Final Results for the Year ended 31 December 2016

06 June 2017

Eland Oil & Gas PLC

("Eland" or the "Company")

Final Results for the Year ended 31 December 2016

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:

"Despite a challenging market environment, Eland ended 2016 on a highly positive note and has since, through Elcrest, reached record production levels from OML 40 onshore Nigeria.

"We have made strong progress in 2017 and are confident of the next phase of our growth as we continue to deliver our low cost workover programme which has the potential to more than double our current production once again."

2016 highlights and 2017 developments

· Challenging year due to prolonged Forcados shut-in and reduced revenues, requiring careful working capital management.

· Cash currently at $6 million with active working capital management to bridge return to Forcados pipeline cash flows.

· Successful equity placing in April 2016 raised $18.5 million (gross) to support the planned work programme.

· $15m of the Reserve Based Lending ("RBL") facility with Standard Chartered Bank had been drawn down by 31 December 2016. The borrowing base amount was $25 million in 2016 with $3.5 million held in reserve until return to production. The facility underwent a redetermination in early 2017 with the borrowing base confirmed at $23.9 million, and the $3.5 million reserve requirement released.

· Elcrest continues to benefit from Pioneer Tax status in respect of OML 40. Elcrest is exempt from paying Petroleum Profits Tax during the Pioneer period and in addition has an estimated $433 million tax loss pool subject to agreement by the Nigerian tax authorities to be utilised to offset future taxes.

· Elcrest has recognised a $17.25 million liability to its local shareholder for management fees accruing since inception and invoiced subsequent to the period. Elcrest's liability to Eland for the same had already been recorded. Therefore, Eland, through its subsidiary Westport, now has an amount to recover from Elcrest of $380.2 million in principal and interest as at 31 December 2016 and remains the sole secured creditor.

Outlook

· The Opuama field in OML 40 recommenced production in January 2017 at initial rates of c.10,000 bopd from a single well before stabilising at 8,500 bopd.

· Updated CPR for four wells in OML 40 which trebled gross 2P reserves to 33mmbbl of oil.*

· Eland has reacted decisively to the shut-in at Forcados by developing an alternative export solution, with c.500k barrels of crude having been exported via shipping to an offshore FPSO. Multiple cargoes have been delivered in the year to date. This followed an 11-month hiatus for the field caused by the shut-down of the Forcados terminal.

· Eland has recently returned to production in May 2017 via Forcados with c.11,500 bopd produced from 2 wells (Opuama-1 and Opuama-3).

· Following the highly successful workover on Opuama-3 in April 2016, Eland now plans to perform a sidetrack on Opuama-7 in early H2 2017, potentially boosting production from the field by a further 6,000 bopd gross.**

· The Company also plans to complete an Early Production System (EPS) on Gbetiokun-1 in OML 40 with a well recompletion planned for H2 2017. This could contribute an initial gross 7,800 bopd to OML production.**

· An EPS on the Ubima field is planned to follow with the re-entry and completion of Ubima-1 potentially contributing production of 2,500 bopd.**

· Expected 2017 near-term production rate of 17,500 bopd, which will be driven by the phasing of, and flow rates from, Opuama-7. Further upside remains after Gbetiokun-1 and Ubima-1 brought on stream.

· Continue to focus on cost reductions and working capital management as further discussed in the CFO statement.

* Source: Independent Report by Netherland Sewell & Associates Inc. April 2016 and April 2017.

** Subject to available capital.

For further definitions, glossary of technical terms, and detailed accounts, please see our full audited 2016 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

Olivier Serra, CFO

Finlay Thomson, IR

Canaccord Genuity Limited (+44 (0)20 7 523 8000)

Henry Fitzgerald O'Connor

Panmure Gordon (UK) Limited (+44 (0)20 7 886 2500)

Adam James / Atholl Tweedie

Tom Salvesen

Camarco (+44 (0) 203 757 4980)

Billy Clegg / Georgia Edmonds

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 located 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 83.2 mmbbls, gross 2C contingent resources of 41.2 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.

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

2016 was again a challenging year for the Nigerian oil industry despite the increase in the oil price. Eland responded very well to this situation by developing alternative export routes for the Company's crude, whilst also delivering its best production test rates to date from OML 40. I believe that the Company is now in its strongest operational and production position to date to enable further growth and value for our shareholders to be delivered, but there are short term working capital challenges to be navigated which are discussed further in the CFO's report.

