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Serinus Energy PLC (SENX)

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Wednesday 25 March, 2020

Serinus Energy PLC

2019 Annual Financial Report

RNS Number : 5154H
Serinus Energy PLC
25 March 2020
 

25 March 2020

 

Press Release

2019 Annual Financial Report

Jersey, Channel Islands, 25 March 2020 -- Serinus Energy plc ("Serinus", the "Company" or the "Group") (AIM:SENX, WSE:SEN) announces its audited annual accounts for the year ended 31 December 2019.

2019 Highlights

Operational

· During the first quarter of 2019, Serinus finalised the construction of the Moftinu gas plant in Romania and brought the Moftinu gas field on production in April 2019.

· Serinus reopened the Chouech Es Saida ("Chouech") and Ech Chouech fields in Tunisia in the second half of the year, bringing four wells onto production at Chouech, and one well onto production at the Ech Chouech field.

·     Production for the year averaged 1,389 boe/d (2018 - 352 boe/d), comprised of 961 boe/d (2018 - nil) from Romania and 428 boe/d (2018 - 352 boe/d) from Tunisia.

· Serinus exited December 2019 with a production rate of 2,089 boe/d, with a December average of 2,175 boe/d (Romania 1,491 boe/d and Tunisia 684 boe/d).

· The Group was granted a twelve-month extension on the third exploration phase of the Satu Mare Concession in Romania until 28 October 2020 with the sole commitment to complete a 3D seismic acquisition program. Prior to the year-end, the Group completed the permitting required to perform the 148km2 3D seismic acquisition program, which was expected to be completed in Q2 2020. Due to the unprecedented disruptions caused by the COVID-19 outbreak, the Group is unable to estimate a completion date at this time.

· During 2019 the Company started well site preparations for the M-1004 well in Romania. In February 2020, this well was successfully drilled, completed, and tested at a rate of 6.0 MMscf/d (approximately 1,000 boe/d) from three perforated zones and then brought onto production.

Financial

· During 2019, Serinus generated gross revenues of $24.4 million (2018 - $8.7 million), comprised of $15.2 million (2018 - $nil) from Romania and $9.2 million (2018 - $8.7 million) from Tunisia.

· Capital expenditures of $4.9 million (2018 - $10.8 million) were incurred for the year and predominantly consisted of costs incurred in the Moftinu gas facility, and preliminary work related to the M-1004 well that was subsequently drilled in 2020.

· Funds from operations increased by 602% for the year to $8.1 million (2018 - $1.2 million), largely due to the Romanian field coming online during the year.

· Serinus fully repaid the European Bank of Reconstruction and Development ("EBRD") Senior loan during the year. The Senior Loan consisted of $5.4 million plus accumulated interest.

· Realized oil price ($/bbl) averaged $ 61.67 (2018 - $66.96), a decrease of 8%.

· Realized gas price ($/Mcf) averaged $7.27 (2018 - $11.69, inclusive of a one-time gain), a decrease of 30%.

· Production costs ($/boe) were reduced by 42% to $13.78 in 2019 from $23.57 in 2018.

 

Annual Report and Accounts

 

The Annual Report and Accounts will be available on the Company's website ( www.serinusenergy.com ) from today. A further announcement will be made in due course confirming the details of the Company's Annual General Meeting and the date of dispatch of the associated notice.

 

About Serinus

Serinus is an international upstream oil and gas exploration and production company that owns and operates projects in Tunisia and Romania.

For further information, please refer to the Serinus website (www.serinusenergy.com) or contact the following:

 

Serinus Energy plc

Jeffrey Auld, Chief Executive Officer

Andrew Fairclough, Chief Financial Officer

Calvin Brackman, Vice President, External Relations & Strategy

+1 403 264 8877

 

 

WH Ireland Limited

(Nominated Adviser and Joint Broker)

Katy Mitchell

Harry Ansell (Broker)

Lydia Zychowska

+44 (0)20 7220 1666

 

 

A rden Partners plc

(Joint Broker)

Paul Shackleton / Dan Gee-Summons (Corporate Finance)

Fraser Marshall (Equity Sales)

+44 (0) 20 7614 5900

 

 

 

 

Camarco

(Financial PR - London)
Billy Clegg
Owen Roberts

+44 (0) 20 3781 8334

 

 

TBT i Wspólnicy

(Financial PR - Warsaw)

Katarzyna Terej

+48 22 487 53 02 

 

Translation : This news release has been translated into Polish from the English original.

Forward-looking Statements This release may contain forward-looking statements made as of the date of this announcement with respect to future activities that either are not or may not be historical facts. Although the Company believes that its expectations reflected in the forward-looking statements are reasonable as of the date hereof, any potential results suggested by such statements involve risk and uncertainties and no assurance can be given that actual results will be consistent with these forward-looking statements.  Various factors that could impair or prevent the Company from completing the expected activities on its projects include that the Company's projects experience technical and mechanical problems, there are changes in product prices, failure to obtain regulatory approvals, the state of the national or international monetary, oil and gas, financial , political and economic markets in the jurisdictions where the Company operates and other risks not anticipated by the Company or disclosed in the Company's published material. Since forward-looking statements address future events and conditions, by their very nature, they involve inherent risks and uncertainties and actual results may vary materially from those expressed in the forward-looking statement. The Company undertakes no obligation to revise or update any forward-looking statements in this announcement to reflect events or circumstances after the date of this announcement, unless required by law.

 

 

 

 

 

 

 

 

 

 

Serinus Energy plc

 

2019 Annual Report and Accounts

(US dollars)

 

2019 Highlights

 

Operational

 

· During the first quarter of 2019, Serinus Energy plc and its subsidiaries ("Serinus", the "Company", or the "Group") finalised the construction of the Moftinu gas plant in Romania and brought the Moftinu gas field on production in April 2019.

· Serinus reopened the Chouech Es Saida ("Chouech") and Ech Chouech fields in Tunisia in the second half of the year, bringing four wells onto production at Chouech, and one well onto production at the Ech Chouech field.

· Production for the year averaged 1,389 boe/d (2018 - 352 boe/d), comprised of 961 boe/d (2018 - nil) from Romania and 428 boe/d (2018 - 352 boe/d) from Tunisia.

· Serinus exited December 2019 with a production rate of 2,089 boe/d, with a December average of 2,175 boe/d (Romania 1,491 boe/d and Tunisia 684 boe/d).

· The Group was granted a twelve-month extension on the third exploration phase of the Satu Mare Concession in Romania until 28 October 2020 with the sole commitment to complete a 3D seismic acquisition program. Prior to the year-end, the Group completed the permitting required to perform the 148km2 3D seismic acquisition program, which was expected to be completed in Q2 2020. Due to the unprecedented disruptions caused by the COVID-19 outbreak the Group is unable to estimate a completion date at this time.

· During 2019 the Company started well site preparations for the M-1004 well in Romania. In February 2020, this well was successfully drilled, completed, and tested at a rate of 6.0 MMscf/d (approximately 1,000 boe/d) from three perforated zones and then brought onto production.

 

Financial

 

· During 2019, Serinus generated gross revenues of $24.4 million (2018 - $8.7 million), comprised of $15.2 million (2018 - $nil) from Romania and $9.2 million (2018 - $8.7 million) from Tunisia.

· Capital expenditures of $4.9 million (2018 - $10.8 million) were incurred for the year and predominantly consisted of costs incurred in the Moftinu gas facility, and preliminary work related to the M-1004 well that was subsequently drilled in 2020.

· Funds from operations increased by 602% for the year to $8.1 million (2018 - $1.2 million), largely due to the Romanian field coming online during the year.

· Serinus fully repaid the European Bank of Reconstruction and Development ("EBRD") Senior loan during the year. The Senior Loan consisted of $5.4 million plus accumulated interest.

· Realized oil price ($/bbl) averaged $ 61.67 (2018 - $66.96), a decrease of 8%.

· Realized gas price ($/Mcf) averaged $7.27 (2018 - $11.69, inclusive of a one-time gain), a decrease of 30%.

· Production costs ($/boe) were reduced by 42% to $13.78 in 2019 from $23.57 in 2018.

 

 

 

Serinus at a Glance

 

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

 

The Romanian business unit is comprised of one concession, Satu Mare, approximately 3,000km2, located in 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 a multitude of significant prospects available for further exploration.

 

The Tunisian business unit is comprised of five concessions, located throughout the country and predominantly produces oil. The corner stone of the Tunisian business unit is the Sabria field, which is a large oilfield play that has been historically 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 development operations.

 

2020 Outlook

 

Corporate

 

Serinus had a transformational year in 2019 which saw significant operational achievements.

 

Serinus repaid the $5.4 million Senior loan outstanding with two payments occurring in March and September 2019.

 

Overall, the outlook for the Group is positive, as both operating units grew production and generated positive cashflows from operations.

 

Romania

 

With the completion of the Moftinu gas plant, Serinus was able to begin production from three wells (M-1000, M-1003 and M-1007) at the Moftinu field on 25 April 2019. This was the Company's first production from the Satu Mare Concession, and it generated significant cashflows for the Company. With Romania's significant contribution to the positive results the Group achieved in 2019, Serinus remains very optimistic about the future growth prospect of its Romanian assets.

 

Subsequent to the year-end, the Company drilled, completed and tested an additional gas development well (M-1004) in the Moftinu field to continue to maximize the recently completed Moftinu gas facility. This well demonstrated excellent test results and flowed at 6.0 MMscf/d during the well test. M-1004 was brought onto production in February 2020 which will significantly increase the Company's cashflows.

 

Serinus will be conducting a 148 km2 3D seismic acquisition program to further delineate, define and de-risk the historical 2D seismic identified shallow gas prospects located to the north of the Moftinu field. This seismic acquisition program is the final commitment on the third exploration phase of the Satu Mare concession and will allow the Group to advance the concession to the next exploration phase starting in Q4 2020. The program was expected to be completed in Q2 2020. Due to the unprecedented disruptions caused by the COVID-19 outbreak the Group is unable to estimate a completion date at this time. The Group is excited about the possibility that the seismic acquisition program will identify additional Moftinu-like fields for development. Such fields are very robust economically given low drilling costs, high productivity, low operating costs, and being located near to transportation infrastructure and markets.

 

Tunisia

 

Operations in Tunisia are ramping up after an extended period of stagnation due to the difficult social conditions in the country. Our local team commenced the reopening of the Chouech field in southern Tunisia in March 2019. During the third quarter, four wells in Chouech recommenced production. During the fourth quarter one well in the Ech Chouech field was put onto production. The Company continues to see increasing production from these wells as the water cuts drop off.

 

Sabria continues to produce with no interruptions and minimal capital outlays. The Group will look at implementing low cost capital programs in 2020 such as the re-entry and workover of the N-2 well and installing artificial lift in the wells currently producing.

 

 

COVID-19

 

In this unprecedented situation, the Company's priority is to ensure the safety and wellbeing of all our staff during this difficult time.  Our contingency planning is in place and is currently working well to ensure business continuity across our operations.  While the full implications of COVID-19 on the performance for the current year are difficult to determine at this stage, the Board remains confident in the long-term prospects of the Company.

 

The outbreak of COVID-19 has had a significant effect on demand for oil and gas globally.  This, along with an increase in production from OPEC and non-OPEC producers, has created abnormal disruptions in the prices of oil and gas in the world markets.  These price dislocations will no doubt affect the Company but we believe that by being a low cost, onshore producer with approximately 70% of our production from Romanian gas, and managing our capital spending until the situation becomes more clear, will put us in a position to deal with these price dislocations. 

 

Serinus Attributes

 

Serinus offers investors access to international oil and gas upstream operations with significant near-term production growth potential and significant organic growth within its existing asset base.

 

Romania is a large contiguous asset base with significant shallow gas development opportunities in a country that is demonstrating a rapidly expanding domestic demand for natural gas, and growing integration with the European gas market. Serinus has demonstrated the shallow gas potential of the northern portion of the Satu Mare concession with the development of the Moftinu gas project.  The Company believes that multiple additional analogous projects exist in the concession area. 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.

 

Tunisia offers significant field development opportunities on existing and under-developed oil fields. The Tunisian fields consist of existing wells with potential low-cost capital optimization work programs to increase production over the next year, along with large acreage with the potential to drill future development wells.

 

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, and become experts in, the operating and fiscal regimes of their respective countries. We have significant technical and commercial experience and are able to apply that experience across our business units.

 

In summary, Serinus offers a combination of near-term production growth, significant exploration opportunity and low-risk oil and shallow gas development opportunities.

 

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:

· One production concession in Romania with one work commitment remaining in the current exploration phase, a 148 km2 3D seismic acquisition program that has been initiated and will be completed in Q2 2020.

· Five exploration and production concessions in Tunisia with all work commitments completed and with low cost capital optimization programs to be undertaken in 2020 to grow production.

· Extensive oil and natural gas exploration and development potential within multiple play horizons provides diversity of both commodity and technical risks.

· A significant future opportunity 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.

 

3.  Manage Risks:

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

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

· Operate all concessions to maintain cost control with the 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,

 

Serinus had a very successful 2019 as the Company was able to achieve several transformational milestones providing significant optimism for the future.

 

The most notable achievements were:

1.  the commissioning and start-up of the Moftinu Gas Plant in Romania, allowing for production to commence on 25 April 2019, and

2.  production restart at the Chouech Es Saida and Ech Chouech fields in Tunisia following a shut-in of over two years.

 

These events have significantly increased the Group's production and materially contributed to the Company's free cash flows providing the Group with levels required to deleverage its balance sheet and to continue to grow the value of the business.

