Genel Energy plc Audited results for the year ended 31 December 2017

Source Press Release
Company Genel Energy Plc 
Tags Strategy - Upstream, Capital Spending, People, Strategy - Corporate, Financial & Operating Data
Date March 22, 2018

Genel Energy plc (‘Genel’ or ‘the Company’) announces its audited results for the year ended 31 December 2017.

Murat Özgül, Chief Executive of Genel, said:

“Another year of consistent payments by the KRG and a disciplined capital allocation strategy helped to generate material free cash flow in 2017. This was enhanced in the latter part of the year by the Receivable Settlement Agreement, from which Genel expects to generate sustainable and significant free cash flow going forward. The strong financial performance of 2017, and the promise of more to come, facilitated the successful refinancing in December, which solidified a significant improvement in the balance sheet and provides a strong platform for growth.

We will continue with our strategy of maximising free cash flow as we focus investment on our producing assets, specifically on the Tawke PSC, where the performance of Peshkabir remains highly encouraging. Prudent expenditure will also be made on the other assets within our portfolio that provide material value creation opportunities. We will continue to construct the building blocks for value creation from Bina Bawi and Miran, while cost-effectively progressing our exploration assets in Africa.”

Results summary ($ million unless stated)

               2017                  2016 
Production (bopd, working interest)  35,200  53,300 
Revenue  228.9  190.7 
EBITDAX1  475.5  130.7 
Depreciation and amortisation  (117.4)  (128.9) 
Exploration expense  (1.9)  (815.1) 
Impairment of property, plant and equipment  (58.2)  (218.3) 
Impairment of receivables  (191.3) 
Operating profit / (loss)  298.0  (1,222.9) 
Cash flow from operating activities  221.0  131.0 
Capital expenditure  94.1  61.2 
Free cash flow before interest2  141.8  59.1 
Cash3  162.0  407.0 
Total debt  300.0  674.6 
Net debt4  134.8  241.2 
Basic EPS (¢ per share)  97.1  (448.6) 
  1. EBITDAX is earnings before interest, tax, depreciation, amortisation, exploration expense and impairment which is operating profit

/ (loss) adjusted for the add back of depreciation and amortisation ($117.4 million), exploration expense ($1.9 million) and impairment of property, plant and equipment ($58.2 million)

  1. Free cash flow before interest is net cash generated from operating activities less cash outflow due to purchase of intangible assets and purchase of property, plant and equipment (oil and gas assets only)
  2. Cash reported at 31 December 2017 excludes $18.5 million of restricted cash
  3. Reported debt less cash


·         $263 million of cash proceeds received in 2017 (2016: $207 million), with strong free cash flow generation of $142 million (2016: $59 million)

  • Year-end net debt of $135 million, a 44% reduction year-on-year (2016: $241 million)
  • Year-end gross debt of $300 million, a 56% reduction year-on-year (2016: $675 million), with debt extended until 2022 and interest cost reduced by 40%
  • Receivable Settlement Agreement resulted in cash benefit of $26 million in Q4 2017
  • Focused capital allocation – 66% of capital expenditure was spent on cash-generative producing assets, and has been cost recovered
  • Drilling success at Peshkabir, with gross production rising to c.15,000 bopd at year-end
    • Taq Taq field production stabilised in H2 2017, with Q4 average of 14,035 bopd in line with Q3 average of 14,080 bopd
    • In January 2018 Bina Bawi and Miran CPRs confirmed c.45% uplift to gross 2C raw gas resources to 14.8 Tcf


  • Combined net production from the Tawke and Taq Taq PSCs during 2018 is expected to be close to Q4 2017 levels of 32,800 bopd, unchanged from previous guidance
  • Genel expects to continue the generation of material free cash flow in 2018
  • Tangible steps to be taken to further de-risk gas resources and unlock value from Bina Bawi and Miran, including the high-value oil resources
  • Capital allocation discipline to continue, with ongoing prioritisation of spend on cash-generative producing assets. Capital expenditure guidance unchanged at c.$95-140 million net to Genel
  • Opex and G&A cash cost guidance unchanged at c.$30 million and c.$15 million respectively


Genel EnergyAndrew Benbow, Head of Communications  +44 20 7659 5100 
Vigo CommunicationsPatrick d’Ancona  +44 20 7830 9700 

There will be a presentation for analysts and investors today at 0830 GMT, with an associated webcast available on the Company's website, .