A difficult start to 2016 saw oil prices reaching 13-year lows below $30 per barrel, although subsequent concerns about a supply squeeze led to a recovery throughout the remainder of the year. As a result, Brent ultimately doubled from its lows to end the year at $57 per barrel. A perceived slowdown in US shale supplies because of the lack of investment and critically low rig utilisation rates was coupled with OPEC announcing a reduction in production quotas. Whilst this was reflected positively in commodity prices, it did little to reinvigorate investment in the oil and gas industry globally, including Nigeria. Ongoing sabotage activities within the country further impacted the oil industry and Eland was not immune to this, with the Shell-operated Forcados oil terminal being shut-in from February for the remainder of the year.

Considering these circumstances, I believe that Eland had a very good year. In April, despite Forcados being shut-in, we performed a successful workover and a production test on our Opuama field in OML 40, with the Opuama-3 well producing in excess of 10,500 barrels of oil per day, the highest rate ever recorded from a single well in OML 40.

With the Forcados terminal being shut-in in February after militant activity in the Niger Delta, and a lack of clarity throughout last year as to when it may come back on-line, we took the decision to investigate alternative export routes for our crude rather than to simply evacuate it via pipeline. We commenced the development of a shipping option, involving transporting our oil to a secure offshore facility via the Benin River. I am extremely proud of this achievement and in particular the speed with which this project was completed. This is a testament both to the quality of our team and the relationship with our joint venture partner.

As a result of this very successful work, production from OML 40 recommenced in 2017 at initial rates of 10,000 barrels of oil per day, and is currently at a stabilised rate of 11,500 bopd, which compares to the rates of 4,400 barrels of oil per day that the field was producing at prior to being shut-in in February 2016. I believe this highlights the prodigious nature of these world-class reservoirs and gives me great confidence in the growth potential of our asset base.

We continue into 2017 confident in the next phase of our growth with plans for additional field work which has the potential to more than double current production.

On the financing side of the business, Eland successfully completed an equity placing in April 2016 to raise funds of $18.5 million at a price of 34 pence per share.

During the year there were a number of changes to the board. In May, Louis Castro retired from his role as Chief Financial Officer, and was replaced by Olivier Serra. In July we also announced the appointment of Henry Obi to the Board as a Non-Executive Director representing Helios Natural Resources, a significant shareholder in Eland. Henry replaced Richard Norris who had been Helios' representative on the Board since September 2014.

Eland has weathered the unforeseen events of 2016 and is now enjoying a period of stabilised oil prices and the recommencement of production at OML 40. The planned 2017 work program should provide a further step change in production growth with a low level of associated capital expenditure. I remain confident that both the team and asset base will deliver in 2017.

Russell HarveyChairman

6 June 2017

CEO Statement

Despite the enforced closure of the Forcados terminal in February, Eland ended 2016 on a highly positive note and has since, through Elcrest, reached record production levels from OML 40 onshore Nigeria. The business model has been validated with the result of two separate workover wells which boosted gross production from c3,000 bopd in late 2015 to 8,500 bopd during shipping and current levels of 11,500 bopd. Furthermore, two additional near term workovers are planned on OML 40, production could potentially more than double again during 2017 subject to sustained production and capital availability. While the outlook on our opportunities look very promising, 2016 has been a very difficult year. Low oil prices combined with the production shutdown for over 10 months, resulted in a variety of measures being put in place to reduce cash expenditures and closely manage our working capital situation. This was a very 'hands on' approach by the management of Eland and Elcrest. With production now re-started our working capital management continues as crude oil receipts continue to build.

Opuama-1 production restart and Forcados

Following a highly successful and low cost workover of Opuama-1 in late 2015, gross production from the field increased by more than 50% to 4,500 bopd, and remained at these higher levels heading into 2016. It was therefore frustrating for Eland and its shareholders when the Forcados terminal, the primary destination for its crude, had a pipeline sabotaged by militants in February. The resulting closure and force majeure remained in place for the rest of the year, despite a brief reopening in November.

Opuama-3 workover and production test

If a single well could be shown to prove that the well re-entry strategy works, then it would be the Opuama-3 workover. The $2 million workover, which was prognosed to deliver 2,000 to 4,000 bopd from the D1000 and D2000 reservoir intervals, was completed in April. The workover produced oil at rates of more than 10,500 bopd during a short-term test, vastly outperforming initial expectations. Since coming onstream in early 2017, stabilised rates of around 8,500 bopd from Opuama-3 alone have been achieved.

