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Preliminary Results for the year ended 31 December 2017

22 Jun 2018

The Company is pleased to announce the financial information for the year ended 31 December 2017. 

Operational Highlights

  • 3.3% increase in gas sales: 3,684mmscf gross gas sold (2016: 3,566mmscf)
  • 10.98mmscf/d average gas production (2016: 10.23mmscf/d)
  • Completion of two well drilling programme
  • The addition of two prospective areas at Matanda

Audited Financial Highlights

  • $23.5 million revenue (2016: $32.8 million)
  • $4.6 million underlying EBITDA (2016: $13.1 million)
  • $10.7 million loss before tax (2016: $30.0 million)
  • $13.1 million net debt (2016: net cash of $1.8 million)
  • $39.8 million capital investment (2016: $27.0 million) principally on the drilling programme

Corporate Highlights

  • $23.7 million net equity raise via placement and open offer

Post Period

  • Significant increase in reserves and resources
  • Successful debt restructuring

Kevin Foo, Chairman, said:

“Despite the grid power supply issue, I believe that the Company will grow stronger and create a more diverse product base. We have built a company recognised by our peers as an outstanding entrepreneurial example of creating cash from stranded gas deposits. For the first time in our 14 year history we have considerable gas reserves to secure long term supply contracts.”

Ahmet Dik, Chief Executive Officer, said:

“The Company’s management is working hard to increase revenue, particularly in more profitable business lines, whilst at the same time driving hard to contract with the large off-take IPP’s in Cameroon whose scale of business will enable the Company to become profitable.”

Andrew Diamond, Finance Director, said:

“The Group’s operational performance for the year ended 31 December 2017 (“current year”) was strong at a project level, with the Logbaba Project achieving its highest ever gross gas sales. The successful completion of well La-107 and La-108 in December 2017 ensures the sustainability of gas supply and diversifies production from one to three wells.”


Chairman’s Letter



Dear Shareholders

In this year’s letter I will address the important challenges that we faced and overcame in 2017, discuss those challenges that remain and outline the strategy for the next couple of years. As both a shareholder and director I have reflected in some depth on the assets we have, the business we have built and the challenges that keep us awake at night.

Our Company was listed on AIM 14 years ago and has operated in the FSU and Africa. We have never been a company with a large market capitalisation or had ready access to capital; however, we have survived and overcome the massive oil and gas price fluctuations, the seemingly endless technical challenges to progress our upstream and downstream activities and the occasional company threatening economic or political problems, which taken together, or even each alone, is very creditable.

In Cameroon, we have built a company, Gaz du Cameroun (“GDC”), that is recognised by our peers as an outstanding entrepreneurial example of creating a cash generating business from stranded gas deposits. It is a model that, under the right conditions, can be replicated across Africa’s multitude of stranded gas deposits. We were honoured to receive the prestigious “Project of The Year” award at this year’s Africa Assembly of the Oil and Gas Council meeting in Paris.

We all have invested in VOG shares because we believe in the future of the Company.  It is my and our management’s primary objective to deliver the real value of the Company to our shareholders. As Chairman, I am also very aware of the extreme patience that our shareholder base has and their resilience in sharing these challenges with us. Thank you.

Our Assets

As a natural resources veteran, I always look at the resource base that nature has provided us and how we have managed to extract those resources and build something of value. On Logbaba, we finished drilling two production wells in 2017, albeit painfully over budget and behind schedule, but these gas discoveries have added significantly to our reserves and resources.

Earlier this month, we announced a material reserves upgrade for the Logbaba Field, reporting a significant 73% increase in gross 1P gas reserves to 69bcf and a 52% increase in gross 2P reserves to 309bcf. Importantly, the latest reported 2P reserves base at Logbaba would support a 90mmscf/d production rate for ten years, providing the volumes necessary to facilitate a significant expansion in VOG’s business in the growing Douala market. We have never been in this position before in our 14-year history and these results open the door to furthering our negotiations with large off-take independent power producers.

We also estimate over 3.7tcf of P50 Prospective Resources at North Matanda, which we could develop as soon as Government approval is received. The Douala Basin is proving to be a very prolific area and your Company has a prime position there.

Let us not forget West Medvezhye (“West Med”) in Russia, the resource on which our Company was started. Updated reserve and resources figures show C1 and C2 reserves of 11.8bcf of gas and 15.6mmbls of oil and Prospective Resources of almost 4tcf of gas and 722mmbls of oil.

