,057	95,754
	51,843	119,665

Deferred tax assets have not been recognized in respect of these items because it is not probable that future taxable profits will be available against which they can be utilized.

The Group had Canadian non-capital losses of $63.6 million (2017 - $61.1 million) that were forfeited upon continuance to Jersey on 3 May 2018, Cyprus tax losses of $9.6 million (2017 - $13.0 million) that expire between 2019 and 2024, Tunisian losses of $13.7 million that expire in four years and $6.7 million have no expiry date (2017 - $10.0 and $6.7 million respectively), and Romanian losses of $5.8 million (2017 - $8.3 million) that expire after seven years between 2019 to 2025.

The Group has temporary differences associated with its investments in its foreign subsidiaries. The Group has not recorded any deferred tax liabilities in respect to these temporary differences as they are not expected to reverse in the foreseeable future.

The Group operates in multiple jurisdictions with complex tax laws and regulations, which are evolving over time. The Group has taken certain tax positions in its tax filings and these filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax impact may differ significantly from that estimated and recorded by management.

18. Long-term debt

As at 31 December	Note	2018	2017
Senior loan ⁽¹⁾		5,521	5,505
Convertible loan ⁽²⁾		29,111	26,362
Debt-principal balance		34,632	31,867
Unamortized discounts and debt costs		(351)	(606)
Modification gain	3	(990)	-
		33,291	31,261

Current portion		5,624	-
Long-term portion		27,667	31,261

⁽¹⁾ Includes loan principal of $5.4 million (31 December 2017 - $5.4 million) plus accrued interest.

⁽²⁾ Includes loan principal of $20.0 million (31 December 2017 - $20.0 million) plus accrued interest.

The following table represents the scheduled principal repayments of the Senior Loan and Convertible Loan plus accrued interest up to 31 December 2018. The Senior Loan bears interest at a variable rate equal to LIBOR plus 6% and the Convertible Loan bears interest at a variable rate equal to LIBOR plus a margin between 8% and 17%, therefore future interest payments have been excluded due to their variable nature.

	Within 1 Year	2-5 Years	Thereafter	Total
Required debt principal repayments	5,521	29,111	-	34,632

As at 31 December 2018, the Group had $33.3 million in total debt with the European Bank for Reconstruction and Development ("EBRD") consisting of a $5.4 million Senior Loan plus accrued interest and a $20.0 million Convertible Loan plus accrued interest, net of unamortized discounts and costs, and a debt modification gain. The current portion of the long-term debt is $5.6 million as described below under the Senior Loan. The three-year period available to draw on these loans has expired (November 2016). Both loans are secured by the Tunisian assets, pledges of certain bank accounts, shares of the Group's subsidiaries through which both Tunisian and Romanian concessions are owned, plus the benefits arising from the Group's interests in insurance policies and on-lending arrangements within the Group.

As at 31 December 2018, the Group was not in compliance with the debt service coverage ratio for the three months ended 31 December 2018. On 21 December 2018, the Group received a waiver from the EBRD formally waiving compliance with this covenant for the period ended 31 December 2018. The implication of this waiver is that the debt repayments will follow their original scheduled repayment terms and the bank will not be acting on its security as a result of the breach.

Under the terms of the loan agreements EBRD has the right on change of control of the Group to demand repayment of the debt. Given the AIM listing and equity raise, EBRD waived its right to require prepayment, provided that, as a result of the equity raise, Kulczyk Investments S.A. shareholding did not drop below 30% and there was no single investor who would hold more than 24.99% of the Group's share capital.

Senior Loan

The Senior Loan bears interest at a variable rate equal to LIBOR plus 6%. The Senior Loan is repayable in two instalments of $2.7 million each on 31 March 2019 and 30 September 2019. The Senior Loan is subject to a cash sweep which is calculated on a semi-annual basis occurring on 31 December and 30 June of each year. The cash sweep is calculated based on the Group's consolidated cash balance (excluding amounts held as restricted cash). If consolidated cash on these dates is in excess of $7 million, the difference is to be used to prepay the Senior Loan in inverse order of maturity until the outstanding loan balance is no greater than that under the original amortization schedule.