Equity raise to bolster operations

With the lack of cash flow as a result of the Forcados terminal being shut in, and a lack of clarity on when it might reopen, the decision was made by Eland to bolster the balance sheet via an equity raise in April 2016. The Company felt it was important to have the funding in place to provide funding initially designated for near term Gbetiokun 1 workover, and subsequently utilised in part to develop a supplementary export route for OML 40 production, especially after such a positive result on Opuama-3. The accelerated book-build was very successful, raising $18.5 million gross in an oversubscribed placing.

Oil price fluctuations in 2016

The oil price experienced significant volatility during 2016, declining to a 10-year low of $27 per barrel in February before a sustained recovery throughout the remainder of the year saw it more than double. Volatility has reduced in the first few months of 2017 with a relatively stable Brent price within the $50 to $55 per barrel range.

Planning and contracting for tankering and engineering of tie in point

Throughout the summer work continued on two supplementary and independent export routes from OML 40 to diversify crude deliveries. Barging proposals were reviewed with options for logistics, storage and offtake all finalised. Preparation for the installation of a dedicated 6 km pipeline extension directly into a nearby terminal also continued. A tie-in point into the OML 40 export line for barging operations and Gbetiokun crude injection point was also completed. Barging of OML 40 crude commenced in late January 2017.

The planning required to contract the barging solution included both the logistical and engineering solutions required to facilitate such a complex operation. Late in 2016 when it became clear that Forcados terminal would remain unavailable to Elcrest, the planning work completed earlier in the year allowed an acceleration of the execution phase. Contracting on Tankers and off take agreements were completed within six weeks which linked well with the completion of engineering works on the Benin river.

The operation, and in particular, the aspects under Elcrest control have performed extremely well, with limited downtime or interruption. However, the FPSO system has suffered some difficulties and downtime associated with the discharge of crude oil, and approximately $8 million of receivables are pending subject to technical resolution. The Group has managed this delay by agreeing the deferral of a number of creditors, and linking their final settlement to the final discharge date. The shipping system is readily repeatable as and when required, with a review of the ultimate point of crude oil discharge being a key focus of any future operation. Many opportunities exist in OML 40 for accelerated production from stranded fields through shipping operations.

CPR update commissioned and trebles reserves

In early 2017 we commissioned a Competent Person's Report (CPR) on the Opuama-1, Opuama-3, Opuama-7 and Gbetiokun-1 wells. This was done with a view to confirming our internal view that these reserves were better than previously anticipated. In the event we were proved correct as the CPR returned with a trebling of its estimate of recoverable reserves from these four wells alone. This is highly encouraging and an extremely positive indication of the potential upside within the rest of OML 40.

Planning Opuama-7 rig access and workover operations

Looking to 2017 plans, Eland is currently preparing for the next workover on the Opuama field. Drilling of the well should commence early in the second half of the year, with a CPR forecasting initial production rates of 6,000 bopd, therefore potentially boosting near term overall production from OML 40 to around 17,500 bopd.

The contract for the rig and services has been fully negotiated and mobilisation is expected to be approximately one month from final execution.

Ubima well access and road construction

The work late in 2016 to prepare the well site and site road access involved considerable community contractor involvement. This work will continue when the season allows to enable the continued development of the Ubima 1 EPS.

Elcrest and Shareholder Agreement

Although 2016 had the positives of a very successful workover of Opuama-3 and the launch of Elcrest's secondary export route from OML 40, due to Elcrest only producing for one and a half months in the year, Elcrest still made a significant operating loss. Therefore, Eland, through our subsidiary Westport, now has an amount to recover from Elcrest of $380.2 million as at 31 December 2016 in principal and interest and remains the sole secured creditor.

Subsequent to year end, Elcrest received a fee invoice from its local shareholder. This fee related to management charges agreed at the onset of the joint venture of $3m per annum for each shareholder, which by the end of 2016 totalled $17.25 million per shareholder. In prior periods Eland and Elcrest had understood that Elcrest's local shareholder would not exercise its ability to levy these charges. Eland has now also formally invoiced the corresponding amounts. The payment profile for settlement of these liabilities is yet to be agreed, but it is intended this will be settled from free cash generated from increasing OML 40 production.