Our “hard” assets at Logbaba are the gas processing facilities and the 50km of gas pipeline that we laid under the city of Douala to reach our 30 plus industrial customers.

Companies often speak of their staff and employees as their most valuable asset, but I believe in some cases they don’t really mean it. Building the Company as we have done needed dedicated and very skilled people who have performed way beyond the call of duty. I believe that shareholders are aware of the total focus and dedication that our Chief Executive Officer Ahmet Dik, Finance Director Andrew Diamond and General Manager Kate Baldwin deliver. But in the field, some other examples come to mind:

Eric Friend, Managing Director of GDC since November 2016 has been instrumental in delivering a disciplined and well organised GDC that operates safely and effectively in the City of Douala. I know first-hand of the daily challenges that Eric deals with.

Eckhard Mueller has been our General Director at West Med in Russia since 2006. He has spent 12 long winters in Siberia carefully managing our project and always looking for ways to add value and save costs. I believe that his dedication is outstanding and with the increased oil price and availability of capital coming back to Russia, West Med is a quality project that we expect will attract a development partner soon and Eckard’s patience will be rewarded.

Divine Mofa Diboto has been a key manager on our Logbaba Project since 2011 and has held various positions in GDC. He is a Chief of his tribe and a leading participant in our community relations programme and as such works tirelessly for GDC from within and outside our operations.

In addition to Eric, Divine and Eckhard our entire teams in London, Russia and Cameroon are the true lifeblood of our company.

Our Operations in Cameroon

When I reflect on operations and activities in 2017, the drilling campaigns on La-107 and La-108 dominate. These wells were truly challenging with the costs overrunning the budget by more than 100% and the schedule approximately double what was originally planned. The prime cause of these difficulties was and will continue to be the truly unpredictable ground and well drilling conditions in the Cretaceous zones of the Logbaba Basin. The well control incident on La-108 caused $24.5 million of additional re-drilling and well repair costs. This is subject to an insurance claim where I believe we have a very credible case. These wells have been shut in for future production. The substantial increase in reserves is primarily due to the prolific gas sands discovered in La-107 and La-108. I have learned that nature makes you work hard for her bounty!

In terms of gas production the annual gross production figure for 2017 was a record for the Logbaba Project, with 3.65bcf of gas sold compared to 3.56bcf in 2016. Average daily production for 2017 was a record of 10.98mmscf/d compared to 10.23mmscf/d in 2016.

However, in January this year, due to factors outside of our control, the ENEO Cameroon S.A. (“ENEO”) contract was not renewed. Cameroon, like many African countries, is chronically short of power and major cities have regular black outs and brown outs. But the resolution of the issue has taken much longer than we expected and clearly there are other complex factors that contribute to this situation that we are working with all stakeholders to resolve.

Despite the grid power supply issue, which will significantly impact our 2018 financial performance, I believe that the Company will grow stronger and create a more diverse product base in 2018 and we can continue to build the business we have created in Cameroon. We now have the gas reserves in place to meet industrial and grid power demand for large quantities of gas and power that is required by groups other than ENEO. We have also committed to build a more diverse customer base that will see the company less reliant on grid power revenues.

GDC is the single onshore gas supplier in Cameroon.  Management estimates that with Logbaba and Matanda, GDC has recoverable gas of at least 2tcf and 50km of gas pipeline and support infrastructure delivering gas to our customer sites. We intend to build on this strong strategic position.

2017 Financial Performance

A cost recovery milestone was reached on Logbaba during 2016 after which revenues are shared in accordance with the participating interests (“Payout”). Whilst gross production increased to record levels on Logbaba in 2017, attributable revenue for the year was $9.3 million lower than the prior year as a consequence of Payout. Payout will apply for future periods, which highlights the importance of scaling up our operations in Douala, Cameroon. With sufficient reserves of gas now in place, this is the principal focus of the management team for the year ahead, a challenge which has not been made easier by the non-renewal of the 50MW power contract.

With a relatively fixed cost base, the reduction in revenue flowed through to the underlying EBITDA which reduced by $8.5 million to $4.6 million.

Further details of our current financial position and uncertainties which may affect the Company’s ability to continue operating as a going concern are to be found in the Financial Review below.

2018 Plans

Coming out of a difficult 2017, but with the drilling campaign behind us, we were aiming for continued production growth in 2018. Instead, we were faced with a seasonal drop in demand of nearly 70% and a proportional reduction in revenue and some truly challenging operational and financial hurdles.

