Latest Results

Final results

Anglo African Oil & Gas plc, an independent oil and gas developer, is pleased to publish its audited final results for the year ended 31 December 2018. The results are copied below and will be posted to shareholders shortly.

The information contained within this announcement is deemed by the Company to constitute inside information for the purposes of the Market Abuse Regulation (EU) No. 596/2014. Upon the publication of this announcement via a Regulatory Information Service, this inside information is now considered to be in the public domain.



Dear shareholder,

This annual report covers the twelve months to 31 December 2018, during which period the Company has drilled its much anticipated new well at the Tilapia field. A detailed summary of the year under review and the prospects for the future is included in the Group Strategic Report.



The original premise of the Company at its IPO was to see if the Mengo and, most importantly, the Djeno could be brought into production within the licence area. At the same rates as seen elsewhere, just one well from the Djeno could result in 5,000/bopd of production, resulting in substantial gross revenues. Having onshore production facilities would then allow for the costs to be managed such that the Company would have substantial net free cashflow and be able to support a dividend.

Following the successful results of well TLP-103C, which have been further confirmed in the recent CPI results released to the market, we have moved close to achieving this aim. While there remain operational and technical risks in bringing the Djeno into production, the prospects are clearly better defined than when we started and the risks are much lower.

We are therefore excited to be moving into the production phase. James Berwick and his operational team have been working hard to refine the plan to give the Company the best chance of success. We now know that the resources are there: we just need to implement a plan that optimises the likelihood of extracting them.

You will see that we have impaired the valuation of TLP-103C to take account of specific costs incurred in the abortive drilling of TLP-103, which was stopped when the rig became unstable. We concluded that these costs would have no future long-term economic benefit for the Group. It is important to note that this impairment has no impact on the prospects for TLP-103C; indeed, having to relocate the rig from TLP-103 had some benefit in drilling TLP-103C

TLP-101 and TLP-102

Although we believe that we will be able to produce from these wells for a considerable time into the future, we are now concentrating on TLP-103C (and potentially further wells). The existing production from TLP-101 is not of itself economically viable, and we have therefore fully impaired the value of the oil & gas assets in these financial statements.


We recognise the need to protect the interests of members and are actively developing plans that will enable the Company to grow and develop the Tilapia asset through re-investment of cashflow as well as through other sources of capital, such as offtake financing. Clearly, bringing TLP-103C into production is the critical first step in our ability to do this and we are examining our financing plans to facilitate this. The Company is in receipt of several offers of capital finance, which it is considering, and the Company is consulting with its major shareholders. Nevertheless, we accept that, at the date of this report, there is an issue in respect of going concern, which is acknowledged in the financial statements.

Licence over Tilapia

We are pleased that the Congolese authorities have offered a new 25-year licence for Tilapia. James Berwick is ably leading negotiations on the production-sharing agreement and other underlying documents, which we aim to get agreed as soon as possible.

Overall strategy

At the moment, the focus is on production from TLP-103C. We have also progressed plans for the full development of the Tilapia field. In addition, we have progressed discussions on new asset opportunities that fit with the Company's continued strategy of becoming a lean, profitable oil producer with a focus on the bottom line and a clear and unswerving commitment to the payment of dividends. Any new assets must bring accretive value to the shareholders

We look forward to progressing these discussions further and will keep members updated on progress. By the end of 2019, we expect the value of, and prospects for, the Company to be very different from what they are today.


David Sefton
Executive chairman



Dear shareholder,

I am pleased to provide an operational update on the Group.


TLP-101 produced at an average rate of 38 bopd for most of 2018 and continues to produce at a stable rate. Due to the works completed in the last period, we are able periodically to increase production for extended periods. Work continues to assess whether TLP-102 is suitable to become a water-injector to assist TLP-101 to maximise flow.