CSR projects

Elcrest has continued with a number of CSR projects during the year within OML 40. The construction of a walkway in Tsekelewu community to allow ease of movement between the community during the wet season and also the completion of a wharf and market area within the Opuama community, allowing market and fishing enterprises to flourish.

In both Opuama and Ubima we continued with our medical outreach program, ensuring free health check within the communities.

Outlook

The prospects for Eland have never been more exciting. The prolonged shut in to Forcados and the interruptions and delays experienced during the shipping period and transition back to Forcados have necessitated and will continue to require careful working capital management.

Eland's value will be delivered from ongoing investment in our drilling programme. Whilst 2017 will not be without its challenges and availability of capital will dictate the timing and schedule of our investment programme, the opportunity to more than double production once again at limited cost and without any exploration risk is very attractive.

George Maxwell

Chief Executive Officer

6 June 2017

Financial Review

Review of 2016

2016 was a challenging year for Eland due to the sabotage and prolonged outage of the Forcados terminal. Against a challenging environment Eland was nonetheless able to raise $18.5 million (gross) in April 2016 which, combined with a substantial reduction in cash operating expenditure, enabled Eland to end the year with a cash balance of over $11 million (including $4.0 million in restricted cash) and no additional debt drawn in the period. As a result of the Forcados interruption, revenue for the year was significantly lower at $2.4 million (down from $18.1 million) which reflected a partial year of production with only two liftings completed.

Operating expenses of $25.5 million (2015: $18.0 million) were impacted by a liability for $17.25 million (2015 release of $2.25 million). Subsequent to year end, Elcrest received a fee invoice for such liability from its local shareholder. This fee related to management charges agreed at the onset of the joint venture of $3m per annum for each shareholder, which by the end of 2016 totalled $17.25 million per shareholder. In prior periods Eland had understood that Elcrest's local shareholder would not exercise its ability to levy these charges. Eland has now also formally invoiced the corresponding amounts. The payment profile for settlement of these liabilities is yet to be agreed, but it is intended this will be settled from free cash generated from increasing OML 40 production.

Excluding the above, operating expenses were $8.2 million (down from $20.2 million) reflecting reduced operations and benefiting from FX gains on NGN depreciation. While operating expenses incurred are mostly fixed, it is important to note however that as the Company produces at higher rates following the successful workover of well Opuama-3, operating expenses per barrel reduce significantly.

Administrative expenses of $5.8 million declined by a further 9% compared with $6.4 million in the previous year, reflecting a continued effort to target corporate savings as well as covering indirect operating expenses as the Company continues to operate key projects for the JV with its local partner.

The adjusted loss before interest, tax and DD&A was $8.8 million compared to $2.5 million in the previous year, after adjusting for the amounts set out above. Finance costs amounted to $2.5 million (down from $3.3 million) reflecting the costs of carry of the reserves based loan ("RBL") from Standard Chartered Bank ("SCB"). Overall, this resulted for the Group in a loss of $30.4 million for the year before exclusion of non-controlling interest.

The Group's consolidated balance sheet shows net assets of $155.7 million ($168.0 million). Within this total, non-current assets represented $206.4 million ($198.2 million), current assets were $13.1 million ($13.8 million), current liabilities $40.4 million ($20.8 million) and non-current liabilities $23.4 million ($23.2 million). Hence, net current liabilities stood at $27.3 million ($7.0 million).

Although the Group has a significant net current liability position this includes the aforementioned

$17.25 million Elcrest charge towards which Elcrest have paid $1 million, with the remainder to be discharged as free cash is generated through increasing production in OML40, and $10.4 million of accrual balances due to our OML 40 partner, NPDC, which the Group plans to settle by carrying NPDC's share of capital expenditures as we deliver the work programme. Eland has reported such liabilities to its lender and how it plans to take them into consideration when determining its covenants, as per the procedures set out in the facility. To date, the Group has reported compliance with covenants to the lender.

The Group began the year with consolidated cash and cash equivalents of $8.4 million and finished the year with $11.1 million, without any further amounts drawn under the RBL facility. In May 2016 the Company completed a placing of $18.5 million gross with existing and new investors. The placing was done at a premium to the prevailing share price and was over-subscribed. The cash was invested during the period as $7.5 million in operating activities and $6.9 million on enhancing the Group's assets through development and evaluation expenditure.

In addition, to support working capital during the prolonged interruption at the Forcados Terminal, in May 2016 the Company also made forward sales to its offtake partner, Shell Western Supply and Trading Limited, of a further $3 million.