 

On behalf of the Board of Directors, I would like to express my highest gratitude to all Serinus employees and partners for their hard work, continuous support and close cooperation, and our thoughts are with them in this difficult time. I would like to thank the members of the Executive Board who, despite many challenges throughout the years, have continued to work diligently to ensure the Group's success in creating a sustainable international oil and gas company. It is through combined efforts of our employees, associates and advisors in Romania and Tunisia that we move closer every day towards this goal. 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. 

 

Yours sincerely,

 

 

Lukasz Rędziniak, Chairman of the Board of Directors

24 March 2020

 

 

Report From CEO

 

Dear Shareholders,

 

2019 was a transformational year for our Company. The completion of the Moftinu Gas Plant and the flow of first sales gas in April heralded the first new source of production and revenue in six years. Soon after the commercial gas flow from the Moftinu Gas Plant was onstream our Tunisian team was able to restart production from the Chouech Es Saida field in the South of Tunisia. By the end of 2019 the Company had dramatically increased its production, revenue and after-tax cash flow and is positioned for further growth in 2020.

 

It is hard to overestimate how important the Moftinu Gas project is for the Company. Aside from the obvious benefits of increased cash flow and production, Moftinu offers a glimpse of the future. The Company believes that there are more shallow gas fields that are similar to Moftinu and that over the course of the next few years we are in an excellent position to unlock that future value.

 

In April 2019 Serinus celebrated the start of commercial production in Romania from the M-1000, M-1003 and M-1007 wells. With the production from Romania the Group's revenue has nearly tripled from the prior year, ultimately leading to significant free cash flows for the year. The free cash flow Serinus was able to generate during the year allowed the Group to make the final payment of the Senior loan, $2.7 million plus accrued interest in September 2019. In 2020 the Company is excited to complete the final commitment of the third exploration phase of the Satu Mare concession, shooting a 148 km2 3D seismic program. In early 2020 the Company also drilled the M-1004 well, which was highly successful. Both the recent drilling and the 3D seismic program will be completed out of the operating cash flow provided by the Moftinu Gas Development.

 

Given the success in Romania it is easy to overlook the progress the Company has made in Tunisia. Tunisia remains a very attractive asset base and one that offers very different commercial opportunities than in Romania. After several years of inactivity in Tunisia forced on the Company by the social disruptions that had interrupted business in the country, we were able to re-open the Chouech Es Saida field. As an added bonus our team was able to re-open the Ech Chouech field. Ech Chouech is an adjacent field to Chouech Es Saida and our technical teams were pleasantly surprised to find that after a long period of forced shut-in, the Ech Chouech field was able to produce volumes of oil. Both fields are now producing and the volume of oil versus water is gradually increasing. This production of water is a natural result of the wells having been shut-in during the disruptions and over time the Company remains confident that these wells can return to pre shut-in levels. The Group is also examining alternatives that would allow these fields to show a continued increase in production.

 

Sabria is our largest asset in Tunisia and remains a core asset for the Group. The Sabria field is a large discovered oil field that our Independent Reserve Engineers believe has 358 million barrels of oil originally in place. The field has only six producing wells and over the life of the field only 1.2% of the oil in place has been recovered. The Company believes that this is an excellent commercialization opportunity. We have looked at a variety of opportunities available to the Company to enhance the recovery factor. In 2019 we had our Tunisian technical teams focus on low capital but high return enhancements to the Sabria field. We believe that our work in 2019 has positioned us for further growth in 2020.

 

2019 has been an excellent year for the Company but it must be remembered that the operational successes of 2019 had their roots in the hard work that has been done by our teams in 2017 and 2018. In the same way that 2019 reflects the successes of earlier years, we are positioning Serinus for success in the future. Our seismic acquisition program will give our geological and geophysical teams the data they require to unlock more opportunities. Our work on production enhancements in Tunisia will provide the detailed knowledge of our reservoirs that will ultimately allow future drilling to unlock greater potential. Underlying all these achievements are our people. Our people are the foundation of this business and their desire to excel and prevail is what will make our successes even more profound. Without the financial governance, technical excellence and strategic insights of all of our staff in all of our offices, Serinus would not be able to look upon the future with such optimism.

 

We start a new decade in a much different position than we finished the last decade. The Company is strengthening itself and now has the capacity to look forward to new and exciting opportunities. On behalf of all of the employees of the Company I would offer thanks to our shareholders for their support as we strove to bring the Moftinu Gas Plant onstream and continue to enhance our production in Tunisia. We look forward to building on the successes of 2019 and increase the value inherent in the Company.

 

The COVID-19 outbreak is a dynamic and ongoing issue. As this outbreak evolves it will no doubt have a further effect on the global economy. Our products, oil and gas, are products whose demand is sensitive to overall economic conditions. Whilst we are a business that is always conscious of the demand and pricing for our products, our first consideration during this crisis is the safety and health of our employees. The company has put in place protocols that are relevant in each of our areas of operation such as restrictions on travel, meetings, adoption of flexible working arrangements and access to medical support as required. Given the regional disparities in the development of this outbreak the company has deferred to the advice of local authorities to manage our reactions. A key trigger to escalate the implementation of our plans has been any government decision in local jurisdictions to close schools, which has now happened in Romania, Tunisia, Canada and Poland, as a result of which we have closed our corporate offices in those countries.

 

The Company is experienced in working remotely and we believe that we have sufficient infrastructure in place that will allow the Company to continue to operate with minimal disruptions. There can be no certainty as to the development of this outbreak and the Company is carefully monitoring our operations in the field. Our operations in Tunisia are very remote and as per the internal procedures in place, we already have medical staff at our fields to monitor the health and welfare of our employees. In Romania we have arranged for a doctor to visit the Moftinu Gas Plant every other day to monitor our staff. At the time of writing we have not suffered operational interruptions, but should the situation change we have plans in place to minimize disruption. The company has also sought means to delay capital expenditures during this time of uncertainty. We will continue to monitor the situation closely while proactively assessing risk and considering options to allow our business to continue to operate, while ensuring the safety of our people.

 

Yours sincerely,

 

 

Jeffery Auld, Chief Executive Officer

24 March 2020

 

 

Report From CFO

 

During 2019 Serinus faced many challenges and made significant progress, which have translated into the financial performance for the year and position of the Group as at 31 December 2019.

 

Liquidity, Debt and Capital Resources

 

In Romania, the Group invested $3.9 million to complete the gas plant in the Moftinu field, as well as preliminary costs to drill M-1004, which was drilled in February 2020. Production from Moftinu commenced on 25 April 2019 and has been producing consistently from M-1003 and M-1007.

 

In Tunisia, the Group reopened the Chouech field in Q3 2019, which contributed 38,415 boe or 105 boe/d for 2019. Production from the Sabria field remained consistent during the year. Tunisia was a positive cash flow generating business unit for the year. With the reopening of Chouech and some planned workovers in Chouech and Sabria in 2020, we expect cash flow generation from Tunisia to improve in 2020.

 

During 2019, funds from operations improved year over year by $6.9 million to $8.1 million in 2019 (2018 - $1.2 million). Taking into consideration the movement in working capital, the cash flows generated from operating activities in 2019 were $8.8 million (2018 - used in operations: $5.9 million).

 

In March 2019 the Group undertook 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 ordinary share at an exercise price of £0.105 per share, exercisable for a period of 24 months after closing.

 

The proceeds of the equity issuance were used to fund a Senior debt repayment to the EBRD due 31 March 2019 of $2.7 million plus accrued interest. The final repayment of $2.7 million plus accrued interest was paid on 13 September 2019, leaving just the convertible debt outstanding with the EBRD. The Convertible debt is due to be repaid in four instalments commencing 30 June 2020, when 25% of the principal and accrued interest at that date will be repayable. The three remaining repayments will be made annually on 30 June. As at 31 December 2019, $7.7 million of the Convertible debt is reported as current. The Company will continue to manage its cash flow from operations to manage it obligations including all payments on the convertible debt.

 

Delays with achieving first production in Romania have resulted in a tightening cash position and breach of the financial covenant of the debt held with the EBRD throughout the year, 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)

2019

2018

Current assets

15,243

13,480

Current liabilities

32,194

28,918

Working Capital deficit

(16,951)

(15,438)

 

The working capital deficit of the Group at 31 December 2019 was $16.9 million (2018 - $15.4 million). Included in current liabilities at 31 December 2019 was $7.7 million of EBRD debt, accounts payable of $16.2 million, income taxes payable of $1.4 million, current portion of lease obligations of $0.5 million and a decommissioning provision of $6.3 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. Included in the asset retirement obligations is $1.8 million relating to Brunei, $1.0 million relating to Canada, and $3.5 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.

 

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, allowing the Group to develop Romania and achieve first production. The Company was successful in repaying the Senior Loan on schedule making one payment in March 2019 and the final payment in September 2019.

 

On 30 December 2019 the Group received a waiver from the EBRD formally waiving compliance with the financial covenants for the period ended 31 December 2019. Under the base case cashflow, the forecast indicates that the Group will be marginally in breach of the EBRD debt service covenant at 31 March 2020 but based on analysis performed, assuming business continuity plans in place are effective, it will be able to repay the 30 June 2020 instalment under the facility, and will subsequently be compliant with the EBRD covenants thereafter. In order to mitigate the potential covenant breach in March 2020, the Group has sought a further covenant waiver from the EBRD and has begun discussions with the EBRD to assess the impact of the current situation and examine options available to manage through this period of uncertainty.

 

Refer to Note 2 of the Consolidated Financial Statements for further discussion on going concern.

 

Financial Review - Year ended 31 December 2019

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)

2019

2018

Cash flow from (used in) operations

8,778

(5,913)

Changes in non-cash working capital

(670)

7,069

Funds from operations

8,108

1,156

Funds from operations per share

0.03

0.01

 

The additional funds from operations in 2019 were primarily attributable to the Romanian Moftinu field coming online in April 2019, along with the reopening of the Chouech field in the second half of the year. Funds from operations generated in Romania were $8.9 million (2018 - $4.3 million), Tunisia $3.4 million (2018 - $2.1 million) and funds used Corporately were $4.2 million (2018 - $5.2 million).

 

Production

 

Year ended 31 December

 

2019

2018

Tunisia (boe/d)

 

 

Crude oil (bbl/d)

339

254

Natural gas (Mcf/d)

534

586

Tunisia (boe/d)

428

352

 

 

 

Romania

 

 

Natural gas (Mcf/d)

5,673

-

Condensate (bbl/d)

15

-

Romania (boe/d)

961

-

 

 

 

Group

 

 

Crude oil (bbl/d)

339

254

Natural gas (Mcf/d)

6,206

586

Condensate (bbl/d)

15

-

Total group production (boe/d)

1,389

352

 

 

 

% liquids weighting

26%

72%

% gas weighting

74%

28%

 

100%

100%

 

Production saw a significant increase during 2019 as Serinus brought the Romanian Moftinu gas field on production and was able to reopen the previously shut-in Chouech production during the year. Production volumes (boe/d) increased by 1,037 to 1,389 for the year (2018 - 352).

 

Romania started production at the end of April 2019 and did not experience any interruptions to the production during the year. The Company completed a planned two-week turn around in October for regular maintenance on the gas plant. The maintenance turnaround was performed on time and under budget. During the year, the Romanian production was predominantly from two wells: M-1003 and M-1007.

 

Tunisia saw a significant improvement in the social situation and protests were reduced, as such the Company was able to restart production from the Chouech field in July 2019, bringing five wells back onto production. Production rates have not returned to pre-shut in levels due to higher than anticipated water levels. The Company also reopened one well in Ech Chouech during the year. Ech Chouech is an adjacent field to the Chouech field and was able to tie Ech Chouech into the Chouech field to sell the associated gas in November 2019.

Oil and Gas Revenue

 

Year ended 31 December

($000)

2019

2018

Oil revenue

7,617

6,216

Gas revenue

1,604

2,500

Tunisia revenue

9,221

8,716

 

 

 

Gas revenue

14,855

-

Condensate revenue

289

-

Romania revenue

15,144

-

 

 

 

Oil revenue

7,617

6,216

Gas revenue

16,459

2,500

Condensate revenue

289

-

Total group revenue

24,365

8,716

 

 

 

Liquids revenue (%)

32%

71%

Gas revenue (%)

68%

29%

 

100%

100%

 

 

 

Realized Price

 

 

Tunisia

 

 

Oil ($/bbl)

61.67

66.96

Gas ($/Mcf)

8.24

11.69

Tunisia average realized price ($/boe)

59.12

67.85

 

 

 

Romania

 

 

Gas ($/Mcf)

7.17

Condensate ($/bbl)

54.79

Romania average realized price ($/boe)

43.22

 

 

 

Group

 

 

Oil ($/bbl)

61.67

66.96

Gas ($/Mcf)

7.27

11.69

Condensate ($/bbl)

54.79

Group average realized price ($/boe)

48.12

67.85

 

Revenue during the year nearly tripled to $24.4 million (2018 - $8.7 million), mainly due to the Romanian production coming online in April 2019. The Group saw the realized price ($/boe) decrease by $19.73 to $48.12 (2018 - $67.85) due to the Group's product weighting changing to majority gas sales compared to mainly oil in the prior year as seen above.

 

Under the terms of the Sabria Concession Agreement 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 a marketing agreement with Shell International Trading and Shipping Company Limited. In 2019, the Group completed one (2018 - one) lifting, which occurred during the fourth quarter.

 

The Group is required to sell 50% of its annual gas production from the Satu Mare concession into the local commodity market, which to date has received comparable prices compared to the prices received from the sales agreement with Vitol Gas and Power B.V.

 

The Group saw a decrease in realized oil prices ($/bbl) of $5.29 to $61.67 (2018 - $66.96), and a decrease in realized natural gas prices ($/Mcf) of $4.42 to $7.27 (2018 - $11.69 or $9.80 - net of a $0.4 million one-time gain due to a change in the reference price).

