18th Apr 2018 07:00
18 April 2018
Eland Oil & Gas PLC
("Eland" or the "Company")
Final Results for the Year ended 31 December 2017
Eland Oil & Gas PLC (AIM: ELA), an oil and gas production and development company operating in West Africa with an initial focus on Nigeria, is pleased to announce the following update.
George Maxwell, CEO of Eland, commented:
"2017 has been the most successful year in Eland's history. This is primarily due to the growth in oil production from OML 40, from an average of 1,500 bopd during 2015 and 2016 (and zero at the start of 2017) to 18,500 bopd gross at year end.
The Company will continue to pursue the strategy of investing and development on near term producing assets in Nigeria and West Africa. These opportunities are ever increasing for the Company as we continue to prove our capabilities in delivering value to all our stakeholders."
2017 Highlights & 2018 Developments
· Step-change year for the company with production increasing from zero at the start of 2017 to 18,500 bopd gross (Elcrest net 8,325 bopd) in December*
· Successful implementation of an alternative oil export system by shipping to a secure offshore storage facility, leading to the recommencement of production in January 2017
· Opuama-7 sidetrack well commenced drilling in September, resulting in initial production of 7,500 bopd gross (Elcrest net 3,375 bopd) in November. This was followed by a successful infill well on Opuama-8
· Successful equity placing in June 2017 raising $19.5 million to accelerate the ongoing work programme
· Syndication of the Reserve Based Lending ("RBL") facility in December 2017 and the re-profiling of the repayment period in March 2018. The $35 million facility is based on production and cash flows from only the Opuama-1, 3, 7 and 8 wells, with principal repayments not due until March 2019
· Cash balance of $36.7 million at end-2017
Outlook
· The Opuama-8 infill well commenced production in January 2018 at rates in excess of 6,000 (net 2,700) bopd. This contributed to a record high production rate for OML 40 of 23,164 bopd from the four producing wells (Opuama-1, 3, 7 and 8) in March
· Drilling operations for Opuama-9 have commenced and the well is expected to contribute an additional 4,000 - 6,000 (1,800 - 2,700 net) bopd to total Opuama production on completion. The well will also appraise the excellent quality shallow "C" reservoirs indicated in Opuama-8 and the deeper E2000 reservoir
· Following on from Opuama-9, the Opuama-10 well will be drilled, targeting all reservoirs from the C3000 to D5000, with initial production rates expected of 4,000 - 6,000 (1,800 - 2,700 net) bopd
· By mid-2018 total OML 40 production in excess of 30,000 (13,500 net) bopd is anticipated
· In H2-2018 the Company currently expects to complete an Early Production System (EPS) on Gbetiokun field in OML 40. Gross initial production rates of around 8,000 (3,600 net) bopd are anticipated from the Gbetiokun well
· In H2-2018 the company also expects to commence operations on the Ubima field including the re-entry and completion of Ubima-1
*Elcrest Exploration & Production Nigeria Ltd has a 45% interest in OML 40. Eland has a 45% equity shareholding in Elcrest. OML 40 net position reflects Elcrest ownership.
For further definitions, glossary of technical terms, and detailed accounts, please see our full audited 2017 Annual Report & Accounts which are available shortly on the Company website: www.elandoilandgas.com.
For further information:
Eland Oil & Gas PLC (+44 (0)1224 737300)
www.elandoilandgas.com
George Maxwell, CEO
Ron Bain, CFO
Finlay Thomson, IR
Canaccord Genuity Limited (+44 (0)20 7 523 8000)
Henry Fitzgerald O'Connor / James Asensio
Panmure Gordon (UK) Limited (+44 (0)20 7 886 2500)
Adam James / Atholl Tweedie
James Stearns
Camarco (+44 (0) 203 757 4980)
Billy Clegg / Georgia Edmonds / Tom Huddart
Notes to editors:
Eland Oil & Gas is an AIM-listed independent oil and gas company focused on production and development in West Africa, particularly the highly prolific Niger Delta region of Nigeria.
Through its joint venture company Elcrest, Eland's core asset is OML 40 which is in the Northwest Niger Delta approximately 75km northwest of Warri and has an area of 498km². In addition, the Company has a 40% interest in the Ubima Field, onshore Niger Delta, in the northern part of Rivers State.
The OML 40 licence holds gross 2P reserves of 83.4 mmbbls, gross 2C contingent resources of 40.4 mmbbls and a best estimate of 254.5 mmbbls of gross unrisked prospective resources. * The Ubima field holds gross 2P reserves of 2.4 mmbbls of oil and gross 2C resource estimates of 31.1 mmbbl.**
Net production figures relate to Elcrest Exploration and Production Nigeria Ltd ("Elcrest"), Eland's joint venture company. Production rates, when oil is exported via Forcados, are as measured at the Opuama PD meter, are subject to reconciliation and will differ from sales volumes.
*Netherland, Sewell & Associates Inc CPR report 31 December 2017
**Source: Independent Report by AGR TRACS April 2016
Cautionary statement regarding forward-looking statements
This Results Statement may contain forward-looking statements which are made in good faith and are based on current expectations or beliefs, as well as assumptions about future events. You can sometimes, but not always, identify these statements by the use of a date in the future or such words as 'will', 'anticipate', 'estimate', 'expect', 'project', 'forecast', 'intend', 'plan', 'should', 'may', 'assume' and other similar words. By their nature, forward-looking statements are inherently predictive and speculative and involve risk and uncertainty because they relate to events, and depend on circumstances that will occur in the future. You should not place undue reliance on these forward-looking statements, which are not a guarantee of future performance and are subject to factors that could cause actual results to differ materially from those expressed or implied by these statements. The Company undertakes no obligation to update any forward-looking statements contained in this Results Statement, whether as a result of new information, future events or otherwise.
Chairman's Statement
2017 was a year of recovery for the Nigerian oil industry and production growth for Eland. This included Eland's key asset, OML 40 in the Niger Delta, which resumed production in late January following an 11-month shut-in, exporting through shipping operations. I am delighted to report that by the end of 2017, OML 40 was producing at its highest ever rates with a development programme in place to further materially increase production from this world-class asset.
2017 saw oil prices continue the recovery that commenced in 2016. Some weakness in the first half of the year was followed by a strong recovery in the second, primarily due to the impact of OPEC cutbacks on global crude stock levels. These stronger oil prices together with material increase in production throughout have led to a welcome cash flow boost for your company.
Throughout 2017 Eland has demonstrated a flexibility which has allowed the Company to overcome the disruptions caused by the Forcados system shutdown while substantially increasing the Opuama production potential. This was initially accomplished through the launch of an alternative tanker export route which capitalised on the successful workover increasing stabilised field production to c.8,000 (3,600 net) bopd.
With the reopening of the Forcados terminal in May, tanker shipping operations were concluded but remain a viable alternative should the need arise, giving security to future cashflows. The company has since embarked upon its planned Opuama drilling campaign which has to date provided peak production in excess of 23,000 (10,350 net) bopd. Opuama's current infill drilling programme is expected to conclude in 2018 and provide a solid base for further financial developments on the OML 40 licence.
On the financing side of the business, 2017 was very successful. An oversubscribed equity placing was completed in June, raising $19.5 million at a price of 55p/share. This combined with increased cashflow from operations resulted in the company ending the year with $37 million, well positioned for 2018.
During the year there were two changes to the Board. Ron Bain joined the company as Chief Financial Officer in August following the resignation of Olivier Serra. Ron brings a wealth of experience in the oil industry relevant to the growth phase that the company is entering.
The Board was further strengthened with the appointment of Brian O'Cathain as non-executive director in October. Brian is a seasoned oil industry professional whose experience and knowledge is additive to the board and we welcome both his and Ron's appointments.
The progress made in 2017 continues to demonstrate both the undoubted potential of OML 40 and the management's ability to deliver in a challenging and ever-changing environment. The achievements of 2017 are just the first step in a potential multifield development within the block which the company is on the cusp of unlocking. While challenges remain, the team assembled has demonstrated the skills necessary to succeed and I look forward to substantial growth in 2018.
Russell Harvey
Chairman
17 April 2017
CEO'S Statement
RECORD YEAR FOR ELAND
2017 has been the most successful year in Eland's history. This is primarily due to the growth in oil production from OML 40, from an average of 1,500 (675 net) bopd during 2015 and 2016 (and zero at the start of 2017) to 18,500 (8,325 net) bopd gross at year end. Contributory factors to this success were improved infrastructure performance and higher oil prices, ending the year at $66.61 per barrel. Eland also benefited from a marked improvement in overall market conditions for the Oil & Gas industry. Investor interest improved in the market as evidenced by the company's $19.5 million equity fund raise in June which was oversubscribed.
It was mentioned within our 2016 report that since production restarted in early 2017, this would be a part recovery year with a focus on improving our production levels, increasing our investment in OML 40 and improving the overall working capital deficit. Over the period our activities resulted in an increase in overall shareholder value of more than £75.0 million. This improvement has continued into Q1-2018 with an increase of over £111.0 million over the 15-month period. Overall working capital has improved by around $20 million from its peak of $(49) million net liabilities in May 2017 and continues to improve into 2018. Investment in our assets continues into 2018 with remarkable results in production performance. During 2017 and so far in 2018 production records have been set for OML 40 and we expect to continue this record breaking performance in production and value growth during 2018 and beyond.
ALTERNATIVE ROUTE TO MARKET
Late in 2016, as the reopening of Forcados Export Terminal (FOT) was further delayed, the Company, through Elcrest, begin the process of establishing an alternative export route for crude oil monetisation. This involved significant logistical and maritime planning in conjunction with major engineering works around our pipeline. This method was designed, engineered, contracted and operational within 3 months of concept. During the 5 months of sole risk shipping operations, Elcrest delivered over 515,000 (231,750 net) bbls of crude oil without loss. This was accomplished through a detailed study of internal capabilities, skill set requirements for marine operations, a detailed work plan which included a comprehensive risk matrix on each event and possible outcome with a full mitigation plan build into the operation. This innovative approach satisfied multiple issues facing the Company in early 2017, the key issue of re-starting production operations after almost a one-year delay, proof of concept for an alternative evacuation route and generation of cash flow relieving working capital pressures. Compared to our peer group, the turnkey approach adopted by the Company was hailed as the most successful, incident free, approach during this period and has now been adopted by others in the industry.
The Forcados system has been operating normally since May 2017. However, should there be long-term problems with the Forcados system in future, we now have an alternative, secure and cost-effective method of oil export that can be implemented at short notice.
DRILLING & PRODUCTION OPERATIONS
During the enforced shut down in 2016 the Company continued with investing activities. This was primarily on the Opuama-3 workover, which was completed in May 2016. However, the full benefit of this investment was only evident in 2017. The success of the workover enabled the Company to deliver export quality crude (zero or low water content) during the shipping operation without the additional investment of de-watering equipment (de-watering was installed later during 2017). This well, produced throughout the shipping period, producing all of the crude exported via shipping.
The other production well Opuama-1 could not be produced as it had a higher water content. In May of 2017 the FOT came back on line and the production could be accessed for all wells (Opuama-1 and 3). This increased production to over 12,000 bopd and enabled the Company to make the commitment to our planned drilling program.
Drilling planning activities had been on-going throughout early 2017, and we had already identified the available drilling units in country. Well planning and design was completed with our partners Nigeria Petroleum Development Company (NPDC) and submitted to the Department of Petroleum Resources (DPR) for approval. Elcrest, through agreement with NPDC contracted the drilling unit OES Teamwork for the planned drilling campaign, and following the completion of dredging, community consents and a full inspection of the rig and drill site, the unit was mobilised in August. Drilling commenced on Opuama-7ST, a side tracked well from the original Opuama-7 well. This side track proved very successful and was completed in November delivering initial rates of up to 7,500 (3,375 net) bopd at a cost of just $14.1 million resulting in a payback period of just 65 days for the well. The rig moved to drill the next target, Opuama-8. This was to be the first new well drilled on OML 40 since 1982, and the first new drill on the Opuama field since 1977, a significant milestone for the asset and the Company. Opuama-8 was successfully drilled to a depth of 9,500 ft and intersected over 160 ft of combined net pay. The well was completed on multiple producing zones in January 2018, contributing initial rates around 6,200 (2,790 net) bopd. The Company exited 2017 with production rates in excess of 18,500 (net 8,325) bopd which has subsequently increased to over 23,000 bopd (net 10,350) during 1st quarter 2018. Drilling operations for Opuama-9 have commenced and the well is expected to contribute an additional 4,000 - 6,000 (1,800 - 2,700 net) bopd to total Opuama production on completion.
During our drilling operations we have performed subsurface logging as we drill each well. This has provided new information with regard to our understanding of the subsurface structure. This information is currently being evaluated and processed into updated mapping of the subsurface and this currently looks promising for the future of the Opuama field and a continued infill drilling program beyond the planned Opuama-10 well due to spud in Q2 2018.
There has been a significant improvement in production facilities and flow station management during 2017. A full audit of the flow station was performed during 2017 and a number of processes, practises and equipment issues were identified. A plan was established for the introduction of revised HSE and safe working environment policies and procedures have been introduced and significant equipment upgrades have been completed during 2017 and continue into 2018. The re-enforcement of the safety culture into the flow station operations is fully supported by the Company and our partner NPDC. Near miss reporting was introduced and Total Recordable Incident Rate (TRIR) is a key performance indicator for the Company.
In 2016 the Company procured a new metering system to be installed at the custody transfer point at the Otumara Manifold near a Shell Flow Station. This Lease Automatic Custody Transfer unit (LACT), measures both volumetric and petro-physical characteristics of the crude oil. The installation of this meter has been ongoing since Q3-2017 and is expected to be fully commissioned in Q2-2018. This will provide accurate and indisputable measurements of the crude oil delivered from OML 40 for transportation by Shell onwards to the FOT. This investment should significantly reduce the computed loss allocation on the Trans Escravos Pipeline (TEP) and provide a detailed measurement of pipeline performance between Opuama and Otumara. Further investment on de-watering capability was made during 2017. A leased unit was installed to de-water produced crude to near export quality. This system currently has the capacity for over 10,000 bopd and is proving very effective in ensuring available ullage in both the flow station and pipeline to maximise crude oil export. Further studies and remedial work is currently underway on the flow station to maximise production capacity within the current set-up.
Our performance during 2017 is testament to our ability to monetise significantly increased production volumes. 2018 production has and is expected to continue to show rapid growth and we will continue to invest and upgrade to support the enormous potential of our subsurface reserves.
There has been a significant investment in our Ubima development (within OML 17) just north of Port Harcourt. There are plans to re-enter Ubima-1 well and evaluate the shallower reservoirs and evaluate and produce from the deeper zones. To facilitate this drilling plan work on the road access began in 2016. This was further augmented in 2017 with more structural work on the road access to ensure we could access the field with heavy equipment during all seasons. The drilling and production site has been landscaped and secured, with all the civil works to be completed during Q1-2018. This includes the security access, perimeters and drilling cellars.