The RBL, on which SCB has committed an initial $35.0 million, has a maturity of four and a half years from 31 December 2014. The amount available to Eland under the RBL is subject to a cap determined by six-monthly reviews and calculated on OML 40 production. The borrowing base amount at the end of 2016 was $25m, but $3.5m was required to be held in reserve by the lenders until the return to production. The facility underwent a redetermination in early 2017, with the borrowing base amount confirmed at $23.9m, and the $3.5m reserve requirement released. Drawdowns to date amount to $15.0 million and, as such, headroom under the facility is reducing over time in accordance with the terms of the RBL. The next redetermination is due in September for the period ending as at end of June 2017.

2017 financial developments

The Company entered into alternative export arrangements to the Forcados export pipeline and terminal by chartering shuttle tankers and entering into handling agreements with an FPSO, which allowed to restore production and sales in January 2017. Shipping operations were funded from cash on hand and working capital management and will be completed upon collection of the $8 million receivable balance as noted in the CEO's report.

The Company continues to actively manage its working capital, including shipping receivables and vendor payment. It has plans to settle the overlift position resulting from shipping operations (in which Elcrest's JV partner did not participate) and the Shell prepayment by offsetting amounts due from sale revenues to be collected from Forcados over the next few months.

Going concern

As set forth in the Going Concern note, there remains risks to mitigate and material uncertainties which could affect the ability of the Company to manage its working capital position or remain compliant with its loan covenants, such as stability of oil prices, sustained access to export routes and collection/settlement of receivables/payables.

Outlook

The Company held its first Capital Markets Day on 27 April 2017 and reported on operational progress, technical development, CPR update, with particular focus on the near term work program and financial development, as well as the value of its assets. The Company pointed out that it expects that increased production levels will allow it to gain access to further debt financing and support the 2017 work programme designed to materially increase production and cash flow.

In May 2017, the Forcados export terminal was re-opened and production has been restored back through the Forcados export line, at 11,500 bopd. Whilst the transition back to Forcados will require careful working capital management, it offers the potential for immediately higher production levels at improved margin and netbacks. Notwithstanding the near term challenges it is against this backdrop that we anticipate further investment and increasing cashflows as 2017 progresses.

Olivier Serra

Chief Financial Officer

6 June 2017

CONSOLIDATED INCOME STATEMENT

for the year ended 31 December 2016

There were no items of comprehensive income in the current or prior year, other than the loss for the year. Accordingly, no statement of comprehensive income is presented.

All activities relate to continuing operations.

* The prior year comparative for cost of sales has been represented to split out the Shareholder management fee separately to aid comparability with 2016.

CONSOLIDATED BALANCE SHEET

as at 31 December 2016

The financial statements of Eland Oil & Gas PLC, registered number SC 364753, were approved and authorised for issue by the Board of Directors on 6 June 2017.

George Maxwell Olivier Serra

Chief Executive Officer Chief Financial Officer

COMPANY BALANCE SHEET

as at 31 December 2016

The Company only loss for the year was $1,696,000 (2015: $4,062,000). 

The financial statements of Eland Oil & Gas PLC, registered number SC 364753, were approved by the Board of Directors on 6 June 2017.

George Maxwell Olivier Serra

Chief Executive Officer Chief Financial Officer

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

year ended 31 December 2016

COMPANY STATEMENT OF CHANGES IN EQUITY

year ended 31 December 2016

CONSOLIDATED CASH FLOW STATEMENT

year ended 31 December 2016

COMPANY CASH FLOW STATEMENT

year ended 31 December 2016

NOTES TO THE FINANCIAL STATEMENTS

year ended 31 December 2016

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 company incorporated in Scotland, under the Companies Act 2006. 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 2016.

2. Significant accounting policies

Basis of accounting

The financial statements have been prepared in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union and therefore the Group financial statements comply with EU IFRS Regulation.

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 income statement for the year. Eland Oil & Gas PLC reported a loss for the year ended 31 December 2016 of $1,696,000 (2015: loss of $4,062,000).

Going concern

In assessing its conclusion on going concern, the Group has prepared cash, funding and liquidity forecasts through this year and next, which forecast that the group will remain compliant with its covenants. In making this assessment, the Directors note that in May 2017 the Forcados export terminal was re-opened and production has been restored back through the Forcados export line.