As stated above, the Company has completed an engineering study to ascertain whether TLP-102 is in connection with TLP-101, which would mean that it could be used as a water-injector to maximise flow rates from TLP-101. Initial results look positive; the operations team are completing pressure monitoring between the two wells, which will result in a forward work plan. After the year-end, gas came to the surface through the well, which is being monitored.

We have, nevertheless, reviewed the carrying value of these two wells in light of the priority that we are now giving to TLP-103C and what is likely to be only a marginal increase in production resulting from further investment in them. For these reasons, we have taken the prudent step of fully impairing the value of these wells in the financial results of the Group.


Drilling of TLP-103C was completed in January 2019. The well was successful, encountering hydrocarbons (both oil and gas) at all three target horizons. The well, in accordance with the original plan, was then plugged back to the Mengo horizon in order to produce via comingling the Mengo and R2 reservoirs.

After several weeks of settling, and unexpectedly, pressure began to rise at the well head. In order to manage this pressure, the well was bled off and, during this bleed, oil was produced at surface along with gas and water. Following this initial bleed, the well has been bled weekly in order to manage pressure. Over this period, the well has continued to produce oil and gas, and the water content has subsided. The well now flows without any assistance for the entire duration of the bleed without a drop in its flow.

The oil has been collected and then tested by both the Total laboratory in Pointe Noire and the Congolese state refinery. Both tests show an oil quality of 43 API; due to the characteristics of the oil and the well design, it is calculated that this oil is from the Djeno reservoir, leaking to surface under associated gas pressure through a fracture in the concrete plug.

This welcome news has confirmed the potential of the Djeno reservoir in our block. As a result, the Company has taken the decision to target the Djeno for production from TLP-103C.

However, we incurred expense in our attempt to drill TLP-103, which we had to shut in once the drilling rig became unstable. These costs will generate no long-term economic benefit for the Company. We therefore decided to impair the value of our exploration and evaluation assets by writing off those costs associated solely with TLP-103.

TLP-103C drilling plan

In order to produce from the Djeno, we intend to side-track the well into what we feel may be the optimal part of the reservoir, first testing the deeper Djeno exploration potential but then producing from the top Djeno, where two CPI reports have indicated a good-to-excellent reservoir potential. The side-track is a 25-30-day programme and we intend to complete this work before the end of the year, subject to rig availability. This is explained in more detail in the Group strategic report.

Results for the year

The Group's loss for the year of £11.8 million includes £6.4 million for the impairments referred to above and the partial provision made against the debt from SNPC. However, as is noted in the Group strategic report, we have invested considerable sums over the past 18 months in the drilling operations across Tilapia and in the deployment of highly experienced consultants to ensure that we plan and operate to the highest standards in all our operations, particularly in respect of minimising health & safety and environmental risks. I fully expect to see this investment bear fruit in the months to come.


The Company is currently assessing its options for the funding for the next stage of development. We are encouraged to have received monthly payments from Société Nationale de Pétroles du Congo ("SNPC") in part settlement of their debt owed to the Company, which has been used to finance the Group's ongoing working capital requirements.

Business development

Our top priority remains the optimisation of our TLP-103C well-development programme. We do however continue to review other opportunities.


The period relating to this report has produced encouraging results at TLP-103C. We now look forward to bringing the well on-line, producing from the Djeno reservoir and making the Company cash-flow positive as soon as possible.


James Berwick
Chief executive officer



Group strategic report for the year ended 31 December 2018

The directors present the strategic report of Anglo African Oil & Gas plc ("AAOG" or the "Company") and its trading subsidiary (together, the "Group") for the year ended 31 December 2018. The Company was incorporated in England and Wales on 12 January 2001.

Principal activity

The Group owns 100 per cent of an oil and gas company, Petro Kouilou SA ("PK"), situated in the Republic of the Congo ("the Congo"). Through PK, it holds a 56 per cent stake in the producing Tilapia oil field ("Tilapia") in the Congo.