INVESTMENT AND FUNDING
The Company held its first Capital Markets Day during April 2017. This presented an ideal opportunity for the management team to highlight the ongoing operational, technical and financial planning around current and future activities. This was fully attended and regarded as a considerable success. It afforded the Company to layout the full range of prospects within OML 40 and Ubima highlighting the considerable potential of the current asset base held by the Company, indicating a success-based potential in excess of 80,000 bopd (Gross). It provides the reminder that OML 40 and Ubima are on the whole mainly green field sites. The more we study our assets the greater potential we discover.
These opportunities also required additional funding, and to kick start our drilling program, we initiated a stock issue in June, raising just over $19.5 million (gross) which was oversubscribed. The majority of the raise was from a number of investors new to the share register, highlighting the increased interest in the Oil & Gas market.
2018 AND BEYOND
Moving into 2018 we have already invested heavily in OML 40 and have plans for Ubima. The drilling programme on OML 40 has had some delays and complexities with the drilling unit. This issue although disappointing is not that unusual in a multi-well campaign especially with the rig having not been operational for some time prior to mobilisation. The program will continue with Opuama-9 and 10 for 2018. Further drilling activity on OML 40 is being considered for the Gbetiokun field development with the re-entry and completion of Gbetiokun-1 and the drilling of Gbetiokun-3 also potentially within 2018, subject to the various regulatory approvals being in place. Eland is also planning an exploration well on the Amobe prospect, to potentially be drilled in late 2018 or 2019. This large, robust, structure is similar to Opuama in structural style, shows structural closure over a vertical interval of 5,000 feet, and is located less than seven kilometres from the Opuama Flow Station. Best estimate prospective resources are assessed by NSAI at 78 MMstb, with very high upside potential, and the geological risk is low. Further drilling opportunities within Opuama are also a real possibility, building on the information obtained during the current drilling campaign. Similar to Gbetiokun, the exact timing of these additional in-fill wells is subject to the various regulatory requirements and approvals. Preparation work on well proposals, draft Field Development Plans and surface engineering concepts are well underway. These include new flow stations, pipelines and infrastructure centred towards enhanced evacuation opportunities. The potential for further wells on OML 40 to appraise and develop the other prospects around our hub gathering facilities are high on our priority and will feature more heavily in our 2019 programme.
The scheduling for evaluation and production of Ubima 1 is planned for 2018, with full field development being scheduled for 2019. The exact details of the development will be subject to the results obtained from the Ubima-1 re-entry. Work is currently on-going with pipeline surveys to both evacuation opportunities to the south through the Bonny Oil Terminal and to the north east through Brass River Oil Terminal. We expect to finalise these studies prior to completing the Ubima-1 re-entry, and we still anticipate production from Ubima field to commence during 2018. The opportunity for a significant reserves upgrade from the results of Ubima-1 highlights the true value of this asset.
The discussions around the renewal of the OML 40 licence began with our Partner NPDC and the DPR early in 2018. This process is expected to conclude within the next few months. This will enable us to firm up our long-term work programme and the required debt financing.
Although the Company has not proposed a dividend in relation to the 2017 financial year, we look forward to reviewing our dividend policy in light of our improved financial performance, increased production, and forward work programme in 2018 and beyond.
The Company will continue to pursue the strategy of investing and development on near term producing assets in Nigeria and West Africa. These opportunities are ever increasing for the Company as we continue to prove our capabilities in delivering value to all our stakeholders.
George Maxwell
Chief Executive Officer
17 April 2017
CFO Statement
REVIEW OF 2017 - A BREAKTHROUGH YEAR
2017 was a breakthrough year for the Company, entering the year with zero production and exiting at over 18,500 gross (8,325 net) barrels per day from the OML 40 license. Average annualised gross production for the full year was 8,743 (3,934 net) bbls/day, a record for the Company. This is a remarkable achievement and the Company fully expects to build on this success in 2018.
As a result, revenue was transformed in 2017 rising to $68.9 million (2016: $2.4 million) derived from net liftings of 1,351,000 bbls (2016: 83,200), with 2016 having been severely impacted by the Forcados downtime experienced from February that year. Eland achieved a realised price of $50.98 (2016: $28.52) compared to the Brent average for the year at $54.25. The lower realised price compared to Brent was impacted by the timing of liftings in the year. However, as we enter 2018 we are seeing the Forcados blend trading at a premium to Brent which is advantageous to the Company's cash flows.
HEDGING
Eland was unhedged throughout 2017 and thus benefited from the strong rise in the oil price in the latter half of 2017 and into 2018. The Company will continue to regularly review its approach to managing commodity prices, interest rate and currency fluctuations in the context of its ongoing operating and capital commitments.
OPERATING COSTS
Operating costs comprise cost of operations, royalties, depreciation of property, plant & equipment ("PPE") and changes in lifting position totalled $77.3 million (2016: $25.4 million).
2017 | 2016 | |
$000 | $000 | |
Direct field operating costs | 10,336 | 6,359 |
Tariff & transportation (incl. shipping) | 23,429 | 241 |
Onshore support | 11,272 | 14,191 |
Royalties and taxes | 16,349 | 2,370 |
DDA | 12,534 | 912 |
Movement in under/over lift
| 3,357 | 1,374 |
Cost of Sales | 77,277 | 25,447 |
Comparisons with the prior year are made difficult due to the prolonged closure of Forcados in 2016, leading to less than two months production in the year. Consequently, production-driven costs including royalties, transportation, and DDA have risen as result of the increasing production, together with operating costs associated with the shipping operations in 2017.
PROFIT AFTER TAX
The full year loss after tax narrowed to $8.8 million (2016: $30.4 million) although as production increased in the second half of the year our profitability and cash generation continued to gather pace with second half year profit after tax of $13.6 million partially offsetting the loss after tax in the opening half year of $22.4 million. By Q4-2017 the Company generated over $9.1million in post-tax profit.
YEAR OF TWO HALVES
January to May: Shipping
Revenue continued to be impacted during the first half of the year due to the shut-in of the Forcados terminal after the terminal operator declared force majeure in February 2016 following disruption to the terminal's subsea crude export pipeline. As the Company entered 2017 it executed its shipping operations to export crude from the Opuama field. Financially this period was hampered by FPSO downtime, limiting its ability to take delivery of the crude, and production constraints where we were limited to producing from a single well due to the unreliability of water handling capabilities at the FPSO. Nonetheless, this successfully demonstrated the ability to execute an alternative method for exporting crude other than through an onshore terminal. Operating costs were impacted by the largely fixed barging costs and constrained production levels. With production levels from OML 40 now almost three times higher than in H1-2017, cash flows would now comfortably cover the largely fixed operating costs making utilising an alternative offtake route via shipping significantly more economically attractive in the future.
June to December: Back to Forcados
With the return to Forcados on 24 May 2017 the Company was able to generate significant operating cashflow and reduced its operating costs substantially. Operating cost from June to December including field opex and transportation to Forcados were around $10/bbl (excluding royalties). We expect to at least maintain this level of operating cost per barrel in 2018 even after an increase in tariff costs to export through the Forcados network, as SPDC begin trying to recoup the costs of the 2016/2017 repairs from the new tariff rate from all injectors.
We were delighted with the infrastructure uptime achieved of over 90% from May to December, covering all facilities from the Opuama field all the way to the Forcados export terminal. Specifically, OML 40 owned infrastructure was over 95% in the period which is a great achievement and testament to our production operating capabilities.
GENERAL AND ADMINISTRATION COSTS
Administrative expenses were reduced to $4.5 million (2016: $5.8 million), largely held flat once the impact of foreign exchange is excluded, a period where the Company remained extremely lean and continued to preserve cash.
TAX
The Company has applied for the two-year extension to its original three-year initial period of pioneer relief. Pioneer tax incentive is granted by the Nigerian Investment Promotion Commission granted under the Industrial Development Income Tax Relief Act. Nevertheless, Elcrest recorded a net loss for the year which limited the benefit from this relief in the period.
An increased tax credit of $6.8 million was booked in 2017 (2016: $1.0 million), principally reflecting the deferred tax credit recording the timing difference between our book depreciation charge and the utilisation of tax capital allowances. We anticipate this unwinding in future periods post the pioneer tax status period. As a consequence, the loss after tax reduced to $8.8 million (2016: $30.4 million).
BALANCE SHEET
Working capital was stretched significantly during 2017 and reached a peak with net current liabilities of $49 million in May 2017. Following the equity raise and return to Forcados production, this position continued to improve in the second half of the year, reducing to $29.4 million even after allowing for the RBL borrowings of $9 million brought into short-term liabilities.
The Company continues to carefully manage its working capital position and anticipates moving towards a net asset position during 2018.
The consolidated balance sheet shows net assets grew to $166.3 million (2016: $155.7 million). This rise reflects the capital investment in the Opuama infield drilling campaign that was initiated in the second half of 2017.
EQUITY RAISE
In June 2017 an oversubscribed equity placing raised $19.5 million at 55p/share. Given the prolonged Forcados shutdown leading up to the raise this was a great sign of investor confidence in the Company's management and operations. This injection of capital enabled the Company to accelerate the well programme, which commenced with the Opuama-7 sidetrack. The OES Teamwork rig was contracted shortly thereafter with drilling completed and production brought on stream by October 2017 at initial rates of around 7,500 (3,375 net) bbls/day. This was a great demonstration of the short lead times available within the portfolio to create value for the Company and ultimately its shareholders.
BANK FACILITY AND DEBT UPDATE
During December 2017 the Company secured new lenders and increased its borrowings from $15 million to $27 million with an extra $12 million (before fees) received by the Company. Securing two new lenders, Mercuria Energy Trading and Mauritius Commercial Bank, was an excellent result for the company, with the new funding on competitive rates. This additional funding allowed the Company to accelerate its current drilling campaign while it had a rig on location with the benefits already being seen in early 2018 as production continues to rise.
Additionally, to fully optimise the available opportunities the Company holds within its portfolio, we believe it is important to broaden our debt funding base. Therefore in 2018 we will look to secure additional debt funding to deliver on our objectives to grow the Company by developing new additional fields within the OML 40 license and Ubima marginal field.
CASH FLOW
Cash generated from operations grew strongly to $13 million from a $5 million deficit in the prior year. Total capital investment rose to $15.6 million (2016: $6.9 million) reflecting the Group's determination to accelerate its growth plans by developing the Opuama field further with the bulk of the capex related to drilling the Opuama-7 sidetrack and Opuama-8 well.
Financing activities generated $30.6 million with proceeds from the June equity raise of $18.6million (net of fees), coupled with its increasing borrowings of $12 million positioning the Company to further invest in 2018.
Finance costs rose to $3.4 million (2016: $2.4 million) although loan interest remained relatively constant. Due to working capital constraints in the early part of 2017 we reached agreement to defer certain payments with a corresponding increase in interest payable.
Cash balances at the year-end grew to $36.7 million (2016: $11.1 million) with net cash of $11.3 million at end 2017 (2016: $(2.2) million net debt).
GOING CONCERN
As set out in Note 2, there remain risks to mitigate, but the Company has made great strides over the past 12 months to manage these risks and as a consequence enters 2018 in significantly healthier financial position than a year ago.
OUTLOOK
The Company had a difficult year in 2016 suffering from the macro-environment in Nigeria, however 2017 was without doubt a breakthrough year. Having emerged from a very difficult period the business has taken proactive steps in identifying and implementing an alternative evacuation plan. We have improved our financial capability both from an equity raise and then re-profiling our RBL facility and introducing two new lenders. The investment has been directed into successful drilling which has optimised earnings and improved our cash flow generation.
The Company has never been in a stronger position, both in terms of opportunities available and financially to take advantage of such opportunities. Our work programme via the current drilling as well as a very positive two-day workshop in March 2018 with our partner NPDC and the Department of Petroleum Resources on licence renewal places us in a good position to look ahead at further drilling opportunities, both in OML 40 and in OML 17.
The Company's strong fundamentals, low gearing, and strong and increasing production provide the foundation for the Company to explore the refinancing opportunities of its RBL with lenders and investors. The Company expects to increase its available facility to over $100 million. Marketing and discussions with lenders and investors is ongoing, and we look forward to refinancing in the second half of 2018 after the renewal of our OML 40 licence.
In 2018 we will continue to retain a cost focus over discretionary spending, monitor and manage our working capital position, our debt service obligations and focus on investment opportunities that offer the greatest long-term return for our stakeholders.
We firmly believe the Company has laid the foundations for a period of significant growth and shareholder return in 2018 and beyond.
Ron Bain
Chief Financial Officer
17 April 2018
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
for the year ended 31 December 2017
| Note | 2017 $000's | 2016 $000's |
Revenue | 4 | 68,915 | 2,373 |
Cost of sales | (77,277) | (25,447) | |
Gross loss | (8,362) | (23,074) | |
Administrative expenses | (4,488) | (5,832) | |
Operating loss | (12,850) | (28,906) | |
Finance income | 8 | 580 | 306 |
Finance costs | 8 | (3,335) | (2,842) |
Loss before tax | 5 | (15,605) | (31,442) |
Income tax credit | 9 | 6,834 | 1,030 |
Loss after tax and total comprehensive loss for the year | (8,771) | (30,412) | |
Profit/(loss) attributable to: | |||
Owners of the Company | 11,843 | 16,881 | |
Non-controlling interests | 24 | (20,614) | (47,293) |
(8,771) | (30,412) | ||
Earnings per share | Note | 2017 $ | 2016 $ |
From continuing operations: | |||
Basic | 10 | 0.06 | 0.09 |
Diluted | 10 | 0.05 | 0.09 |
All activities relate to continuing operations.
The prior year financial statements had disclosed a shareholder management fee separately from Cost of Sales. This has been reclassified above and is now included within Cost of Sales in 2016 and 2017.
The company has elected to take the exemption under section 408 of the Companies Act 2006 from presenting the parent company statement of comprehensive income.
CONSOLIDATED BALANCE SHEET
As at 31 December 2017
| Note | 2017 $000's | 2016 $000's |
Non-current assets | |||
Intangible oil and gas assets | 11 | 13,149 | 12,200 |
Property, plant and equipment | 12 | 196,043 | 190,005 |
Deferred tax asset | 9 | 12,436 | 4,195 |
221,628 | 206,400 | ||
Current assets | |||
Inventory | 13 | 888 | 353 |
Trade and other receivables | 14 | 9,340 | 1,213 |
Current tax | - | 426 | |
Cash and cash equivalents | 15 | 36,743 | 11,144 |
46,971 | 13,136 | ||
Total assets | 268,599 | 219,536 | |
Current liabilities | |||
Trade and other payables | 16 | (67,358) | (40,406) |
Bank loan | 17 | (9,000) | - |
(76,358) | (40,406) | ||
Net current liabilities | (29,387) | (27,270) | |
Non-current liabilities | |||
Decommissioning provision | 18 | (9,548) | (10,120) |
Bank loan | 17 | (16,417) | (13,334) |
(25,965) | (23,454) | ||
Total liabilities | (102,323) | (63,860) | |
Net assets | 166,276 | 155,676 | |
Shareholders' equity | |||
Share capital | 19 | 257,034 | 253,497 |
Share premium | 20 | 27,466 | 12,452 |
Other reserve | 21 | (10,542) | (10,542) |
Retained earnings | 22 | 59,092 | 46,429 |
Translation reserve | 23 | 1,429 | 1,429 |
Equity attributable to the owners of the Company | 334,479 | 303,265 | |
Non-controlling interests | 24 | (168,203) | (147,589) |
Total equity | 166,276 | 155,676 |
The financial statements of Eland Oil & Gas PLC, registered number SC 364753, were approved and authorised for issue by the Board of Directors on 17 April 2018 and signed on its behalf by:
George Maxwell | Ron Bain |
Chief Financial Officer | Chief Financial Officer |
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
for the year ended 31 December 2017
Share capital $000's |
Share premium $000's |
Other reserve $000's |
Retained earnings $000's |
Translation reserve $000's |
Total $000's | Non- controlling interests $000's |
Total equity $000's | |
Balance at 1 January 2016 | 248,039 | - | (10,542) | 29,412 | 1,429 | 268,338 | (100,296) | 168,042 |
Profit/(loss) for the year and total comprehensive profit/(loss) | - | - | - | 16,881 | - | 16,881 | (47,293) | (30,412) |
Share-based payments (note 28) | - | - | - | 136 | - | 136 | - | 136 |
Issue of share capital (note 19) | 5,458 | 12,452 | - | - | - | 17,910 | - | 17,910 |
Balance at 31 December 2016 | 253,497 | 12,452 | (10,542) | 46,429 | 1,429 | 303,265 | (147,589) | 155,676 |
Profit/(loss) for the year and total comprehensive profit/(loss) | - | - | - | 11,843 | - | 11,843 | (20,614) | (8,771) |
Share-based payments (note 28) | - | - | - | 820 | - | 820 | - | 820 |
Issue of share capital (note 19) | 3,537 | 15,014 | - | - | - | 18,551 | - | 18,551 |
Balance at 31 December 2017 | 257,034 | 27,466 | (10,542) | 59,092 | 1,429 | 334,479 | (168,203) | 166,276 |
CONSOLIDATED CASH FLOW STATEMENT
for the year ended 31 December 2017
| Note | 2017 $000's | 2016 $000's |
Cash generated from/(used in) operating activities | 25 | 12,976 | (5,057) |
Interest and financing fees paid | (3,397) | (2,449) | |
Income tax received | 430 | - | |
Net cash generated from/(used in) operating activities | 10,009 | (7,506) | |
Investing activities | |||
Development expenditure | (14,368) | (5,122) | |
Exploration and evaluation expenditure | (1,111) | (1,758) | |
Purchases of fixtures, equipment, and motor vehicles | (132) | (25) | |
Net cash used in investing activities | (15,611) | (6,905) | |
Financing activities | |||
Net proceeds on issue of shares | 18,551 | 17,910 | |
Net proceeds from borrowings | 12,000 | - | |
Net cash generated from financing activities | 30,551 | 17,910 | |
Net increase in cash and cash equivalents | 24,949 | 3,499 | |
Cash and cash equivalents at the beginning of the year | 11,144 | 8,461 | |
Effect of foreign exchange rate changes | 650 | (816) | |
Cash and cash equivalents at the end of the year | 15 | 36,743 | 11,144 |
NOTES TO THE FINANCIAL STATEMENTS
for the year ended 31 December 2017
1. General information
The principal accounting policies are summarised below. They have all been applied consistently throughout the year and preceding year.
Eland Oil & Gas PLC (the "Company", together with its subsidiaries and controlled entities, the "Group") is a public limited company, which is listed on the London Stock Exchange and incorporated and domiciled in Scotland. The address of the registered office is given on the back cover. The nature of the Company's operations and its principal activities are set out in the Strategic Report.
The Company and the Group's financial statements cover the year to 31 December 2017.
2. Significant accounting policies
Basis of accounting
The financial statements of Eland Oil & Gas plc have been prepared in accordance with International Financial Reporting Standards (IFRS) and IFRS Interpretations Committee (IFRS IC) interpretations as adopted by the European Union and with the Companies Act 2006 applicable to companies reporting under IFRS.
The financial statements have been prepared on the historical cost basis. Historical cost is generally based on the fair value of the consideration given in exchange for the assets at the date of transaction. The principal accounting policies adopted are set out below.
As permitted by section 408 of the Act, the Company has elected not to present its statement of comprehensive income for the year. Eland Oil & Gas PLC reported a profit for the year ended 31 December 2017 of $7,793,000 (2016: loss of $1,696,000).
Going concern
In assessing its conclusion on going concern, the Group has prepared cash, funding and liquidity forecasts through this year and next, and has appropriate plans and levers in place including capex scheduling and hedging to ensure it has access to funding when required and that it is compliant with its covenants.
The return to Forcados combined with the increased production achieved from the 2017 capital investment (post equity raise) has seen profitability and cash flows ramp up significantly as noted in the CFO report. Although risks and uncertainties remain as set out in the 2017 Annual Report and Accounts, management has sufficient mitigating action available to them.
Having regard to the matters above, and after making reasonable enquiries and taking account of uncertainties and reasonably possible changes in operating performance, the Directors have a reasonable expectation that the Group has adequate resources to continue operations for the foreseeable future. For that reason, they continue to adopt the going concern basis in the preparation of the accounts.
Basis of consolidation
The Group's consolidated financial statements incorporate the financial statements of the Company and entities controlled by the Company made up to 31 December each year. Control exists when an investor has power over the investee, exposure or rights to variable returns from its involvement with the investee and the ability to use power over the investee to affect the amount of returns.
The Group owns 45% of the shares of Elcrest Exploration and Production (Nigeria) Limited. It has been consolidated because it is controlled by the Company. The Company has power to affect the amount of returns for the following reasons:
the Company is entitled to appoint a number of Directors to the Board such that it can control decision making.
In the event of disagreement amongst the Board of Directors, decisions are reached by shareholder vote and the Company has the ability, through the combined effect of a Shareholders Agreement, Loan Agreement and Share Charge, to direct the votes of the 55% shareholding that it does not own.
Non-controlling interests in the net assets of the consolidated subsidiaries are identified separately from the Group's equity therein. Non-controlling interests consist of the amount of those interests at the date of the original business combination and the non-controlling interest's share of changes in equity since the date of combination.
New IFRS standards and interpretations
In the current year the following new and revised Standards and interpretations have been adopted, none of which have a material impact on the Group's annual results.
IAS 1 (amendments) Disclosure initiatives
IFRS 10, IFRS 12 and IAS 28 (amendments) Investment Entities: Applying the Consolidation Exception
IFRS 11 (amendments) Accounting for Acquisitions of Interests in Joint Operations
IAS 16 and IAS 38 (amendments) Clarification of Acceptable Methods of Depreciation and Amortisation
IAS 16 and IAS 41 (amendments) Agriculture: Beaver Plants
IAS 27 (amendments) Equity Method in Separate Financial Statements
Annual Improvements to IFRSs: 2012-14 Cycle; Amendments to: IFRS 5 Non-current Assets Held for Sale and Discontinued Operations, IFRS 7 Financial Instruments: Disclosures, IAS 19 Employee Benefits and IAS 34 Interim Financial Reporting
At the date of approval of these financial statements, the following Standards and Interpretations which have not been applied in these financial statements were in issue but not yet effective (and in some cases had not yet been adopted by the European Union):
IFRS 9 Financial Instruments
IFRS 14 Regulatory Deferral Accounts
IFRS 15 Revenue from Contracts with Customers
IFRS 16 Leases
IFRS 10 and IAS 28 (amendments) Sale or Contribution of Assets between an Investor and its Associate or Joint Venture
IAS 12 (amendments) Recognition of Deferred Tax Assets for Unrealised Losses
IAS 7 (amendments) Disclosure Initiative
IFRS 2 (amendments) Classification and Measurement of Share-based Payment Transactions
IFRS 4 (amendments) Applying IFRS 9 Financial Instruments with IFRS 4 Insurance Contracts
New and amended standards and interpretations need to be adopted in the first interim financial statements issued after their effective date (or date of early adoption). There are no new IFRSs or IFRICs that are effective for the first time for this reporting year that would be expected to have a material impact on the Corporation.
The following standards have been published and are mandatory for the Group's accounting periods beginning on or after 1 January 2018, but the Group has not early adopted them:
IFRS 15 'Revenue from contracts with customers'
From its assessment of the standard, the Company does not expect a significant impact on the financial statements.
IFRS 9 'Financial instruments'
The Company will adopt IFRS 9 Financial Instruments for the year commencing 1 January 2018. IFRS 9 addresses the classification, measurement and recognition of financial assets and financial liabilities, introduces a new impairment model for financial assets, as well as new rules for hedge accounting. It replaces the old standard of IAS 39 in its entirety.
The Company has undertaken an assessment of the standard, and does not expect a significant impact on the financial statements.
IFRS 16 'Leases'
The adoption of IFRS 16 Leases, which the Company will adopt for the year commencing 1 January 2019, will impact both the measurement and disclosures of leases over a low value threshold and with terms longer than one year. The directors do not expect that the adoption of IFRS 16 will have a material impact on the financial statements of the group in future periods.
No new Standards or Interpretations were early adopted by the Group or Company during the year.
Joint arrangements
The group applies IFRS 11 to all joint arrangements. Under IFRS 11, investments in joint arrangements are classified as either joint operations or joint ventures, depending on the contractual rights and obligations of each investor. The Company has assessed the nature of its joint arrangements and determined them to be joint ventures. Joint ventures are accounted for using the equity method.
Revenues
Sales revenue represents the sales value of the Group's oil liftings in the year. Oil revenue is recognised when the risks and rewards of ownership have transferred substantially to the buyer and it can be reliably measured, and occurs when title has passed on bill of lading. Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for oil and gas products in the normal course of business, net of discounts, customs duties and sales taxes.
Overlift / underlift
Lifting or offtake arrangements for oil and gas produced in the Group's jointly owned operations are such that each participant may not receive and sell its precise share of the overall production in each period. The resulting imbalance between cumulative entitlement and cumulative production is underlift or overlift. Underlift and overlift are valued at market value and included within receivables and payables respectively. Movements during an accounting period are adjusted through cost of sales such that gross profit is recognised on an entitlement basis.
Intangible oil and gas assets - Pioneer tax
When granted, Pioneer tax relief provides relief from Petroleum taxes. Amounts paid for the approval of Pioneer tax status are initially capitalised and then amortised on a straight-line- basis over the expected tax relief period. Further details are disclosed in Note 9.
Oil and gas assets - exploration and evaluation assets
During the geological and geophysical exploration phase, expenditures are charged against income as incurred. Once the legal right to explore has been acquired, expenditures directly associated with exploration and evaluation are capitalised as intangible assets and are reviewed at each reporting date to confirm that there is no indication of impairment and that drilling is still underway or is planned. If no future exploration or development activity is planned in the licence area, the exploration licence and leasehold property acquisition costs are written off. Pre-licensing expenditures on oil and gas assets are recognised as an expense within the consolidated statement of comprehensive income when incurred.
Oil and gas assets - development and production assets
Once a project is commercially feasible and technically viable, which in practice is when the asset has been approved for development by the appropriate regulatory authorities, the carrying value of the associated exploration licence and property acquisition costs and the related cost of exploration wells are transferred to development oil and gas properties after the impairment test. Development and production assets are accumulated generally on a field-by-field basis and represent the full cost of developing the commercial reserves discovered and bringing them into production. The cost of development and production assets also includes the cost of acquisitions and purchase of such assets, directly attributable overheads, finance costs capitalised, and the cost of recognising provisions for future restoration and decommissioning.
Depreciation of producing assets
The net book values of producing assets are depreciated on a field-by-field basis using the unit-of-production method by reference to the ratio of production in the year and the related proved and probable commercial reserves of the field, taking into account future development expenditures necessary to bring those reserves into production. Producing assets are generally grouped with other assets that are dedicated to serving the same reserves for depreciation purposes, but are depreciated separately from producing assets that serve other reserves.
Impairment of development and production assets
An impairment test is performed whenever events and circumstances arising during the development or production phase indicate that the carrying value of a development or production asset may exceed its recoverable amount.
The carrying value is compared against the expected recoverable amount of the asset, generally by reference to the fair value less costs to sell expected to be derived from production of commercial reserves. The cash generating unit applied for impairment test purposes is generally the field, except that a number of field interests may be grouped as a single cash generating unit where the cash inflows of each field are interdependent.
Commercial reserves are proved and probable oil and gas reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially viable. There should be at least a 50% statistical probability that the actual quantity of recoverable reserves will be equal or more than the amount estimated as proved and probable reserves.
Any impairment identified is charged to the consolidated statement of comprehensive income as additional depreciation. Where conditions giving rise to impairment subsequently reverse, the effect of the impairment charge is also reversed as a credit to the consolidated statement of comprehensive income, net of any depreciation that would have been charged since the impairment.
Impairment of exploration and evaluation assets
Exploration and evaluation ("E&E") costs are not amortised prior to conclusion of appraisal activities. Once active exploration is completed the asset is assessed for impairment. If commercial reserves are discovered then the carrying value of the E&E asset is reclassified as a development and production ("D&P") asset, following development sanction, but only after the carrying value is assessed for impairment and where appropriate its carrying value adjusted. If commercial reserves are not discovered the E&E asset is written off to the consolidated statement of comprehensive income.
Other property, plant and equipment
All classes of other property, plant and equipment are stated at cost less accumulated depreciation and any recognised impairment loss.
Depreciation is recognised so as to write off the cost or valuation of assets less their residual values over their useful lives, using the straight-line method, on the following bases:
Fixtures and equipment: 10% - 30% per annum
Motor vehicles: 30% per annum
Acquisitions, asset purchases and disposals
Acquisitions of oil and gas properties are accounted for as a business combination when the assets acquired and liabilities assumed constitute a business. There have been no such acquisitions to date.
Transactions involving the purchase of an individual field interest, or a group of field interests, that do not constitute a business, are treated as asset purchases irrespective of whether the specific transactions involve the transfer of the field interests directly or the transfer of an incorporated entity. Accordingly, no goodwill and no deferred tax gross up arises, and the consideration is allocated to the assets and liabilities purchased based on relative fair values.
Proceeds on disposal are applied to the carrying amount of the specific intangible asset or development and production assets disposed of and any surplus or deficit is recorded as a gain or loss on disposal in the consolidated statement of comprehensive income.
Cash and cash equivalents
Cash and cash equivalents comprise cash and short-term bank deposits with an original maturity of three months or less. Under the terms of the Reserves Based Lending ("RBL") facility, the Company is required to set aside as Restricted Cash amounts to cover the costs of servicing the debt and stamp duty. As at 31 December 2017, under the terms of the RBL facility, the balance of restricted cash amounted to $1,106,000 (2016: $3,986,000). A re-determination of the facility amount was undertaken in April 2017, and consequently the required amount of restricted cash was reduced to $1,106,000. The restricted cash balances were increased to $1,959,000 in April 2018 in accordance with the terms of the RBL, following the drawdown of an additional $12 million of debt in December 2017. See note 15 for further details.
Inventories
Inventories are stated at the lower of cost and net realisable value. Cost comprises direct materials, and where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their present location and condition and is determined on a first-in, first-out method. Net realisable value represents the estimated selling price less all estimated costs to be incurred in marketing, selling and distribution.
Provisions
Provisions are recognised when the Group has a present obligation as a result of a past event, it is probable that the Group will be required to settle that obligation and a reliable estimate can be made of the amount and timing of the obligation.
The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at the balance sheet date, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows.
When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, a receivable is recognised as an asset if it is virtually certain that reimbursement will be received and the amount of the receivable can be measured reliably.
Decommissioning provision
A provision for decommissioning the Group's oil and gas assets is recognised in full when the related facilities are installed or acquired. The extent to which a provision is required depends on the legal requirements for decommissioning, the costs and timing of work and the discount rate to be applied. A corresponding adjustment to property, plant and equipment of an amount equivalent to the provision is also recognised. This is subsequently depreciated as part of the asset and included in depletion expense in the consolidated statement of comprehensive income. Changes in the estimated timing of decommissioning or decommissioning cost estimates are accounted for prospectively by recording an adjustment to the provision, and a corresponding adjustment to property, plant and equipment. The unwinding of discount on the decommissioning provision is classified in the consolidated consolidated statement of comprehensive income as finance costs.
Leases
Leases are classified as finance leases whenever the terms of the lease transfer substantially all of the risks and rewards of ownership to the lessee. All other leases are classified as operating leases. Rentals payable under operating leases are charged to income on a straight line basis over the term of the lease.
Finance income and costs
Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation.
Borrowing costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.
Foreign currencies
For the purpose of the consolidated financial statements, the results and financial position of each group company are expressed in US Dollars, which is the presentation currency for the consolidated financial statements.
The Group's income, and the majority of its costs, are denominated in US Dollars. The remainder of the costs are denominated in other currencies, predominantly Sterling and Nigerian Naira. The Group also has foreign currency denominated liabilities. Exposures to exchange rate fluctuations therefore arise. The Directors currently believe that foreign currency risk is at an acceptable level.
During the year the Group adopted the use of the parallel exchange rate in Nigeria, which more closely reflects the rate at which the Group converts US Dollars to Nigerian Naira. Further details of the resulting exchange impact are provided in note 5.
Exchange differences are recognised in profit or loss in the period in which they arise.
Taxation
Deferred tax
Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised.
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.
Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realised based on tax laws and rates that have been enacted or substantively enacted at the balance sheet date. Deferred tax is charged or credited in the consolidated statement of comprehensive income, except when it relates to items charged or credited in other comprehensive income, in which case the deferred tax is also dealt with in other comprehensive income.
Financial instruments
Financial assets and financial liabilities are recognised on the balance sheet when the Company or Group has become a party to the contractual provisions of the instrument.
Trade and other receivables
Trade receivables are initially measured at fair value and subsequently measured at amortised cost. The exception to this is underlift which is valued at market value. Further details can be found in note 14.
Trade and other payables
Accounts payable are initially measured at fair value and subsequently measured at amortised cost. The exception to this is overlift which is valued at market value. Further details can be found in note 16.
Financial liabilities and equity
Debt and equity instruments are classified as either financial liabilities or as equity in accordance with the substance of the contractual arrangement.
Capital risk management
Details of significant accounting policies and methods adopted, including the criteria for recognition, the basis of measurement and the basis on which income and expenses are recognised, in respect of each class of financial asset, financial liability and equity instrument are disclosed in note 29 to the financial statements.
Other financial liabilities
Other financial liabilities (including borrowings) are initially measured at fair value, net of transaction costs.
Other financial liabilities (including borrowings) are subsequently measured at amortised cost using the effective interest method, with interest expense recorded on an effective yield basis.
The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability to the net carrying amount on initial recognition.
Equity instruments
An equity instrument is any contract that evidences a residual interest in the assets of an entity after deducting all of its liabilities. Equity instruments issued by the Company are recognised at the proceeds received, net of direct issue costs.
Share-based payments
Equity settled share-based payments are measured at the fair value of the equity instruments at the grant date. The fair value excludes the effect of non-market-based vesting conditions. Details regarding the determination of the fair value of equity settled share-based transactions are set out in note 28.
The fair value determined at the grant date of the equity settled share-based payments is expensed on a straight- line basis over the vesting period, based on the Group's estimate of equity instruments that will eventually vest.
At each balance sheet date, the Group revises its estimate of the number of the equity instruments expected to vest as a result of the effect of non-market-based vesting conditions. The impact of the revision of the original estimates, if any, is recognised in profit or loss such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to equity reserves.
Pension costs
Payments to defined contribution retirement benefit scheme are charged as an expense as they fall due. The Group had no defined benefit schemes in place during the years presented.
3. Critical accounting judgements
In the application of the Company and the Group's accounting policies, which are described in note 2, the Directors are required to make critical accounting judgments and assumptions. The assumptions are based on historical experience and other factors that are considered to be relevant.
The following are the critical judgements that the Directors have made in the process of applying the Company and the Group's accounting policies and that have the most significant effect on the amounts recognised in the financial statements.
Exploration and evaluation assets (note 11)
The accounting for exploration and evaluation ("E&E") assets requires management to make certain estimates and assumptions, including whether exploratory wells have discovered economically recoverable quantities of reserves. Designations are sometimes revised as new information becomes available. If an exploratory well encounters hydrocarbons, but further appraisal activity is required in order to conclude whether the hydrocarbons are economically recoverable, the well costs remain capitalised as long as sufficient progress is being made in assessing the economic and operating viability of the well. Criteria used in making this determination include evaluation of the reservoir characteristics and hydrocarbon properties, expected additional development activities, commercial evaluation and regulatory matters. The concept of 'sufficient progress' is an area of judgement, and it is possible to have exploratory costs remain capitalised for several years while additional drilling is performed or the Group seeks government, regulatory or partner approval of development plans.
Impairment indicators (notes 11, 12)
The Group monitors internal and external indicators of impairment relating to E&E assets and property, plant and equipment. For E&E assets the following are examples of the types of indicators used:
· The entity's right to explore in an area has expired or will expire in the near future without renewal;
· No further exploration or evaluation is planned or budgeted;
· The decision to discontinue exploration and evaluation in an area because of the absence of commercial reserves; or
· Sufficient data exists to indicate that the book value will not be fully recovered from future development and production.
For development and producing oil and gas properties, the following are examples of the indicators used:
· A significant and unexpected decline in the asset's capital market value or likely future revenue;
· A significant change in the asset's reserves assessment;
· Significant changes in the technological, market, economic or legal environments for the asset; or
· Evidence is available to indicate obsolescence or physical damage of an asset, or that it is underperforming expectations.
The assessment of impairment indicators requires the exercise of judgement. If an impairment indicator exists, then the recoverable amounts of the cash-generating units and/or individual assets are determined based on the higher of value-in-use and fair values less costs of disposal calculations. These require the use of estimates and assumptions, such as future oil and natural gas prices, life of field, discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, reserves and operating performance. These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or Cash Generating Units (CGUs).
OML 40 licence extension (note 12)
In line with the licence agreement, the Group alongside its joint venture partner, NPDC, has an option to request an extension of up to 20 years on the OML 40 licence at the current licence expiry date of June 2019, at additional cost, provided the terms of OML 40 have been complied with. There is a precedent for extension of licences in Nigeria and management believe that it is more likely than not that an extension of the licence from June 2019 for a period of 20 years, can be obtained. As referred to in the CEO report on page 8 the Group is currently in discussions with the regulator, DPR, regarding the renewal and is confident of securing the licence extension well in advance of the existing expiry date. Any failure to secure the renewal of the OML 40 licence would have a material adverse impact on the carrying value of the Group's PPE balance, the estimated level of reserves and resources and hence the Group's ability to generate revenue beyond June 2019.
Amounts payable to partners in oil and gas arrangements (notes 16, 31)
In line with the Joint Operating Agreement ('JOA'), the Group is responsible for its share of expenditures incurred on OML 40 in respect of its participating interest, on the basis that the operator's estimated expenditures are reasonably incurred based on the approved programme and budget. From time to time, management disputes such expenditures on the basis that they do not meet these criteria, and when this occurs management accrues at the period end for its best estimate of the amounts payable to the operator. Consequently, the amounts recognised as accruals as at 31 December 2017 reflect management's best estimate of amounts that have been incurred in accordance with the JOA and that will ultimately be paid to settle its obligations in this regard. To the extent additional amounts have been claimed by the operator which are being disputed, management consider any material liability in excess of that accrued to be unlikely. However, where such liability is considered possible the Group will disclose its best estimate within the Contingent liability note. Where management are of the view the liability is considered remote no such disclosure is made.
Further details can be found in note 31.
Critical accounting estimates
The key assumptions concerning the future and other key sources of estimation uncertainty at the balance sheet date that may have a significant risk of carrying a material adjustment to the carrying amount of assets and liabilities within the next financial year are discussed below.
Carrying value of oil and gas assets (note 12)
The carrying value of oil and gas assets is subject to judgement over their recoverable value. The calculation of recoverable value requires estimates of future cash flows within complex value-in-use or fair value less costs to dispose models. Key assumptions and estimates in the cash flow models relate to commodity prices, commercial reserves and the related cost and production profiles, discount rates that are adjusted to reflect risk specific to individual assets.
Management assesses the Group's oil and gas assets for indicators of impairment at least annually with reference to indicators as defined in IAS 36. During 2017 management assessed the following indicators; oil price environment, reserve revisions, tax or regulatory changes, local market conditions, licence expiry terms, and Group market capitalisation movement. In addition, management reviewed the economic outputs from the December 2017 NSAI reserves compared to it's carrying value which showed significant headroom exists to cover the carrying value. Following this assessment management concluded that no material adverse impact had occurred across any key indicator. As such, and in line with its policy, management never completed a full impairment review in the year.
Note 12 discloses the carrying value of tangible oil and gas assets.
Decommissioning provision (note 18)
The Group has significant obligations to decommission and remove oil and gas facilities from its OML 40 licence at the end of the production period currently estimated to be 2031 - see the note on OML 40 licence extension above. Legal and constructive obligations associated with the retirement of non-current assets are recognised at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, that cost is capitalised as part of the related non-current asset and allocated to expense over the useful life of the asset. Management apply judgement in deciding on an appropriate inflation rate to estimate costs in the future and also apply judgement in selecting a discount rate that reflects the time value of money and the risks specific to the liability, and in estimating the likelihood that the licence will be extended after its initial period, as further described in note 18.
The costs of decommissioning are reviewed internally on an annual basis and by an independent specialist at least every three years. A review of all decommissioning cost estimates was undertaken by an independent specialist in 2017 and the updated cost estimate provided by the specialist has been applied in recording the 2017 provision. Provision for environmental clean-up and remediation costs is based on current legal and constructive requirements, technology and price levels.
It is difficult to estimate the costs of these decommissioning and removal activities, which are based on current regulations and technology, considering relevant risks and uncertainties. Most of the removal activities will be undertaken many years into the future and the removal technology and costs are constantly changing. As a result, the initial recognition of the liability and the capitalised cost associated with decommissioning and removal obligations, and the subsequent adjustment of these balance sheet items, involve the application of significant accounting judgement, further details of which are provided in note 18.
Commercial reserves
Proved and probable reserves are estimates of the amount of oil and gas that can be economically extracted from the Group's oil and gas assets and changes are reflected prospectively. The Group estimates its reserves using standard recognised evaluation techniques. The estimate is reviewed annually.
Proved and probable reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves. Future development costs are estimated taking into account the level of development required to produce the reserves by reference to operators, where applicable, and internal engineers.
Reserves estimates are inherently uncertain, especially in the early stages of a field's life, and are routinely revised over the producing lives of oil and gas fields as new information becomes available and as economic conditions evolve. Such revisions may impact the Group's future financial position and results, in particular, in relation to DD&A and impairment testing of oil and gas property, plant and equipment.
4. Revenue
An analysis of the group's revenue is as follows:
2017 $000's | 2016 $000's | |
Sale of oil | 68,915 | 2,373 |
68,915 | 2,373 |
From January to May 2017, crude from the OML40 asset was shipped to a FPSO and sold to Vitol SA. Once the Forcados oil terminal re-opened in late May 2017, the revenue for the remainder of the year was derived from an offtake contract with Shell Western Supply and Trading Limited ("Shell Western"). See note 26 on segmental analysis.
5. Loss before tax
The loss before tax for the year is stated after charging/(crediting):
2017 $000's | 2016 $000's | |
Depreciation on property, plant and equipment (note 12) | 12,746 | 1,320 |
Amortisation of other intangible assets (note 11) | 500 | 1,500 |
Net foreign exchange loss/(gain) | 1,520 | (6,511) |
Royalties | 14,968 | 609 |
Wages, salaries and other employment costs1 | 12,823 | 9,721 |
Shareholder management fee | 4,800 | 17,250 |
1 Includes costs of $805,000 (2016: $816,000) relating to non-executive directors' fees/employee benefits and other temporary employment costs not included in note 7 below.
Adjusted EBITDA
Adjusted EBITDA is a non-IFRS measure that represents net income before additional specific items that are considered to impact the comparability of the Group's performance in each period or with other businesses. The Group defines Adjusted EBITDA as the operating result for the year excluding depreciation, amortisation and foreign exchange. The items excluded are non-cash in the year.
The Group believes that adjusted EBITDA is an important indicator of the operational strength and the performance of the business, and provides a meaningful performance indicator of underlying operating cash generation.
Adjusted EBITDA is calculated as follows:
2017 $000's | 2016 $000's | |
Operating loss | (12,850) | (28,906) |
Add: | ||
Depreciation on property, plant and equipment | 12,746 | 1,320 |
Amortisation of other intangibles | 500 | 1,500 |
Foreign exchange | 1,520 | (6,511) |
Adjusted EBITDA | 1,916 | (32,597) |
6. Auditor's remuneration
The analysis of auditor's remuneration is as follows:
2017 $000's | 2016 $000's | |
Fee payable to the Company's auditors for the audit of the Company's annual accounts | 202 | 246 |
The audit of the Company's subsidiaries pursuant to legislation | 124 | 167 |
Total audit fees | 326 | 413 |
2017 $000's | 2016 $000's | |
Fees payable to the Company's auditors and their associates for other services to the Group | ||
Tax compliance services | - | 12 |
Tax advisory services | - | 13 |
Other assurance services | 46 | 67 |
Total non-audit fees | 46 | 92 |
As noted in the Directors' Report the Group appointed PwC as auditors in August 2017, with the existing auditors, Deloitte LLP resigning on the same date. The other assurance services provided in 2017 relate to non-audit procedures on the interim financial statements performed by PwC.
The 2016 comparative relates to non-audit services provided by Deloitte LLP. The tax services in 2016 predominantly relate to UK and overseas tax advice, controlled foreign company rules and transfer pricing advice, in addition to non-audit procedures on the interim financial statements performed by Deloitte LLP in 2016. Deloitte LLP continued to provide taxation services to the Group during 2017, but as they are no longer auditors, no disclosure of such fees is noted above.
7. Staff costs
The average monthly number of employees (including Executive Directors) was:
2017 No. | 2016 No. | |
Management | 4 | 4 |
Technical | 42 | 20 |
Administration | 24 | 22 |
70 | 46 |
Their aggregate remuneration comprised: | 2017 $000's | 2016 $000's |
Wages and salaries | 10,324 | 7,903 |
Social security costs | 444 | 414 |
Share-based payments | 820 | 136 |
Pension costs | 430 | 452 |
12,018 | 8,905 |
The Group operates a defined contribution pension scheme, and has no obligation to pay amounts other than the contributions. Obligations are recognised as staff costs and are expensed to the consolidated statement of comprehensive income in the periods during which services are rendered by employees. Contributions owed to the scheme at 31 December 2017 amounted to $21,000 (2016: $8,000).
The above share based payment charge represent a non-cash charge principally from the granting of share awards with an effective date of July 2017. Further details are provided in the Remuneration Report and in note 28.
8. Finance income and costs
2017 $000's | 2016 $000's | |
Interest and fees charged on JV billings (note 11) | 580 | 306 |
Total finance income | 580 | 306 |
RBL interest and fees | (2,380) | (2,366) |
Unwinding of discount on decommissioning provision (note 18) | (284) | (311) |
Interest on unpaid preference shares dividend* | (25) | (115) |
Other interest** | (581) | - |
Bank charges | (65) | (50) |
Total finance costs | (3,335) | (2,842) |
* The preference shares, on which the interest on the unpaid dividends arose, were all converted into ordinary shares in the prior year. The unpaid dividends and associated interest thereon has been fully settled in early 2018.
** Relates to cost of obtaining currency option facility, interest payable in respect of agreed deferral of payments to suppliers and offtake partner to assist working capital during shipping operations.
9. Tax
2017 $000's | 2016 $000's | |
Current tax | ||
Adjustments in respect of prior years | - | 431 |
Withholding tax | (1,407) | - |
Deferred tax | ||
Origination and reversal of temporary differences | 8,241 | 599 |
Total tax credit for the year | 6,834 | 1,030 |
The standard rate of tax for the year is 65.75% (2016: 65.75%), being the current applicable rate of Nigerian Petroleum Profits Tax.The total tax credit can be reconciled to the loss per the consolidated statement of comprehensive income as follows:
2017 $000's | 2016 $000's | |
Loss before tax on continuing operations | (15,605) | (31,442) |
Loss on activities multiplied by the relevant rate of tax of 65.75 % (2016: 65.75%) | 10,260 | 20,673 |
Reconciling items: Tax deduction on intercompany financing costs | 22,134 | 38,355 |
Temporary differences | (8,619) | (939) |
Non-deductible expenses for tax purposes | (153) | (130) |
Losses not utilised in the period on which no deferred tax is recognised | (23,622) | (57,959) |
Adjustments in respect of prior years | - | 431 |
Withholding tax suffered | (1,407) | - |
Recognition of deferred tax asset | 8,241 | 599 |
Total tax credit | 6,834 | 1,030 |
The following is the deferred tax asset recognised by the Group and movements thereon during the current and prior reporting years.
Depreciation in excess of capital allowances $'000s | |
As at 1 January 2016 | 3,596 |
Credit to income | 599 |
As at 31 December 2016 | 4,195 |
Credit to income | 8,241 |
As at 31 December 2017 | 12,436 |
Pioneer tax relief
When granted, Pioneer tax relief provides relief from Petroleum Profits tax for an initial period of three years and can be extended on an annual basis, at the agreement of the tax authorities, for an additional two years. Pioneer was granted to Elcrest Exploration and Production Nigeria Limited ("Elcrest") with effect from May 2014 and management anticipate the Pioneer relief will expire at the end of the 5-year period, May 2019.
Net aggregate tax losses arising in the Pioneer period, in addition to losses generated prior to Pioneer, are available for carry forward to offset against taxable profits arising in future periods. There is no time restriction in the utilisation of these losses.
As at 31 December 2017, the Group has taxable losses of $327,611,000 (2016: $271,400,000) for which no deferred tax asset has been recognised as there is not sufficient certainty at this time regarding the utilisation of these losses. In particular, Elcrest accounts for the majority of these tax losses totalling $307,844,000 (2016: $244,900,000). On expiry of Pioneer tax status, and following the full utilisation of available tax losses and $207,869,000 (2016: $188,200,000) of capital allowances, Elcrest is expected to be paying tax at 65.75% for five years and at 85% thereafter. The quantum of losses reported above represent amounts submitted to the Nigerian tax authorities although is subject to agreement.
The Group has recognised a deferred tax asset of $12,436,000 as at 31 December 2017 (2016: $4,195,000) in relation to the temporary difference that arises between the net book value and the tax written down value of the oil and gas assets. Capital allowances can be deferred during the Pioneer tax relief period and will be available following the tax relief period, whilst the book value of the asset is depreciated following commencement of production.
10. Earnings per share
Earnings per share ('EPS') is the amount of post-tax profit attributable to each share. Diluted EPS takes into account the dilutive effect of share option plans being exercised.
From continuing operations
The calculation of the basic and diluted earnings per share is based on the following data:
Earnings | 2017 $000's | 2016 $000's |
Earnings for the purpose of the basic earnings per share being net profit attributable to owners of the Company | 11,843 | 16,881 |
Earnings for the purposes of basic and diluted earnings per share | 11,843 | 16,881 |
Number of shares | 2017 000's | 2016 000's |
Weighted average number of Ordinary Shares for the purposes of basic earnings per share | 207,786 | 180,540 |
Equity options | 8,193 | 1,830 |
Weighted average number of Ordinary Shares used in the calculation of diluted earnings per share | 215,979 | 182,370 |
From continuing operations | 2017 $ | 2016 $ |
Basic | 0.06 | 0.09 |
Diluted | 0.05 | 0.09 |
All activities relate to continuing operations.
For diluted earnings per share, the weighted average number of ordinary shares in issue is adjusted to assume conversion of all dilutive potential ordinary shares. The Company only has one class of ordinary share which have the potential to be dilutive, being the share options issued to employees and Directors (see note 28 for details).
At the end of 2017 both the share options issued in January 2016 totalling 1,830,000 shares and the issue during the year for 9,080,500 shares are considered dilutive. The impact on the EPS between basic and diluted EPS is noted above.
Shares issued in 2017 are detailed in note 19.
11. Intangible oil and gas assets
Group | Exploration and evaluation assets $000's | Other intangible assets $000's | Total $000's |
Cost | |||
At 1 January 2016 | 9,052 | 3,929 | 12,981 |
Additions | 2,648 | - | 2,648 |
At 31 December 2016 | 11,700 | 3,929 | 15,629 |
Additions | 1,449 | - | 1,449 |
At 31 December 2017 | 13,149 | 3,929 | 17,078 |
Amortisation | |||
At 1 January 2016 | - | (1,929) | (1,929) |
Charge for the year | - | (1,500) | (1,500) |
At 31 December 2016 | - | (3,429) | (3,429) |
Charge for the year | - | (500) | (500) |
At 31 December 2017 | - | (3,929) | (3,929) |
Carrying amount | |||
Balance at 1 January 2016 | 9,052 | 2,000 | 11,052 |
Balance at 31 December 2016 | 11,700 | 500 | 12,200 |
Balance at 31 December 2017 | 13,149 | - | 13,149 |
The Group's oil & gas exploration and evaluation assets at 31 December 2017 relate to the Group's interest in the Ubima marginal field in Nigeria.
In August 2014, the Group's subsidiary Wester Ord Oil & Gas (Nigeria) Limited ('Wester Ord') acquired a 40% participating interest in the Ubima field from All Grace Energy Limited ("All Grace"). Wester Ord paid a signature bonus of $7 million at completion. A production bonus of $3,000,000 may become payable in the future. Further details are disclosed in note 31.
Wester Ord has agreed to fund 100% of the initial work programme and will be entitled to 88% of production cash flow until the partner costs have been recovered. The above exploration and evaluation balance therefore include 100% of the initial work programme expenditure, together with interest charged to All Grace of $580,000 (2016: $306,000) as detailed in note 8.
The other intangible asset relates to the approval fee paid on grant of Pioneer tax status during 2014 (note 9). The cost has been amortised on a straight-line basis over the minimum expected tax relief period of three years. The charge for the year has been included within operating expenses in the consolidated statement of comprehensive income for the year ended 31 December 2017 of $500,000 (2016: $1,500,000).
The Group monitors both internal and external indicators of impairment, at least on an annual basis. The types of indicators are noted on page 79 within the critical accounting judgements. As the Group continues to have a right to explore and intends further investment, with an appraisal well planned on the Ubima licence in 2018 no impairment indicator has been triggered. Following an analysis of the results of the Ubima appraisal well a decision will be made whether to pursue a Field Development Plan ("FDP") and an impairment review would be undertaken at that time in line with the Group's E&E accounting policy.
12. Property, plant and equipment
Group | Fixtures and equipment $000's | Motor vehicles $000's | Oil and gas development and production assets $000's | Total $000's |
Cost | ||||
At 1 January 2016 | 1,549 | 185 | 188,181 | 189,915 |
Additions | 25 | - | 7,715 | 7,740 |
At 31 December 2016 | 1,574 | 185 | 195,896 | 197,655 |
Additions | (31)* | 163 | 19,508 | 19,640 |
Effect of changes to decommissioning estimates | - | - | (856) | (856) |
At 31 December 2017 | 1,543 | 348 | 214,548 | 216,439 |
Accumulated depreciation | ||||
At 1 January 2016 | (747) | (114) | (5,469) | (6,330) |
Charge for the year | (382) | (27) | (911) | (1,320) |
At 31 December 2016 | (1,129) | (141) | (6,380) | (7,650) |
Charge for the year | (182) | (30) | (12,534) | (12,746) |
At 31 December 2017 | (1,311) | (171) | (18,914) | (20,396) |
Carrying amount | ||||
At 31 December 2017 | 232 | 177 | 195,634 | 196,043 |
At 31 December 2016 | 445 | 44 | 189,516 | 190,005 |
\* The 2017 additions number is a credit in the year as a result of finalisation of previously accrued capital costs.
The Group's oil and gas development and production assets at 31 December 2017 and 31 December 2016 relate to the Group's interest in OML 40 in Nigeria. In respect to the oil and gas development and production assets the Group has recognised a depletion, depreciation and amortisation charge for the year of $12,534,000 (2016: $911,000).
Management assess the Group's oil and gas assets for indicators of impairment at least annually. In line with the Group's accounting policy management assessed the following indicators of impairment at 2017 year-end; oil price environment, reserve revisions, tax or regulatory changes, local market conditions, licence expiry terms and the movement in Group market capitalisation. Following this assessment management concluded that no material adverse impact had occurred across any key indicator and no impairment review was therefore undertaken.
In assessing for impairment of property, plant and equipment, fair value less costs of disposal are determined by discounting the post-tax cash flows expected to be generated from oil production, net of selling costs taking into account assumptions that market participants would typically use in estimating fair values. The key assumptions and estimates in the cash flow models relate to commodity prices, commercial reserves and the related cost and production profiles, discount rates that are adjusted to reflect risk specific to individual assets.
The following key assumptions were used in developing the cash flow model used to support the carrying value:
Oil price: $66.54/bbl flat
Reserves: 83.4 mmbbls
Licence expiry: 2039 (20-year renewal from 2019)
Discount rate: 12%
As no indicators for impairment were triggered and significant headroom between the carrying value and the fair value exist a full impairment review was not undertaken. Nonetheless, a reasonably possible change in key assumptions, deemed to be a+/-10% movement in either oil price, reserves, discount rate would not result in an impairment charge.
13. Inventory
2017 $000's | 2016 $000's | |
Spare parts | 353 | 353 |
Stock in terminal tanks | 535 | - |
888 | 353 |
Spare parts inventory relates to equipment which will be used in future drilling campaigns. The stock in terminal tanks relates to crude oil held in Eland's storage tanks at the Forcados terminal. The stock is required by Shell to operate Forcados pipeline/refinery system efficiently.
14. Trade and other receivables
2017 $000's | 2016 $000's | |
Trade receivables | 1,550 | 28 |
Provision for trade receivables | (893) | - |
Net trade receivables | 657 | 28 |
Other receivables | 8,211 | 353 |
Prepayments | 472 | 832 |
9,340 | 1,213 |
The Directors consider that the carrying value of trade and other receivables is approximately equal to their fair value.
The net receivable balance is over 90 days overdue. Management are confident this balance will be recovered in full during 2018.
15. Cash and cash equivalents
2017 $000's | 2016 $000's | |
Unrestricted cash in bank accounts | 35,637 | 7,158 |
Restricted cash | 1,106 | 3,986 |
36,743 | 11,144 |
Under the terms of the reserve based lending facility ("RBL"), the group is required to set aside amounts to cover the servicing of the debt and stamp duty costs in restricted cash accounts. The restricted amount increased during 2016 pending the outcome of the re-determination process and the return to production, which determines the size of facility available to the Group. The facility underwent a redetermination in early 2017, with the borrowing base amount confirmed at $23,900,000 and the $3,500,000 reserve requirement released. The facility underwent further amendment in December 2017 which saw the borrowing base increase to $37,900,000. See further details in note 17.
16. Trade and other payables
2017 $000's | 2016 $000's | |
Trade payables | 1,531 | 1,074 |
Accruals | 16,293 | 5,010 |
Joint venture creditor* | 8,906 | 10,463 |
Overlift | 5,959 | 2,067 |
Other payables | 21,144 | 4,542 |
Shareholder management fee | 13,525 | 17,250 |
67,358 | 40,406 |
*2016 comparative includes $8,529,000 previously included in accruals line above in the 2016 annual accounts.
Trade and other payables principally comprise amounts outstanding for trade purchases and ongoing costs.
The Directors consider that the carrying amounts of trade and other payables are approximate to their fair values. All trade and other payables are denominated in Sterling, US Dollars or Nigerian Naira.
The accruals balance includes estimates due under the OML 40 Joint Operating Agreement ("JOA") which are either not yet invoiced or agreed with our partner on the licence. The joint venture creditor includes amounts which have been billed and agreed upon. See note 31 for further details.
Other payables relates principally to amounts due to the DPR in respect of Royalty payments outstanding at year-end. The remaining balance within other payables relates to employment taxes, VAT and withholding tax liabilities.
The shareholder management fee is due from Elcrest to its indigenous shareholder in Nigeria, for a liability due under a shareholders' agreement signed in March 2011. The management fees payable under the agreement are $3 million per annum.
The Company has financial risk management policies in place to ensure that all payables to third parties are paid within the credit timeframe. Details of interest charged by suppliers as a result of late payment has been disclosed in note 8.
17. Bank loan
Reserves based lending facility: | 2017 $000's | 2016 $000's |
Reserve based facility agreement with maturity date 30 June 2019: | ||
Amount drawn | 27,000 | 15,000 |
Amount undrawn | 8,000 | 10,400 |
35,000 | 25,400 |
The maturity of the loan balances due for repayment can be categorised as follows:
2017 $000's | 2016 $000's | |
Amount due for repayment within 1 year | 9,000 | - |
Amount due for repayment after 1 year | 18,000 | 15,000 |
27,000 | 15,000 |
The reserves based lending facility with Standard Chartered Bank (SCB), which Westport (the Group's finance vehicle) entered into on 31 December 2014 (the "RBL") is available to the Group to fund, amongst other things, capital expenditure obligations in respect of Elcrest's participating interest in OML 40 and for the Group's working capital purposes up to $5 million.
The RBL has a maturity of four and a half years from 31 December 2014 and is repayable as set out in note 29. The facility was amended in December 2017 which saw the available amount increase to $27 million, with two new lenders - The Mauritius Commercial Bank Ltd and Mercuria Energy Trading SA - joining the syndicate alongside SCB, with equal participation by each of the three lenders. Interest is payable on amounts outstanding on a quarterly basis at a rate equivalent to USD LIBOR plus a margin of 9% from 21 December 2017 (previously 7.75%).
The amount available under the RBL is subject to a cap determined by the lower of the borrowing base amount and the committed facility amount. The borrowing base amount is calculated on OML 40 production and is re-determined every six months in accordance with the terms of the RBL.
As at 31 December 2017 the borrowing base stood at $37,900,000 (31 December 2016: $25,400,000), although the amount available under the RBL is capped at the facility amount of $35,000,000 (2016: $25,400,000), of which $27 million is committed as at 31 December 2017.
The RBL is secured over the Company's shares in Elcrest, and by way of a debenture which creates a charge over certain asset of the Group, including its bank accounts.
The RBL facility includes certain financial covenants on which the group is required to submit compliance documents showing that it has met these requirements at all times throughout the term of the loan. These submissions are subject to agreement by the lender on the treatment of certain items. The prolonged shut-in of the Forcados Oil Terminal during 2016 and 2017 (as described in the Strategic Report) led to reduced revenues which resulted in the group being unable to meet the Historic Debt Service Cover ratio for a temporary period. A waiver was duly granted by the lenders for the period to August 2017, and the group subsequently complied with the covenant following the re-opening of the FOT.
The carrying amount of the loan is classified as below on the balance sheet: | 2017 $000's | 2016 $000's |
Current liabilities |
9,000 | - |
Non-current liabilities | 16,417 | 13,334 |
25,417 | 13,334 |
The amount drawn under the RBL is reconciled to the carrying amount of the loan as at the Balance Sheet date as follows:
$000's | |
Balance as at 1 January 2016 | 13,367 |
Arrangement fees and costs amortised in year | (436) |
Interest charged | 2,366 |
Interest and fees paid | (1,963) |
Balance as at 31 December 2016 | 13,334 |
Amounts drawn | 12,000 |
Arrangement fees and costs amortised in year | (460) |
Interest charged | 2,380 |
Interest and fees paid | (1,837) |
Balance as at 31 December 2017 | 25,417 |
18. Decommissioning Provision
2017 $000's | 2016 $000's | |
At 1 January | 10,120 | 9,809 |
Unwinding of discount (note 8) | 284 | 311 |
Effect of changes to decommissioning estimates (note 12) | (856) | - |
At 31 December | 9,548 | 10,120 |
The provision for decommissioning is in respect of the Group's interest in OML 40 and Ubima. The provision represents the present value of amounts that are expected to be incurred in 2031 and 2034 for OML40 and Ubima respectively, discounted to the present value using a 2.75% discount rate (2016: 2.75%) and an inflation rate of 2% (2016: 2%).
A corresponding amount equivalent to the provision is recognised as part of the cost of the related intangible assets and property, plant and equipment for the Ubima and OML 40 licence respectively. The amount recognised is the estimated cost of decommissioning, discounted to its net present value, and is reassessed each year in accordance with local conditions and requirements, reflecting management's best estimates.
The unwinding of the discount on the decommissioning is included in the consolidated statement of comprehensive income as a finance cost (see note 8).
Changes in the estimated timing of decommissioning or decommissioning estimates are dealt with prospectively by recording an adjustment to the provision and a corresponding adjustment to property, plant and equipment.
During 2017, an independent specialist evaluated the decommissioning costs for the OML40 licence and the study led to the adjustment of the amounts previously provided for. Management believes the estimates continue to form a reasonable basis for the expected future costs of decommissioning, which are now expected to be incurred in 2031. The effect in future periods is impractical to calculate, as the provision in future periods may be affected by the drilling of future wells, and changes to inflation or discounting assumptions.
19. Share capital
2017 $000's | 2016 $000's | |
Allotted, issued and paid: | ||
220,164,155 (2016: 186,319,340) voting ordinary shares of £0.10 each | 33,799 | 29,138 |
Nil (2016: 6,296,815) non-voting ordinary shares of £0.10 each | - | 1,124 |
155,263,214 (2016: 155,263,214) non-voting deferred shares of £0.90 each | 223,235 | 223,235 |
257,034 | 253,497 |
Voting £0.10 ordinary shares | Non-voting £0.10 ordinary shares | Total £0.10 ordinary shares | |
Allotted, issued and paid ordinary shares | |||
At 1 January 2016 | 145,263,214 | 10,000,000 | 155,263,214 |
Conversion of non-voting to voting | 4,613,685 | (4,613,685) | - |
Issued and fully paid on equity placing | 36,442,441 | 910,500 | 37,352,941 |
As at 31 December 2016 | 186,319,340 | 6,296,815 | 192,616,155 |
Conversion of non-voting to voting | 6,296,815 | (6,296,815) | - |
Issued and fully paid on equity placing | 27,548,000 | - | 27,548,000 |
As at 31 December 2017 | 220,164,155 | - | 220,164,155 |
During 2016, the company issued 36,442,441 new ordinary shares and 910,500 new non-voting ordinary shares pursuant to the share placing announced on 29 April 2016. The company raised approximately $18,600,000 (gross) through the placing at 34 pence per share (representing a premium to the closing mid-market price on 28 April 2016). Of the net proceeds received $5,458,000 has been recorded in share capital, $13,099,000 in share premium with expenses of $647,000 also included in share premium.
During 2017, a total of 27,548,000 new ordinary shares were issued pursuant to the Share Placing announced on 14 June 2017. The company raised approximately $19.5 million (gross) through the placing at 55 pence per share. Of the net proceeds received $3,537,000 has been recorded in share capital, $15,917,000 in share premium with expenses of $903,000 also included in share premium.
Each new voting ordinary share has the same rights and benefits as the existing voting ordinary shares.
In addition to the placings mentioned above, on 23 February 2016 and 14 June 2017 as a shareholder, Helios Natural Resources ("Helios") requested the conversion of 4,613,685 and 6,296,815 respectively of £0.10 non-voting shares into voting shares. Following completion of these conversions all non-voting ordinary shares have now been converted into voting shares.
Deferred shares do not entitle holders to receive notice of or attend and vote at any general meeting of the company or to receive a dividend or other distribution or to participate in any return on capital on a winding up or other than the nominal amount paid on such shares following a substantial distribution to the holders of ordinary shares in the company. As such the deferred shares do not form part of the calculation of earnings per share.
20. Share premium
Company | Share premium $000's |
Balance at 1 January 2016 | - |
Issue of shares at a premium | 13,099 |
Expenses related to issue of equity shares | (647) |
Balance at 1 January 2017 | 12,452 |
Issue of shares at a premium | 15,917 |
Expenses related to issue of equity shares | (903) |
Balance at 31 December 2017 | 27,466 |
As described in note 19, a total of 27,548,000 (2016: 37,352,941) new ordinary shares were issued in June 2017 consisting of 27,548,000 (2016: 36,442,441) voting and Nil (2016: 910,500) non-voting shares.
In 2017 the difference between the placing price of 55 pence per share and the share capital of 10 pence per share was recorded in share premium at a rate of GBP:USD 1:1.28. Further, share premium expenses for broker and professional fees totaling $903,000 (2016: $647,000) were recorded against the share premium account. In 2016 the difference between the placing price of 34 pence per share and the share capital of 10 pence per share was recorded in share premium at a rate of GBP:USD 1:1.46.
21. Other Reserve
$000's | |
Balance at 31 December 2016 and 2017 | (10,542) |
This reserve relates to costs incurred on funds raised on AIM in 2012.
22. Retained earnings
$000's | |
Balance at 1 January 2016 | 29,412 |
Profit for the year | 16,881 |
Credit to equity-settled share-based payments | 136 |
Balance as at 31 December 2016 | 46,429 |
Profit for the year | 11,843 |
Credit to equity-settled share-based payments | 820 |
Balance as at 31 December 2017 | 59,092 |
23. Translation reserve
Prior to 1 January 2013 exchange differences relating to the translation of the net assets of the Company from its functional currency (Sterling) into the Group's presentation currency, US Dollars, were recognised directly in the translation reserve. From 1 January 2013, the Company's functional currency changed to US Dollars. As a result, there is no movement on the reserve in the current year or the prior year.
$000's | |
Balance at 31 December 2016 and 2017 | 1,429 |
24. Non-controlling interests
Summarised financial information in respect of each of the Group's subsidiaries that has a material non-controlling interest is set out below.
The summarised financial information below represents amounts before intragroup eliminations.
Elcrest Exploration and Production Nigeria Limited
Balance Sheet | 2017 $'000s | 2016 $'000s |
Non-current assets | 208,277 | 194,264 |
Current assets | 22,071 | 2,475 |
Current liabilities | (526,793) | (455,126) |
Non-current liabilities | (9,313) | (9,892) |
Net liabilities | (305,758) | (268,279) |
Equity attributable to owners of the Company | (137,555) | (120,690) |
Non-controlling interest | (168,203) | (147,589) |
Total equity | (305,758) | (268,279) |
Consolidated Statement of Comprehensive Income | 2017 $'000s | 2016 $'000s |
Revenue | 68,915 | 2,373 |
Expenses | (106,394) | (88,361) |
Loss for the year | (37,479) | (85,988) |
Total loss and comprehensive loss attributable to owners of the Company | (16,865) | (38,695) |
Total loss and comprehensive loss attributable to the non-controlling interests | (20,614) | (47,293) |
Cashflow | 2017 $'000s | 2016 $'000s |
Net cash inflow from operating activities | 19,870 | 800 |
Net cash outflow from investing activities | (14,487) | (5,275) |
Net cash inflow from financing activities | 4,010 | 2,734 |
Net cash inflow/(outflow) | 9,393 | (1,741) |
25. Notes to the cash flow statement
Group | 2017 $000's | 2016 $000's |
Loss for the year before tax | (15,605) | (31,442) |
Adjustments for: | ||
Increase in management fee (note 16) * | - | 17,250 |
Share-based payments (note 28) | 820 | 136 |
Net finance costs (note 8) | 2,755 | 2,536 |
Amortisation of intangible assets (note 11) | 500 | 1,500 |
Depreciation of property, plant and equipment (note 12) | 12,746 | 1,320 |
Unrealised foreign exchange losses on operating activities | (651) | 817 |
16,170 | 23,559 | |
Operating cash flows before movements in working capital | 565 | (7,883) |
Increase in inventories | (535) | - |
(Increase) / decrease in trade and other receivables * | (8,132) | 2,256 |
Increase in trade and other payables | 21,078 | 570 |
12,411 | 2,826 | |
Net cash generated from / (used in) operating activities | 12,976 | (5,057) |
\* The management fee was adjusted for in the 2016 cashflow as this was categorised as a non-cash item provided for at 2016 year-end. During 2017 amounts totaling $5,000,000 were paid in respect of the management fee, with a further $3,000,000 charge in the year, exclusive of applicable taxes. The 2017 movement is contained within operating payables as this is now deemed a cash-based item.
26. Segmental information
The Directors believe that the Group has only one reportable operating and geographic segment, which is the exploration and production of oil and gas reserves in Nigeria. All operations are classified as continuing. The Board monitors the operating results of its operating segment for the purpose of making decisions and performance assessment. Segmental performance is evaluated based on operating profit or loss and is reviewed consistently with operating profit and loss in the consolidated financial statements.
27. Operating lease arrangements
2017 $000's | 2016 $000's | |
Minimum lease payments under operating leases recognised as an expense in the year | 609 | 645 |
At the balance sheet date, the Group had outstanding commitments for future minimum lease payments under non-cancellable operating leases, which fall due as follows:
| 2017 $000's | 2016 $000's |
Within one year In the second to fifth years inclusive After five years | 168 629 144 | 202 576 276 |
941 | 1,054 |
Operating lease payments represent rentals payable by the Group for certain of its office properties and staff residences.
28. Share-based payments
Equity settled share option scheme
The Company operates an employee share option plan. Details of share options granted in the years up to 31 December 2017 are noted below.
On 3 December 2012 all Directors and key personnel of the Group comprising of 2,669,763 Founder options exercisable at £1.00 each, 8,210,000 share options exercisable at £1.00 each and 368,500 share options exercisable at £1.13 each. As at 31 December 2017 2,269,301 Founder options and 157,500 share options both of which are (exercisable at £1.00) remain outstanding.
During 2014, 65,000 share options at £1.25 each and 1,250,000 share options were granted to employees at £1.16 each. The options will be exercisable in full if the average closing price per share over any continuous thirty day period, ignoring any days which are non-dealing days for AIM, occurring wholly during the period of 10 years from the date of grant, is equal to or greater than one hundred and fifty percent (150%) of the grant price. As at 31 December 2017 52,500 of these share options remain outstanding.
On 8 January 2016 the Company offered employees (including directors) the chance to waive the 150% hurdle rate performance condition associated with their holding. If the employee accepted the offer, they would relinquish their rights to 25% of their options.
On 31 January 2016 share options were granted to certain employees of the Group comprising of 1,830,000 options exercisable at £0.285 each. There were no performance conditions associated with the options. As at 31 December 2017 1,630,000 of these share options remain outstanding.
On 7 November 2017 share options were granted to certain employees of the group comprising 9,080,500 options exercisable at £0.10 each, with an effective date of 1 July 2017. Some employees were also offered to forfeit their existing options into the new scheme on a 1:1 basis. This was deemed to be a modification to the original equity instruments and as their vesting period was already complete the charge associated with this modification has been recognised immediately. This amounted to $461,000 and is included in the consolidated statement of comprehensive income.
All of the share options, except for Founder Options which had a vesting period of two years, have a vesting period of three years from the date of grant. The £1.00 Founder options are exercisable for a period of eight years (less one day) from the second anniversary of the date of the grant. The other options are exercisable for a period of seven years (less one day) from the third anniversary of the date of the grant. If the options remain unexercised after the day preceding the tenth anniversary of the date of the grant the options expire.
During 2016 personnel left the Company and as a result 5,517,813 share options lapsed.
There were three performance conditions attached to the share options granted in 2017:The total shareholder return condition applies to 60% of the number of shares subject to the option. This tranche is only exercisable, on a straight line basis, if the adjusted share price exceeds 50p. Whereby 50p results in 0% being exercisable up to 200p+ when 100% is exercisable.
15% of the number of shares subject to the option are tied to the oil price condition. This tranche will only be exercisable if the weighted average share price (expressed in pence) for the 20 dealing days from the publishing date of 31 December 2019 accounts is great than the average Brent Crude oil price for the same period expressed in dollars per barrel
The production growth condition will apply to 25% of the shares subject to the option. This tranche will only be exercisable, on a straight line basis, from 25,000 bopd (gross) initial vesting to 40,000 bopd (gross) at 100% vesting, calculated at any 3 month average during the time vesting period.
In addition to the above, holder of the options must remain in employment at the end of the three year vesting period.
Details of the movements in share options during the year are as follows:
2017 | 2016 | |||
Number of share options | Weighted Average Exercise Price (£) | Number of share options | Weighted Average Exercise Price (£) | |
Outstanding at the start of the year | 6,968,738 | 0.85 | 12,563,263 | 1.02 |
Hurdle rate reduction | - | - | (1,906,712) | (1.02) |
Lapsed | - | - | (5,517,813) | (1.00) |
Forefeited | (2,859,438) | (1.06) | - | - |
Granted during the year | 9,080,500 | 0.10 | 1,830,000 | 0.29 |
Outstanding at the end of the year | 13,189,800 | 0.29 | 6,968,738 | 0.85 |
Exercisable at the end of the year | 2,479,301 | 1.00 | 4,813,738 | 1.01 |
The options outstanding at 31 December 2017 had a weighted average exercise price of £0.29, and a weighted average remaining contractual life of 8 years and 6 months. The aggregate of the estimated fair values of the options granted in 2017 was $2,162,000 (2016: $83,000). In prior years the Black Scholes model has been used to fair value the options, however, the 2017 Long Term Incentive Plan has been valued using the Monte Carlo simulation as this enables the barrier price to be factored in to the calculation. The inputs into the Monte Carlo model (2016 Black Scholes) during 2017 were as follows:
2017 | 2016 | |
Year-end closing share price | 64p | 40.25p |
Weighted-average exercise price | 10p | 29p |
Expected volatility | 2.87% | 13.25% |
Expected life | 3 years | 3 years |
Risk-free rate | 1.28% | 1.73% |
Barrier price | 50p | - |
Dividend yield | nil | nil |
Expected volatility was determined by calculating the historical volatility of the Company's share price from the date of admission to AIM to the date the share options were issued. The expected life used in the model has been adjusted, based on management's best estimate, for the effects of non-transferability, exercise restrictions, and behavioral considerations.
The Company has assumed an annual attrition rate of nine per cent (2016: nil) in determining the share based payment charge based on historical attrition rates of the Company.
The Group recognised total expenses of $820,000 (2016:$136,000) related to equity settled share-based payment transactions in 2017.
29. Financial instruments
Capital Management
The objective of the Group's capital management structure is to ensure sufficient liquidity exists within the Group to carry out committed work programme requirements. The Group monitors both short and long-term cash flow requirements of the business in order to assess the requirement for changes to the capital structure to meet that objective and to maintain flexibility.
Eland manages the capital structure and may make adjustments in light of opportunities available or changes to economic conditions. To maintain or adjust the capital structure, Eland may issue new shares for cash, buy back shares, return capital, repay debt, put in place new debt facilities or undertake other such restructuring activities as appropriate. No significant changes were made in the objectives, policies or processes during the year ended 31 December 2017 although additional capital was raised through the issue of new shares as noted above in note 19.
Group 2017 $000's | Group 2016 $000's | |
Borrowings | 25,417 | 13,334 |
Less: cash and cash equivalents | (36,743) | (11,144) |
Net cash and cash equivalents/(debt) | (11,326) | 2,190 |
Total equity | 166,275 | 155,676 |
Gearing | 0% | 1% |
The capital structure of the Group includes debt drawn down from the RBL of $27,000,000 as at 31 December 2017 (2016: $15,000,000). Equity attributable to equity holders of the parent comprises issued capital, share premium, reserves and retained earnings as disclosed in notes 19 to 23.
The Group is not subject to any externally imposed capital requirements.
Principal financial instruments
The principal financial instruments used by the Group, from which financial instrument risk arises, are as follows:
· Trade and other receivables
· Trade and other payables
· Cash and bank balances
· Bank loans
Categories of financial instruments
At 31 December 2017 and 2016, the Group held the following financial assets:
2017 $000's | 2016 $000's | |
Trade and other receivables | 8,868 | 730 |
Cash and bank balances | 36,743 | 11,144 |
45,611 | 11,874 |
Of the cash balances of $36.7 million (2016: $11.1 million), $34.2 million (2016: $5.5 million) was denominated in US Dollars, $0.9 million (2016: $5.4 million) was denominated in Sterling and $1.6 million (2016: $0.2 million) was denominated in Naira.
Credit risk management
Credit risk arises from cash and cash equivalents and deposits with banks. Cash balances are held with banks with an 'A' rating or better where possible. There is believed to be insignificant credit risk associated with trade, other debtors and prepayments.
At 31 December 2017, the Group held the following financial liabilities at amortised cost:
2017 $000's | 2016 $000's | |
Trade payables | 1,531 | 1,074 |
Accruals | 16,293 | 5,010 |
Joint venture creditor | 8,906 | 10,463* |
Other payables | 186 | 3,168 |
Shareholder management fee | 13,525 | 17,250 |
Bank loans | 25,417 | 13,334 |
65,858 | 50,299 |
*Comparative includes $8,529,000 previously included in accruals line above in the 2016 annual accounts.
Market risk
The Group's activities expose them primarily to the financial risks of changes in foreign currency exchange rates. There has been no change to the Group's exposure to market risk or the manner in which these risks are measured and managed.
Foreign currency risk management
With effect from 1 January 2013, the functional currency of the Company changed from Sterling to US Dollars. The functional currency of the Group is now US Dollars. The change was triggered by the increasing influence of the US Dollar on its operations as its borrowing facilities and income are borrowings denominated in US Dollars.
The Group's income, borrowings, and the majority of its costs, are denominated in US Dollars. The remainder of the costs are denominated in other currencies, predominantly Sterling and Nigerian Naira. The Group also has foreign currency denominated assets and liabilities. Exposures to exchange rate fluctuations therefore arise. The Directors currently believe that foreign currency risk is at an acceptable level.
Foreign currency sensitivity analysis
Although the Group reports in US Dollars, elements of its business are conducted in Sterling and Nigerian Naira. The current exposure to foreign currency risk is manageable due to the predictability of transactions in these currencies. A reasonably possible exchange rate variance based on historical volatility and the impact on the financial statements are presented below.
If the US Dollar had strengthened by 10% against Sterling, with all other variables held constant, post tax loss for the year would have been $685,000 lower mainly as a result of differences of translation of Sterling denominated expenditure at lower rates of exchange.
If the US Dollar had weakened by 10% against Sterling, with all other variables held constant, post tax loss for the year would have been $837,000 higher mainly as a result of translating Sterling denominated expenditure at higher rates of exchange.
If the US Dollar had strengthened by 10% against Naira, with all other variables held constant, post tax loss for the year would have been $1,271,000 lower mainly as a result of translating Naira denominated expenditure at higher rates of exchange.
If the US Dollar had weakened by 10% against Naira, with all other variables held constant, post tax loss for the year would have been $1,553,000 higher as a result of translating Naira denominated expenditure at lower rates of exchange.
Liquidity risk management
Liquidity risk is the risk that the Group will encounter difficulty in meeting its financial obligations as they fall due. Ultimate responsibility for liquidity risk management rests with the Board of Directors. In order to mitigate this risk, management regularly reviews liabilities to ensure these can be met as and when they fall due.
The Group manages liquidity risk by maintaining adequate cash reserves and reserve borrowing facilities and by continuously monitoring forecast and actual cash flows. Details of undrawn facilities that the Group has at its disposal to further reduce liquidity risk are set out in note 17.
Fair value of financial instruments
The Directors consider that the carrying amounts of financial assets and financial liabilities approximate their fair values, unless otherwise stated.
Maturity of financial assets and liabilities
All of the Group's financial assets as at 31 December 2017 are receivable within one year. On this basis, no maturity analysis has been disclosed.
All of the Group's financial liabilities are payable within one year with the exception of the RBL. The following table as at 31 December 2017, for the years 2018 through 2022 and thereafter, shows the maturities of the Group's undiscounted financial liabilities inclusive of any interest and fees associated with the RBL:
2018 $000s | 2019 $000s | 2020 $000s | 2021 $000s | 2022 $000s | Thereafter $000s | Total $000s | |
RBL interest | 2,846 | 652 | - | - | - | - | 3,498 |
RBL commitment fees | - | - | - | - | - | - | - |
Other fees (RBL) | 180 | 90 | - | - | - | - | 270 |
Principal repayment | 9,000 | 18,000 | - | - | - | - | 27,000 |
Trade and other payables | 67,358 | - | - | - | - | - | 67,358 |
Decommissioning provision | - | - | - | - | - | 9,548 | 9,548 |
79,384 | 18,742 | - | - | - | 9,548 | 107,674 |
Under the terms of the RBL amounts repayable are first to be held in restricted accounts for principal and interest due six months prior to the repayment dates.
Maturity of financial assets and liabilities (continued)
In comparison the following table as at 31 December 2016, for the years 2017 through 2021 and thereafter, shows the maturities of the Group's undiscounted financial liabilities inclusive of any interest and fees associated with the RBL (all of the Group's financial liabilities were payable within one year with the exception of the RBL):
2017 $000s | 2018 $000s | 2019 $000s | 2020 $000s | 2021 $000s | Thereafter $000s | Total $000s | |
RBL interest | 1,308 | 895 | 162 | - | - | - | 2,365 |
RBL commitment fees | 74 | - | - | - | - | - | 74 |
Other fees (RBL) | 150 | 150 | 75 | - | - | - | 375 |
Principal repayment | 184 | 11,867 | 2,949 | - | - | - | 15,000 |
Trade and other payables | 23,156 | - | - | - | - | - | 23,156 |
24,872 | 12,912 | 3,186 | - | - | - | 40,970 |
Financial facilities
Loan facility
The Group has a loan facility with Standard Chartered Bank and other lenders. Details are given in note 17.
Interest rate risk management
As the Group utilises the RBL facility it will become exposed to potential adverse movements in the US Dollar LIBOR component of the rate. Based on existing borrowings of $27 million and a reasonably possible interest rate variance at 31 December 2017, a 1.0 percentage point change in average interest rates over a twelve month period would increase or decrease net income or loss by approximately $260,000.
30. Related Party Transactions
Remuneration of key management personnel
The remuneration of the Directors, who are the key management personnel of the Group, is set out below in aggregate for each of the categories specified in IAS 24, Related Party Disclosures.
2017 $000's | 2016 $000's | |
Short term employee benefits | 1,478 | 1,056 |
Post-employment benefits | 78 | 79 |
Share-based payments | 106 | 39 |
1,662 | 1,174 |
31. Contingent liabilities
JOA accruals
Under the Joint Operating Agreement ("JOA"), the Group is responsible for its share of expenditures incurred on OML 40 in respect of its participating interest, on the basis that the operator's estimated expenditures are reasonably incurred based on the approved work programme and budget. From time to time, management disputes such expenditures on the basis that they do not meet these criteria, and when this occurs management accrues at the period end for its best estimate of the amounts payable to the operator. Consequently, the amounts recognised as accruals as at 31 December 2017 reflect management's best estimate of amounts that have been incurred in accordance with the JOA and that will ultimately be paid to settle its obligations in this regard. However, management recognise there are a range of possible outcomes, which may be higher or lower than the management estimate of accrued expenditure. To the extent additional amounts have been claimed by the operator it is estimated that around $6,700,000 (2016: $6,300,000) remains under dispute and management consider any liability in this respect to be remote.
Wester Ord production bonus
The Group's subsidiary Wester Ord Oil & Gas (Nigeria) Limited may become, subject to certain conditions, ultimately liable to pay a production bonus of $3,000,000 to All Grace Energy Limited in respect of the transfer of a 40% interest in the Ubima Field. The payment is contingent on both receiving Nigerian Ministerial Consent to the transfer and attaining production volume of 2,000 barrels gross of crude oil per day on average over a thirty-day period. Management consider that the asset is still in the exploration and evaluation stage, the Group is required to obtain DPR approval for a field development plan ("FDP") and subsequently, be successful in developing and reaching production for the above obligation to arise. These events are not within the control of the Group and further, it is not uncommon in the oil and gas industry for these contingent events/milestones not to be achieved on any given E&E project. On this basis management has disclosed this amount as a contingent liability, but do not consider payment of the amount to be probable.
32. Post-balance sheet events
In March 2018, the Company agreed with its lenders to amend the repayment profile of the Reserve Based Lending ("RBL") facility from that described in Note 29 with the first loan repayment deferred from September 2018 until March 2019. This is an excellent result and the deferral enables the Company to continue with its planned capital programme during 2018, with the final repayment date of the loan remaining unchanged at June 2019.
At the same time the lenders agreed a borrowing base increase from $37.9 million as described in Note 17 to $70 million based on the Opuama, 1,3,7 and 8 wells, with the previous $37.9million borrowing base supported by the Opuama 1, 3 and 7 wells. While the borrowings available remain capped at the facility size of $35 million, it nonetheless provides a valuable indication of the borrowing base capability of the asset base as it looks to raise further financing in the near future.
COMPANY BALANCE SHEET
as at 31 December 2017
| Note | 2017 $000's | 2016 $000's |
Non-current assets | |||
Investments in group undertakings | 34 | 198,015 | 191,915 |
Property, plant and equipment | 35 | 167 | 334 |
198,182 | 192,249 | ||
Current assets | |||
Trade and other receivables | 36 | 71,577 | 58,223 |
Current tax | - | 426 | |
Cash and cash equivalents | 37 | 12,972 | 5,456 |
84,549 | 64,105 | ||
Total assets | 282,731 | 256,354 | |
Current liabilities | |||
Trade and other payables | 38 | (2,995) | (3,782) |
Net current assets | 81,554 | 60,323 | |
Net assets | 279,736 | 252,572 | |
Shareholders' equity | |||
Share capital | 19 | 257,034 | 253,497 |
Share premium | 20 | 27,466 | 12,452 |
Other reserve | 21 | (10,542) | (10,542) |
Retained earnings/(accumulated losses) | 39 | 4,707 | (3,906) |
Translation reserve | 40 | 1,071 | 1,071 |
Equity attributable to the owners of the Company | 279,736 | 252,572 |
The Company only loss for the year after tax was $7,793,000 (2016: $1,696,000).
The financial statements of Eland Oil & Gas PLC, registered number SC 364753, were approved by the Board of Directors on 17 April 2018 and signed on its behalf by:
George Maxwell | Ron Bain |
Chief Executive Officer | Chief Financial Officer |
COMPANY STATEMENT OF CHANGES IN EQUITY
for the year ended 31 December 2017
Share capital $000's |
Share premium $000's |
Other reserve $000's | (Accumulated losses)/ retained earnings $000's |
Translation reserve $000's |
Total equity $000's | |
Balance at 1 January 2016 | 248,039 | - | (10,542) | (2,346) | 1,071 | 236,222 |
Loss for the year and total comprehensive loss | - | - | - | (1,696) | - | (1,696) |
Share-based payments (note 28) | - | - | - | 136 | - | 136 |
Issue of share capital (note 19) | 5,458 | 12,452 | - | - | - | 17,910 |
Balance at 31 December 2016 | 253,497 | 12,452 | (10,542) | (3,906) | 1,071 | 252,572 |
Profit for the year and total comprehensive profit | - | - | - | 7,793 | - | 7,793 |
Share-based payments (note 28) | - | - | - | 820 | - | 820 |
Issue of share capital (note 19) | 3,537 | 15,014 | - | - | - | 18,551 |
Balance at 31 December 2017 | 257,034 | 27,466 | (10,542) | 4,707 | 1,071 | 279,736 |
COMPANY CASH FLOW STATEMENT
for the year ended 31 December 2017
| Note | 2017 $000's | 2016 $000's |
Cash used in operating activities | 41 | (5,056) | (8,621) |
Interest and financing fees paid | (598) | (117) | |
Income tax receivable | 430 | - | |
Net cash used in operating activities | (5,224) | (8,738) | |
Investing activities | |||
Investment in Group undertakings | (6,100) | (2,665) | |
Purchases of fixtures and equipment | - | (6) | |
Net cash used in investing activities | (6,100) | (2,671) | |
Financing activities | |||
Net proceeds on issue of shares | 18,551 | 17,910 | |
Net cash from financing activities | 18,551 | 17,910 | |
Net increase in cash and cash equivalents | 7,227 | 6,501 | |
Cash and cash equivalents at the beginning of the year | 5,456 | 753 | |
Effect of foreign exchange rate changes | 289 | (1,798) | |
Cash and cash equivalents at the end of the year | 37 | 12,972 | 5,456 |
NOTES TO THE FINANCIAL STATEMENTS
for the year ended 31 December 2017
33. Staff costs
The average monthly number of employees (including Executive Directors) was:
2017 No. | 2016 No. | |
Management | 2 | 3 |
Technical | 6 | 6 |
Administration | 14 | 13 |
22 | 22 |
Their aggregate remuneration comprised: | 2017 $000's | 2016 $000's |
Wages and salaries | 3,743 | 4,277 |
Social security costs | 362 | 345 |
Share-based payments | 820 | 136 |
Pension costs | 240 | 281 |
5,165 | 5,039 |
The Company operates a defined contribution pension scheme, and has no obligation to pay amounts other than the contributions. Obligations are recognised as staff costs and are expensed to the consolidated statement of comprehensive income in the periods during which services are rendered by employees. Contributions owed to the scheme at 31 December 2017 amounted to $21,000 (2016: $8,000).
Details of each director's remuneration are set out in the Directors' Remuneration Report on pages 58 to 61. Details of the share based payments are contained in note 28 and remuneration in aggregate is set out in note 30 including the charge attributable to share based payments. Director's contracts are held directly by the Company. No charge or fees are paid by any other subsidiary to directors, therefore all amounts disclosed within the Annual Report are attributable to the Company.
34. Investments in Group undertakings
$000's | |
Cost and net book value at 1 January 2016 | 189,250 |
Additions | 2,665 |
At 31 December 2016 | 191,915 |
Additions | 6,100 |
At 31 December 2017 | 198,015 |
The additions in both years relate to the Company's investment in Westport Oil Limited being subscription for shares in cash.
The Company's subsidiaries as at the balance sheet date are listed below:
Direct holdings
Nature of entity | Place of incorporation and operation | Proportion of ownership interest | Proportion of voting power held | |
Eland Oil & Gas (Nigeria) Limited1 | Oil and Gas Exploration and Production | Nigeria | 100% | 100% |
Elcrest Exploration and Production Nigeria Limited1 | Oil and Gas Exploration and Production | Nigeria | 45% | 45% |
Westport Oil Limited2 | Financing | Jersey | 100% | 100% |
Tarland Oil Holdings Limited2 | Holding Company | Jersey | 100% | 100% |
Brineland Petroleum Limited3 | Dormant | Nigeria | 49% | 49% |
Destination Natural Resources Limited4 | Dormant | Dubai | 70% | 70% |
Indirect holdings | ||||
Nature of entity | Place of incorporation and operation | Proportion of ownership interest | Proportion of voting power held | |
Wester Ord Oil & Gas (Nigeria) Limited1 | Oil and Gas Exploration and Production | Nigeria | 100% | 100% |
Wester Ord Oil and Gas Limited2 | Holding Company | Jersey | 100% | 100% |
Registered addresses for the above listed subsidiaries are as follows:
1 Plot 1384 Tiamiyu Savage Street, Victoria Island, Lagos, Nigeria
2 2nd Floor, The Le Gallais Building, 54 Bath Street, St Helier, Jersey JE1 1FW
3 Block C Terrace 3, Lobito Crescent, Stallion Estate, Wuse II, Abuja
4 ASP Auditing, Office#M6B, Mezzanine Floor, Al Nakheel Building, Zabeel Road, Karama, Dubai
In accordance with the Group's accounting policy in note 2, Elcrest Exploration and Production Nigeria Limited has been consolidated because it is controlled by the Company. The Company has the power to govern the financial and operating policies for the following reasons:
the Company is entitled to appoint a number of Directors to the Board such that it can control decision making.
in the event of disagreement amongst the Board of Directors, decisions are reached by shareholder vote and the Company has the ability, through the combined effect of a Shareholders Agreement, Loan Agreement and Share Charge, to direct the votes of the 55% shareholding that it does not own.
35. Property, plant and equipment
Fixtures and equipment | Total $000's |
Cost | |
At 1 January 2016 | 995 |
Additions | 6 |
At 31 December 2016 and 2017 | 1,001 |
Accumulated depreciation | |
At 1 January 2016 | (430) |
Charge for the year | (237) |
At 31 December 2016 | (667) |
Charge for the year | (167) |
At 31 December 2017 | (834) |
Carrying amount | |
At 31 December 2017 | 167 |
At 31 December 2016 | 334 |
36. Trade and other receivables
2017 $000's | 2016 $000's | |
Amounts due from Group undertakings (note 44) | 71,294 | 57,830 |
Other receivables | 76 | 77 |
Prepayments | 207 | 316 |
71,577 | 58,223 |
The Directors consider that the carrying value of trade and other receivables is approximately equal to their fair value.
37. Cash and cash equivalents
2017 $000's | 2016 $000's | |
Unrestricted cash in bank accounts | 12,972 | 5,456 |
12,972 | 5,456 |
38. Trade and other payables
2017 $000's | 2016 $000's | |
Trade payables | 452 | 140 |
Amounts due to Group undertakings (note 44) | 904 | 904 |
Accruals | 1,388 | 2,455 |
Other payables | 251 | 283 |
2,995 | 3,782 |
Trade and other payables principally comprise amounts outstanding for trade purchases and ongoing costs.
The Directors consider that the carrying amounts of trade and other payables are approximate to their fair values. All trade and other payables are denominated in Sterling or US Dollars.
The Company has financial risk management policies in place to ensure that all payables to third parties are paid within the credit timeframe and no interest has been charged by any suppliers as a result of late payment of invoices during the year.
39. Retained earnings/ (accumulated losses)
$000's | |
Balance at 1 January 2016 | (2,346) |
Loss for the year | (1,696) |
Credit to equity-settled share-based payments | 136 |
Balance as at 31 December 2016 | (3,906) |
Profit for the year | 7,793 |
Credit to equity-settled share-based payments | 820 |
Balance as at 31 December 2017 | 4,707 |
On 24 November 2017, the directors of Westport Oil Limited ("Westport") a 100% subsidiary of the Company, after due and careful consideration of the financial position of Westport declared a $10 million dividend to the Company. Westport have committed to pay the full dividend within 12 months of the declaration date.
40. Translation reserve
Prior to 1 January 2013 exchange differences relating to the translation of the net assets of the Company from its functional currency (Sterling) into the Group's presentation currency, US Dollars, were recognised directly in the translation reserve. From 1 January 2013, the Company's functional currency changed to US Dollars. As a result, there is no movement on the reserve in the current year or the prior year.
Company | $000's |
Balance at 31 December 2016 and 31 December 2017 | 1,071 |
41. Notes to the cash flow statement
2017 $000's | 2016 $000's | |
Profit/(Loss) for the year before tax | 9,200 | (4,061) |
Dividends not paid | (10,000) | - |
Adjustments for: | ||
Depreciation of property, plant and equipment (note 35) | 167 | 234 |
Net finance cost/(income) | 169 | (2,306) |
Share-based payments (note 28) | 820 | 812 |
Unrealised foreign exchange (gains)/losses on operating activities | (289) | 39 |
9,133 | (1,221) | |
Operating cash flows before movements in working capital | 67 | (5,282) |
(Increase) / decrease in trade and other operating receivables |
(3,435) |
4,386 |
Decrease in trade and other operating payables | (1,688) | (480) |
(5,123) | 3,906 | |
Net cash used in operating activities | (5,056) | (1,376) |
42. Operating lease arrangements
2017 $000's | 2016 $000's | |
Minimum lease payments under operating leases recognised as an expense in the year | 313 | 345 |
At the balance sheet date, the Company had outstanding commitments for future minimum lease payments under non-cancellable operating leases, which fall due as follows:
2017 $000's | 2016 $000's | |
Within one year | 168 | 202 |
In the second to fifth years inclusive | 629 | 576 |
After five years | 144 | 276 |
941 | 1,054 |
Operating lease payments represent rentals payable by the Group for certain of its office properties and staff residences.
43. Financial instruments
Set out below is the comparison by category of carrying amounts and fair values of all of the Company's financial instruments that are carried in the Financial Statements.
At 31 December 2017 and 2016, the Company held the following financial assets:
2017 $000's | 2016 $000's | |
Amounts due from Group undertakings (note 36) | 71,294 | 57,830 |
Other receivables (note 36) | 76 | 426 |
Cash and bank balances | 12,972 | 5,456 |
84,342 | 63,712 |
At 31 December 2017, the Company held the following financial liabilities at amortised cost:
2017 $000's | 2016 $000's | |
Trade payables (note 38) | 452 | 140 |
Amounts due to Group undertakings (note 38) | 904 | 904 |
Accruals | 1,388 | 2,455 |
Other payables | 209 | 172 |
2,953 | 3,671 |
44. Related Party Transactions
Loans to related parties
2017 $000's | 2016 $000's | |
Loans from Eland Oil & Gas PLC to Eland Oil & Gas (Nigeria) Limited | 17,333 | 15,319 |
Loans to Eland Oil & Gas (Nigeria) Limited are short term and carry interest of 5% per annum.
Other transactions between the Company and Group undertakings
Eland Oil & Gas (Nigeria) Limited $000's |
Exploration & Production Limited $000's | Wester Ord Oil & Gas Limited $000's | Wester Ord Oil & Gas (Nigeria) Limited $000's |
Westport Oil Limited $000's | Tarland Oil Holdings Limited $000's | Total $'000's | |
Balance at 1 January 2016 | 3,552 | 31,899 | 11 | 783 | 214 | 16 | 36,475 |
Transactions during the year ended 31 December 2016: | |||||||
Management fees | - | 3,000 | - | - | - | - | 3,000 |
Costs recharged | 732 | 3,660 | 23 | 781 | 2,698 | 25 | 7,919 |
Interest on loans to related parties | 679 | - | - | - | - | - | 679 |
Reimbursement of costs recharged | (2,386) | (3,176) | - | - | - | - | (5,562) |
Balance at 31 December 2016 | 2,577 | 35,383 | 34 | 1,564 | 2,912 | 41 | 42,511 |
Transactions during the year ended 31 December 2017: | |||||||
Management fees | - | 3,000 | - | - | - | - | 3,000 |
Costs recharged | 861 | 4,112 | 2 | 1,160 | 1,858 | 3 | 7,996 |
Dividend | - | - | - | - | 10,000 | - | 10,000 |
Interest on loans to related parties | 788 | - | - | - | - | - | 788 |
Reimbursement of costs recharged | - | (6,938) | - | - | (3,396) | - | (10,334) |
Balance at 31 December 2017 | 4,226 | 35,557 | 36 | 2,724 | 11,374 | 44 | 53,961 |
In addition, the Company also has a payable balance of $904,000 (2016: $904,000) due to Eland Oil & Gas (Nigeria) Limited.
Trading transactions
Purchase of services 2017 $000's | Purchase of services 2016 $000's | |
Henderson Global Investors | 21 | 62 |
Lombard Odier | 51 | - |
Henderson Global Investors is a related party of the Group because it is a substantial shareholder of Eland Oil & Gas plc. During the year, the management of the investment in Eland was transferred from Henderson Global Investors to Lombard Odier.
FORWARD-LOOKING STATEMENTS
Cautionary statement regarding forward-looking statements
This Annual Report may contain forward-looking statements which are made in good faith and are based on current expectations or beliefs, as well as assumptions about future events. You can sometimes, but not always, identify these statements by the use of a date in the future or such words as "will", "anticipate", "estimate", "expect", "project", "intend", "plan", "should", "may", "assume" and other similar words. By their nature, forward- looking statements are inherently predictive and speculative and involve risk and uncertainty because they relate to events, and depend on circumstances, that will occur in the future. You should not place undue reliance on these forward-looking statements, which are not a guarantee of future performance and are subject to factors that could cause actual results to differ materially from those expressed or implied by these statements. The Company undertakes no obligation to update any forward-looking statements contained in this Annual Report, whether as a result of new information, future events or otherwise.
Related Shares:
Eland Oil & Gas