Latest Results

Final results and Notice of Annual General Meeting

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 2017. The results are copied in full below and have been posted to shareholders today.

The Annual General Meeting of the Company will be held at the offices of finnCap at 60 New Broad Street, London EC2M 1JJ on 20 July 2018 at 11.00 a.m. A notice of this meeting is also being posted to shareholders.


Executive chairman's letter

Dear shareholder

Although this report and accounts covers the twelve months to 31 December 2017, it is since that date that significant events have taken place which are now bearing fruit in building on the promise of AAOG and its interest in the Tilapia field.


The entire board and I are very grateful to members for their support in the recent placing. By raising sufficient capital in June 2018, AAOG can now ensure that TLP-103 is drilled and any delay in partner contributions can be better managed. This well is pivotal to the value of the Company and we are determined to execute the drilling operation and achieve our planned timetable.

The Tilapia field

At the risk of repeating what is well understood by many shareholders, it is worth taking the opportunity to explain why TLP-103 is such an important well for AAOG.

AAOG holds, through Petro Kouilou ("PK"), its wholly owned subsidiary, a 56 per cent interest in the Tilapia field, which covers an area straddling both on-shore and off-shore in the Republic of the Congo.

Unusually for a small E&P company, AAOG is already a producer and the field has been in production for over ten years. We have successfully worked over both existing wells, TLP-101 and TLP-102, and while production from these wells is small, the Company does generate some cashflow and, as a result, there is a base value to PK that acts as a backstop and downside protection for investors.

The current focus of AAOG is on drilling a new well, TLP-103, in this field. This well is a multi-target well, which aims to hit three horizons:

  • R1/R2 - the existing producing horizon, from which it is expected that approximately 100 bopd can be added with no exploration risk, and minimal execution or technical risk;
  • The Mengo Sands - a well-known horizon from which we have direct proof of producible hydrocarbons from an earlier test well. This horizon should add between 400 and 500 bopd with no exploration risk but with a small amount of execution or technical risk; and
  • The Djeno Sands - an horizon recently brought into production in neighbouring licence areas. In those areas, oil flow rates of approximately 5,000 bopd have been achieved. While seismic data indicate the possibility of the reservoir extending into Tilapia, this will be the first time that it has been drilled in our licence area. For this reason, we will not know whether there is producible oil at his level within our licence until it is tested, which means that this part of the drilling plan clearly carries exploration risk. However, the value that could accrue from a new discovery in the Djeno clearly makes drilling deeper a compelling opportunity.

Importantly, a profitable, valuable business can be developed from bringing only the Mengo Sands on line. Just one well would make AAOG significantly cashflow positive and a full field Mengo development plan would make the asset very valuable. This opportunity provides a backstop that has no exploration risk while the Company still has the considerable exploration upside potential from the Djeno.

In this context, if we are not successful in the Djeno on TLP-103, we will put in place a Mengo field development plan. Where there is a technical case for further testing of the Djeno, we will continue to consider the opportunity worth investigating.

New management team

It is never easy to decide to change the management team of a company, but the decisive action we took in 2017 and early 2018 to replace the senior operating executives has clearly worked. Whereas the operational team was previously floundering in delays and unable to achieve any success, since the appointment of James Berwick as CEO, the plan for AAOG has finally been properly executed. The workovers have been carried out on time, under budget and with successful outcomes. The drilling plan for TLP-103 has been meticulously put together and James has assembled an experienced team who are working very hard to deliver the well safely, successfully and on budget. As a board, we have complete confidence in the ability of James to take AAOG forward.

New board members

I was very pleased in January to welcome Phil Beck, Nick Butler and Sarah Cope to the board to join Brian Moritz as non-executive directors. We now have a non-executive team with an excellent and complementary mixture of skills and experience and I have already seen how valuable their advice can be to AAOG as we take the company forward. I also want to thank our finance director, James Cane, for his continuing hard work and sometimes unsung contribution to the success of AAOG.

New licence

We have worked carefully on the process for a new licence for the Tilapia field and received the welcome news in February that the state oil company, SNPC, has recommended that PK be granted a 20-year extension. This recommendation is now going through the Congolese regulatory and administrative processes. We have recently received assurances that our work on TLP-103 is of critical importance to the finalisation of this process.

Overall strategy

At the moment, the clear and overriding focus of everyone is on drilling TLP-103. However, as we move forward, we will look to further opportunities available to the Company, provided they fit with its 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.

We look forward to keeping members updated on progress.

David Sefton
Executive chairman


Chief executive's report

Although the annual report covers the twelve months to 31 December 2017, I am using my report to provide an update on the latest progress on these three wells:


Following the successful work to disconnect, clean through and reconnect the flowlines to TLP-101, and testing of flow through the annulus, the well was then re-directed to production through the coiled tubing. Having done so, pressure stabilised in April, at which time the well was re-opened. It was successfully brought back on line and the flow rate immediately surpassed the previous rate of 35 bopd. The Company is now allowing the flow rate to increase gradually until it achieves the maximum level of sustainable flow.