Our Executive and Operational teams developed and implemented a plan for 2018, outlined in the CEO’s Report, which includes expansion of revenues, with a more diverse customer base, embracing technologies such as CNG, completion of the Matanda approvals, reducing costs and preserving available cash reserves. In this respect the Board have decided that no bonuses will be awarded to Executive Directors for the year ended 31 December 2017.

The Board remain confident of the potential of the demand for gas in Douala, which is currently experiencing regular blackouts following the shutdown of the Logbaba and Bassa power stations.  We are now well positioned in our upstream capabilities to reach a much larger downstream gas demand. 

VOG has set an ambitious business strategy to substantially increase gas sales by 2021. We still believe that this is achievable as the demand for gas within Cameroon remains robust.  However, for this to be achieved within the timeframe, a positive resolution of the current hurdles in the energy sector is required in a manner that fosters confidence in international investors to invest in the sector.


In November 2017, we secured net proceeds of $23.7 million in a share placing to new and existing shareholders. We are extremely grateful to our shareholders who continue to show confidence in the prospects in Cameroon.

In relation to the West Medvezhye Project, we are engaged with several interested parties to sell or farm-out our Russian asset.

Our recent sluggish share price has largely been due to the non-renewal of the 50MW power contract. The Board shares the frustration felt by all in the unappreciated value of VOG’s shares, especially when the Company had made such significant progress in recent years. We thank our shareholders for their continued support and patience.

At the Board level, after two and a half years of service to the Company Iain Patrick resigned as an independent Non-Executive Director on 23 April 2018. I would like to thank Iain for his sound contribution to the Board. At that time we reviewed our Board Committee appointments and as a result I stood down from the Remuneration Committee and Roger Kennedy was appointed our Senior Independent Director and Chair of the Audit Committee.  We will endeavour to appoint a suitable third Non-Executive Director in due course.  I would also like to thank the Groups management and employees for a dedicated and focused year of work and our independent Non-Executive Directors for their ongoing guidance.

I would also like to thank, our partners, RSM for their ongoing support of the Logbaba Project and The National Hydrocarbons Corporation of Cameroon (“SNH”) for their invaluable in country support.  

Kevin Foo

Executive Chairman

21 June 2018


Chief Executive Officer’s Review of Operations

I am pleased to report on the progress in 2017. The highlights were:

  • 2017 gross gas sold was a record 3,684mmscf (3.3% increase on 2016)
  • 2017 average daily gas production of 10.98mmscf/d was also a record (2016: 10.23mmscf/d)
  • Drilling completed on Wells La-107 and La-108.
  • Successful $23.7 million net equity raise via Placing and Open Offer to new and existing shareholders

Operations Review

Gas production continued its upward trend and 2017 gross gas sold of 3,684mmscf was a record, as was the 2017 average daily gas production of 10.98mmscf/d. Production was approaching the capacity of our Logbaba Gas Processing Facility (20-25mmscf/d) when the 50MW grid power was operating at its peak consumption in the dry season. GDC management took the decision to defer any plant or pipelines expansion until reserves were secured and Gas Sale Agreements were signed with large gas consumers.

Until GDC had increased reserves from the new wells, it was unable to commit to the long-term contract conditions required by large gas off-takers who specify minimum levels of reserves to commit to their large capital investments. Following the update of its reserves, Logbaba now has sufficient reserves to support production levels of 90mmscf/d for 10 years, which enables GDC to engage in earnest negotiations with prospective grid power customers.

As previously disclosed, ENEO ceased consuming GDC gas on 31 December 2017. Despite the city of Douala being in a significant power deficit, the use of the Logbaba and Bassa gas-fired power stations was terminated by ENEO for reasons entirely beyond our control. From that point on, Management has engaged with all levels within ENEO, the Government of Cameroon, the Energy regulator of Cameroon, Altaaqa (the generation equipment provider) and other interested parties to reinstate the contract and resume the production of electricity using gas. Negotiations are ongoing and we are ready to recommence the supply of gas as all infrastructure and equipment is still in place.

The disruption in the grid power supply by 50MW coming offline has led to customers seeking independent gas to power solutions. GDC has been working closely with various generator suppliers and is looking to provide an integrated solution to customers. One such example is a Combined Heat and Power (CHP) unit at our customer SCTB, a flour mill and pasta producer, who is consuming gas for power and recycling heat and steam from the generation for process heating. The overall energy efficiency for this CHP unit is significantly higher than the efficiency for power generation alone.