Royalties

 

 

Year ended 31 December

($000)

2019

2018

Tunisia

1,057

867

Romania

803

-

Total

1,860

867

($/boe)

3.67

6.75

Tunisia (% of revenue)

11.5%

9.9%

Romania (% of revenue)

5.3%

0.0%

Total (% of revenue)

7.6%

9.9%

 

Royalties saw a significant increase for the year, up $1.0 million to $1.9 million (2018 - $0.9 million). This increase is directly attributable to the Romanian production starting in April 2019. The effective royalty rate saw a sharp decline compared to 2018 due to lower royalty rates in Romania, which accounted for 62% of the total revenue.

 

Romanian royalties are a flat 7.5% for gas revenues and 3.5% for condensate for the entire field.

 

Tunisian royalties are based on individual concession agreements. Sabria royalty rates vary 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 2019, the royalty rate in the Sabria concession was 10% for oil and 8% for gas. Chouech and Ech Chouech royalty rates are flat at 15% for both oil and gas.

 

Production Expenses

 

 

Year ended 31 December

($000)

2019

2018

Tunisia

4,606

2,990

Romania

2,332

-

Canada

47

54

Group

6,985

3,044

 

 

 

Tunisia production expense ($/boe)

29.46

23.27

Romania production expense ($/boe)

6.65

Total production expense ($/boe)

13.78

23.57

 

The Group realized a large decrease in production expenses ($/boe) of $9.79 to $13.78 (2018 - $23.57). The primary reason for the decrease is due to the production from the Romanian Moftinu field where production expenses per boe is lower than Tunisia. The Tunisian operating costs saw a minor increase due to work required to bring the Chouech field online as well as other minor workovers to help stimulate the wells.

 

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

($/boe)

2019

2018

Tunisia

 

 

Production volume (boe/d)

428

352

Realized price

59.12

67.85

Royalties

(6.76)

(6.75)

Production expense

(29.46)

(23.27)

Operating netback - Tunisia

22.90

37.83

 

 

 

Romania

 

 

Production volume (boe/d)

961

Realized price

43.22

Royalties

(2.29)

Production expense

(6.65)

Operating netback - Romania

34.28

 

 

 

Group

 

 

Production volume (boe/d)

1,389

352

Realized price

48.12

67.85

Royalties

(3.67)

(6.75)

Production expense

(13.78)

(23.57)

Operating netback - Group

30.67

37.53

 

 

The Group operating netback ($/boe) decreased by $6.86 to $30.67 (2018 - $37.53). The main contributing factor to this decrease is lower realized prices, partially offset by lower royalties and production expenses as described above.

 

General and Administrative ("G&A") Expense

 

 

Year ended 31 December

($000)

2019

2018

G&A expense

3,801

3,422

G&A expense ($/boe)

7.50

26.64

 

G&A costs had a minor increase during the year of $0.4 million to $3.8 million (2018 - $3.4 million). On a per boe basis, G&A has decreased due to the incremental production added from the Moftinu and Chouech fields during the year.

 

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.

 

Windfall Tax

 

 

Year ended 31 December

($000)

2019

2018

Windfall tax

3,155

Windfall tax ($/Mcf - Romania gas)

1.52

Windfall tax ($/boe - Romania gas)

9.14

 

In Romania, the Group is subject to a windfall tax on its natural gas production which is applied to supplemental income

once natural gas prices exceed 47.53 RON/Mwh (approximately $3.40 per mcf). This supplemental income is taxed at

a rate of 60% between 47.53 RON/Mwh and 85.00 RON/Mwh and at a rate of 80% above 85.00 RON/Mwh. Expenses

deductible in the calculation of the windfall tax include royalties and capital expenditures limited to 30% of the

supplemental income.

 

During 2019, the Group has incurred windfall taxes of $3.2 million which equates to $1.52 per mcf of Romanian gas

Share-Based Compensation

 

 

Year ended 31 December

($000)

2019

2018

Share-based compensation

528

820

Share-based compensation ($/boe)

1.04

6.38

 

Share-based compensation decreased by $0.3 million to $0.5 million (2018 - $0.8 million) due to a large number of options being cancelled during the year due to staff turnover.

 

Depletion and Depreciation

 

 

Year ended 31 December

($000)

2019

2018

Tunisia

2,576

1,586

Romania

7,216

14

Corporate

685

201

Total

10,477

1,801

 

 

 

Tunisia ($/boe)

16.48

12.35

Romania ($/boe)

20.59

Total ($/boe)

20.67

14.02

 

Depletion and depreciation expense increased for the year by $8.7 million to $10.5 million (2018 - $1.8 million). The increase is due to Depletion and depreciation incurred on the Romanian assets as the Moftinu field was brought online in April 2019. The Group also realized additional Depletion and depreciation expense related to the adoption of the new lease accounting standard (IFRS 16). On a per boe basis, the Depletion and depreciation expense also increased year over year.

 

Net Finance Expense

 

 

Year ended 31 December

($000)

2019

2018

Interest expense on long-term debt

3,319

3,212

Amortization of debt costs

144

255

Amortization of debt modification

97

44

Interest of leases

145

-

Accretion on decommissioning provision

1,224

1,030

Other interest and foreign exchange

(126)

26

 

4,803

4,567

Net finance expense for 2019 increased by $0.2 million to $4.8 million (2018 - $4.6 million). Serinus repaid the Senior loan over the course of the year in two installments, but the compounding component of the Convertible debt more than offset these interest savings. Interest from the adoption of IFRS 16 accounted for $0.1 million (2018 - $nil).

 

Decommissioning provision

 

During the year, the Group conducted a thorough analysis of the decommissioning requirements for the Tunisian business unit and determined that there were significant cost savings, based on revised abandonment procedures and cost estimates, that could be applied to the decommissioning of the fields. This resulted in a change in estimate to the decommissioning liability and to the offsetting decommissioning asset. In the case where the decommissioning asset has been fully impaired, the Group recognized this change in estimate through the Statement of Comprehensive Loss. For 2019, this amounted to $14.8 million (2018 - $0.3 million), of which $6.9 million (2018 - $0.3 million) was booked as a recovery through the Statement of Comprehensive Loss, with the remainder booked against the decommissioning asset.

 

Andrew Fairclough, Chief Financial Officer

24 March 2020
 

REVIEW OF OPERATIONS

 

Romania

· Satu Mare Block - 2,949 km2 (729 thousand gross acres) of onshore Romanian land.

· 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 S.A. The phase 1 & 2 exploration obligations were completed in April 2015, and the third exploration phase is currently ongoing. Phase 3 received a twelve-month extension to 28 October 2020, extending the Company's timing to carry out the remaining 3D seismic acquisition commitment.

 

Satu Mare Concession - History

· Serinus farmed-in to the Satu Mare Concession in 2008 and earned 60% WI by funding 100% of work commitments for Exploration Phases 1 and 2.

· The Company has a deemed 100% working interest in the concession as its partner has defaulted. The Company is working with the local authorities to have the partner's working interest officially transferred.

· 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 four 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:

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

To acquire 120 km2 of 3D Seismic.

· Phase 3 was extended to 28 October 2020.

 

Serinus completed the Moftinu Gas Plant with first gas production in April 2019. The Moftinu Gas Project is the development of the Moftinu gas field, a shallow (800-1,000m), multi-zone gas field. The field has relatively low drilling and completion costs, with strong initial well production rates. Serinus also built a 3km sales line that ties-in the major Transgaz pipeline, Abramut to 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.

 

The Moftinu gas plant was designed at a capacity of 15 MMscf/d and can accommodate up to six flowlines. During 2019, production was predominantly comprised from two wells (M-1003 and M-1007) and averaged 5.7 MMscf/d. Subsequent to the year-end, the Company drilled, completed, and tested the M-1004 well in the Moftinu field. The well tested at 6.0 MMscf/d and was connected to the gas plant and brought onto production in February 2020.

 

The Group has future capital plans to continue to develop the Satu Mare concession, which includes the completion of the 148 km2 seismic acquisition program and tentative plans to drill M-1008 in Q4 2020, dependent on available capacity of the gas plant.

 

Tunisia

 

The Group currently holds five Tunisia concessions that comprise a diverse portfolio of development and exploration assets. The Group currently produces oil and gas in three of the concessions (Sabria, Chouech, and Ech Chouech). This production can and has been sustained with low-risk development drilling but also has significant growth opportunities over the medium to long-term. The Group has no outstanding work commitments with any of their concessions.

License

Serinus Working Interest

Approximate Gross

Area (acres)

Expiry

Sabria

45% (ETAP 55%)

26,196

November 2028

Chouech Es Saida

100%

42,526

December 2027

Ech Chouech

100%

35,139

June 2022

Sanghar

100%

36,879

December 2021

Zinnia

100%

17,471

December 2020

 

Sabria

· Contains 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 million bbl 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

· In early 2020, the Group performed a coil-tubing on Win-12 bis. For the remainder of 2020, the Group will be performing artificial lift studies and surface upgrades. Beyond 2020, 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

· Produced over 9.8 million boe to date from the TAGI Formation in the Triassic reservoir

· 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 block, are emerging in Southern Tunisia as a major new oil, condensate and gas play with exploration-well success rates of nearly 100%

· For 2020, the Group is assessing different alternatives to enhance the production in the field in an effort to return to historical levels of approximately 600 boe/d

 

Ech Chouech

· Produced oil intermittently from the TAGI formation, dating back to the discovery of the field in 1970

· Adjacent to the Chouech 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 Company successfully brought the EC-1 well back on production in Q4-2019

· The Group has no work plans in 2020

· This asset was previously fully impaired in the accounts; carrying value will be reviewed dependent on the future performance of the field

 

Zinnia

· Currently non-producing block with two formerly producing oil and gas wells discovered in 1991

· Prospectively lies within an undrilled fault block that requires 3D seismic to be confidently defined

· The Group has no work plans in 2020

· This asset was previously fully impaired in the accounts

 

Sanghar

· Located 60 kms 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 historical oil 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 km2 of modern full fold vibriosis 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 2020

· This asset was previously fully impaired in the accounts

 

RESERVES

 

Company Gross Reserves - Using Forecast Prices

 

 

2019

2018

 

 

Oil/Liquids

Gas

Boe

Oil/Liquids

Gas

Boe

Change

 

(Mbbl)

(MMcf)

(Mboe)

(Mbbl)

(MMcf)

(Mboe)

 

Tunisia

Proved

 

 

 

 

 

 

 

Producing

734

1,157

927

292

687

406

128%

Non-producing

90

231

129

570

1,358

796

-84%

Undeveloped

644

1,520

897

750

1,765

1,044

-14%

Proved (1P)

1,468

2,908

1,953

1,612

3,810

2,246

-13%

Probable

4,747

10,472

6,492

4,421

10,542

6,179

5%

Proved & Probable (2P)

6,215

13,380

8,445

6,033

14,352

8,425

0%

 

 

 

 

 

 

 

 

Romania

Proved

 

 

 

 

 

 

 

Producing

12

4,220

715

-

Non-producing

-

Undeveloped

4

1,404

238

18

8,961

1,512

-84%

Proved (1P)

16

5,624

953

18

8,961

1,512

-37%

Probable

21

6,967

1,182

19

5,260

896

32%

Proved & Probable (2P)

37

12,591

2,135

37

14,221

2,408

-11%

 

 

 

 

 

 

 

 

Group

Proved

 

 

 

 

 

 

 

Producing

746

5,377

1,642

292

687

406

304%

Non-producing

90

231

129

570

1,358

796

-84%

Undeveloped

648

2,924

1,135

768

10,726

2,556

-56%

Proved (1P)

1,484

8,532

2,906

1,630

12,771

3,758

-23%

Probable

4,768

17,439

7,674

4,440

15,802

7,075

8%

Proved & Probable (2P)

6,252

25,971

10,580

6,070

28,573

10,833

-2%

 

Serinus entered 2019 under significant operational and financial challenges, although the petroleum industry in general benefited from an increasing Brent oil price from around US$60.00/bbl in January to over US$70.00/bbl in April, from which it declined before settling in a range between US$60.00- $65.00/bbl for the remainder of 2019.

 

Total corporate 1P and 2P reserves in 2019 versus 2018 decreased by 23% and 2%, respectively. There were positive and negative revisions as follows:

 

Tunisia

In Tunisia, 1P reserves decreased by 13% and 2P reserves remained flat. The change in reserves volumes are due to the following revisions:

 

Sabria:

· Positive revisions to producing wells based on 2019 performance

· Positive revisions to SAB NW1 Estimated Ultimate Recovery based on artificial lift plans

· Negative Revisions due to later drilling of Proven Underdeveloped wells vs. 2018 forecast

 

Chouech:

· Negative revisions to CS1, CS3, CS7, and CS9 due to lower than expected performance when brought back on production (although these wells have shown during past shut-ins that they can take upwards of a year to fully return to past production levels)

Ech Chouech

· EC-1 was brought back on production in 2019 and was reclassified as Proven Developed Producing from contingent resources

 

Romania

 

In Romania, 1P and 2P reserves decreased by 37% and 11%, respectively. The changes in reserves volumes are due to the following revisions:

· 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

 

 

2019

2018

 

 

Discount rates

PV 10%

(US$ millions)

0%

10%

15%

0%

10%

15%

Change

Tunisia

Proved

 

 

 

 

 

 

 

Producing

(18.6)

(7.3)

(4.1)

(10.0)

(5.1)

(3.6)

-43%

Non-producing

(0.5)

0.1

0.1

(9.2)

(1.3)

0.8

108%

Undeveloped

10.1

5.1

3.4

8.5

4.4

2.8

16%

Proved (1P)

(9.0)

(2.1)

(0.6)

(10.7)

(2.0)

-5%

Probable

113.7

62.9

46.7

99.6

58.9

44.1

7%

Proved & Probable (2P)

104.7

60.8

46.1

88.9

56.9

44.1

7%

 

 

 

 

 

 

 

 

Romania

Proved

 

 

 

 

 

 

 

Producing

14.3

13.8

13.5

-

Non-producing

-

Undeveloped

3.6

3.3

3.1

25.0

23.1

22.2

-86%

Proved (1P)

17.9

17.1

16.6

25.0

23.1

22.2

-26%

Probable

24.3

20.7

19.3

23.4

18.8

17.0

10%

Proved & Probable (2P)

42.2

37.8

35.9

48.4

41.9

39.2

-10%

 

 

 

 

 

 

 

 

Group

Proved

 

 

 

 

 

 

 

Producing

 (4.3)

6.5

9.4

(10.0)

(5.1)

(3.6)

227%

Non-producing

 (0.5)

0.1

0.1

(9.2)

(1.3)

0.8

108%

Undeveloped

13.7

8.4

6.5

33.5

27.5

25.0

-69%

Proved (1P)

8.9

15.0

16.0

14.3

21.1

22.2

-29%

Probable

138.0

83.6

66.0

123.0

77.7

61.1

8%

Proved & Probable (2P)

146.9

98.6

82.0

137.3

98.8

83.3

0%

 

Net present values at 10% for Serinus' reserves decreased by 29% for 1P reserves whilst the 2P reserves remained flat.