The Senior Loan agreement contains a prepayment clause whereby EBRD has the option to request prepayment in the event that the annual reserves coverage ratio for Tunisian reserves is less than 1.5, in an amount to bring the ratio back on side. With respect to 31 December 2017 reserves, EBRD has waived its right to require prepayment. The Group anticipates that the reserves coverage ratio as at 31 December 2018 will not be met. This ratio is due to be calculated and reported in April 2019, at which time if the ratio is not met, the Group will seek relief from the EBRD.

Convertible Loan

The Convertible Loan is repayable in four equal instalments on 30 June 2020, 2021, 2022 and 2023. Interest is accrued up to 30 June 2020 and will form part of the principal to be amortized over these repayment periods. Interest accruing subsequent to June 2020 will be paid annually with the principle repayments. The Convertible Loan bears interest at a variable rate equal to LIBOR plus a margin between 8% and 17%. The margin level is determined based on consolidated Tunisian and Romanian net revenues earned.

The conversion terms in the Convertible Loan agreement have not yet been updated with the EBRD to reflect the Group's listing on AIM and delisting from the TSX, and are as follows:

The Group can elect, subject to certain conditions, to convert all or any portion of the Convertible Loan principal and accrued interest outstanding for newly issued shares of the Group at the then current market price of the shares on the TSX or WSE, as required by the exchange rules. The EBRD can also at any time, and on multiple occasions elect to convert all or any portion of the Convertible Loan principal and accrued interest outstanding for newly issued shares of the Group at the then current market price of the shares on the TSX or WSE. The conversion amount is restricted such that the number of shares issued would result in EBRD holding a maximum of 5% of the issued share capital of the Group. Conditions to conversion include a requirement for substantially all of the Group's assets and operations to be located and carried out in the EBRD countries of operations. The Convertible Loan terms have not yet been updated with the EBRD to reflect the Group's listing on AIM and delisting from the TSX.

The conversion feature of the loan is based on market price, which would result in the issuance of a variable number of shares of the Group, and as a result, no value was allocated to the conversion option. The Convertible Loan is recorded as debt and classified as financial liabilities at amortized costs.

The Group can also repay the Convertible Loan at maturity in cash or in-kind, subject to certain conditions, by issuing new ordinary shares valued at the then current market price of the shares on the TSX or WSE. The repayment amount is subject to a discount of approximately 10% in the event that the requirement for substantially all of the Group's assets and operations to be located and carried out in the EBRD countries of operations is not met at the date of repayment.

Covenants

Both loan agreements contain a number of affirmative covenants, including maintaining the specified security, environmental and social compliance, and maintenance of specified financial ratios. Financial covenants are calculated at the consolidated level, and there was relief from financial covenants from the quarter ended 30 September 2017 until the quarter ended 30 September 2018. The consolidated debt to EBITDA covenant came into effect 30 September 2018, with a required maximum ratio of 10.0 times and from 1 January 2019 onwards the required maximum ratio will be 2.5 times. The debt service coverage ratio came into effect 31 December 2018 with a minimum ratio of 1.3 times and is only applicable to the Senior Loan.

Debt costs

Long-term debt transaction costs are recorded within long-term debt and are amortized over the remaining term of the committed credit facility. No transaction costs were incurred in 2018. During 2017, transaction costs of $0.3 million were recorded using the effective interest rate.