The Compressed Natural Gas (CNG) project has also become a top priority and GDC is working to have customers signed by the end of 2018 and thereafter brought online without delay. We have identified a number of potential customers in Eastern Douala who are within a 30km delivery range.  Projected consumption is 1.7mmscf/d of CNG. Stage 1 of the CNG plant is being designed at 2mmscf/d and Gas Sale Agreements are being negotiated with all potential customers. Discussion with technology providers are progressing to ensure a solution is readily deliverable once sufficient customers have customers have been signed up.

Financial Performance

Despite the growth in gross production during 2017, attributable revenue for 2017 was $23.5 million (2016: $32.8 million) which reflects GDC’s 57% participating interest in Logbaba, where previously we accounted for higher levels of revenue in recovery of our former exploration costs. This reduction in revenue flowed through to the underlying EBITDA of $4.6 million compared to $13.1 million in the prior year. The loss before tax of $10.7 million translates to a loss per share of 8.86p (2016: $30.0 million and 28.74p). A more detailed review of the financial performance is recorded in the Financial Review below.

The financial performance for 2017 was below expectations and with the loss of revenue from ENEO, the 2018 results are expected to be significantly impacted. Management is working hard to increase revenue, particularly in more profitable business lines, whilst at the same time driving hard to contract with the large off-take Independent Power Producer’s (“IPP’s”) in Cameroon whose scale of business will enable the Company to become profitable.

The Directors have given careful consideration to the appropriateness of the going concern basis in the preparation of the financial statements. Further details of our current financial position and uncertainties which may affect the Company’s ability to continue operating as a going concern are to be found in the Financial Review below and are disclosed in the Financial Statements.

Looking forward

Having secured gas reserves, the key strategic directions for the Company are as follows:

  • Renew the gas supply contract for the current installed 50MW of power and add further grid power, including new contracts with other IPP’s;
  • Increase thermal gas sales to existing and new customers;
  • Work with existing and new customers to create bespoke gas to power solutions with individual generator designs. These solutions will allow customers to be less dependent on grid power;
  • Maximise return from our high-grade gas condensate. Studies have shown that our condensate is very high grade and close in composition to diesel. We currently sell condensate at near to crude oil prices, which is about half the price of diesel;
  • Actively develop the CNG and Natural Gas Vehicle (NGV) markets. CNG would compete with diesel and LPG as a source of energy in the more remote regions, it offers considerable uplift on current margins and can be transported 250-300km;
  • Sustain progress on the promising Matanda opportunity; and
  • Review capital projects, operational and general and administrative (“G&A”) expenditure rigorously to preserve cash.

Attainment of these objectives is paramount to the future success and profitability of the Company and the Management team is fully focused on delivering on these strategies.

Logbaba Drilling Programme

The drilling of wells La-107 and La-108 during 2016 and 2017 was very challenging and expensive, but we had success in booking significantly more reserves and two new production wells in the onshore Cameroon Logbaba Field. The new wells supplement the two original Logbaba production wells, La-105 and La-106, which were drilled in 2009/2010. The Logbaba wells were required to meet the growing market demand for gas in Douala, Cameroon, to develop our 1P (Proven) Logbaba reserves, and to move some 2P (Proven plus Probable) reserves into the 1P reserve category. Both La-107 and La-108 were drilled directionally from a drilling pad adjacent to the Logbaba Gas Processing Facility. We have increased Logbaba gross 1P reserves by 73% and gross 2P reserves have risen by 52% (as reflected in the table below).

Logbaba Reserves 31 December 2017






Net (57%)

Proved (1P)






Proved + Probable (2P)






Proved + Probably + Possible (3P)






Prospective Resources






La-107 was a near vertical well that twinned the La-104 well drilled in 1957; this well has increased our 1P Logbaba reserves. The La-108 ‘step-out’ well target was about 1,100m to the south- east of the Logbaba drilling pad and was drilled into an area that potentially allowed us to move some of our 2P reserves into the 1P category.

As of 31 December 2017, both La-107 and La-108 have been completed in the Upper Cretaceous (Campanian and Santonian) Logbaba Formation, which is a thick sequence of interbedded sands and shales found at depths between 1,700m and 3,200m below the surface.