As announced in April, Schlumberger conducted a successful intervention focused on the integrity of the perforations on TLP-102. Following the intervention, oil and gas samples were taken at the surface and were sent to Total's laboratory in Pointe-Noire for testing. The test result has now been received and has confirmed the Company's evaluation that TLP-102 is now in contact with the reservoir. The pressure in the well continued to increase steadily.

Well TLP-102 was opened on 17 June 2018 with a view to bringing the well online. When the well was opened, it was believed that water was found to be blocking the tubing. As a result of this information, the Company decided to conduct a swabbing exercise and engaged Slick Line to carry out the work on a turnkey contract. Slick Line commenced work on 19 June.

Eight runs were made down hole and oil was recovered to surface. The oil samples appear to be identical to samples from TLP-101 and have been sent for testing. The well requires two further runs in order to fully complete the work programme, which will be finished shortly.

Due to the absence of gas in the well, a pump will need to be installed. The Company intends to install this pump following completion of Slick Lines' work programme.

Based on the data obtained during the work, the Company's reservoir engineers now expect a minimum flow rate of 120 bopd from TLP-102 once the pump has been installed.


Drilling operations have commenced ahead of mobilisation of the rig:

  • The team has completed construction of the wellhead cellar and a 30-inch conductor case has been hammered in situ in preparation for drilling.
  • Due to the size of the rig an additional access road to the site has been constructed.
  • The majority of long lead items have now cleared customs and are in country.
  • The Company has procured two wellheads from FMC that have been prepared and tested and they are on site at FMC's facility in Pointe-Noire.
  • The well design has been completed and is undergoing final verification testing with a third-party contractor using specialised software. 
  • HSE planning and procedures have been completed and documented following site visits by specialist consultants.
  • The environmental impact assessment is nearing completion ahead of submission to the Minister of the Environment.
  • Security procedures and site protection are underway with the construction of fencing to secure the drill site.
  • All draft contracts from suppliers have been received and have either been signed or are in the final stages of negotiation.
  • Logistics, such as personnel and catering, have all been identified or contracted.

The Company has also received a notification from its specialist transport contractor, Ocean Transport, who are responsible for delivering the rig, SMP 102, from Port Gentil in Gabon to the Tilapia site, that the transport vessel, the Kota Bakat, on which the rig is to be loaded, is late in arriving and is now due to arrive in Port Gentil on 4 July.

After the delays over the last year, it is very pleasing to have a rig under contract and underway, and the entire team is focused on drilling a successful well.


The funding for the next stage of development was completed in early June. We now have the necessary resources to finance the total cost of the planned work, when previously we had anticipated SNPC paying its 44 per cent contribution as costs were incurred. We will be able to recover their unpaid contribution from future oil sales cash flow.

Business development

Our top priority remains the optimisation of our drilling programme from TLP-103 and, to a lesser extent, enhancing production from TLP-101 and TLP-102. In addition, we are reviewing other opportunities that come across our desks as we seek to build a high-quality oil and gas company.


Since my appointment at the turn of the year, I have been very pleased and am grateful to all the staff and contractors to the Company, who have supported me and worked hard to enable a turnaround in operational performance and effectiveness. They have worked impressively on the workovers, which have also allowed me to have a dry-run with the team and make such further tweaks to the organisation as needed ahead of drilling TLP-103. I approach the new well with confidence, while being very aware that it is hard work as well as care and attention to detail that have delivered the performance so far this year; more of the same will be needed in the second half.

James Berwick
Chief executive officer

28 June 2018


Group strategic report for the year ended 31 December 2017

The directors present the strategic report of Anglo African Oil & Gas plc ("AAOG" or the "Company") and its subsidiary (together, the "Group") for the year ended 31 December 2017. 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 in the Congo.

Group strategy

The directors aim to secure the Company's financial stability by increasing production from existing wells in the short term and to generate significant upside over the next twelve months through the targeting of deeper horizons within the licence area.


The Group reports a loss from operating activities of £3,086,657 for the year to 31 December 2017. This loss is after charging £329,825 of costs related to the Initial Public Offering and the admission of the ordinary shares to trading on AIM, which took place on 6 March 2017 (a further £613,657 was charged in FY16). A balance of AIM admission costs of £1.1 million has been written off to share premium. During the year, the Company acquired PK (in two tranches, in March and August), reorganised the administrative and operational structure of PK, and laid the initial groundwork for the drilling programme that is now underway.

Future development of the Group

Enhancing production from the Tilapia field

The Company's planned production development programme is as follows:

Stage One - The Company has completed successful workovers of TLP-101 and TLP-102. It is in the process of bringing TLP-101 back into production and bringing TLP-102 into production for the first time.

Stage Two - The more significant potential increase in the value of the Tilapia field is expected to be achieved by a new drilling programme that will go through R1/R2 and then into deeper geological structures, the Mengo and Djeno Sands, which Tilapia shares with surrounding fields. The Company has data from an earlier test well into the Mengo Sands that indicates producible hydrocarbons and therefore this part of the first new well is classified as appraisal. The Company has seismic and other data which suggests the possibility of producible hydrocarbons in the Djeno Sands, and therefore this deepest part of the first new well is classified as exploration. Depending on the results achieved from drilling into the Mengo and Djeno Sands, there is also a further, deeper horizon, the Vanji, which the Company may also target. The first of these new wells, TLP-103, will be drilled during the summer of 2018, with the result of the well due in late Q3/18.

Stage Three - If the drilling of TLP-103 is successful, a second well, TLP-104, will be drilled. Following that, a full field development plan can be put in place.

The directors believe this development programme is commercially attractive because:

  1. Low cost - the Company's budgeted break-even cost of production at 5,300 bopd is less than US$5 per barrel and, at an oil price of US$35 per barrel, it can be profitable at approximately 500 bopd. The financial models produced by the directors, and, in particular, the low and flexible cost base that allows the Company to be break even at production levels lower than 500 bopd, provide evidence that the Company can withstand low oil prices even at modest rates of production.
  2. Upside - The drilling programme into the Mengo Sands and the Djeno Sands provides qualified potential upside to the existing production. Further, while the Djeno Sands represent the most significant potential upside to the Company, a profitable, valuable business can be developed from R1/R2 and the Mengo Sands alone.
  3. Existing production and storage facilities in place - there are in place existing facilities that have been constructed to international standards, have been regularly maintained and are fully amortised. PK's facilities currently have the capacity to achieve production of up to 4,000 bopd, with scope for expansion.
  4. Already in production - the workovers and drilling programme, well design and authorisation for expenditure were agreed with SNPC.
  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 - Drilling equipment and ancillary services to carry out the development programme are available in-country or close by. If drilling into the Djeno Sands proves unsuccessful, the Company nevertheless intends to perforate the well at the Mengo Sands and/or Pointe Indienne R1/R2 reservoir and thereby increase daily production, with a positive effect on cash flows and asset value.

Potential new assets

At present, the Company is focused on successfully drilling TLP-103. However, the Company is at the same time evaluating other asset opportunities, both in the Republic of the Congo and elsewhere. The Company believes that the future acquisition of assets which are attractive in terms of their risk profile and value will enable the Company to scale quicker and will also diversify risk.

Significant events after the balance sheet date

On 5 June 2018, the Company issued 92,551,459 ordinary shares of nominal value of five pence at eight pence per share, generating gross cash proceeds of £7,404,117 (US$10 million).

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 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, this report, the Directors' report and the annexed financial statements.

Key performance indicators (KPIs)

The Company, directors and staff are focused over the next six to twelve months on delivering a successful well TLP-103, optimising production at TLP-101 and TLP-102, and minimising the risks and uncertainties set out below.

The board of directors reviews the Company's performance and plans regularly and will assess its KPIs as operations develop.

Risks and uncertainties

The Board regularly 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 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 is historical drilling or geological data available.

Exploration risk (licence)

The licence in respect of the Tilapia field expires in July 2020. There is a risk that the licence will not be renewed. The Group mitigates this risk by developing and delivering on its planned development plans for the asset and engaging in regular dialogue with the Congolese authorities.

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 will have available to it a small team of professionals experienced in geological evaluation, exploration, financing and development of oil and gas projects. To mitigate development risk, the Group supplements this from time to time with the engagement of 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.

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 Republic of 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 ongoing financial performance is monitored in a timely manner, that, where required, corrective action is taken and that risk is identified as early as practically possible. The directors have reviewed the effectiveness of internal financial control.

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 is executing the three-stage production development programme that was set out in the admission document. If the Company is successful in obtaining significant production from the Mengo and/or Djeno Sands, the directors will take technical advice in conjunction with SNPC on field optimisation. This could include up to ten additional wells alongside expanded surface facilities. As a field-optimisation plan could take several years to implement, the Company would likely seek to agree the plan with SNPC in conjunction with securing a new licence

On behalf of the Board:

James Cane
28 June 2018


Directors' report

The directors present their report together with the audited financial statements of Anglo African Oil & Gas Plc and its subsidiaries for the year ended 31 December 2017.

A review of the business, future developments, subsequent events and risks and uncertainties is included in the strategic report.