Group strategy

The directors intend to secure the Company's financial stability over the next twelve months by producing from the well TLP-103C ("TLP-103C") that was drilled in late 2018. This plan is explained in more detail below. If production from TLP-103C is successful, the impact on the Company's cash flow and prospects will be transformational. Further development of the existing producing well may take place once production from the deeper horizons has been consolidated.

Review of the year

Although the financial results for the year appear disappointing, particularly because oil production has not increased, the Company has been prudent in making three impairment provisions, which are discussed in greater detail below. Importantly, considerable progress has been achieved on the operational front. The Company made a substantial investment in drilling TLP-103C , which confirmed oil in all the horizons that were targeted, built a balanced and experienced team, achieved significant progress towards the grant of a new licence and developed a detailed plan to capitalise on the probable reserves in the Djeno horizon (the "Djeno"). The Djeno has always been the target that has most excited investors because it has the possibility of being transformative for AAOG.

Financial results

The Group reports a loss from operating activities of £11.8 million for the year to 31 December 2018.

Described in this report:

1. Small reduction in income because TLP-101 was shut in for the workovers and during the drilling programme for TLP-103C

2. Full impairment of the carrying value of TLP-101 and TLP-102 (£3.4m)

3. Impairment of the carrying value of TLP-103C (£1.5m)

4. Impairment of the carrying value of the receivable from SNPC (£1.5m)

Included in administration expenses

5. Costs relating to a potential acquisition (£0.3m)

6. Personnel costs (£1.6m)

7. Legal fees (£0.6m)

8. Travel and associated costs (£0.9m).

Capital investment

During 2018, the Group invested £9.6 million gross (£5.4 million net of the contribution due from its partner, SNPC) into developing TLP-103C. The Tilapia development expenditure incurred has enabled the Group to discover oil across a total of 56 metres in all the horizons through which it drilled. This success has resulted in the drilling programme currently planned for the latter half of 2019, which is described below.

Key performance indicators (KPIs)

The Group is focused almost exclusively over the next six to twelve months on drilling a side-track into the Djeno and producing commercially significant quantities of high-grade oil from it. If this endeavour is not sufficiently successful, the directors will seek to produce from the Mengo as well as optimising production from TLP-101.

Barrels of oil per day is currently monitored and reviewed daily. Once production from Tilapia has increased, this will become the key KPI for the operation in Congo.


James Berwick was appointed Chief Executive Officer to replace Alex MacDonald in January 2018. Jeremy Patullo and David Livingston joined in August 2018 as director of finance (projects) and director of operations respectively. The operational team in the Congo was strengthened considerably by the presence of several specialist consultants and AAOG has engaged further expertise since the year-end.

TLP-101 and TLP-102

Following the successful work to disconnect, clean through and reconnect the flowlines to well TLP-101 ("TLP-101") during April 2018, and testing of flow through the annulus, the well was then re-directed to production through the coiled tubing. TLP-101 was taken offline during the drilling programme for TLP-103 and TLP-103C. Since then, TLP-101 has been producing consistently for the period from December 2018 to June 2019 at an average of 33 barrels of oil per day ("bopd"). Production is regulated by the choke, and in its current configuration, TLP-101has produced at levels between 25 and 55 bopd.

In May, testing of the R2 reservoir in TLP-102 confirmed the presence of hydrocarbons and pressure within the reservoir. However, despite reperforation and acidisation, the well did not flow oil. While it is believed that the well is connected to TLP-101 and could be used as a water injector for that well, achieving production from TLP-102 is no longer a priority for the Company.


The directors have reviewed the carrying value of these two wells in light of the results of the workovers during 2018 and the revised plan to develop TLP-103C as a priority in 2019. It is considered unlikely that TLP-101 and TLP-102 would ever, on a standalone basis, be commercially viable, although the directors believe that they could generate useful marginal revenue for long into the future. For these reasons, the directors have fully impaired the value of these two wells (2017 - £2.6 million) as at 31 December 2018.