La-107 Results

La-107 was drilled to the base of the Logbaba Formation, Target Depth (TD) at 3,180m Measured Depth (MD), 3,166m True Vertical Depth (TVD), where a 4½” liner was run and cemented. The well encountered 54m of net pay, as prognosed based on the original La-104 well that it twinned.

After completion, La-107 was flow tested to a maximum rate of 54mmscf/d on a 70/64ths inch choke, with a stabilized flowing wellhead pressure of 2,951psig. The multi-rate test results indicate that the well has an AOF (Absolute Open Flow) potential in excess of 160mmscf/d.

La-108 Results

La-108 was drilled to its TD of 2,865m MD, 2,463m TVD, where a 4½” liner was run and cemented. La-108 encountered 85m of net pay, about twice that prognosed in the pre-drill estimate. As La-108 was drilled into a previously un-appraised area of the Logbaba Field, this result is very encouraging.

The completion was run and a flow test run on 19m of net sand in the lower part of the Logbaba Formation delivered flow rates of up to 15mmscfd on a 40/64ths inch choke with a flowing wellhead pressure of 2006 psi. During the testing operations, a spent perforating gun became stuck in the production tubing and remains in the well.

In Q2 2018, La-108 was made safe using wireline cutting equipment to cut the wireline cable as close as possible to the spent gun and the barriers securing the well at the surface were reinstated. Planning has been completed to recover the perforating gun and conduct further perforating and flow testing of La-108 later when production demands justify the additional expense.

Drilling Issues

Whilst the drilling programme was successful in its objective to secure more gas for our operations, it did not come without its challenges. As is well documented, these wells are deep, high pressure, high temperature wells. These challenges led to significant overspend on the project. 

The La-107 and La-108 drilling campaign ran significantly over the pre-drill time and cost estimates. The overruns were dominated by:

  • Time lost when La-108 lost circulation in the 8½” hole section, the well took a kick and well control operations were required.
  • The time lost when an 8½” bit was lost in La-107 to perform fishing and side track operations.
  • Time lost due to the electrical problems on the top drive and draw works that was incurred on La-108 ST2 during November 2017.
  • An attempt to log the La-108 8½” hole section and subsequent fishing operations to retrieve a wireline tool string.
  • Difficulty in drilling the La-108 8½” hole, downhole motor problems, anomalously high pore pressures and shallow set of the 7” liner.
  • The additional time required milling the window in La-108 for a second side-track out of the 9⅝” casing.
  • Slower than anticipated drilling in the La-108 ST2 8½” hole.
  • Additional time required to run the 4½” liner in La-107.
  • Significant difficulties in obtaining wireline logs in the La-107 6” hole section.
  • Slower than anticipated drilling in the La-107 6” hole section.
  • Additional time required to run a 7” liner in La-107 and prepare to drill the 6” hole section.

Final costs incurred on the drilling programme were $90.0 million (gross). The well control incident caused significant delays and brought additional costs to the project of $24.5 million (gross). Internal and third-party reviews of the incident support a claim under the Group’s energy package insurance which is being pursued.


As previously announced VOG entered into an agreement for the assignment of 75% of the neighbouring 1,235km2 Matanda block from Glencore in 2016. We have negotiated with the Government some new terms for the PSC agreement in relation to the block which will clarify the work programme obligations going forward.  We anticipate Government approval of the PSC changes shortly and thereafter the Presidential Decree to formally convey title to the Project.

In the meantime we have advanced certain geological and geophysical work on the block aimed at identifying one or more onshore well locations in the Tertiary and/or Cretaceous formations. Two prospective areas in the Matanda Block were initially identified; the Matanda-Bomono border/Missellele onshore area to the north (Area 1) and the onshore area between the Logbaba producing field and the offshore North Matanda field (Area 2).

Reprocessing of heritage 2D seismic was carried out on a 2010 seismic 2D survey in Area 1.  ERCL Consultants carried out a full time and depth interpretation through to prospect identification, evaluation, risking and ranking.  Angle stack (qualitative AVO) data was utilised to assist the team in identifying hydrocarbons and/or liquids.

Alongside this, RPS Energy carried out a reservoir characterisation study to begin work on the least understood element of the Douala Basin hydrocarbon system – its reservoirs.  This work stream included a petrophysical analysis, biostratigraphy, stratigraphy, well correlation and GDE (gross depositional environment) mapping.  This was carried out simultaneously with the ERCL work and the results were fully integrated, allowing ground truthing of the seismic interpretation which added confidence to the prospect evaluation.

As an outcome of this work, 20 prospects and 4 leads were identified in the Tertiary and Cretaceous formations in Area 1.  Economics are currently being run on these prospects and plans are in place for further technical work during 2018 including the completion of reprocessing of vintage seismic and evaluation of the prospectivity of Area 2, quantitative AVO analysis and forward modelling before a well location will be identified.

The identified prospects are a mixture of stratigraphic and structural play types. 


During 2017 the Company announced that a farm-out agreement had been signed with Bowleven plc in relation to an assignment of an 80% participating interest in the neighbouring, 2,237km2 Bomono block production sharing contract. The conditions precedent in the farm-out agreement were not met, and as a result, with effect from 31 December 2017, the agreement lapsed.  Both parties remain amenable to ongoing discussions on this block, however the existing license and work programme commitments are due to expire at the end of 2018, which has a material effect on these discussions.


I am pleased to inform our shareholders that in a year of record gas production and over a long drilling programme, GDC was able to maintain its continued high safety track record with nil lost time injuries reported. The safety of our employees, suppliers and other stakeholders is taken seriously, and this is a record we are both proud of and work hard to defend. I would like to thank our safety officers and all of the GDC staff whose ongoing compliance to our policies and procedures have allowed us to report another year of safe operations.


We pride ourselves on being more than just investors into the Cameroonian market place. We are employers of 121 Cameroonians, providing healthcare to our employees and some 340 additional family members. We are large contributors to the local economy, contributing some $22.6 million (2016: $12.5 million) in direct and indirect taxes in Cameroon.

In addition to this we also support further community outreach programmes and activities. I am particularly pleased to report on our participation in the Orbis Eye Clinic which provided sponsored optical medical treatment to people in Cameroon. Details of our CSR programmes in 2017 will be detailed in the CSR report contained in the Annual Report and Accounts.


We reported the positive actions taken in evaluating the West Medvezhye subsurface potential for the purposes of seeking an investment partner or sale. We remain committed to making use of this asset and continue in our efforts to attract interest from potential investors.

I thank our shareholders for their ongoing support and continued faith in our Cameroonian stranded gas development story. The commitment and dedication of our management and employees during times such as these is admirable, and I thank them for their past and ongoing services.

Ahmet Dik

Chief Executive Officer

21 June 2018

Financial Review


The Group’s operational performance for the year ended 31 December 2017 (“current year”) was strong at a project level, with the Logbaba Project achieving its highest ever gross gas sales. However, for the financial year, where the Group now reflects only the participating interest portion of Logbaba revenues generated, the results were below expectation. The Logbaba drilling programme, which commenced in 2016, was completed in December 2017. The programme was complex and ran over budget, however both wells La-107 and La-108 were drilled to depth successfully and the Group has been able to increase its reserves considerably.







Gas sales (mmscf) - Gross



Gas sales (mmscf) - Attributable



Condensate sales (bbls) - Attributable



Revenue ($’000) - Gross



Revenue ($’000) - Attributable



Net royalties ($’000)



Underlying EBITDA ($’000)



Impairment of Oil and Gas assets, net ($’000)



Loss before tax ($’000)



Loss after tax ($’000)



Basic loss per share (cents)



Operating cash flow before working capital ($’000)



Cash working capital movement ($’000)



Capital invested ($’000)



Net debt ($’000)



A cost recovery milestone was reached on Logbaba during the year ended 31 December 2016 (“prior year”) after which revenues are shared in accordance with the participating interests (“Payout”). Prior to Payout, GDC received 100% of Logbaba revenue as a recovery mechanism for costs incurred during the exploration phase of the Project. Post Payout, GDC accounts for its participating interest of Logbaba revenues. Aside from incurring 100% of the initial exploration costs, GDC contributes its participating interest towards all exploitation costs incurred on Logbaba. Whilst the attainment of this milestone midway through 2016 should be viewed as a positive in terms of the development of Logbaba, Payout has had an impact on the Group’s revenue, performance and cash generated. Having achieved Payout midway through 2016, the impact on the results of the Group in the prior year was not as great as the impact in the current year, which reports the attributable revenues, performance and cash generated for the full year.

On 12 June 2017, the Group formalised a participation agreement entitling The National Hydrocarbons Corporation of Cameroon (“SNH”) to a 5% participating interest in the upstream operations of the Logbaba Project with an effective date of the commencement of exploitation activities on the Logbaba Project in late 2012. As a result, the Group’s participating interest in the upstream activities of the Logbaba Block has reduced from 60% to 57% to accommodate SNH’s interest. The Company is in ongoing negotiations with SNH regarding the mechanism for splitting the Logbaba activities into the upstream and downstream components to determine, amongst others: the potential participation of SNH in the downstream activities; the allocation of assets, liabilities, revenues and costs, and the associated transfer pricing mechanisms; and the net settlement required by SNH to take ownership of their entitlement. The Company has previously disclosed that it has a contingent liability regarding the payment of state royalty on the Logbaba Block. The resolution of the state royalty matter is included in these negotiations. The presentation of the Company’s Financial Statements has required management’s judgement with regard to the outcome of these negotiations to ensure that the Financial Statements present a fair and reasonable view of the financial position and results of the Company.

The completion of wells La-107 and La-108 in December 2017 ensures the sustainability of gas supply and diversifies production from one to three wells. In addition, the increase in reserves announced on 4 June 2018, will enable the Group to enter negotiations for a number of long-term, high volume gas supply agreements with electricity producers and other industries within Douala, which provides significant potential to grow the business.

The final cost of the drilling programme, excluding capitalised interest costs, was $87.0 million (gross). For reasons explained in the CEO’s Review of Operations set out above , these wells significantly exceeded their initial gross budget of $40.0 million. On an attributable basis this has resulted in the Company needing to fund an additional $26.8 million, in addition to the initial budget of $22.8 million. The funding for the incremental cost of the drilling programme was achieved via a blend of debt, new equity and management of our principal drilling suppliers.

The most significant reason for the increased drilling costs was the well control incident on La-108. Having obtained internal and external expert opinions in support of the chain of events, the Company has lodged an insurance claim with the Company’s insurers to cover the substantial and material costs associated with this event and the consequential schedule and cost overruns. The gross amount of the claim submitted is $24.5 million. As is common in these situations, the outcome of our claim is not certain. The claim has been disclosed as a contingent asset in the financial statements.

On 31 December 2016, the Board decided that it was appropriate to fully impair La-106 as the well was not able to produce the volumes of gas expected from it. Despite the Company continuing to bear 100% of the depreciation on well La-105, a consequence of fully funding the exploration activities on the Logbaba Block, no further asset impairments have been made in the current year.

Statement of Comprehensive Income

At a gross level the gas sold for the year of 3,684mmscf is a 3.3% increase on the 3,566mmscf sold in the prior year. Attributable gas sold for the current year was 2,163mmscf (2016: 2,898mmscf). Attributable gas sold was 59% of gross gas (2016: 81%, owing to the timing of Payout).

Revenue from attributable gas and condensate sales was $23.5 million (2016: $32.8 million). The $9.3 million reduction in revenue, on an increasing level of gross gas sold, reflects the full impact of Payout on the Company. With a relatively fixed cost base, this reduction in attributable revenue flows directly through to underlying EBITDA. The extension of the ENEO Cameroun S.A. (“ENEO”) contract to 31 December 2017 at a gas price of $7.50/mmbtu (previously $9.00/mmbtu) also impacted the revenue for the year.

Net royalties, being the royalties paid less the Group’s share of profit from associate (which represents the Group’s 35% interest in Cameroon Holdings Limited, which in turn earns a royalty from GDC), was 11.1% of attributable revenue for the current year (2016: 11.5%).

Management continues to make efforts to reduce costs in the business. Administrative expenses, which were broadly in line with the prior year, were affected by a further $0.6 million increase provision for land claims, which was disclosed as a contingent liability in the prior year. Other losses include $1.8 million of losses related to foreign exchange movements (2016: $0.7 million).







Operating loss






Impairment of Oil and Gas asset



Underlying EBITDA



Depreciation for the current year was $14.8 million (2016: $18.7 million), which is largely variable and associated with the volumes of gas produced.

Underlying EBITDA, which removes depreciation and impairment charges from the reported operating loss, of $4.6 million (2016: $13.1 million) reflects the impact of Payout on the revenues and underlying performance of the Logbaba Project.

The Group produced a loss before tax of $10.7 million (2016: $30.0 million), and a loss after tax of $10.1 million (2016: $31.1 million). The basic and diluted loss per share was 8.86 cents (2016: 28.74 cents).

Statement of Financial Position

Intangible assets of $54.2 million (2016: $17.6 million) represent the costs incurred on the Logbaba drilling programme. When feasible these costs will be transferred to oil and gas assets within property, plant and equipment.

The increase in trade receivables to $13.5 million (2016: $8.8 million) is due to an attributable increase in the ENEO receivable of $1.2 million and a $3.8 million increase in partner receivables being RSM’s share of drilling costs and SNH’s receivable following their participation.

Trade and other payables of $14.3 million (2016: $12.8 million) increased due to increased expenditure on the drilling programme.

Cash and cash equivalents were  $11.5 million (2016: $16.3 million). Borrowings have increased to $24.5 million (2016: $14.5 million). The Company had made applications for an additional debt facility with local banking institutions in Cameroon during the second half of 2017. With ENEO suspending the consumption of gas on 1 January 2018, management decided to place the applications on hold until the matter was resolved.







Cash and cash equivalents



Borrowings: Current liabilities



Borrowings: Non-current liabilities



Net (debt) / cash



During 2017, the Company obtained shareholder and High Court approval for the cancellation of the Company’s deferred shares and a reduction of the Company’s share premium account from $230.6 million to nil.

Net debt and liquidity

Net debt of $13.1 million (2016: net cash of: $1.8 million) reflects the liquidity position of the Group.

The Company raised $23.7 million net proceeds in an equity placement in November 2017. We thank our new and existing shareholders for the confidence that they have shown in the Company.

Cash Flow Statement

Operating cash inflows, prior to the effects of working capital movements, were $5.7 million (2016: $12.7 million), reflecting the impact of the revenue sharing post Payout.

Working capital increased $2.0 million (2016: decreased $10.3 million) owing to larger drilling related payables and accruals.

Capital investment of $39.8 million (2016: $27.0 million) relates mainly to spending on the drilling programme and process plant enhancements. The capital investment was funded by the $23.7 million net proceeds from the equity placement, $15.2 million proceeds from borrowings (2016: $10.0 million), and the balance via an increase in trade and other payables. Repayment of capital on borrowings was $7.8 million (2016: $2.7 million). Capital investment in 2018 has been reduced to only the essential spending and committed costs.

At year-end the Group had cash and cash equivalents and debt headroom of $11.5 million (2016: $30.8 million).


The Logbaba Concession does not contain any work programme obligations.

The Group awaits the Presidential Decree to formalise its assignment of a 75% participation in the Matanda Block. GDC’s share of the Matanda work programme, which the block will have two years to execute from the date of the Presidential Decree, is anticipated to be $11.25 million.

Subsequent Events

With effect from 1 January 2018, ENEO ceased taking gas from GDC and did not renew the gas sale agreement. Management continues to engage with the relevant stakeholders in Cameroon with the aim of agreeing a new long-term contract and reinstating the production of gas fired electricity at the Logbaba and Bassa power stations.

On 23 April 2018, Iain Patrick resigned as an independent non-executive director of the Company.

On 14 June 2018, the Group announced that it had renegotiated the terms of the BGFIBank loan agreement. The revised loan agreement has a five-year tenure commencing in July 2018 and includes a twelve-month interest-only period. The remaining terms of the loan remain materially unchanged.

Going Concern

The Directors have given careful consideration to the appropriateness of the going concern basis in the preparation of the financial statements. There are a number of uncertainties that may affect the Company’s ability to continue operating as a going concern, these are disclosed in the Financial Statements.

The Directors have reviewed operating and cash forecasts in respect of the operating activities and planned work programmes of the Group’s assets. In the case that either ENEO does not resume consumption or a settlement of the insurance claim is not completed, additional finance will be required and, in this event, the Directors believe that they will be able to access additional financing in order to continue to meet obligations and develop operations for a period of at least twelve months from the date of approval of these Financial Statements. 

On this basis the Directors have concluded that it is appropriate to prepare the Financial Statements on a going concern basis. Accordingly, these Financial Statements do not include any adjustments to the carrying amount and classification of assets and liabilities that may arise if the Group was unable to continue as a going concern.

Looking Ahead

The non-renewal of the ENEO contract will have a significant impact on the financial results of the Company in 2018.

Maintaining sufficient liquidity and meeting the Group’s obligations as they fall due will enable the Group to remain in position to benefit from the considerable upside potential which exists in the Cameroonian energy market.

Andrew Diamond

Finance Director

21 June 2018