The Group reports a total comprehensive loss for the year to 31 December 2017 (after tax) of £2,925,555 (Period ended 31 December 2016: £937,313).


The directors do not recommend payment of a dividend for the year to 31 December 2017 (Period ended 31 December 2016: £nil).

Political donations

There were no political donations during the year (Period ended 31 December 2016: £nil).

Corporate governance statement

The Board is committed to maintaining high standards of corporate governance. Following the recent changes in the AIM rules, the directors have reviewed the corporate governance arrangements and intend on applying the QCA Corporate Governance Code. They will report on the Company's compliance with that Code in the next annual report.

The Company's corporate governance procedures take due regard of the principles of good governance.

The Company has established audit and remuneration committees, with formally delegated duties and responsibilities.

Audit committee

In January 2018, Sarah Cope was appointed chairman of the audit committee, on which Brian Moritz also sits.

Remuneration committee

In January 2018, Nick Butler was appointed chairman of the remuneration committee, on which Phil Beck also sits.



  Notes Year ended
31 December
  Period ended
31 December
Continuing operations        
Revenue   226,757   -
Cost of sales   (405,349)   -
    (178,592)   -
Administrative expenses 8 (2,769,733)   (931,829)
Share-based payment charges 20 (138,332)   -
Loss from operating activities   (3,086,657)   (931,829)
Finance income   8,131   -
Finance costs   (62,543)   (5,484)
Loss before tax   (3,141,069)   (937,313)
Taxation 10 -   -
Loss for the year from operating activities   (3,141,069)   (937,313)
Exchange translation on foreign operations   215,514   -
Total comprehensive loss for the year   (2,925,555)   (937,313)
Loss per ordinary share (pence)        
Basic and diluted 11 (5.75)   (2.21)



  Notes 31 December
  31 December
Non-current assets        
Property, plant and equipment 12 3,048,818   -
Intangible assets 13 7,592,008   -
    10,640,826   -
Current assets        
Trade and other receivables 15 245,275   84,346
Prepayments   4,215   -
Cash and cash equivalents 16 2,696,911   2,078
    2,946,401   86,424
Total assets   13,587,227   86,424
Share capital 19 7,851,238   4,463,008
Share premium   12,003,418   1,555,144
Currency translation reserve   372,071   156,557
Retained deficit   (10,293,637)   (7,290,900)
    9,933,090   (1,116,191)
Current liabilities        
Trade and other payables 17 1,027,091   1,029,091
Loans and borrowings 18 15,000   50,000
Provisions 21 123,524   123,524
    1,165,615   1,202,615
Long term liabilities        
Provisions 21 2,488,522   -
Total equity and liabilities   13,587,227   86,424

The financial statements of Anglo African Oil & Gas plc were approved by the Board and authorised for issue on 28 June 2018. They were signed on its behalf by:

James Cane



translation reserve
Balance at 28 February 2016 4,463,008 1,555,144 156,557 (6,353,587) (178,878)
Loss and total comprehensive loss for the period - - - (937,313) (937,313)
Total comprehensive loss for the period - - - (937,313) (937,313)
Balance at 31 December 2016 4,463,008 1,555,144 156,557 (7,290,900) (1,116,191)
Issue of share capital
Costs of issue of share capital
Loss for the year from operating activities - -  - (3,141,069) (3,141,069)
Share-based payment charges - - - 138,332 138,332
Foreign exchange difference - - 215,514 - 215,514
Total comprehensive loss for the year 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



Notes Year ended
31 December
  Period ended
31 December
Cash flows from operating activities        
Total comprehensive loss for the year   (2,925,555)   (937,313)
Depreciation and amortisation   86,473   -
Provision movement   2,488,522   100,000
Share-based payment charge   138,332   -
    (212,228)   (837,313)
(Increase) in trade and other receivables   (160,929)   (26,141)
(Increase)/decrease in prepayments   (4,215)   71,998
(Decrease)/increase in trade and other payables   (2,000)   742,303
Cash used in operating activities   (379,372)   (49,153)
Cash flows from investing activities        
Purchase of tangible fixed assets   (3,112,816)   -
Purchase of intangible fixed assets   (1,051,348)   -
Acquisition of subsidiaries net of cash received   (6,563,135)   -
Net cash used in investing activities   (10,727,299)                         -
Cash flows from financing activities        
Loan (repayment)/received   (35,000)   50,000
Issue of share capital   14,973,259                         -
Costs of issuing share capital   (1,136,755)                         -
Net cash flows from financing activities   13,801,504   50,000
Net increase in cash and cash equivalents   2,694,833   847
Cash and cash equivalents at beginning of year 16 2,078   1,231
Cash and cash equivalents at year-end 16 2,696,911   2,078



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


Page last updated: 29 June 2018

back to top