However, the sustained closure of the Forcados terminal from February 2016 has placed working capital pressure on the Group and consequently, as at the date of issue of the Annual Report the Group has net current liabilities of $49.0 million, including cash of $6 million, which will require careful working capital management in the coming months to unwind.

As such, the Directors have concluded that material uncertainties exist any of which could lead to a liquidity shortfall or the Company becoming non-compliant with its loan covenants in the near term, including:

1) Operational performance - where a further sustained period of closure of the Forcados terminal, or operational issues at the Opuama field, would lead to a period where the Group is unable to produce and/or lift crude oil, or would require to resume shipping operations;

2) Oil prices - a deterioration of Brent crude prices would lead to reduced cash flows from operations;

3) Completion of shipping operations - further delays to expected cash receipts from shipping operations, where as mentioned in the CEO statement, the Group's crude buyer will settle outstanding invoices totalling approximately $8 million once the FPSO's technical capacity to export is confirmed. The Group has to date mitigated this risk by managing vendor payments, and linking them to the expected dates of cash inflows, but any further delay would require further agreement from suppliers to defer payment;

4) Shareholder Management Fees - the Group currently holds liabilities to Elcrest's indigenous shareholder of

$17.25 million for which the timing of cash outflows has not yet been agreed. This liability reflects a $17.25 million invoice received by Elcrest against which a payment of $1m has been made, with no further settlement included in the Group's current 12 month forecast. There is a risk that the local shareholder of Elcrest will request from Elcrest an acceleration of payments beyond the funding available to Elcrest. In making a determination with respect to payment settlement plan, Elcrest shall continue to exercise its fiduciary duty towards its board and shareholders, taking into account the objectives to continue to develop OML40 and preserve the integrity of all its agreements in place, including similar levels of management fees payable from Elcrest to Eland and Elcrest's loan payable to an Eland subsidiary. The Group shall carry out the same duties via its participation in Elcrest, with all the means, remedies and loan security available to it;

5) NPDC - the Group currently holds liabilities to NPDC of $14.0 million, and the intention is to settle this liability through funding NPDC's share of future capital projects, subject to capital availability. In addition, there are rejected cash call amounts in issue, disclosed in note 33, which are subject to JV audit. As such, there is a risk that NPDC seek payment for amounts, or the JV audit does not support Elcrest's position, and funding might not be available to Elcrest to settle amounts then being called;

6) Covenant compliance - the Group's historic and forecast covenant calculations exclude the Elcrest shareholder management fee, overlift position and NPDC liabilities. The details and assumptions to be used in the covenant calculations are disclosed and discussed with the lender, Standard Chartered Bank. Maintaining covenant compliance through the coming 12 months will be reliant on both increased production and cashflow, and agreement to exclude these liabilities from covenant calculations determined and submitted by the Group to its lender as per the terms of the facility. The covenant calculations as at 31 December 2016 were submitted prior to recognition of the Shareholder Management Fee noted above, and therefore excluded this amount. Should Eland be required to resubmit its covenant calculations, the Company would remove these charges from its determination in order to preserve compliance with the covenant in accordance with its interpretation of the facility agreement. Maintaining covenant compliance therefore requires the lender to accept the adjustments to the calculation, as per the terms of the facility. There is no guarantee that the lender will approve the covenant calculation at the time it is made.

The Directors have assessed a number of potential mitigating actions if any one or more of the above uncertainties crystallises, which include the recommencement of shipping activities, seeking credit agreements to defer cash outflows, and capital markets funding. As such, the Directors acknowledge the above risks are material uncertainties which could cast significant doubt on the Group's ability to continue as a going concern and therefore, the Group may be unable to realise its assets and discharge its liabilities in the normal course of business, but believe mitigating actions are in place to counter those risks.

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.

The financial statements do not include the adjustments that would result if the Company does not continue as a going concern.

Further information on the Group's business activities, together with factors which impact these activities, such as the risk of interruptions to production, are included within the Chief Executive's Report and the risk factors described on pages 26 to 27. Analysis of the Group's financial position, its cash flows, liquidity position, cost estimates and borrowing facilities are described in the Financial Review on pages 22 and 23, and in notes 3 and 33 of the Financial Statements.

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.