19. Other provisions

	JV audit	Severance	Total
Balance as at 31 December 2016	1,148	-	1,148
Provisions made during the year	-	599	599
Balance as at 31 December 2017	1,148	599	1,747
Amount paid	-	(331)	(331)
Change in provision	-	(49)	(49)
Balance as at 31 December 2018	1,148	219	1,367
Current	-	-
Non-current	1,148	219	1,367

The Group is subject to audits arising in the normal course of business, with its joint venture partner in the Sabria concession in Tunisia. A provision is made to reflect management's best estimate of eventual settlement of these audits. Management expects settlement of the joint venture audit provision to occur later than twelve months from 31 December 2018.

As at 31 December 2017, a provision was made for potential severance costs relating to the termination of employees in the Chouech Es Saida field in Tunisia. During 2018, agreement was reached with all stakeholders as to the rehiring of certain employees with the planned reopening of the Chouech Es Saida field and the severance cost associated with the other employees. Severance payments were made in 2018 to certain employees not to be rehired. The provision at 31 December 2018 reflects the potential costs to terminate the remaining employees taking into consideration the likelihood of this occurring.

20. Accounts payable and accrued liabilities

As at 31 December	2018	2017
Accounts payable and accrued liabilities	14,313	17,404
Taxes payable	285	1,321
	14,598	18,725

21. Aggregate payroll expense

The aggregate payroll expense of employees and executive management of Serinus was as follows:

Year ended 31 December	2018	2017
Wages, salaries and benefits ⁽¹⁾	3,987	3,250
Severance	-	236
Share-based payment expense ⁽²⁾	820	691
Total compensation	4,807	4,177

⁽¹⁾ Includes amounts in general and administrative expenses, production expenses and exploration and development expenditures

⁽²⁾ Represents the amortization of share-based payment expense associated with options granted.

22. Related party transactions

During the years ended 31 December 2018 and 2017, related party transactions include the compensation of key management personnel. Key management personnel include Serinus' Board of Director's and members of the Executive Leadership Team. Transactions with key management personnel (including directors) are noted in the table below:

Year ended 31 December	2018	2017
Wages and salaries	742	827
Benefits	32	109
Severance	-	236
Share-based payment expense	835	644
Total compensation for key management personnel	1,609	1,816

23. Supplemental cash flow disclosures

Year ended 31 December	2018	2017
Cash provided by (used in):
Trade receivables and other	(2,530)	(325)
Accounts payable and accrued liabilities	(4,539)	2,714
	(7,069)	2,389
Changes in non-cash working capital relating to:
Operating	(7,069)	2,389

The following table reconciles long-term debt⁽¹⁾ to cash flows arising from financing activities:

As at 31 December	2018	2017
Balance, beginning of the year	31,261	30,699
Cash changes:
Principal payment on senior loan	-	(1,667)
Financing costs on senior loan	-	(279)
Interest payments on senior loan	(436)	(475)
Non-cash changes:
Modification gain upon adoption of IFRS 9	(1,034)	-
Amortization of discounts and debt costs	255	222
Amortization of modification gain	44	-
Accrued interest on senior loan	452	449
Accrued interest on convertible loan	2,749	2,312
Balance, end of the year	33,291	31,261

⁽¹⁾ Includes the current portion of long-term debt.

24. Financial instruments and risk management

The Group's financial assets and liabilities are comprised of cash and cash equivalents, restricted cash, trade receivables and other receivables, accounts payable and accrued liabilities and long-term debt (including the current portion of long-term debt).

The estimated fair values of the financial instruments have been determined based on the Group's assessment of available market information. To estimate fair values of its financial instruments, Serinus uses quoted market prices when available, or third-party models and valuation methodologies that use observable market data. These estimates may not necessarily be indicative of the amounts that could be realized or settled in a market transaction.

Fair value of financial instruments

There are three levels of fair value by which a financial instrument can be classified:

· Level 1 - fair value measurements are based on unadjusted quoted market prices.

· Level 2 - fair value measurements are based on valuation models and techniques where the significant inputs are derived from quoted indices. Inputs other than quoted prices that are observable for the asset and liability either directly or indirectly such as quoted forward prices for commodities, time value and volatility factors which can be substantially observed or corroborated in the marketplace; and

· Level 3 - fair value measurements rely on inputs that are not based on observable market data.

The fair values of cash and cash equivalents, restricted cash, trade receivables and other receivables and accounts payable and accrued liabilities approximate their carrying amounts due to their short-term maturities.

The fair value of the long-term debt approximates its carrying value as it is at a market rate of interest and accordingly the fair market value approximates the carrying value (level 2). Serinus does not have any derivative financial instruments at 31 December 2018 (2017 - nil).

Risk management

The Directors have overall responsibility for identifying the principal risks of the Group and ensuring the policies and procedures are in place to appropriately manage these risks. Serinus' management identifies, analyzes and monitors risks and considers the implication of the market condition in relation to the Group's activities.

Market risk is the risk that the fair value of future cash flows of financial assets or financial liabilities will fluctuate due to movements in market prices. Market risk is comprised of commodity price risk, foreign currency risk and interest rate risk, as well as credit and liquidity risks.

Commodity price risk

The Group is exposed to commodity price risk in fluctuations in the price of oil, natural gas and natural gas liquids. In Tunisia, oil prices are based on the terms of the Shell contract which reflects the market price of Brent crude oil. Brent averaged $71.06 per bbl in 2018 and $54.25 per bbl in 2017, an increase of 31%. The Group has no commodity hedge program in place which could limit exposure to price risk.

For the year ended 31 December 2018, a 5% change in the price of crude oil per bbl would have impacted revenue, net of royalties by $0.3 million.

Foreign currency exchange risk

The Group is exposed to risks arising from fluctuations in currency exchange rates between Pound Sterling, the Canadian dollar, Polish zloty, Romanian leu, Tunisian dinar, Euro and United States dollar. At 31 December 2018, the Group's primary currency exposure related to the Pound Sterling ("GBP"), the Canadian dollar ("CAD"), Romanian LEU ("LEU"), and Tunisian dinar ("TND") balances. The following table summarizes the Group's foreign currency exchange risk for each of the currencies indicated:

As at 31 December 2018	GBP	CAD	LEU	TND
Cash and cash equivalents	9	515	3	549
Accounts receivable	-	69	12,324	5,330
Restricted cash	-	1,400	109	-
Accounts payable and accrued liabilities	(33)	(88)	(10,985)	(8,379)
Net foreign exchange exposure	(24)	1,896	1,451	(2,500)
Translation to USD	1.2769	0.7342	0.2455	0.3340
USD equivalent at period end exchange rate	(31)	1,392	356	(835)

As at 31 December 2017	GBP	CAD	LEU	TND
Cash and cash equivalents	-	4,130	1,591	12
Accounts receivable	-	82	5,814	2,704
Restricted cash	-	1,378	-	-
Accounts payable and accrued liabilities	-	(153)	(10,371)	(6,956)
Net foreign exchange exposure	-	5,437	(2,966)	(4,240)
Translation to USD	-	0.7971	0.2572	0.4028
USD equivalent at period end exchange rate	-	4,334	(763)	(1,708)

Based on the net foreign exchange exposure at the end of the year, if these currencies had strengthened or weakened by 10% compared to the U.S. dollar and all other variables were held constant, the after-tax earnings would have decreased or increased by approximately the following amounts:

Year ended 31 December	2018	2017
Pound sterling (GBP)	(3)	-
Canadian dollar (CAD)	139	433
Romanian leu (LEU)	36	(76)
Tunisian dinar (TND)	(84)	(171)
Impact on profit (loss)	88	186

Interest rate risk

The Group's interest rate risk arises from the floating rate on the Senior Loan and Convertible Loan. The Group had locked in the interest rate on the $20.0 million Senior Loan at a rate of 6.9% for a two-year period from 30 September 2014 to 30 September 2016 at which time it reverted back to LIBOR plus 6%. The convertible loan is based on LIBOR and has a portion based on incremental revenue with a floor of 8% and ceiling of 17%.

The Group's net earnings are impacted by changes in LIBOR interest rates, if interest rates applicable to the long-term debt increased by 1%, assuming the amount of debt remains unchanged, the impact to net profit (loss) before income taxes for the year ended 31 December 2018 would be $322 thousand (31 December 2017 - $303 thousand).

Credit risk

The Group's cash and cash equivalents and restricted cash are held with major financial institutions. The Group monitors credit risk by reviewing the credit quality of the financial institutions that hold the cash and cash equivalents and restricted cash.

The Group's trade receivables consist of receivables for revenue in Tunisia and receivables from joint venture partners.

Management believes that the Group's exposure to Tunisian credit risk is manageable, as commodities sold are under contract or payment within 30 days. Oil is sold with reputable parties and collection is prompt based on the individual terms with the parties. For the year ended 31 December 2018, the Group had three customers with sales representing 46%, 29% and 25% of total revenue (for year ended December 2017 - three customers representing 54%, 24% and 22%). At 31 December 2018, the Group had $0.6 million (December 31, 2017 - nil) of revenue receivables that were considered past due (over 90 days outstanding). The average expected credit loss on the Group's revenue receivable was nil. Subsequent to 31 December 2018 the Group has collected the full $0.6 million of the past due revenue receivables.

Substantially all receivables from joint venture partners are with government agencies which minimizes credit risk.

Management has no formal credit policy in place for customers and the exposure to credit risk is approved and monitored on an ongoing basis individually for all significant customers. The maximum exposure to credit risk is represented by the carrying amount of each financial asset in the statement of financial position. The Group does not require collateral in respect of financial assets.

Liquidity risk

Liquidity risk is the risk that Serinus will not be able to pay financial obligations when due. There are inherent liquidity risks, including the possibility that additional financing may not be available to the Group, or that actual capital expenditures may exceed those planned. The Group mitigates this risk through monitoring its liquidity position regularly to assess whether it has the resources necessary to fund planned exploration commitments on its petroleum and natural gas properties or that viable options are available to fund such commitments. Alternatives available to the Group to manage its liquidity risk include deferring planned capital expenditures that exceed amounts required to retain concession licenses, farm-out arrangements and securing new equity or debt capital.

Timing of cash outflows related to commitments follow the schedule provided under note 26 commitments and contingencies. Timing of cash outflows related to debt follow the schedule provided in note 18. All outflows are anticipated to follow the schedule for payment. The risk that payment could occur significantly earlier may arise if a loan covenant is violated and an acceptable arrangement could not be made, in which case the bank could act on its security for that particular loan. The maximum exposure to liquidity risk in this case is represented by the loan principal plus accrued interest.

25. Capital management

Year ended 31 December	2018	2017
Long-term debt	33,291	31,261
Shareholder's equity	13,342	3,704
Total capital resources	46,633	34,965

Consistent with prior years, the Group manages its capital structure to maximize financial flexibility, making adjustments in light of changes in economic conditions and risk characteristics of the underlying assets. Further, each potential acquisition and investment opportunity is assessed to determine the nature and total amount of capital required together with the relative proportions of debt and equity to be deployed. The Group does not presently utilize any quantitative measures to monitor its capital.

During 2018 and 2017 the Company has undertaken two equity raises as steps towards strengthening its capital structure, in addition, effective October 2017, the Company completed the amendment of the loan agreements with EBRD with respect to the terms of the Tunisian Loan Agreements. In 2017 the Company completed an equity raise, raising $18 million though the issuance of 72.0 million ordinary shares. In May 2018, the Company continued from Alberta, Canada to Jersey, Channel Islands and listed on the AIM market of the London Stock Exchange. Subsequent to the listing on AIM, the Company raised $12.7 million in equity through the issuance of 66.7 million ordinary shares.

26. Commitments and contingencies

Commitments

Future payments for the Group's commitments as at 31 December 2018 are below. A commitment is an enforceable and legally binding agreement to make a payment in the future for the purchase of goods and services. These items exclude amounts recorded on the balance sheet.

	Within 1 Year	2-3 Years	4-5 Years	Thereafter	Total
Operating leases	621	464	12	-	1,097
Gas plant - Romania ⁽¹⁾	335	-	-	-	335
Total	956	464	12	-	1,432

⁽¹⁾ Contractual obligation on the construction of the gas processing facility.

The Group's commitments are all in the ordinary course of business and include the work commitments for Tunisia and Romania.

Romania

The work obligations pursuant to the Phase 3 extension, approved on 28 October 2016, include the drilling of two wells, and, at the Group's option, either the acquisition of 120 km2 of new 3D seismic data or drill a third well. The two firm wells must be drilled to minimum depths of 1,000 and 1,600 meters respectively, and if so elected, the third well to a depth of 2,000 meters. The term of the Phase 3 extension is for three years, expiring on 28 October 2019. On 5 May 2017, the Group signed a letter of guarantee with the National Agency for Mineral Resources in Romania for up to $12 million to cover the necessary expenses for the fulfillment of the minimal commitments for the Phase 3 extension. This guarantee was made net of any amounts already spent by the Group since the time of the extension's approval. The Group has completed the work obligations for drilling the first two wells, the Moftinu-1007 and Moftinu-1003 wells. During 2019 the Group intends to acquire 120 km2 of new seismic in order to meet its third and final commitment.

Office space

The Group has a lease agreement for office space in Calgary, Canada, which expires on 30 November 2020, and an office lease agreement in Bucharest, Romania, which expires on 27 August 2020. Operating leases on office buildings are in the ordinary course of business. The Group has the option to renew or extend the leases on its office buildings with new lease terms to be based on current market prices.

Contingencies

Tunisia

The Tunisian state oil and gas company, ETAP, has the right to back into up to a 50% working interest in the Chouech Es Saida concession if, and when, the cumulative crude oil sales, net of royalties and shrinkage, from the concession exceeds 6.5 million barrels. As at 31 December 2018, cumulative liquid hydrocarbon sales net of royalties and shrinkage was 5.2 million barrels.

ADVISORS

Registered Office		Legal Advisors
JTC Group		English Solicitors to the Company
28 Esplanade		McCarthy Tétrault, Registered Foreign Lawyers & Solicitors
St Helier		26th Floor
Jersey JE1 8SB		125 Old Broad Street
		London EC2N 1AR
Registration Number
126344		Canadian Solicitors to the Company
		McCarthy Tétrault LLP
Nominated Advisor & Joint Broker		PO Box 48, Suite 5300
Numis Securities Limited		Toronto-Dominion Bank Tower
The London Stock Exchange Building		Toronto M5K 1E6
10 Paternoster Square
London EC4M 7LT		Jersey Solicitors to the Company
		Mourant Ozannes
Joint Broker		22 Grenville Street
GMP FirstEnergy		St Helier
85 London Wall		Jersey JE4 8PX
London EC2M 7AD
		Polish Solicitors to the Company
Auditors		T. Studnicki, K. Płeszka, Z. Ćwiąkalski, J. Górski sp.k.
BDO LLP		Oddział w Warszawie
55 Baker St		ul. Złota 59,
London W1U 7EU		00-120 Warsaw

Registrar		Financial Public Relations Advisor
Computershare Investor Services (Jersey) Limited		Camarco
Queensway House, Hilgrove Street		107 Cheapside
St Helier		London EC2V 6DN
Jersey JE1 1ES
		TBT i Wspólnicy
Competent Person		ul. A. Branickiego 10, lok. 2
RPS Energy Canada Ltd		02-972 Warsaw
Suite 600
555-4th Avenue S.W.
Calgary T2P 3E7

Company Secretary
JTC Group
28 Esplanade
St Helier
Jersey JE1 8SB

This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.

END

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