Drilling TLP-103 and then 103C

This time last year, it was anticipated that, after the fundraise in June 2018 raising £7.4 million gross, PK would have drilled TLP-103 by October and higher production from the Mengo (and possibly from TLP-101/102 following the workovers) would be reflected in the Group's FY18 year-end results. The delays caused mainly by (i) the instability of the SMP rig and the subsequent need to reposition it over TLP-103C and (ii) the rig's poor condition both contributed to AAOG suffering considerable overruns on capital and running costs during the year without any increased offsetting sales revenue.


The directors have reviewed the carrying value of the exploration and evaluation assets (namely, TLP-103C) in light of the expenditure incurred on TLP-103 before that well site had to be relocated following the subsidence of the rig. A full analysis of the costs incurred exclusively on TLP-103 has been carried out and the directors have written down the valuation of the Company's share of the exploration and evaluation assets (within intangible assets) by £1.5 million.

New licence

Discussions about the issue of a new 25-year licence to replace the existing one that expires on 15 July 2020 have made good progress. The Tilapia site and the Group's field-development plan were subject to audits and analysis by the Director-General of Hydrocarbons ("DGH") to ensure that AAOG was committed to invest sufficiently in the field. In April 2019, a letter was received from the Ministry offering the 25-year licence subject to final negotiations, which commenced in June 2019.

The directors have assessed the carrying value of the well TLP-103C on the basis that the licence would be renewed on commercially acceptable terms.


AAOG has a considerable debtor balance with Société Nationale de Pétroles du Congo ("SNPC"), because, throughout the period since the Company's IPO in March 2017, SNPC has been unable to honour its commitment to pay 44 per cent share of the drilling and ancillary costs as they were incurred by PK. SNPC's unpaid share reached approximately US$8.5 million (a figure agreed by SNPC as its share after a comprehensive audit of PK's books) at the beginning of 2019 following the TLP-103C drilling campaign.

In March 2019, SNPC made the first repayment of its debt, namely US$0.60 million. A further repayment of US$0.67 million was received in April and a third (US$0.72 million) was received in May. SNPC have confirmed in writing that they acknowledge the debt, recognise that the delays in making these payments have caused harm to PK's operations, and expect the payments to increase from July 2019 onwards. The total balance owing by SNPC to PK at the date of this report is approximately £4.7 million.


The directors have considered the likelihood of full recoverability of this debt, which had been fully provided against at 31 December 2017 (£0.23 million), at which time no payments had been received by SNPC. They have taken into account the amount of the payments already made, that these payments were made monthly as promised, that these costs have been audited and agreed by SNPC, and that SNPC acknowledges the full amount of the debt and has stated its intention to meet its obligations over the coming months at a rate that will extinguish the amount owing by the end of the current licence period. The directors consider that it is prudent to make a partial provision of £1.5 million (US$2 million) against the debt due from SNPC. If the debt is repaid in full, this provision will be written back. The resultant balance of the receivable from SNPC in the accounts of the Group at 31 December 2018 is US$4.8 million (£3.8 million).

Issue of convertible loan notes

The delays in drilling and the SNPC cash shortfall meant that AAOG needed to raise further capital in November. The Company issued £1 million of convertible loan notes, which were almost immediately converted into ordinary shares at 6.3 pence per share.

Fundraise in January 2019

A fundraise of £6 million at 10 pence per share took place in January 2019. This provided development and working capital while the team drew up detailed plans for the next stage of the drilling campaign.

Results from drilling TLP-103C

The beginning of 2019 saw the results of the drilling of TLP-103C, which proved the existence of columns of hydrocarbons at the RI/R2 (five metres), a new horizon between R3 and the Mengo (13 metres), and the Mengo horizon itself (26 metres). At the end of January 2019, it was confirmed that the upper Djeno displayed a 12-metre column, with the expectation of further (middle and potentially lower) Djeno reservoirs below the final depth (FD) of 2,683 metres.

During the three months between February and April 2019, AAOG focused on how best to release value from Tilapia, primarily in the context of whether to (i) drill into the Mengo, which would require waiting for fracking equipment to be available in country (and subsequently fracking), or (ii) produce from the Djeno, which would require re-entering the well and either drilling through the cement plugs or drilling a side-track. This decision became easier at the end of March, when AAOG announced that high-quality oil, which preliminary analysis showed had almost certainly come from the Djeno, had risen to the surface under its own pressure. As a result, the development plan was changed: see 'Future development of the Group' below.

Future development of the Group

The Group is currently solely focused on enhancing production from Tilapia. It was always intended to produce from the Djeno and, following the discovery of oil reaching the surface under its own pressure, this has now become the key priority for AAOG. The five stages of the full field development plan are described below.

Stage One - The largest potential increase in the value of Tilapia is still expected to be achieved by drilling into the deeper geological structures, particularly the Djeno, which Tilapia shares with surrounding fields. The oil that flowed to the surface has an API of 43, and it is considered very likely that it flowed from the Djeno The well will be drilled using a side-track into the Middle Djeno and then pulled back into the Upper Djeno to produce.

Stage One can usefully be divided into four separate actions, and illustrated by the diagram below:

i. Re-enter TLP-103C
Rig up onto the existing TLP-103C well head and then drill through the two cement plugs inside the 95/8" casing in preparation for drilling the new side-track

ii. Drill new 8½" side-track
Drill a new 8 ½" hole section as per the directional-drilling plan, penetrating both the Upper and Middle Djeno formations, and then acquire a comprehensive suite of formation evaluation logs across the Djeno reservoirs

Click on, or paste the following link into your web browser, to view the associated PDF document.

iii. Set 7" liner
Run and cement a string of 7" liners across the open-hole interval in readiness for producing from either the Middle or Upper Djeno

iv. Perforate Djeno formation
Use high-shot density perforation guns to perforate the Djeno prior to running the completion string. Following that, clean up the well before putting TLP-103C-ST1 onto production, utilising the existing enhanced surface facilities.

Stage Two - Not only did the drilling of TLP-103C show a 26-metre column in the Mengo Sands (the "Mengo") but also found 13 metres of oil columns across new horizons between the R3 and the Mengo. The current plan is to perforate the well at the Mengo and/or Pointe Indienne R1/R2 reservoir once the Djeno drill has been completed. This should further increase daily production, with a positive effect on cash flows and asset value. Should the Djeno sidetrack be unsuccessful at both depths, the Company plans to perforate the well at the Mengo and/or Pointe Indienne R1/R2 reservoir, as these reservoirs continue to provide the Group with a strong alternative to increased daily production, cash flow and profitability.

Stage Three - The Company may then develop TLP-101 to enhance its production. The data received to date suggest that this well, which is considered likely to be joined to TLP-102, may have an expected production life of up to 50 years and could therefore generate material annuity income if production exceeded 100 bopd.

Stage Four - Depending on the results achieved from the drill into the Djeno, the Company will consider drilling into a further, deeper horizon, the Vandji, via a new well.

Stage Five - A ten-well development plan for Tilapia is under discussion with the DGH, and the scale and speed of its execution will depend on the results from the stages described above and the finalisation of attractive terms for the new licence over Tilapia that is currently being negotiated.

The directors believe this development programme is commercially attractive because:

1. Low cost - the directors believe that PK can break even at modest rates of oil production (approximately 800 bopd) as long as the price of Brent Crude oil, which largely mirrors the price achieved by PK, remains in excess of US$35 per barrel.

2. Upside - as described above, the drilling programme into the Djeno provides the opportunity for significant upside to the existing production. Further, while the Djeno represents the most significant potential upside to the Company, the directors believe that a profitable, valuable business can be developed from producing from the Mengo alone.

3. Existing production and storage facilities in place - the existing topside facilities have been constructed to international standards and are fully amortised. While the directors consider that PK's facilities currently have sufficient capacity for production of approximately 2,500 bopd, the intention is to upgrade them to handle higher levels of production.

4. Already in production - Tilapia is already producing.

5. Ability to drill from on-shore - Tilapia is near off-shore, being only 1.8 kilometres from the coastline. This gives PK the considerable advantage of being able to drill from on-shore using deviated wells, at a considerably reduced cost compared to off-shore drilling.

6. Light oil - The oil currently produced from Tilapia is high-quality, light, sweet crude (39 - 41 API) with a market value that currently tracks Brent crude oil.

7. Availability of equipment - During the past eighteen months, the Group has successfully obtained the equipment that it has needed to carry out its production and development activities. PK is sourcing the required equipment and do not anticipate unreasonable delays. Production scheduling takes account of timing.

Potential new assets

At present, the Company is focused on drilling TLP-103C and producing commercial volumes of high-grade oil from it. At the same time, the Company is evaluating other asset opportunities in the Congo and, possibly, further afield. The Company is particularly interested in assets offering similar risk/reward profiles to Tilapia. The Company believes that any future acquisition of assets that are attractive in terms of their risk profile and value would diversify risk and build a larger, more sustainable group.

Significant events after the balance sheet date

On 9 January 2019, the Company announced that it had issued 60 million ordinary shares of nominal value five pence at ten pence per share, raising gross cash proceeds of £6 million.

Negotiations to secure a new 25-year licence for Tilapia have been in progress throughout 2019. PK has been discussing with the Government of the Congo the terms of the new production-sharing contract and these negotiations are ongoing. The current 20-year licence would expire in July 2020 and it is hoped that the new licence will take effect before the end of 2019.

Review of business and financial performance

The Board has reviewed whether the Annual Report, taken as a whole, presents a fair, balanced and comprehensive summary of the Group's position and prospects. The Board considers that the financial results included in this Annual Report bear no relation to the Group's position and prospects, which are set out in detail under 'Future development of the Group' above.

Information on the financial position and development of the Group is set out in the Chairman's letter, the Chief Executive's letter, this report, the Directors' report and the annexed financial statements.

Risks and uncertainties

The Board frequently reviews the risks to which the Group is exposed and ensures, through its meetings and regular reporting, that these risks are minimised as far as possible.

The principal risks and uncertainties facing the Group, which have remained mainly the same as last year, at this stage in its development are:

Exploration risk

The Group's business includes oil and gas exploration and evaluation, which are speculative activities, and there is no certainty that the Group will be successful in the definition of economic resources, or that it will proceed to the development of any of its projects or otherwise realise their value.

The Group aims to mitigate this risk when evaluating new business opportunities by targeting areas of potential where there are historical drilling or geological data available.

Exploration risk (licence)

The existing 20-year licence in respect of Tilapia expires in July 2020. The Director of Hydrocarbons from the Congolese oil ministry has written to the Company offering a new licence of 25 years duration (namely to 2045), with a further five-year option, subject to various conditions. These conditions have not, at the balance sheet date, been spelled out, nor have they been negotiated. If the negotiations prove not to be fruitful, there is a significant risk that the licence will not be renewed. However, all the indications from the Group's discussions with the Ministry are that they welcome the investment of the Group into Tilapia, are pleased with the successful initial drill of well TLP-103C and are supportive of a longer-term development plan for the field. For these reasons, the directors are confident that agreement can be reached on the terms of the new licence before the end of 2019.

Resource risk

All oil and gas projects have risk associated with defined resources and recoverability. Resources will be calculated by the Group in accordance with accepted industry standards and codes but are always subject to uncertainties in the underlying assumptions, which include geological projection and commodity price assumptions.

Development risk

Delays in permitting, financing and commissioning a project may result in delays to the Group meeting its production targets. Changes in commodity prices can affect the economic viability of the drilling programme and affect decisions on continuing exploration activity.

Production technical risk

Notwithstanding the completion of test work, and pilot studies indicating the technical viability of an operation, unforeseen variations may still render an oil and gas recovery operation economically or technically non-viable.

The Group has available to it a team of professionals experienced in geological evaluation, exploration, financing and development of oil and gas projects. To mitigate development risk, the Group supplements the team as necessary by engaging other external expert consultants and contractors.

Environmental risk

Exploration and development of a project can be adversely affected by environmental legislation and the unforeseen results of environmental studies carried out during evaluation of a project. Once a project is in production, unforeseen events can give rise to environmental liabilities. The Group takes its responsibilities to the environment and the local community very seriously. PK's operations and procedures have been audited by the local ministry and found to be fully compliant. The Group ensures that its operational activities comply with best-of-class procedures and uses highly skilled and experienced individuals in its operations.

Financing and liquidity risk

The Company may have an ongoing requirement to fund its activities through the equity markets and in future may need to obtain finance for project development. There is no certainty such funds will be available when needed.

Partner risk

In the Congo, the Group operates in partnership with parastatal entities. The Group can be adversely affected if partners are unable or unwilling to perform their obligations or fund their share of future developments, or if legislation is introduced varying the legal requirements for such partnerships.

Bribery risk

The Group has adopted an anti-corruption policy and whistle-blowing policy under the Bribery Act 2010. Notwithstanding this, the Company may be held liable for offences under that act committed by its employees or subcontractors, whether or not the Company or the directors have knowledge of the commission of such offences.

Internal controls and risk management

The directors are responsible for the Group's system of internal financial control. Although no system of internal financial control can provide absolute assurance against material misstatement or loss, the Group's system is designed to provide reasonable assurance that problems are identified on a timely basis and dealt with appropriately.

In carrying out their responsibilities, the directors have put in place a framework of controls to ensure, as far as possible, that (i) ongoing financial performance is monitored in a timely manner, (ii) where required, corrective action is taken and (iii) risk is identified as early as practically possible. The directors have reviewed the effectiveness of internal financial control and believe that the Company has adequate staff and controls in place to reduce risk.

The Board, subject to delegated authority, reviews capital investment, property sales and purchases, additional borrowing facilities, guarantees and insurance arrangements.

Forward-looking statements

This annual report contains certain forward-looking statements that have been made by the directors in good faith, based on the information available at the time of the approval of the annual report. By their nature, such forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that will or may occur in the future. Actual results may differ from those expressed in such statements.


The Company continues to deliver on its long-term plan to develop Tilapia and significantly increase production from it. This plan has been facilitated by the success of the drilling of TLP-103C and the discovery of hydrocarbons at each level that was penetrated. Nothing is more important to the Group than producing commercially sustainable volumes of oil from its existing asset.

The further field-development plan that could include up to ten additional wells alongside expanded surface facilities will be pursued once production from the existing wells has enabled PK to be cash-flow generative and to remit funds back to the holding company on a sustainable basis.



  Notes Year ended
31 December
  Year ended
31 December
Continuing operations        
Revenue   133,503   226,757
Cost of sales   (89,039)   (405,349)
    44,464   (178,592)
Administrative expenses 8 (5,147,777)   (2,769,733)
Impairment of trade and other receivables 16 (1,536,918)   -
Impairment of oil and gas assets 12 (3,407,395)   -
Impairment of exploration and evaluation assets 13 (1,498,591)   -
Share-based payment credit/(charge) 20 3,540   (138,332)
Loss from operating activities   (11,542,677)   (3,086,657)
Finance income   -   8,131
Finance costs   (143,207)   (62,543)
Loss before tax   (11,685,884)   (3,141,069)
Taxation 10 (8,550)   -
Loss for the year from operating activities   (11,694,434)   (3,141,069)
Exchange translation on foreign operations   (136,355)   215,514
Total comprehensive loss for the year   (11,830,789)   (2,925,555)
Loss per ordinary share (pence)        
Basic and diluted 11 (9.26)   (5.75)



  Notes 31 December
  31 December
Non-current assets        
Property, plant and equipment 12 110,612   3,048,818
Intangible assets 13 10,386,085   7,592,008
    10,496,697   10,640,826
Current assets        
Stock 15 37,101   -
Trade and other receivables 16 4,135,134   245,275
Prepayments   45,364   4,215
Cash and cash equivalents 17 120,983   2,696,911
    4,338,582   2,946,401
Total assets   14,835,279   13,587,227
Share capital 20 13,272,462   7,851,238
Share premium   14,492,407   12,003,418
Currency translation reserve   188,941   372,071
Retained deficit   (21,944,836)   (10,293,637)
    6,008,974   9,933,090
Current liabilities        
Trade and other payables 18 5,919,659   1,027,091
Loans and borrowings 19 -   15,000
Provisions 21 2,906,646   2,612,046
    8,826,305   3,654,137
Total equity and liabilities   14,835,279   13,587,227



Balance at 31 December 2016 4,463,008 1,555,144 156,557 (7,290,900) (1,116,191)
Share issue in the year 3,388,230 11,585,029 - - 14,973,259
Costs of issue of share capital - (1,136,755) - - (1,136,755)
Loss for the year from operating activities - - - (3,141,069) (3,141,069)
Share-based payment charges - - - 138,332 138,332
Foreign exchange adjustment - - 215,514 - 215,514
Total comprehensive loss for the period 3,388,230 10,448,274 215,514 (3,002,737) 11,049,281
Balance at 31 December 2017 7,851,238 12,003,418 372,071 (10,293,637) 9,933,090
Share issue in the year 5,421,224 2,982,893 - - 8,404,117
Costs of issue of share capital - (493,904) - - (493,904)
Loss for the year from operating activities - - - (11,694,434) (11,694,434)
Foreign currency translation reclassified     (46,775) 46,775 -
Share-based payment credit - - - (3,540) (3,540)
Foreign exchange adjustment - - (136,355) - (136,355)
Total comprehensive loss for the year 5,421,224 2,488,989 (183,130) (11,651,199) (3,924,116)
Balance at 31 December 2018 13,272,462 14,492,407 188,941 (21,944,836) 6,008,974



  Notes Year ended
31 December
  Year ended
31 December
Cash flows from operating activities        
Total comprehensive loss for the year   (11,830,789)   (2,925,555)
Depreciation and amortisation   277,455   86,473
Provision movement   294,600   2,488,522
Impairment of trade and other receivables   1,536,918   -
Impairment of oil and gas assets   3,407,395   -
Impairment of evaluation and exploration assets   1,498,591   -
Share-based payment (credit)/charge   (3,540)   138,332
    (4,819,370)   (212,228)
(Increase) in stock   (37,101)   -
(Increase) in trade and other receivables   (5,426,777)   (160,929)
(Increase) in prepayments   (41,149)   (4,215)
Increase/(decrease) in trade and other payables   4,892,568   (2,000)
Cash used in operating activities   (5,431,829)   (379,372)
Cash flows from investing activities        
Purchase of tangible fixed assets   (258,071)   (3,112,816)
Purchase of intangible fixed assets   (4,781,241)   (1,051,348)
Acquisition of subsidiaries net of cash received   -   (6,563,135)
Net cash from investing activities   (5,039,312)   (10,727,299)
Cash flows from financing activities        
Loan repayment   (15,000)   (35,000)
Issue of share capital   8,404,117   14,973,259
Costs of issuing share capital   (493,904)   (1,136,755)
Net cash flows from financing activities   7,895,213   13,801,504
Net increase in cash and cash equivalents   (2,575,928)   2,694,833
Cash and cash equivalents at beginning of year 17 2,696,911   2,078
Cash and cash equivalents at year-end 17 120,983   2,696,911



The notes to the financial statement are available in the PDF download.


Page last updated: 28 June 2019

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