Elcrest Exploration and Production Nigeria Limited 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

The Directors do not expect that the adoption of the Standards and Interpretations listed above will have a material impact on the financial statements of the Group in future periods, IFRS 15 may have an impact on revenue recognition and related disclosures. IFRS 16 is likely to require a change in the treatment of our lease agreements. IFRS 9 will affect both the measurement of and disclosures relating to financial instruments. Beyond the information above, it is not practicable to provide a reasonable estimate of the effect of IFRS 15, IFRS 16 and IFRS 9 until a detailed review has been completed.

No new Standards or Interpretations were early adopted by the Group or Company during the year.

Joint arrangements

A joint arrangement is an arrangement over which two or more parties have joint control. The Group is engaged in oil and gas exploration, development and production through unincorporated joint ventures which it accounts for as joint operations whereby the Group accounts for its share of the results, assets and liabilities of these joint operations. The Group accounts for its interests in joint operations using the equity method. Under the equity method, the investment is initially recognised at cost. The carrying amount of the investment is adjusted to recognise changes in the Group's share of net assets of the venture since the acquisition date.

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

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.

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 income statement 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.

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 

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 present value of the future net cash flows 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 income statement 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 income statement, 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 income statement.

Acquisitions, asset purchases and disposals

Acquisitions of oil and gas properties are accounted for under the acquisition method 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 income statement.

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 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 2016, under the terms of the RBL facility, the balance of restricted cash amounted to $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. See account note 16 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 income statement. 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 income statement 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 income statement, 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 on page 68.

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 on page 69.

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 account note 31 to the financial statements.

Other financial liabilities

Other financial liabilities are initially measured at fair value, net of transaction costs.

Other financial liabilities 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 account note 30.

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.

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.

3. Critical accounting judgements 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 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 to 2026 can be obtained. 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 (Note 17)

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 2016 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 liability in this respect to be remote. Further details can be found in Note 33.

Contingent liability (Note 33)

The Group's subsidiary Wester Ord Oil & Gas (Nigeria) Limited may become, subject to certain conditions (see below), 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.

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 models. Key assumptions and estimates in the cash flow models relate to commodity prices, discount rates that are adjusted to reflect risk specific to individual assets, commercial reserves and the related cost and production profiles.

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. Note 12 discloses the carrying value of tangible oil and gas assets. Due to the prevailing low oil prices, compared to the date of the acquisition of the OML40 licence, together with the disruption experiences at Forcados terminal in 2016 management have performed a full impairment review of the carrying value of the Group's interest in OML 40 as at 31 December 2016. The impairment review assumes a life of field to 2026, an oil price profile benchmarked to ICE commodity forward prices to end 2018 and thereafter based on analysts' forecasts (specifically $56/bbl in 2017, $60/bbl in 2018, $64/bbl in 2019 rising steadily to $77/bbl by 2022 and held consistent thereafter), management's best estimates of proved and probable reserves and a 12% post-tax discount rate. Based on this calculation, no impairment of the carrying value of the Group's oil and gas assets was identified as at 31 December 2016.

Decommissioning provision (Note 20)

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 2026 - 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 20.

The costs of decommissioning are reviewed annually. A review of all decommissioning cost estimates was undertaken by an independent specialist in 2013. This has been reassessed by the same independent specialist in early 2015, at the request of the Directors. An updated decommissioning review is likely to be undertaken during 2017. 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 20.

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:

Revenue derives from an offtake contract with its partner, Shell Western Supply and Trading Limited. See note 28 on segmental analysis.

5. Loss for the year

The loss before tax for the year is stated after charging/(crediting):

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 shareholder management charges. The items excluded are non-cash in the year, and individually or collectively material.

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:

1 The large foreign exchange gain above totaling $6,511,000 principally reflects the significant drop in the value of the Nigerian currency, Naira (NGN). The NGN: USD rate moved from NGN198: US$1 at 2015 year-end to NGN487: US$1 at 2016 year-end. The Naira liabilities of the Group, particularly OML 40 liabilities, have been devalued in USD terms resulting in a large foreign exchange gain. All Naira exchange revaluations are classified within operating expenses. As noted in the accounting policies the Group adopted the use of the parallel rate in the year, the 2016 year end rate quoted above being the parallel rate.

2 Includes costs of $816,000 (2015: $880,000) relating to non-executive directors' fees/employee benefits and other temporary employment costs not included in note 7 below. See account note 7 for further details on the 2015 restatement.

3 The management fee charge above is in relation to a local Nigerian partner who provides logistical and support services. Full details are disclosed in note 18.

6. Auditor's remuneration

The analysis of auditor's remuneration is as follows: