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Final Results for the Year ended 31 December 2017

18 Apr 2018 07:00

RNS Number : 2475L
Eland Oil & Gas PLC
18 April 2018
 

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.

 

 

 

This information is provided by RNS
The company news service from the London Stock Exchange
 
END
 
 
FR GGUUGCUPRPPM
Date   Source Headline
17th Dec 20193:15 pmPRNForm 8.3 - Eland Oil & Gas plc
17th Dec 20193:08 pmRNSForm 8.3 - Eland Oil & Gas PLC
17th Dec 20192:59 pmRNSForm 8.3 - Eland Oil & Gas PLC
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17th Dec 201910:30 amRNSCompletion of Acquisition by Seplat
17th Dec 20199:30 amRNSForm 8.5 (EPT/RI)
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16th Dec 20193:16 pmRNSForm 8.3 - Eland Oil & Gas PLC
16th Dec 20193:15 pmPRNForm 8.3 - Eland Oil & Gas plc
16th Dec 20191:20 pmRNSForm 8.3 - Eland Oil & Gas PLC
16th Dec 201912:00 pmRNSForm 8.5 (EPT/RI) - Eland Oil & Gas Plc
16th Dec 201911:16 amRNSForm 8.3 - Eland Oil & Gas plc
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13th Dec 201912:00 pmRNSForm 8.5 (EPT/RI) - Eland Oil & Gas PLC
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13th Dec 201910:28 amRNSForm 8.5 (EPT/RI)
12th Dec 20195:30 pmRNSEland Oil & Gas
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12th Dec 20191:00 pmRNSCOURT SANCTION OF SCHEME OF ARRANGEMENT
12th Dec 201912:00 pmRNSForm 8.5 (EPT/RI) - Eland Oil & Gas Plc
12th Dec 201911:51 amRNSForm 8.3 - Eland Oil & Gas plc
12th Dec 20199:49 amRNSForm 8.5 (EPT/RI)
11th Dec 20193:15 pmPRNForm 8.3 - Eland Oil & Gass plc
11th Dec 20193:04 pmRNSForm 8.3 - Eland Oil & Gas PLC
11th Dec 201912:00 pmRNSForm 8.5 (EPT/RI) - Eland Oil & Gas PLC
11th Dec 201911:34 amRNSForm 8.3 - Eland Oil & Gas plc
11th Dec 20198:52 amRNSForm 8.5 (EPT/RI)
10th Dec 20195:31 pmRNSForm 8.3 - Eland Oil Gas PLC
10th Dec 20195:12 pmRNSForm 8.3 - Eland Oil & Gas plc
10th Dec 20192:54 pmRNSForm 8.3 - Eland Oil & Gas PLC
10th Dec 201912:00 pmRNSForm 8.5 (EPT/RI) - Eland Oil & Gas
10th Dec 20199:02 amRNSForm 8.3 - Eland Oil & Gas plc
9th Dec 20193:02 pmRNSForm 8.3 - Eland Oil & Gas PLC
9th Dec 201912:00 pmRNSForm 8.5 (EPT/RI) - Eland Oil & Gas Plc
9th Dec 20199:25 amRNSForm 8.3 - Eland Oil & Gas plc
6th Dec 20195:51 pmRNSForm 8.3 - Eland Oil Gas plc
6th Dec 20193:20 pmRNSForm 8.3 - Eland Oil & Gas plc
6th Dec 20193:12 pmRNSForm 8.3 - Eland Oil & Gas PLC
6th Dec 201912:00 pmRNSForm 8.5 (EPT/RI) - Eland Oil & Gas Plc
6th Dec 201911:02 amRNSForm 8.3 - Eland Oil & Gas plc
6th Dec 201910:47 amBUSForm 8.3 - Eland Oil & Gas plc
6th Dec 20198:42 amRNSForm 8.5 (EPT/RI)
6th Dec 20197:00 amRNSForm 8.3 - Eland Oil Gas plc

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