 

 

 

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 Sanghar field, 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 (with the exception of EC-1), 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 $6.0 million, $10.1 million and $10.1 million 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

 

Resource Volumes (Risked)

NPV (risked)

 

 

Oil/Liquids

Gas

Boe

0%

10%

15%

Likelihood

 

(Mbbl)

(MMcf)

(Mboe)

(US$ millions)

 

1C Contingent Resources

26

-

26

(0.7)

(0.6)

(0.5)

90%

2C Contingent Resources

84

-

84

(0.6)

(0.3)

(0.2)

90%

3C Contingent Resources

122

-

122

(0.2)

0.1

0.2

90%

 

 

 

 

 

 

 

 

Romania

 

Resource Volumes (Risked)

NPV (risked)

 

 

Oil/Liquids

Gas

Boe

0%

10%

15%

Likelihood

 

(Mbbl)

(MMcf)

(Mboe)

(US$ millions)

 

1C Contingent Resources

6

2,217

376

3.1

2.7

2.5

90%

2C Contingent Resources

16

5,218

886

14.3

10.4

8.9

90%

3C Contingent Resources

29

8,600

1,462

29.9

18.7

14.9

90%

 

 

 

 

 

 

 

 

Group

 

Resource Volumes (Risked)

NPV (risked)

 

 

Oil/Liquids

Gas

Boe

0%

10%

15%

Likelihood

 

(Mbbl)

(MMcf)

(Mboe)

(US$ millions)

 

1C Contingent Resources

32

2,217

402

2.4

2.1

2.0

90%

2C Contingent Resources

100

5,218

970

13.7

10.1

8.7

90%

3C Contingent Resources

151

8,600

1,584

29.7

18.8

15.1

90%

 

 

Notes to Contingent Resources Table:

1.  Contingent Resources are those quantities of petroleum estimated, as of 31 December 2019 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 2020 reserves and resources is as follows:

 

 

Brent

Sabria Gas

Chouech Gas

Romania Gas

Year

(US$/bbl)

(US$/mcf)

(US$/mcf)

(US$/mmbtu)

2020

63.00

7.90

7.05

6.54

2021

65.00

8.15

7.27

6.75

2022

68.00

8.52

7.61

7.06

2023

71.00

8.90

7.94

7.37

2024

75.50

9.46

8.45

7.83

2025

76.50

9.59

8.56

7.94

2026

78.83

9.88

8.82

8.18

2027

80.41

10.08

9.00

8.34

2028

82.02

10.28

9.18

8.51

2029

83.66

10.49

9.36

8.68

Remainder

+2.0% per year

+2.0% per year

+2.0% per year

+2.0% per year

 

 

RISK MANAGEMENT STATEMENT

 

The Group is subject to several 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 provides details as to how these are managed.

 

Risk

Description

Mitigation

Political and Regulatory Risk

Operating in multiple jurisdictions poses a variety of political, regulatory and social environments, and risks such as social unrest, political violence, corruption, expropriation and non-compliance with laws and regulations

· Actively monitors political developments and maintains relationships with government, authorities and industry bodies, as well as with other stakeholders

· 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 and Development Risk

The nature of oil and gas operations brings risks such as equipment failure, well blow-outs, fire, pollution, performance of partners/contractors, delays in installing property, plant or equipment, unknown geological conditions and failure to achieve capital costs, operating costs, production or reserves. The unprecedented global pandemic COVID-19 may impact operational performance

· Has enhanced its operating standards, reflecting the well incident in late 2017

· Has extensive monitoring and review of HSE and crisis management policies and procedures

· Carries enough levels of insurance coverage

· Rigorous tender processes when selecting vendors and contractors

· Tightly monitors costs, monitoring monthly actual to budget trends and adjusting forecasts

· Employs geological and technical experts to review data and work programs

· Has adopted additional protocols and procedures for the protection of staff and stakeholders, which follow the advice of local government and health authorities, as well as increased health monitoring of operations staff and implementing staff hygiene protocols

Capital Structure and availability of Financing

There can be no assurances that the Group can raise additional financing if required for debt repayment

· Monitors cash position, producing monthly cash projections to determine future cash flow needs

· Listed on the AIM equity market to access capital, with a successful raise in 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

· Actively monitoring the business, preparing monthly forecasts with the various sensitivities (price, interest, foreign exchange)

· The Group's financial risk policies are set out in Note 4 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, Appointed March 2016

 

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.

 

Jeffrey Auld

CEO, Executive Director, Appointed September 2016

 

Mr. Auld has been involved with the international oil and gas business for over 25 years. He has managed companies and acted as an advisor to companies operating in the emerging oil and gas market. Mr. Auld has an abundance 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

 

Eleanor Barker

Independent Director, Chair of the Audit Committee, Member of the Remuneration Committee, Member of the Nomination Committee, Member of the Reserves Committee, Appointed May 2017

 

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 Kingston, Ontario with an Honours Bachelor of Science degree, and earned her MBA from the University of Western Ontario.

 

 

Jim Causgrove

Independent Director, Chair of the Reserves Committee, Member of the Audit Committee, Appointed September 2017

 

Mr. Causgrove is an experienced Oil and Gas executive with over 35 years of 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 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 working closely with the Board of Directors.

 

Mr. Causgrove graduated with a Chemical Engineering degree from the University of Alberta and has earned his P. Eng designation in Alberta.

 

Dawid Jakubowicz

Non-Independent Director, Appointed March 2018

 

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 KPMG, where he was responsible for audit of financial statements 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.

 

Andrew Fairclough

Chief Financial Officer, Executive Director, Appointed February 2020

 

Mr. Fairclough served in the Armed Forces, prior to moving into a career in investment banking, where he worked for a number of banks in London and New York, including Flemings, Rothschild, Merrill Lynch and Espirito Santo Investment Bank, providing corporate finance and capital markets advice and execution. He subsequently moved into the oil and gas industry becoming the Chief Financial Officer of Whalsay Energy Limited, prior to joining Serinus Energy.

 

Mr. Fairclough has nearly 30 years of financial and management experience from which he brings a wide range of experience to the Group including corporate strategy and planning, debt and equity capital markets, mergers and acquisitions, capital management and restructuring.

 

Mr. Fairclough has a degree in Law from University College London and was commissioned into the Scots Guards.

 

SENIOR MANAGEMENt

 

Calvin Brackman

Vice President, External Relations & Strategy

 

Mr. Brackman has more than 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 management team and business units to develop and implement the Group's exploration and development strategies and oversee government and stakeholder relations.

 

Mr. Brackman has a Masters in Economics from the University of Waterloo and a degree 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 been an integral piece to bringing the Romanian assets from the exploration phase to production in 2019. 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. Ms. Damascan 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 B.V. 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 B.V. He has been responsible for the completion of numerous capital projects undertaken by Serinus Energy Tunisia B.V. He was also appointed to handle the technical aspect of the Moftinu Development Project in Romania.

 

Mr. Ben Hassen has over 15 years of experience in the oil and gas industry, as well as power plants and renewable energies. He has a very well-rounded breadth of knowledge including; project management, engineering, construction, completions, handover and closeout and operating, contract review, business plan development and budgeting and forecasting.

 

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

 

Arafet Mansali

Chief Operating Officer, Serinus Energy Tunisia B.V.

 

Mr. Mansali joined Serinus Energy Tunisia B.V. 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 Energy Tunisia B.V in January 2018. Prior to joining Serinus, 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 for the Company's Tunisian assets.

 

Mr. Mansali has a degree in Mechanical Engineering 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 business model which is the exploration and production of hydrocarbon resources from its current 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"), the Company was subject and followed the recommendations and rules contained within the "Code of Best Practice for WSE Listed Companies 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.

· 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 with relative experience in the upstream oil & gas environment. The Group has been structured to give the Board the necessary oversight of all investment decisions of the Group.

· 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. Providing an open environment with investors and analysts allows us to build our relationships with these audiences, while providing the opportunity to further share our business model and allows us to drive our business forward. The initiatives taken by the Company to keep investors and analysts informed are as follows:

· Investor roadshows

· Attending investor conferences

· Hosting capital markets days

· Timely disclosure of material information

· Regular reporting

 

The Directors understand the importance of building relationships with institutional shareholders and will make presentations when appropriate. The Directors welcome all feedback and concerns from shareholders and will implement the appropriate action as required. The Board is in active communication with the CEO, and other management members to ensure they are up to date on all recent corporate activities.

 

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 EBRD

· Employees

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

 

Engaging with all stakeholders strengthens our relationships and allows for better business decisions to ensure the Company delivers on our commitments to all parties

 

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

· Regular meetings with local authorities and governments providing progress updates 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 Company has a risk register that outlines the key financial and operational risks which has been circulated to all management and Board members. 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.

· The Audit Committee focuses particularly on compliance with legal requirements, accounting standards and the relevant rules for the listings the Company resides (AIM and Warsaw).

· 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 led by the chair

 

The Board comprises of a non-executive, non-independent Chairman, two Executive Directors, two non-executive independent Directors, and one non-executive non-independent Director. The Board is satisfied that it has a well-diversified and balanced team with varying levels of expertise in different facets of the business. This allows the Board to act effectively and efficiently in the best interests of the Company.

 

Directors' attendance at Board and Committee meetings during 2019 was as follows:

Director

Board

Audit
Committee

Remuneration Committee

Nomination Committee

Reserves Committee

Total Meetings

6

7

3

1

1

 

 

 

 

 

 

Jeffrey Auld

6

5

1

-

1

Lukasz Redziniak

6

2

3

1

-

Jim Causgrove

6

7

-

-

1

Eleanor Barker

6

7

3

1

1

Dawid Jakubowicz

6

3

1

-

-

Tracy Heck (1)

4

4

-

-

1

Evgenij Iorich (2)

2

2

-

-

-

1.  Tracy Heck resigned on 31 October 2019

2.  Evgenij Iorich resigned 16 May 2019

 

Key Board activities this year included:

· Continued an open dialogue with the investment community

· 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. The Board of Directors and Management Team section of this annual report contains the biographies and experience of each of the Directors and key management personnel.

 

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 financial, legal, capital markets, and technical skill sets. The Board also has one female Director as the Company believes in diversity.

 

All Directors receive regular and timely information on the Group's operational and financial performance. Board members are provided with agendas and related materials in advance of all 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.

 

New directors have access to the entire management team, and other Directors to further develop their understanding of the business operations and risks. The Directors are encouraged to seek independent advice to ensure they are able to fulfill their duties at the expense of the Company.

 

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

 

The Company is constantly assessing the individual contributions of all Board members to ensure each member:

· Is actively contributing to the success of the Company

· Is fully committed

· Is maintaining their independence

 

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. 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 if, and when required. During the year ended 31 December 2019, the Board met for its four scheduled meetings plus an additional two times.

 

The Board and the Committees are provided with the agenda and other appropriate material on a timely basis in order to prepare for each meeting. Any Director may challenge Group proposals and after all relevant discussions, are voted on. 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 and implementing and overseeing the projects as they are approved by the Board. 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, oversight of the CFO and the finance team,  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, considering 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, and the AGM. Corporate announcements, results and presentations is available 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 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. This report sets out the details of the remuneration policy for the Directors and discloses the amounts paid during the year.

 

Remuneration Committee

 

The Remuneration Committee is comprised of Lukasz Redziniak (Chairman), a non-independent non-executive Director, and Eleanor Barker, an independent non-executive Director. Other Directors are invited to attend as appropriate and only if they do not have a conflict of interest. The Committee met three times throughout the year.

 

The aim of the Remuneration Committee is to:

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

· To offer the opportunity for employees to participate in share option schemes to incentivize employees to enhance shareholder value, and to retain employees

 

To achieve the above, the Committee considers the following categories of remuneration:

i.  Annual salary and associated benefits

ii.  Share option plan and long-term share-based incentive plan

iii.  Performance based annual bonuses

 

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 other members of the executive management as  designated by the Board to consider

· Review the ongoing appropriateness and relevance of the remuneration policy

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

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

· To review and approve any, and all, termination payments

· To review and monitor the remuneration trends across the Group and if required undertake a benchmarking exercise to compare against a peer group, obtaining reliable, up to date third party remuneration

 

Directors Remuneration

 

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

Director

Salaries
and fees (1)

Benefits

Shares based Compensation (2)

2019 Total

2018 Total

Executive Directors

 

 

 

 

 

Jeffrey Auld

334,250

9,369

267,850

611,469

648,430

Tracy Heck (3)

241,701

15,113

-

256,814

526,922

 

575,951

24,482

267,850

868,283

1,175,352

 

 

 

 

 

 

Non-Executive Directors

 

 

 

 

Lukasz Redziniak

25,609

-

-

25,609

23,247

Jim Causgrove

27,870

-

8,456

36,326

31,899

Eleanor Barker

31,074

-

5,117

36,191

37,970

Dawid Jakubowicz

21,657

-

-

21,657

13,948

Evgenij Iorich (4)

6,784

-

-

6,784

28,671

 

112,994

-

13,573

126,567

135,735

 

688,945

24,482

281,423

994,850

1,311,087

1.  Director's compensation was paid in CAD for the first three quarters of the year when it was amended as per below and paid in GBP. Mr. Auld was paid in GBP for the entirety of the year. The compensation is translated using the average exchange rate for the year CAD:USD 1.3266 and GBP:USD 0.7816 (2018 - CAD:USD 0.7749 GBP:USD 1.332)

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.

3.  Tracy Heck resigned 31 October 2019

4.  Evgenij Iorich resigned 16 May 2019

During the year the fee structure for the non-executive Directors was amended effective Q4 2019. The plan prior to the amendment was as follows:

· Non-executive Directors received C$1,000 for each meeting attended as well as a C$1,000 monthly retainer. The Audit Committee Chair received an additional retainer of C$250 per month

 

The amended fee structure is as follows:

· Non-executive Directors receive a £30,000 annual fee, with each Chair receiving an additional £10,000 fee. These fees are prorated over the year

 

Directors Interests in Share Capital

 

The Group operates a share option plan such that 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 7 to the financial statements.

 

Subsequent to listing on AIM in May 2018, the Company converted its options 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 2019 and changes since 31 December 2019, up to the date of this report, for all Directors:

 

 

Options held at 31 December 2019 and 24 March 2020

Shares held at 31 December 2018

Change in ownership

Shares held at 31 December 2019 and 24 March 2020

Executive directors

 

 

 

 

Jeffrey Auld

8,000,000

22,197

22,197

 

 

 

 

 

Non-Executive directors

 

 

 

 

Jim Causgrove

100,000

Eleanor Barker

100,000

100,000

100,000

 

8,200,000

122,197

122,197

 

The Directors who held options as at 31 December 2019 and the terms of those options are as follows:'

 

 

Options held at 31 December 2019

Options held at 31 December 2018

Exercise price

Date of grant

Executive Directors

 

 

 

 

Jeffrey Auld

1,000,000

-

£0.13

03 Dec 2018

Jeffrey Auld

2,500,000

2,500,000

£0.18

03 Dec 2018

Jeffrey Auld

1,000,000

1,000,000

£0.21

31 May 2017

Jeffrey Auld

3,500,000

3,500,000

£0.18

22 Sep 2016

Tracy Heck (1)

733,333

2,200,000

£0.15

03 Dec 2018

Tracy Heck (1)

1,833,334

2,750,000

£0.21

31 May 2017

 

 

 

 

 

Non-Executive Directors

 

 

 

 

Jim Causgrove

100,000

100,000

C$0.37

31 May 2017

Elanor Barker

100,000

100,000

C$0.37

31 May 2017

Evgenij Iorich (2)

-

100,000

C$0.37

31 May 2017

 

10,766,667

12,250,000

 

 

1.  Tracy Heck resigned 31 October 2019

2.  Evgenij Iorich resigned 16 May 2019

 

 

Lukasz Redziniak, Chairman of the Remuneration Committee

24 March 2020

AUDIT COMMITTEE REPORT

 

This report addresses the responsibilities, the membership and the activities of the Audit Committee in 2019 up to the approval of the 2019 Annual Report and 2019 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.  Oversight of the appointment of the CFO

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

4.  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) and Jim Causgrove, both independent non-executive Directors. Other Directors are invited to attend as appropriate and only if they do not have a conflict of interest. The Committee met seven times throughout the year.

 

Activities in 2019

 

External Auditor

The Committee is responsible for the relationship with the external auditor. In the prior year, congruent with the Company's listing moving to the AIM, the Company transitioned to BDO as the external auditor. The Committee recommended the reappointment of BDO as the auditor for the 2019 fiscal year-end, which was approved.

 

Financial Reporting

For the 2019 fiscal year-end, the Committee has reviewed the following key audit matters:

1.  Carrying value of E&E and PP&E Assets

2.  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 lease standard (IFRS 16).

 

The Directors consider the continuing availability of the existing facilities, future covenant breaches, and cash flow forecasts 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 2019, the Committee has undertaken anti-bribery and anti-corruption exercises and has reviewed whistle blowing arrangements.

 

Conclusion

 

In 2020 and beyond, the Committee will continue to adapt to new reporting and regulatory requirements, while maintaining proper controls in order to mitigate the evolving financial risk environment.

 

 

Eleanor Barker, Chairman of the Audit Committee

24 March 2020

 

 

REPORT OF THE DIRECTORS

 

The Directors' present their report, together with the audited consolidated financial statements of Group for the year ended 31 December 2019.

 

Principal Activities

 

The principal activity of the Group is oil and gas exploration and 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.  38.09%

Canaccord Genuity Wealth Management  10.64%

JCAM Investments Ltd.  7.89%

 

Results and Dividends

 

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

 

The Directors do not recommend payment of a dividend in respect of these financial statements (2018: $nil).

 

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. 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.

 

The Group meets its day-to-day working capital requirements from net operating cash flows, cash balances, equity, and a fully drawn Convertible loan from the EBRD of $31.1 million (see note 21). As at 29 February 2020 the group had cash balances of $4.9 million.

 

The Group achieved a number of significant milestones during 2019 which have begun to make a positive impact on the financial position of the Group, bringing average production for the year to 1,389 boe/d (2018 - 352 boe/d) and gross revenues to $24.4 million (2018 - $8.7 million). During the second quarter of 2019 the construction of the gas plant in Romania was completed, and production commenced on 25 April 2019. Romanian production for the year averaged 961 boe/d, resulting in $15.2 million in gross revenues. In Tunisia, the Group reopened the Chouech field during the third quarter of 2019, resulting in additional production for the year of 105 boe/d, and bringing net production up to an average of 428 boe/d and resulting in $9.2 million in revenue attributable to the Group. The Group exited December 2019 with a production rate of 2,089 boe/d, with average production in December 2019 of 2,175 boe/d (Romania - 1,491 boe/d and Tunisia 684 boe/d). The combination of the additional production from Romania and Chouech has significantly increased the Group's cash flows.

 

During 2019, the Group met its obligations under the Senior loan ($5.4 plus accrued interest), and fully repaid the facility. The Group raised $3 million through an equity placing in March 2019 to fund an initial payment instalment, with the final payment funded through free cashflow generated from operations, as a result of establishing production in Romania and increasing production in Tunisia.

 

The Group's 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 with interest after 30 June 2020 to be paid annually on the loan repayment dates. As at 31 December 2019, the Group was not in compliance with the debt service coverage ratio, however the Group sought, and received, a waiver from the EBRD on 30 December 2019, formally waiving compliance with this covenant for the period ended 31 December 2019.

 

Under the base case cashflow, the forecast indicates that the Group will be marginally in breach of the EBRD debt service covenant at 31 March 2020 but based on analysis performed, assuming business continuity plans in place are effective, it will be able to repay the 30 June 2020 instalment under the facility, and will subsequently be compliant with the EBRD covenants thereafter. In order to mitigate the potential covenant breach in March 2020, the Group has sought a further covenant waiver from the EBRD and has begun discussions with the EBRD to assess the impact of the current situation and examine options available to manage through this period of uncertainty. The key assumptions in the base case forecasts are the operational performance at the operating fields and commodity prices.

 

However, 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 its obligations as they come due, including the future repayments of the Convertible loan, and breach future bank covenants, which represents a material uncertainty that may cast significant doubt on the ability of the Group to continue as a going concern. The full implications of COVID-19 on the performance of the business for the current year are difficult to determine at this stage. 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.

 

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

· 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

24 March 2020

 

 

 

Serinus Energy PLC

 

Serinus is a Jersey incorporated company that holds investments in wholly owned subsidiaries, which hold the rights to oil and gas assets 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 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 18 May 2018 and are listed on the WSE.

 

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

· Note 3(l) and 17 - Share capital of the Company.

· Note 2 - Going concern

· Note 4 - Risk management

 

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 2019, all relate to the Company.

 

 

 

 

Independent auditor's report to the members of Serinus Energy plc

 

Opinion

We have audited the consolidated financial statements of Serinus Energy plc (the 'Company') and its subsidiaries (the 'Group') for the year ended 31 December 2019 which comprise the consolidated statement of comprehensive income, the consolidated statement of financial position, the consolidated statement of cash flows and 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 consolidated 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 2019 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;

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 potential non-compliance with loan covenants, the sensitivity of cashflows required to continue to provide the Group with the ability to meet its obligations as they fall due and the potential impact of
COVID-19 on the Company and the international markets 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 was 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 no less than 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 Management's 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

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, which 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 indicators of potential impairment present in the current year, and as a result have performed a full impairment review. 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:

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

Considering Management's and the Board's conclusion on the appropriate identification of the Group's cash generating units ('CGUs') 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 impairment triggers present for all CGUs 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 and to third party publically available information in order to benchmark the assumptions applied by the 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 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 an 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.

 

 

Our findings

 

We found Management's conclusion that no impairment charge was required in respect of the CGU's as at 31 December 2019 to be supported by the underlying models. We found the judgments and estimates applied by Management in preparing the forecasts to be supportable.

Accounting for Decommissioning Provisions 

Management are required to identify a provision for decommissioning for all oil and gas assets under the provisions of the relevant accounting standard. The provision is determined based on the present values of the expected cashflow that are expected to be required to satisfy the decommissioning obligations. During the year Management performed a detailed review of the engineering applied in the Group's models which support the decommissioning provision and as a result of the review the level of decommissioning provision provided changed materially. 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:

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 available, third party, reports on the decommissioning of the Group's assets in order to benchmark available data for the key inputs applied 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 

Reviewed the oil services market trends over a number of years in order to assess the reasonableness of the cost assumptions applied in the model

Reviewed correspondence with relevant jurisdictional authorities with responsibility for oversight of the decommissioning provisions to assess whether Group actions were in line with informed requirements

 

We also performed the following work:

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

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

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

Verified unit costs included in the decommissioning provision calculation to supporting documentation where available and sensitised such

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

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

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.

 

Our findings

We found the key assumptions made by Management in respect of their assessment of the Group's decommissioning provision to be acceptable and appropriately disclosed.

 

Our application of materiality

 

 

 

FY 2019

Group: 1.4m

1.3% of Total Assets

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% (2018 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 $30,000 (2018 $32,000). 

Whilst materiality for the financial statements as a whole was $1.4 million, each significant component of the Group was audited to a lower level of materiality ranging from $0.6 million to $0.9 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 charts below highlight the coverage obtained from the full scope audits performed across the Group, based on Revenue and Total Assets.

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 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.

Opinions 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 Ministers 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 Group'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

24 March 2020

 

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Serinus Energy plc

 

Consolidated Financial Statements

For the year ended 31 December 2019

(US dollars in 000s)

 

Serinus Energy plc

Consolidated Statement of Comprehensive Loss for the year ended 31 December 2019

(US 000s, except per share amounts)

 

 

Note

2019

2018

 

 

Revenue, net of royalties

6

22,505

7,849

 

 

Cost of sales

 

 

 

Production expenses

 

(6,985)

(3,044)

Depletion and depreciation

12,14

(10,477)

(1,801)

Windfall tax

 

(3,155)

-

Total cost of sales

 

(20,617)

(4,845)

 

 

Gross profit

 

1,888

3,004

 

 

 

 

Administrative expenses

 

(3,801)

(3,422)

Share-based payment expense

7

(528)

(820)

Listing costs

8

(7)

(1,377)

Total administrative expenses

 

 

 

 

 

Well incident recovery

8

52

3,602

Decommissioning provision recovery

18

6,891

316

Gain on sale of assets

 

20

117

Operating income

 

 

 

 

 

Finance expense

9

(4,803)

(4,567)

Net loss before tax

 

 

 

 

 

Taxation

10

(1,652)

(1,743)

Loss after taxation attributable to equity owners of the parent

 

(1,940)

(4,890)

 

 

 

 

Other comprehensive loss

 

 

 

Other comprehensive loss to be classified to profit and loss in subsequent periods:

 

 

 

Foreign currency translation adjustment

 

(243)

  -

Total comprehensive loss for the year attributable to equity owners of the parent

 

(2,183)

(4,890)

 

 

Loss per share:

 

 

 

Basic and diluted

11

(0.01)

(0.03)

The accompanying notes on pages 6 to 34 form part of the consolidated financial statements

 

 

Serinus Energy plc

Consolidated Statement of Financial Position as at 31 December 2019

(US 000s, except per share amounts)

As at

Note

 31 December 2019

 31 December 2018

 

 

Non-current assets

 

 

 

Property, plant and equipment

12

93,396

107,541

Exploration and evaluation assets

13

1,004

-

Right-of-use assets

14

817

-

Total non-current assets

 

95,217

107,541

 

 

Current assets

 

 

 

Restricted cash

15

1,122

1,054

Trade and other receivables

16

11,341

10,143

Cash and cash equivalents

 

2,780

2,283

Total current assets

 

15,243

13,480

Total assets

 

110,460

121,021

 

 

Equity

 

 

 

Share capital

17

377,942

375,208

Warrants

17

97

-

Share-based payment reserve

 

23,835

23,307

Cumulative translation reserve

 

(243)

-

Accumulated deficit

 

(387,113)

(385,173)

Total Equity

 

14,518

13,342

 

 

Liabilities

 

 

 

Non-current liabilities

 

 

 

Decommissioning provision

18

25,304

36,573

Deferred tax liability

19

13,392

13,154

Lease liabilities

20

342

-

Long-term debt

21

23,387

27,667

Other provisions

22

1,323

1,367

Total non-current liabilities

 

63,748

78,761

 

 

Current liabilities

 

 

 

Current portion of decommissioning provision

18

6,334

8,696

Current portion of lease liabilities

20

534

-

Current portion of long-term debt

21

7,709

5,624

Accounts payable and accrued liabilities

23

17,617

14,598

Total current liabilities

 

32,194

28,918

Total liabilities

 

95,942

107,679

Total liabilities and equity

 

110,460

121,021

The accompanying notes on pages 6 to 34 form part of the consolidated financial statements

 

These consolidated financial statements were approved by the Board of Directors and authorized for issue on 24 March 2020 and were signed on its behalf by:

 

 

 

 

 

 

 

ELEANOR BARKER

DIRECTOR, CHAIR OF THE AUDIT COMMITTEE

 

JEFFREY AULD

DIRECTOR AND CEO

Serinus Energy plc

Consolidated Statement of Shareholder's Equity for the year ended 31 December 2019

(US 000s, except per share amounts)

 

 

Note

Share capital

Share-based payment reserve

Warrants

Accumulated deficit

Accumulated other comprehensive loss

Total

 Balance at 31 December 2017

 

362,534

22,487

-

(381,317)

-

3,704

 Initial application of IFRS 9

3

 

 

 

1,034

-

1,034

 Balance at 1 January 2018

 

362,534

22,487

-

(380,283)

-

4,738

 Comprehensive loss for the year

 

-

-

-

(4,890)

-

(4,890)

 Transactions with equity owners

 

 

 

 

 

 

 

 Share issue, net of issue costs

17

12,674

-

-

-

-

12,674

 Share-based payment expense

7

-

820

-

-

-

820

 Balance at 31 December 2018

 

375,208

23,307

-

(385,173)

-

13,342

 Comprehensive loss for the year

 

-

-

-

(1,940)

-

(1,940)

 Other comprehensive loss for the year

-

-

-

-

(243)

(243)

 Transactions with equity owners

 

 

 

 

 

 

 

 Shares issued

17

2,903

-

-

-

-

2,903

 Share issue costs

17

(170)

-

-

-

-

(170)

 Warrant issue

17

-

-

97

-

-

97

 Warrants exercised

17

1

-

-

-

-

1

 Share-based payment expense

 

-

528

-

-

-

528

 Balance at 31 December 2019

 

377,942

23,835

97

(387,113)

(243)

14,518

The accompanying notes on pages 6 to 34 form part of the consolidated financial statements

 

Serinus Energy plc

Consolidated Statement of Cash Flows for the year ended 31 December 2019

(US 000s, except per share amounts)

 

 

Note

2019

2018

 

 

Operating activities

 

 

 

Loss for the period

 

(1,940)

(4,890)

Items not involving cash:

 

 

 

Depletion and depreciation

12,14

10,477

1,801

Accretion expense

9

1,224

1,030

Decommissioning provision recovery

18

(6,891)

(316)

Gain on disposition

 

(20)

(117)

Share-based payment expense

7

528

820

Foreign exchange unrealized (gain) loss

 

(123)

211

Change in other provisions

22

(44)

(49)

Current tax expense

10

1,414

2,089

Deferred tax recovery

19

238

(346)

Interest and amortization expense

9

3,560

3,493

Income taxes paid

 

(315)

(2,540)

Expenditures on decommissioning liabilities

18

-

(30)

Funds from operations

 

Changes in non-cash working capital

26

670

(7,069)

Cashflows from (used in) operating activities

 

8,778

(5,913)

 

 

Financing activities

 

 

 

Proceeds from equity issuance

17

3,000

13,475

Share issue costs

17

(170)

(801)

Warrants exercised

17

1

-

Repayment of long-term debt

21

(5,400)

-

Interest paid on long-term debt

9

(355)

(436)

Payments on lease obligations

20

(466)

-

Cashflows (used in) from financing activities

 

(3,390)

12,238

 

 

Investing activities

 

 

 

Property, plant and equipment expenditures

12

(4,888)

(11,396)

Interest earned on restricted cash

15

(22)

(44)

Proceeds on disposition of property, plant and equipment

 

20

117

Cashflows used in investing activities

 

(4,890)

(11,323)

 

 

Impact of foreign currency translation on cash

 

(1)

29

Change in cash and cash equivalents

 

Cash and cash equivalents, beginning of year

 

2,283

7,252

Cash and cash equivalents, end of year

 

2,780

2,283

The accompanying notes on pages 6 to 34 form part of the consolidated financial statements

1.  General information
 

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

 

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. holds a 38.09% investment in Serinus as of 31 December 2019.

 

The consolidated financial statements for Serinus include the accounts of the Group and its subsidiaries for the years ended 31 December 2019 and 2018.

 

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 2019 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 applied in accordance with the provisions of the Companies (Jersey) Law 1991.

 

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. 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.

 

The Group meets its day-to-day working capital requirements from net operating cash flows, cash balances, equity, and a fully drawn Convertible loan from the EBRD of $31.1 million (see note 21). As at 29 February 2020 the group had cash balances of $4.9 million.

 

The Group achieved a number of significant milestones during 2019 which have begun to make a positive impact on the financial position of the Group, bringing average production for the year to 1,389 boe/d (2018 - 352 boe/d) and gross revenues to $24.4 million (2018 - $8.7 million). During the second quarter of 2019 the construction of the gas plant in Romania was completed, and production commenced on 25 April 2019. Romanian production for the year averaged 961 boe/d, resulting in $15.2 million in gross revenues. In Tunisia, the Group reopened the Chouech field during the third quarter of 2019, resulting in additional production for the year of 105 boe/d, and bringing net production up to an average of 428 boe/d and resulting in $9.2 million in revenue attributable to the Group. The Group exited December 2019 with a production rate of 2,089 boe/d, with average production in December 2019 of 2,175 boe/d (Romania - 1,491 boe/d and Tunisia 684 boe/d). The combination of the additional production from Romania and Chouech has significantly increased the Group's cash flows.

 

During 2019, the Group met its obligations under the Senior loan ($5.4 plus accrued interest), and fully repaid the facility. The Group raised $3 million through an equity placing in March 2019 to fund an initial payment instalment, with the final payment funded through free cashflow generated from operations, as a result of establishing production in Romania and increasing production in Tunisia.

 

The Group's 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 with interest after 30 June 2020 to be paid annually on the loan repayment dates. As at 31 December 2019, the Group was not in compliance with the debt service coverage ratio, however the Group sought, and received, a waiver from the EBRD on 30 December 2019, formally waiving compliance with this covenant for the period ended 31 December 2019.

 

Under the base case cashflow, the forecast indicates that the Group will be marginally in breach of the EBRD debt service covenant at 31 March 2020 but based on analysis performed, assuming business continuity plans in place are effective, it will be able to repay the 30 June 2020 instalment under the facility, and will subsequently be compliant with the EBRD covenants thereafter. In order to mitigate the potential covenant breach in March 2020, the Group has sought a further covenant waiver from the EBRD and has begun discussions with the EBRD to assess the impact of the current situation and examine options available to manage through this period of uncertainty. The key assumptions in the base case forecasts are the operational performance at the operating fields and commodity prices.

 

However, 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 its obligations as they come due, including the future repayments of the Convertible loan, and breach future bank covenants, which represents a material uncertainty that may cast significant doubt on the ability of the Group to continue as a going concern. The full implications of COVID-19 on the performance of the business for the current year are difficult to determine at this stage. 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 Group and all subsidiaries. Subsidiaries are entities over which the Group 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 Holdings Limited, Serinus Petroleum Consultants Limited and Serinus B.V. Through Serinus Holdings Limited, the Group has the following indirect wholly-owned subsidiaries, SE Brunei Limited and AED South East Asia Ltd., which held the Group's interests in Brunei Block L, and KOV Borneo Limited, which held the Group's interest in Brunei Block M. Through Serinus B.V., Serinus has one wholly-owned subsidiary Serinus Tunisia B.V. and 99.9995% of Serinus Energy Romania S.A. Serinus Tunisia B.V. owns the remaining 0.0005% of Serinus Romania S.A.

 

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 Loss.

 

Basis of consolidation

 

Where the Group has control over an investee, it is 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 as 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.

 

(c)  Foreign currency

 

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 Loss. During the year the functional currencies for the Romanian and Canadian subsidiaries were amended to the Leu and Canadian Dollar, respectively. These changes were required due to the nature of each business unit, the currency that the business conducts its operations in, and the currency of the country it is situated in.

 

(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 barrel ("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)  Windfall tax

 

Within the Romanian CGU, the Group recognizes windfall tax on a production basis and is shown as a cost of sale.

 

(f)  Share-based compensation

 

The Group 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.

 

(g)  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 loss, in which case the current and deferred taxes are also recognized directly in equity or other comprehensive loss, 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.

 

(h)  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.

 

 

 

(i)  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.

 

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, lease 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.

 

 

 

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.

 

 

(j)  Exploration and evaluation ("E&E") and Property, plant and equipment ("PP&E")

 

i.  Exploration and evaluation 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.

 

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

 

E&E 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, E&E 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 E&E assets to a separate category within PP&E referred to as oil and natural gas interests.

 

ii.  Development and production costs

 

Items of PP&E, 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. PP&E is comprised of drilling and well servicing assets, office equipment and other corporate assets. When significant parts of an item of PP&E, 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 PP&E, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of PP&E 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 PP&E 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 PP&E 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 ("mcf") 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 PP&E 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 PP&E 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 (CGUs). The Group's CGUs 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 CGUs 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 if no impairment loss had been recognized.

 

vi. Corporate assets

 

Corporate assets consist primarily of office equipment, and computer hardware. 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.

 

 

 

(k)  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 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. Downward revisions to the liability in cases when the full decommissioning asset has been impaired, the resulting change in estimate will flow through the Statement of Comprehensive Loss.

 

(l)  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.

 

(m)  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.

 

(n)  Warrants

 

Warrants are classified as equity. Incremental costs directly attributable to the issuance of warrants are recognized as a deduction from equity, net of any tax effects. 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.

 

 

 

(o)  Dividends

 

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

 

(p)  Changes to accounting policies

 

IFRS 16 Leases

 

In January 2016, the IASB issued IFRS 16 "Leases" ("IFRS 16"), which requires entities to recognize right-of-use ("ROU") assets and lease obligations on the statement of financial position. Serinus adopted IFRS 16 on 1 January 2019 using the modified retrospective approach. The modified retrospective approach does not require restatement of prior period financial information, instead recognizing the cumulative effect as an adjustment to the opening retained earnings and the Group applied the standard prospectively. Serinus does not participate in any lease agreements where it acts as a lessor or intermediate lessor.

 

Serinus has applied the standard while using the following optional expedients permitted under the standard:

 

· Short-term leases - those with terms of 12 months or less at date of adoption

· Low-value leases - those with a value less than US $5,000

 

On 1 January 2019, the Group recognized a cumulative increase to ROU assets of $1.2 million for leases previously classified as operating leases, directly offset to the lease obligations. The weighted average incremental borrowing rate used to determine the lease obligation at adoption was approximately 17.1%. The assets and lease obligations related to the adoption of IFRS 16, relate to office leases and vehicles.

 

The Company depreciates the ROU assets on a straight-line basis over the length of the lease unless management determines this is not representative of the useful life, in which case, management will estimate the useful life of the asset to be used.

 

The following table reconciles the minimum lease commitments disclosed in the Group's 31 December 2018 annual financial statements to the amount of lease liabilities recognised on 1 January 2019:

 

($000)

1 January 2019

Minimum operating lease commitment at 31 December 2018

1,097

Less: short-term leases not recognised under IFRS 16

(4)

Less: low value leases not recognised under IFRS 16

-

Plus: effect of extension options reasonably certain to be exercised

270

Undiscounted lease payments

1,363

Less: effect of discounting using the incremental borrowing rate as at the date of initial application

(204)

Lease liabilities for leases classified as operating type under IAS 17

1,159

Plus: leases previously classified as finance type under IAS 17

-

Lease liability as at 1 January 2019

1,159

 

 

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 USD 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

2019

2018

GBP

(19)

(3)

CAD

131

139

LEU

199

36

TND

60

(84)

Impact on profit

371

88

 

Interest rate risk

 

The Group's interest rate risk arises from the floating rate on the Convertible Loan. The Convertible loan's interest rate 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 loss before income taxes for the year ended 31 December 2019 would be $0.3 million (2018 - $0.3 million).

 

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 Romania, along with receivables from joint venture partners in Tunisia.

 

Management believes that the Group's exposure to credit risk is manageable, as commodities sold are under contract or payment within 30 days. Commodities are sold with reputable parties and collection is prompt based on the individual terms with the parties. For the year ended 31 December 2019, Tunisia's revenue was generated from three customers (2018 - three), with a 62%, 21%, and 17% weighting (2018 - 46%, 29% and 25%). Romania's sales were made to two customers (2018 - nil), with a 98% and 2% weighting (2018 - nil%). At 31 December 2019, the Group had $0.3 million (31 December 2018 - $0.6M) 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 (31 December 2018 - $nil). Subsequent to the year end, all revenue receivable has been collected in full. Substantially all receivables from joint venture partners are with government agencies which minimizes credit risk.

 

The Company manages its current VAT receivables by submitting VAT returns on a monthly basis. This allows the Company to receive the VAT in a timely matter while any amounts that may come under scrutiny, only delays one month's refund.

 

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 working capital, development costs, and 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 debt follow the schedule provided in note 21. 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.

 

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 2019 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. 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. As at 31 December 2019 the Company is continuing discussions with the government to have the partners working interest transferred to Serinus, and the Company remains optimistic the working interest will be transferred and approved by 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 operation. 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.

 

(c)  Oil and gas activities

 

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 Group 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.

 

(j)  Right-of-use assets and lease obligations

 

The measurement of ROU assets and the corresponding obligations are subject to managements judgement of the applicable incremental borrowing rate and the expected lease term. The net book value of the ROU assets, lease obligations, and interest and depreciation expense may differ due to changes in the expected lease terms. In applying the discount rate, management has applied internally calculated weighted average cost of capital on an entity by entity basis. The lease term is determined to be the length of the lease contract, but when management does not believe these terms represent the useful life of the asset, an internally estimated useful life is applied.

 

5.  Revenue, net of royalties

 

Year ended 31 December

2019

2018

Petroleum and natural gas revenues

24,365

8,716

Royalties

(1,860)

(867)

Revenue, net of royalties

22,505

7,849

 

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, and 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. The disaggregation of revenue by major products and geographical market is included in the segment note (see note 29).

 

As at 31 December 2019, the receivable balance related to contracts with customers, included within accounts receivable is $4.2 million (31 December 2018 - $1.9 million).

 

6.  Share-based payment expense

 

The Group 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 Group 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 GBP 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 GBP represents a modification to the share-based payment arrangement. The Group 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 2019 was £0.13 per option (31 December 2018 - £0.12 per option) using the following assumptions:

 

Inputs used in the Black-Scholes model

2019

2018

Risk-free interest rate

0.91%

1.33%

Expected dividend yield

nil

nil

Expected volatility

76%

77%

Forfeiture rate

5%

5%

Expected option life (in years)

10.0

10.0

 

A summary of the changes to the option plans during the year ended 31 December 2019, are presented below:

 

(a)  USD denominated options

 

 

2019

2018

 

 

Number of options

Weighted average exercise price (USD)

Number of options

Weighted average exercise price (USD)

Balance, beginning of year

-

-

67,000

3.68

Expired

-

-

(67,000)

3.68

Balance, end of year

-

-

-

-

 

(b)  CAD denominated options

 

 

2019

2018

 

Number of options

Weighted average exercise price (CAD)

Number of options

Weighted average exercise price (CAD)

Balance, beginning of year

300,000

0.37

9,933,000

0.36

Forfeited

(100,000)

(0.37)

(1,043,000)

0.37

Converted to GBP

-

-

(8,590,000)

0.36

Balance, end of year

200,000

0.37

300,000

0.37

 

As at 31 December 2019 there are 200,000 (2018 - 300,000) options outstanding to non-executive directors with a weighted average contractual life of 2.7 (2018 - 3.6) years and a weighted average exercise price of CA$0.37 (2018 - CA$0.37).

 

 

 

(c)  GBP denominated options

 

 

2019

2018

 

Number of options

Weighted average exercise price (GBP)

Number of options

Weighted average exercise price (GBP)

Balance, beginning of year

14,793,000

0.18

-

-

Granted

2,280,000

0.12

6,203,000

0.15

Converted from CAD

-

-

8,590,000

0.20

Expired

(616,668)

(0.22)

-

-

Forfeited

(3,376,665)

(0.16)

-

-

Balance, end of year

13,079,667

0.17

14,793,000

0.18

 

As at 31 December 2019 there are 13,079,667 (2018 - 14,793,000) options outstanding to executive directors and employees with a weighted average contractual life of 4.5 (2018 - 6.5) years and a weighted average exercise price of £0.17 (2018 - £0.18).

 

GDP denominated option breakdown

Exercise price (GBP)

Options outstanding

Options exercisable

Weighted average contractual life (years)

 

0.00 - 0.10

50,000

16,667

9.7

 

0.10 - 0.20

9,046,333

7,031,999

5.4

 

0.20 - 0.30

3,983,334

3,266,668

2.4

 

 

13,079,667

10,315,334

4.5

 

7.  Other expenses and income

 

(a)  Well incident recovery

 

Year ended 31 December

2019

2018

Well incident recovery

52

3,926

Well incident expense

-

(324)

 

52

3,602

 

In December 2017, an unexpected gas release occurred at the M-1001 well and ignited. The costs associated with bringing the well under control were recorded in 2017. The Group 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 $4.0 million.

 

The Group also submitted insurance claims for the cost of re-drilling a replacement well, M-1007. An interim claim of $2.9 million was recognized as a receivable at 31 December 2018. The insurance claim has been finalized and all cash has been collected during 2019.

 

(b)  Listing costs

 

Listing costs include costs associated with the continuance of the Group 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.

 

 

 

8.  Finance expense

 

Year ended 31 December

Note

2019

2018

Interest expense on long-term debt

21

3,319

3,212

Amortization of debt costs

21

144

255

Amortization of debt modification

21

97

44

Interest of leases

20

145

-

Accretion on decommissioning provision

18

1,224

1,030

Other interest and foreign exchange

 

(126)

26

 

 

4,803

4,567

 

9.  Taxation

 

 

Note

2019

2018

Current income tax expense

 

1,414

2,089

Deferred income tax expense (recovery)

19

238

(346)

 

 

1,652

1,743

 

Reconciliation of the effective tax rate:

Year ended 31 December

2019

2018

Loss before income taxes

(288)

(3,147)

Statutory tax rate

0.0%

0.0%

Expected income tax reduction

-

-

Non-deductible expenditures

489

4,802

Losses utilized

(33)

-

Tax rate differences

2,774

(3,814)

Other

967

2,521

Net change in tax attributes not recognized

(2,545)

(1,766)

Income tax expense

1,652

1,743

 

As a result of the Company's continuance from being a Canadian incorporated entity to a Jersey incorporated entity, the statutory tax rate was reduced from 27% to 0%. 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 Group which occurred prior to the continuance. Net change in tax attributes not recognized relates to tax losses that expired during the year.

 

10.  Loss per share

 

Year ended 31 December

 

 

(000's, except per share amounts)

2019

2018

Loss for the year

(1,940)

(4,890)

 

 

 

Weighted average shares outstanding

 

 

Basic and dilutive (1)

234,211

192,113

Loss per share - basic and diluted

(0.01)

(0.03)

(1) For the year ended 31 December 2019, there were 10.3 million weighted average stock options exercisable that were excluded from the calculation as the impact was anti-dilutive (31 December 2018 - 6.1 million).

 

In determining diluted net loss per share, the Group assumes that the proceeds received from the exercise of "in-the-money" stock options are used to repurchase common shares at the average market price. In calculating the weighted-average number of diluted common shares outstanding for the year ended 31 December 2019, the Group excluded all stock options as their exercise price was greater than the average common share market price during the year. The total stock options excluded were 13.3 million stock options (31 December 2018 - 15.1 million).

11.  Property, plant and equipment
 

 

Oil and gas interests

Corporate assets

Total

Cost or deemed cost:

 

 

 

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

Capital expenditures

3,856

35

3,891

Change in decommissioning provision

(7,886)

-

(7,886)

Disposals

-

(62)

(62)

Balance as at 31 December 2019

256,234

2,552

258,786

 

 

 

 

Accumulated depletion and depreciation

 

 

 

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)

Depletion and depreciation

(9,683)

(277)

(9,960)

Disposals

-

62

62

Balance as at 31 December 2019

(163,048)

(2,152)

(165,200)

 

 

 

 

Cumulative translation adjustment

 

 

 

Balance as at 31 December 2018

-

-

-

Currency translation adjustments

(212)

22

(190)

Balance as at 31 December 2019

(212)

22

(190)

 

 

 

 

Net book value

 

 

 

Balance as at 31 December 2018

106,899

642

107,541

Balance as at 31 December 2019

92,974

422

93,396

 

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

 

Year ended 31 December

2019

2018

Development expenditures

4,888

10,758

Changes in non-cash working capital

-

638

Development cash payments

4,888

11,396

 

Future development costs associated with the proved plus probable reserves are included in the calculation of the Group's depletion. The future development costs for Tunisia are $42.2 million (31 December 2018 - $55.6 million) and for Romania are $12.4 million (2018 - $nil).

 

As at 31 December 2019 all insurance proceeds had been collected relating to the well blow-out and the drilling of M-1007. The insurance proceeds have been offset against the capital costs to drill M-1007 as this well was drilled to replace the M-1001.

 

The Company has realized a change in estimate related to the decommissioning liability (note 18). This resulted in a decrease to the decommissioning asset related to this liability of $7.9 million (2018 - $1.0 million).

 

Impairment

 

At 31 December 2019, the Company completed an evaluation on its PP&E for indicators of any possible impairment or impairment reversals. Due to the decrease in the commodity price the Company deemed there were indicators of impairment. An impairment test was conducted on all CGUs, but no impairment was recognized as the estimated recoverable amount of each CGU exceeded the carrying value. The Company determined the estimated recoverable amount based on a discounted cash flow, using an after-tax discount rate equal to the weighted average cost of capital of each subsidiary (Romania - 12%, Tunisia - 22%).

 

The following commodity prices obtained from RPS Group were used in the discounted cash flow model:

 

 

Brent

Sabria Gas

Chouech Gas

Romania Gas

Year

(US$/bbl)

(US$/mcf)

(US$/mcf)

(US$/mmbtu)

2020

63.00

7.90

7.05

6.54

2021

65.00

8.15

7.27

6.75

2022

68.00

8.52

7.61

7.06

2023

71.00

8.90

7.94

7.37

2024

75.50

9.46

8.45

7.83

2025

76.50

9.59

8.56

7.94

2026

78.83

9.88

8.82

8.18

2027

80.41

10.08

9.00

8.34

2028

82.02

10.28

9.18

8.51

2029

83.66

10.49

9.36

8.68

Remainder

+2.0% per year

+2.0% per year

+2.0% per year

+2.0% per year

 

Although the discounted cash flow indicated no impairment or reversal of impairment for the year ended 31 December 2019, the following table provides a sensitivity of the estimated recoverable amount with any changes to the key assumptions used in the model.

 

 

1% increase to discount rate

1% decrease to discount rate

5% increase to commodity prices

5% decrease to commodity prices

Additional impairment, net of tax

(0.1)

-

-

(1.0)

 

The results of the impairment tests completed by management are sensitive to changes with regards to any of the key assumptions such as, commodity prices, expected royalties, future development costs, change in reserves, or the expected future operating costs. Any changes to the assumptions could increase or decrease the expected recoverable amounts from the assets and may result in impairment or potential reversal of impairment.

 

12.  Exploration and Evaluation assets

 

Carrying amount

 

Balance, beginning of the year

-

Additions

997

Cumulative translation adjustment

7

Balance, end of the year

1,004

 

The Company currently has land rights to a large amount of undeveloped land in Romania. In conjunction with the final commitment for the Romania concession, the Company is currently undertaking a 3D seismic acquisition program to the north of the operating Moftinu field. During the year, the initial preparations were initiated, while the project is anticipated to be finalized in the first half of 2020.

 

 

 

13.  Right-of-use assets

 

The following table details the cost and accumulated depreciation of the ROU assets:

 

 

Buildings

Vehicles

Total

Cost

 

 

 

Balance as at 31 December 2018

-

-

-

Additions

1,293

39

1,332

Balance as at 31 December 2019

1,293

39

1,332

 

 

 

 

Accumulated depreciation

 

 

 

Balance as at 31 December 2018

-

-

-

Depreciation

(504)

(13)

(517)

Balance as at 31 December 2019

(504)

(13)

(517)

 

 

 

 

Cumulative translation adjustment

 

 

 

Balance as at 31 December 2018

-

-

-

Currency translation adjustments

2

-

2

Balance as at 31 December 2019

2

-

2

 

 

 

 

Carrying amounts

 

 

 

Balance as at 31 December 2018

-

-

-

Balance as at 31 December 2019

791

26

817

 

14.  Restricted cash

 

The Group has cash on deposit with the Alberta Energy Regulator of $1.1 million (2018 - $1.1 million), as required to meet future abandonment obligations existing on certain oil and gas properties in Canada (see note 18). This deposit accrues nominal interest. The fair value of restricted cash approximates the carrying value.

 

15.  Trade and other receivables

 

As at 31 December

2019

2018

Trade receivables

5,793

2,930

VAT receivable

2,780

2,701

Insurance receivable

-

2,881

Corporate tax receivable

1,452

1,357

Prepaids and other

1,316

274

 

11,341

10,143

 

The trade receivables consist of commodity sales in both Romania and Tunisia. The Group has not taken any ECLs as the Company has received in full all revenue receivables subsequent to the year end. The VAT receivable relates to operating and development costs in Romania and are recovered through the Romanian government. The Company is currently awaiting an audit for the VAT returns predominantly related to the periods prior to production commencing. This portion of the VAT receivable amounts to $2.5 million, which the Company believes is fully recoverable.

 

16.  Shareholder's capital

 

Authorized

 

The Group 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

2019

2018

 

Number of shares

Amount ($000s)

Number of shares

Amount ($000s)

Balance, beginning of the year

217,318,805

375,208

150,652,138

362,534

Issued for cash

21,553,583

2,903

66,666,667

13,475

Issuance costs, net of tax

-

(170)

-

 (801)

Warrants exercised

8,897

1

-

-

Balance, end of the year

238,881,285

377,942

217,318,805

375,208

 

Warrants

 

Year ended 31 December 2019

Number of Warrants

Amount ($000s)

Balance, beginning of the year

-

-

Issued with shares

2,263,126

97

Warrants exercised

 (8,897)

-

Balance, end of the year

2,254,229

97

 

Along with the share issuance in March 2019, the company issued 0.105 share purchase warrants for each unit, totaling 2,263,126 warrants. The warrants were valued using the Black-Scholes pricing model using the following assumptions:

 

Inputs used in the Black-Scholes model

 

Risk-free interest rate

3.91%

Expected dividend yield

nil

Expected volatility

54%

Expected warrant life (in years)

2.0

 

17.  Decommissioning provision

 

As at 31 December

2019

2018

Balance, beginning of the year

45,269

45,681

Liabilities incurred

-

1,101

Liabilities settled

-

(30)

Accretion

1,224

1,030

Change in estimate (1)

(14,777)

(2,411)

Foreign currency translation

(78)

(102)

Balance, end of year

31,638

45,269

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

 

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 as at 31 December 2019 the decommissioning provisions of Brunei's Block L, Block M and the wells in Canada to be $2.8 million (2018 - $2.8 million). These obligations are reported as current liabilities as they relate to non-producing properties or expired production sharing contracts.

 

The Group has been in contact with the Alberta Energy Regulator with regards to the abandonment and reclamation of the Canadian assets.

 

 

As at 31 December

2019

2018

Tunisia

26,137

39,929

Romania

2,687

2,560

Brunei

1,801

1,801

Canada

1,013

979

 

31,638

45,269

Due within one year

6,334

8,696

Long-term liability

25,304

36,573

 

31,638

45,269

 

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

 

As at 31 December

2019

 

2018

 

Net present value

Risk-free
rate (%)

Inflation rate (%)

Net present value

Risk-free
rate (%)

Inflation rate (%)

Tunisia

26,137

2.7 - 3.1

2.3

39,929

2.7 - 3.1

1.9

Romania

2,687

3.4 - 4.8

2.5

2,560

4.3

2.5

Brunei

1,801

1,801

Canada

1,013

979

 

31,638

 

 

45,269

 

 

 

During the year, the Group conducted a thorough analysis of the decommissioning requirements for the Tunisian business unit and determined that there were significant cost savings, based on revised abandonment procedures and cost estimates, that could be applied to the decommissioning of the fields. This resulted in a change in estimate to the decommissioning liability and to the offsetting decommissioning asset. In the case where the decommissioning asset has been fully impaired, the Group recognized this change in estimate through the Statement of Comprehensive Loss. For 2019, this amounted to $14.8 million (2018 - $0.3 million), of which $6.9 million (2018 - $0.3 million) was booked as a recovery through the Statement of Comprehensive Loss, with the remainder booked against the decommissioning asset.

 

18.  Deferred income tax

 

The deferred taxes are recognized on a taxable body basis, specifically on an entity by entity basis with the exception of Tunisia. Tunisia taxes each concession on a standalone basis, and therefore the deferred taxes are determined on each concession.

 

Movement in deferred income tax balances:

 

Tax effect related to:

31 December 2018

Recovery/ (expense)

31 December 2019

PP&E and E&E assets

(18,288)

1,326

(16,962)

Decommissioning provision

4,102

(441)

3,661

Other

1,032

(1,123)

(91)

Deferred income tax liability

(13,154)

(238)

(13,392)

 

 

 

 

Tax effect related to:

31 December 2017

Recovery/ (expense)

31 December 2018

PP&E and E&E assets

(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)

 

Unrecognized deferred tax assets

 

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

 

As at 31 December

2019

2018

PP&E and E&E assets

(5,447)

5,588

ROU assets

(376)

-

Lease liabilities

349

-

Decommissioning provision

6,886

10,198

Non-capital losses carried forward and other

11,006

36,057

Unrecognized deferred tax asset

12,418

51,843

 

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

 

The Group has Canadian non-capital losses of $0.6 million (2018 - $0.1 million), Cyprus tax losses of $7.7 million (2018 - $8.0 million) that expire between 2020 and 2025, Tunisian losses of $8.2 million that expire in four years and $6.7 million have no expiry date (2018 - $13.7 and $6.7 million respectively), and Romanian losses of $5.4 million (2018 - $7.6 million) that expire after seven years between 2020 to 2026.

 

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.

 

19.  Lease liabilities

 

The following table details the movement in the Group's lease obligations for the period ended 31 December 2019:

 

Balance, 1 January 2019

1,159

Additions

173

Payments

 (466)

Cumulative translation adjustment

10

Balance, end of the year

876

Lease liabilities due within one year

534

Lease liabilities due beyond one year

342

 

The Group has elected to exclude short-term leases and low-value leases from the Group's Lease liabilities. Payments towards short-term leases, and leases of low-value assets for the year ended 31 December 2019 were nominal and have been included in G&A expense in the Statement of Comprehensive Loss. The Group's short-term leases and leases of low-value consist of leases primarily of office equipment.

 

The following table details the future cash settlement for the outstanding lease liabilities at 31 December 2019:

 

As at 31 December 2019

 1 Year

 1-3 Years

 Beyond 3 Years

 Total

 Carrying Value

Lease liabilities

622

172

231

1,025

876

 

 

 

20.  Long term debt

 

As at 31 December

2019

2018

Senior loan (1)

-

5,521

Convertible loan (2)

32,196

29,111

Debt-principal balance

32,196

34,632

Unamortized discounts and debt costs

(207)

(351)

Modification gain

(893)

(990)

 

31,096

33,291

Current portion

7,709

5,624

Long-term portion

23,387

27,667

(1) Includes loan principal of $nil (2018 - $5.4 million) plus accrued interest
(2) Includes loan principal of $30.6 (2018 - $27.6 million) plus accrued interest

 

The following table represents the scheduled principal repayments of the Convertible Loan plus accrued interest up to 31 December 2019. The Convertible Loan bears interest at a variable rate equal to LIBOR plus a margin between 8% and 17%, therefore an estimated interest rate has been used in calculating the repayments.

 

 

Within 1 year

2-5 years

Thereafter

Total

Required debt cash payments

8,049

16,098

8,049

32,196

 

As at 31 December 2019, the Group had $31.1 million (2018 - $33.3 million) in total debt with the EBRD consisting of a $30.6 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 $7.7 million (2018 - $5.6 million). The three-year period available to draw on these loans expired in November 2016. The Convertible loan is 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.

 

Senior Loan

 

The Senior Loan was repaid in full during the year with two installments of $2.7 million principal plus accrued interest in March and September 2019. The Senior Loan had a variable interest rate equal to LIBOR plus 6%.

 

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 any other recognized exchange (including the WSE) nominated by the Group and which is acceptable to the EBRD and on which its shares are and will be listed or quoted, 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 any other recognized exchange (including the WSE) nominated by the Group and which is acceptable to the EBRD and on which its shares are and will be listed or quoted. 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 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 any other recognized exchange (including the 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

 

The Convertible Loan agreement contains affirmative covenants, including maintaining the specified security, environmental and social compliance, and maintenance of specified financial ratios. The consolidated debt to EBITDA covenant came into effect 30 September 2018, with a required maximum ratio of 2.5 times to be calculated at the consolidated financial level.

 

As at 31 December 2019, the Group was not in compliance with the debt service coverage ratio. On 30 December 2019, the Group received a waiver from the EBRD formally waiving compliance with this covenant for the period ended 31 December 2019. 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.

 

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 have been incurred during the periods being reported.

 

21.  Other provisions

 

 

JV audit

Severance

Other

Total

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

Amount paid

-

(10)

-

(10)

Change in provision

(13)

(61)

40

(34)

Balance as at 31 December 2019

1,135

148

40

1,323

Current

-

-

-

-

Non-current

1,135

148

40

1,323

 

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. The years currently under audit are 2014-2017. Management has reviewed the audit claims and has determined a reasonable amount that the Company may be liable for. Management expects settlement of the joint venture audit provision to occur later than twelve months from 31 December 2019.

 

As at 31 December 2017, a provision was made for potential severance costs relating to the termination of employees in the Chouech 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 field and the severance cost associated with the other employees. Severance payments were made in 2018 to certain employees not to be rehired. During 2019 one additional settlement was reached and paid. The remaining provision at 31 December 2019 reflects the potential costs to terminate the remaining employees.

22.  Accounts payable and accrued liabilities

 

As at 31 December

2019

2018

Accounts payable and accrued liabilities

16,231

14,313

Taxes payable

1,386

285

 

17,617

14,598

 

23.  Aggregate payroll expense

 

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

 

Year ended 31 December

2019

2018

Wages, salaries and benefits (1)

3,523

3,987

Share-based payment expense (2)

528

820

 

4,051

4,807

(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

 

24.  Related party transactions

 

During the years ended 31 December 2019 and 2018, related party transactions include the compensation of key management personnel. Key management personnel include Serinus' Board of Directors and key members of the executive leadership team. Transactions with key management personnel (including directors) are noted in the table below:

 

Year ended 31 December

2019

2018

Wages and salaries

690

742

Benefits

24

32

Share-based payment expense

365

835

 

1,079

1,609

 

25.  Supplemental cash flow disclosure

(a) 

Year ended 31 December

2019

2018

Cash provided by (used in):

 

 

Trade receivables and other

(1,198)

(2,530)

Accounts payable and accrued liabilities (1)

1,920

(4,539)

Foreign exchange

(52)

-

 

670

(7,069)

 

 

 

Changes in non-cash working capital relating to:

 

 

Operating

670

(7,069)

(b)  (1) Inclusive of tax expense and taxes paid

 

 

 

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

As at 31 December

2019

2018

Balance, beginning of the year

33,291

31,261

Cash Changes:

 

 

Principal payment on senior loan

(5,400)

-

Interest payments on senior loan

(355)

(436)

Non-cash Changes:

 

 

Modification gain upon adoption of IFRS 9

-

(1,034)

Amortization of discounts and debt costs

144

255

Amortization of modification gain

97

44

Interest on senior loan

233

452

Interest on convertible loan

3,086

2,749

Balance, end of the year

31,096

33,291

 

26.  Capital management

 

Year ended 31 December

2019

2018

Long-term debt

31,096

33,291

Shareholder's equity

14,518

13,342

Total capital resources

45,614

46,633

 

Consistent with prior years, the Group manages its capital structure to maximize financial flexibility. Due to the tight cash balance, the Group is closely monitoring forecasts and makes amendments as required from changes to commodity prices, economic conditions and other risk characteristics. 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 the Group finalized the move from the TSX to the AIM market, which has allowed for two equity raises as steps towards strengthening its capital structure. In May 2018, the Group raised $12.7 million, net of issuance costs, in equity through the issuance of 66.7 million ordinary shares. In March 2019, the Group raised $2.7 million, net of issuance costs, in equity through the issuance of 21.6 million ordinary shares.

 

The Company was able to fully repay the Senior loan during 2019, consisting of two payments totalling $5.4 million principal plus accrued interest.

 

27.  Commitments and contingencies

 

Commitments

 

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 was originally for three years. During the fourth quarter of 2019, Serinus received an extension delaying the expiration until 28 October 2020.

 

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 M-1003 and M-1007 wells. The Group was granted a twelve-month extension on the third exploration phase of the Satu Mare Concession in Romania until 28 October 2020 with the sole commitment to complete a 3D seismic acquisition program. Prior to the year-end, the Group completed the permitting required to perform the 148km2 3D seismic acquisition program, which was expected to be completed in Q2 2020. Due to the unprecedented disruptions caused by the COVID-19 outbreak the Group is unable to estimate a completion date at this time.

 

Contingencies

 

The Tunisian state oil and gas company, ETAP, has the right to back into up to a 50% working interest in the Chouech 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 2019, cumulative liquid hydrocarbon sales net of royalties and shrinkage was 5.3 million barrels. The Company does not expect to meet this threshold in the next 12 months.

 

28.  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.

 

As at 31 December 2019

 Romania

 Tunisia

 Corporate

 Total

Total assets

44,175

63,508

2,777

110,460

For the year ended 31 December 2019 

 

 

 

Petroleum and natural gas revenues

 

 

 

 

Crude oil

-

7,617

-

7,617

Natural gas

14,855

1,604

-

16,459

Condensate

289

-

-

289

Total

15,144

9,221

-

24,365

Royalties

(803)

(1,057)

-

(1,860)

Revenue, net of royalties

14,341

8,164

-

22,505

Cost of sales

 

 

 

 

Production expenses

(2,332)

(4,606)

(47)

(6,985)

Depletion and depreciation

(7,216)

(2,576)

(685)

(10,477)

Windfall tax

(3,155)

-

-

(3,155)

Total cost of sales

(12,703)

(7,182)

(732)

(20,617)

Gross profit (loss)

1,638

982

(732)

1,888

Administrative expenses

-

-

(3,801)

(3,801)

Share-based payment expense

-

-

(528)

(528)

Well incident recovery

52

-

-

52

Decommissioning provision recovery

-

6,891

-

6,891

Listing costs

-

-

(7)

(7)

Gain on sale of assets

3

17

-

20

Operating profit (loss)

1,693

7,890

(5,068)

4,515

Finance expense (income)

387

(809)

(4,381)

(4,803)

Net income (loss) before income taxes

2,080

7,081

(9,449)

(288)

Current income tax expense

-

(1,411)

(3)

(1,414)

Deferred income tax expense

-

(238)

-

(238)

Net income (loss) for the year

2,080

5,432

(9,452)

(1,940)

Capital expenditures

3,858

1,019

11

4,888

 

 

 

 

 

 

As at 31 December 2018

 Romania

 Tunisia

 Corporate

 Total

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

Total

-

8,716

-

8,716

Royalties

-

(867)

-

(867)

Revenue, net of royalties

-

7,849

-

7,849

Cost of 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 loss

(14)

3,273

(255)

3,004

Administrative expenses

-

-

(3,422)

(3,422)

Share-based payment expense

-

-

(820)

(820)

Well incident recovery

3,602

-

-

3,602

Decommissioning provision recovery

-

316

-

316

Listing costs

-

-

(1,377)

(1,377)

Gain on sale of assets

-

117

-

117

Operating profit (loss)

3,588

3,706

(5,874)

1,420

Finance expense (income)

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

10,905

(233)

86

10,758

 

 


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