This announcement includes inside information.


This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company’s control or within the Company’s control where, for example, the Company decides on a change of plan or strategy. Accordingly no reliance may be placed on the figures contained in such forward looking statements.


I am pleased to welcome you to Genel’s seventh annual results statement, and my first as Chairman.

Looking at Genel from an external perspective it was clear that the Company operated in a challenging environment, but it had demonstrated resilience while retaining real growth potential. In 2017 Genel delivered on that potential, and I am now more confident than ever that, while challenges remain, there is material upside in the Genel portfolio and significant opportunities ahead. As we enter 2018, I believe that we have both the right strategy to take advantage of these and the right management team to deliver on that strategy.

The macroeconomic climate altered again in 2017. On the positive side, the increase in the oil price helped to boost cash flows from our producing assets, and also provided a more solid basis for the economy of the Kurdistan Region of Iraq (‘KRI’). The unfortunate events in the KRI in the last quarter of the year and the subsequent material reduction in KRG exports caused by these events significantly disrupted the status quo. However, despite the decrease in oil exports, the KRG continued to demonstrate its ability and willingness to make payments, and Genel has received payments for sales on a monthly basis since September 2015. This has enabled investment by the Company to continue.

Financial strength underpinning opportunity

Genel is currently on a sound financial footing, and continues to generate significant free cash flow, something boosted by the signing of the Receivable Settlement Agreement (‘RSA’) in August 2017. The successful refinancing in December then provided a bedrock from which we can move forward with a proactive growth strategy.

There are exciting opportunities available for cash-generative, proactive companies, and the Board and management carried out a comprehensive review of Genel strategy in order to define a clear and focused roadmap to creating significant shareholder value. The refreshed strategy focuses on the creation of shareholder value, providing growth opportunities while retaining a firm focus on prudent financial planning.

Our strategy builds on our core strengths – a robust and cash-generative asset portfolio, technical and commercial expertise, and our ability to leverage regional relationships and manage risk in complex areas. These were key drivers behind our excellent performance in 2017.

We have significant organic development options within Genel’s KRI portfolio, the financial ability to add assets to the portfolio, and management with the skills and experience to maximise the value of these opportunities.

Focus on cost and capability

Genel will continue to ensure that its cost base reflects the external economic situation. Total general and administrative cash costs were more than halved from 2014 to 2016, and the Company continues to ensure the most appropriate structure and cost base from which to grow and deliver maximum value to stakeholders. In 2017 reductions were made to remuneration at all levels, and executive remuneration brought into line with comparable listed E&P companies.

Side by side with this focus on cost, is a focus on operational capability. There has been significant change at both Board and management levels over the last twelve months or so, and we have a high-quality team working well together. As we go forward, the Board will work to ensure continuity at management level and provide leadership on management succession.

In 2017 we welcomed Tim Bushell and Martin Gudgeon to the Board, adding relevant skills and experience. Both have made a significant contribution to the healthy dynamics and strong processes confirmed by an external board evaluation review carried out at the end of 2017.

Despite changes to personnel, one thing that has not changed has been the Company-wide focus on health, safety, and responsible operations. Genel takes pride in its operations and strives for positive community impact, and it was pleasing to see a repeat of 2016’s performance in achieving no lost-time incidents, while reducing incidents of primary containment loss to a single minor event. I would like to thank all employees across our operations for their ongoing vigilance and hard work.

Focus in 2018

We have a robust balance sheet, a clear strategy, and the correct team to implement it. Going through 2018 we look forward to clearly setting out the growth potential that this provides, and as such plan for active capital market engagement.

We appreciate the patience and confidence that our shareholders have shown in Genel over the last few turbulent years, and hope that the successes seen in the second half of 2017, and our strong financial position, provide renewed confidence that we can deliver on our plans to add material shareholder value in the years to come.


Delivering on our focus

2017 was a successful year for Genel Energy. We went into the year with a clear focus, and took proactive steps to deliver our key goals.

I was pleased to welcome Esa Ikaheimonen as Chief Financial Officer and Bill Higgs as Chief Operating Officer, both of whom bring the qualities and experience to help us deliver on these goals.

A primary aim was to maximise the generation of free cash flow from our producing oil assets in the KRI. In the year, monthly payments totalling $263 million were received from the KRG, with our ongoing focus on cost and disciplined capital allocation helping to convert this into $142 million in free cash flow, before bond interest payments.

This figure was boosted in the second half of the year by additional proceeds received under the RSA. This was a very positive deal for Genel, and helped to fulfil our second aim for 2017 of converting the receivable into cash generation.

Writing off the past receivable in favour of increased future cash flows helped to simplify our balance sheet while significantly increasing cash flow. Under the RSA, Genel receives override payments of 4.5% of Tawke gross PSC revenues for the five year period from 1 August 2017 to 31 July 2022, while capacity building payments ('CBP') on the profit share element of our Tawke entitlement are eliminated over the entire life of the field.

This definitive agreement was the positive culmination of a constructive dialogue with the KRG, and has already provided significant benefits to Genel, with the promise of more to come. $19 million was received in 2017 under the override, and the elimination of CBP resulted in a $7 million benefit to Genel in Q4.

Cash-generative oil assets

The receipt of 4.5% of gross Tawke PSC revenues means that the positive performance of Peshkabir adds material cash flow to Genel. The successful Peshkabir-2 well was followed by the equally successful Peshkabir-3 well, and production of c.5,000 bopd from the former was commingled with the latter to end the year at a very consistent 15,000 bopd from the field. Working with the operator, we will continue to focus on Peshkabir in 2018.

The Peshkabir-4 well spud in February, and will potentially be followed by a further five wells in 2018. Field production is expected by the operator to reach 30,000 bopd by the summer and

continue to ramp up in the second half of the year. This is very encouraging, and when added to the robust production from the main Tawke field, highly cash-generative.

Despite operational activity at the Tawke PSC being focused on maximising the potential of Peshkabir, general Tawke field production was solid in 2017. Work done at Taq Taq also provided encouragement. While the field declined year-on-year as anticipated, production was relatively stable in the second half of 2017, with the TT-29w well providing a positive result in December 2017. The well encountered a deeper free water level and more extensive oil bearing cretaceous reservoirs on the northern flank of the field than previously forecast, and potentially opens up further development avenues.

This well result, and the stabilisation of production, led to a 12% reserves replacement at Taq Taq for 2P, and 40% reserves replacement at the higher confidence 1P level, as upwards technical revisions partially offset the five million barrels of production in 2017. 2P reserves more than doubling at Peshkabir also bolstered reserves at the Tawke PSC, and prudent expenditure will allow ongoing cash generation from across the Genel portfolio for years to come.

Opportunities for growth

Prudent capital allocation is at the core of everything that we do, and we spend each dollar in a way that creates the greatest value for our shareholders. The most cost-effective way of spending is to invest in our producing assets, as money spent is cost-recoverable. In 2017, 66% of our capital expenditure was spent on our producing fields. As payments are received monthly, this is currently recovered through cash receipts within approximately 90 days.

This focus on expenditure and value creation, with a cash investment of $345 million in buying back bonds at below par reducing gross debt from $675 million to $300 million, helped to reduce our net debt as at end-2017 to $135 million. This was a 44% reduction year-on-year from the end-2016 figure of $241 million, providing Genel with the financial flexibility to take advantage of new opportunities. We are focused on finding those opportunities that promise to add to our financial strength, and capital allocation will remain biased on near-term cash generation.

Some of these near-term cash-generative opportunities can be found within the Genel portfolio. The significant increase in high-value Bina Bawi 2C oil resources we saw in the recent CPR by RPS Consultants offers a tangible opportunity. As Bina Bawi oil is both high-quality and in close proximity to the Taq Taq field and associated export infrastructure, it is an attractive near-term development candidate for the Company.

This would be the beginning of tangible value crystallisation of our Bina Bawi and Miran assets, another key strategic focus for Genel. In 2017 we moved towards this goal through the finalisation of PSC amendments together with the Gas Lifting Agreements ('GLA's) for both fields, incorporating the commercial terms as announced in the term sheets signed in 2015. This provided certainty and allowed the progression of talks with potential partners, which were slowed down following developments in the KRI in the second half of 2017. Entering 2018 we are now in a stronger position to move the project forward, with upstream materially de-risked. The updated CPRs, announced in January 2018 confirmed a c.40% increase in gross combined 2C resources to almost 15 Tcf. Even at a 1C level, gross raw gas resource estimates are significantly higher than the gas volumes agreed under the Gas Lifting Agreements.

The extension to the schedule for satisfying the conditions precedent, signed in January 2018, provided further clarity over the timetable, and the bolstered financial position of the Company means that we are well-positioned to progress with the building blocks of value creation. We have optionality about the progression of the project, with the ability to take the upstream towards FID with 100% ownership, should this be the best way to maximise shareholder value. Expenditure will remain prudent, as the upstream development matches the progress of the midstream. An extended well test at Bina Bawi will then provide valuable data on well deliverability and gas

composition, and we will proactively engage with potential farm-in partners at the best possible time and terms for Genel. Bina Bawi and Miran remain a significant opportunity for Genel, and we will work to convert that opportunity into shareholder value in 2018.

Genel will also make appropriate expenditure on our African exploration assets, which offer longer- term opportunities. Following the completion of over 3,000 km of 2D seismic in Somaliland, which was purchased from the government, the first in this highly prospective area for over 25 years, we are excited about the long-term opportunities and see significant geological potential on the Genel acreage position. This 10-month seismic acquisition project was completed with an impeccable HSE and security record. There were successful elections held in 2017, and increasing international investment is opening up opportunities. Of particular note is DP World’s almost half a billion dollar investment in the port at Berbera, which being just 100 km from our licence offers a clear route to market. 2018 will see the processing of the Somaliland seismic, which will then guide the optimal strategy to maximise future value.

Offshore Morocco the conversion of our well commitment to a 3D seismic acquisition programme was both cost-effective for Genel and will help materially de-risk the Sidi Moussa licence. It is worth noting ENI’s recent acquisition of the licence block adjacent to Sidi Moussa.


Genel is a highly cash-generative business, and we expect to continue to generate significant free cash flow throughout 2018. Prudent expenditure will progress the significant near-term opportunities within the portfolio, and our sound financial position allows us to explore the possibility of bolstering our portfolio and adding to the strength of our core assets. I look forward to updating all stakeholders on our progress throughout the year.


Production and sales

Net production in 2017 averaged 35,200 bopd. While production at the Tawke PSC increased, boosted by the contribution from the Peshkabir field, overall production declined year-on-year as Taq Taq continued its decline in the first half of 2017. The implementation of an active well intervention programme and contributions from new well stock arrested this decline in H2 2017.

Exports by the KRG were consistent in 2017, and almost all Tawke PSC production was exported via Ceyhan. Approximately two thirds of Taq Taq production was exported by the KRG, with the remainder being delivered to the local Bazian refinery, for which Genel invoices at the same price under the terms of the February 2016 payment mechanism.

Consistent and predictable payments throughout the year allowed for a proactive drilling programme to be carried out across Genel assets. Drilling activity was targeted in line with our capital allocation policy, aiming for cost-effective activity for the greatest reward. As such, a significant focus was placed on the appraisal of Peshkabir, which promised and delivered near-term cash generation. Activity at Taq Taq in the year led to a stabilisation of production, with the TT-29w then contributing to an uplift at the end of the year.

Average production in 2018 to date has been 33,300 bopd, in line with guidance.

Reserves and resources

At 31 December 2017, Genel’s proven (1P) and proven plus probable (2P) net working interest reserves totalled 97.1 MMbbls and 150.0 MMbbls respectively. 1P and 2P reserves increased by 9.8 MMbbls and 2.2 MMbbls, when compared to the figures as at 31 December 2016, after adjustment for 2017 production of 12.9 MMbbls. This is a reserves replacement of 75% for the high-confidence

proven reserves, and yields a reserves to production ratio of greater than seven years for 1P, and greater than 11 years for 2P reserves.

Genel has booked 504 MMbbls gross (126 MMbbls net working interest) 2P reserves at the Tawke PSC, as a 133% increase in 2P reserves at Peshkabir to 75 MMbbls helped to offset a downward technical revision of 36.6 MMbbls at the Tawke field, leading to an overall increase in Tawke PSC 2P reserves of 7.6 MMbbls. The reserves booked are in line with the operator’s Annual Statement of Reserves, but do not include those associated with the proposed enhanced oil recovery project at the Tawke field. While the Company sees merit in the proposal, further definition of the project is required prior to FID and reserves booking.

Taq Taq gross 2P reserves were largely unchanged, estimated at 54.7 MMbbls, compared to 59.1 MMbbls as of 28 February 2017, with the difference being production in the intervening period, partly offset by a small reserves increase, a result of stabilising production and the integration of the TT-29w well into the field model.

Bina Bawi gross 2C light (c.45◦ API) oil resources are estimated by RPS at 37.1 MMbbls, compared to 13 MMbbls as of July 2013. Due to the high-quality of the Bina Bawi oil, and given the value of these barrels, this represents an attractive near-term development candidate.

A decline in estimated Miran West gross 2C heavy (c.15◦ API) oil resources from the previously carried 52 MMbbls to 18.0 MMbbls is based on Management estimates that include a downwards revision for the removal of matrix contribution from the Shiranish reservoir, a lesson learnt from Taq Taq.

Genel’s 2C raw gas resources at Miran and Bina Bawi were lifted c.40% to 14,792 Bscf, a figure which excludes associated condensate volumes attributable to the upstream partners of 137 MMbbls. Even on a 1C gross raw gas resources basis, estimated at 6,618 Bcf, volumes at Miran and Bina Bawi greatly exceed those agreed under the Gas Lifting Agreement.

Reserves and resources development

  Remaining reserves (MMboe)  Resources (MMboe) 
  Contingent  Prospective 
1P  2P  1C  2C  Best 
Gross  Net  Gross  Net  Gross  Net  Gross  Net  Gross       Net      
31 December 2016  380  100  597  161  1,082  1,037  2,142  1,937  3,923  2,556 
Production  (47)  (13)  (47)  (13) 
Acquisitions and disposals  (7)  (3)  (78)  (31)  (109)  (44) 
Extensions and discoveries 
New developments  11  62  15 
Revision of previous estimates  27  (53)  (13)  231  205  958  909  (132)  46 
31 December 2017  371  97  559  150  1,306  1,239  3,022  2,813  3,682  2,549 

KRI assets

Genel’s KRI oil assets provide the cash generation that drives the business and provides the bedrock for future growth. As such, maximising the cash flow from these assets is a key priority for Genel. With capital expenditure being cost-recoverable, they are also the focus of the majority of Genel activity.

Tawke PSC (25% working interest)

Tawke PSC production averaged 109,050 bopd in 2017, a slight increase year-on-year, with aggregate production from the Peshkabir-2 and Peshkabir-3 wells contributing 3,590 bopd to this figure.

In line with Genel’s focus to invest in those areas that provide the best returns, the focus of drilling in 2018 will be on the Peshkabir field. A total of six Peshkabir wells are planned to be drilled this

year, and field production is expected by the operator to reach 30,000 bopd by summer and continue to ramp up in the second half of the year. Following the signing of the RSA, these are highly cash-generative barrels for Genel.

The first of the six wells, Peshkabir-4, is currently drilling, with results expected in Q2.

At the Tawke field, the Tawke-48 well was recently completed and is being brought onto production. The focus in the first half of the year is on workovers and rebuilding of the Tawke field reservoir models to incorporate the learning from the 2017 campaign. Further drilling will be weighted to the back half of 2018 and will be agreed by the joint venture after completion of the model rebuild.

Taq Taq (44% working interest, joint operator)

Production in 2017 averaged 18,050 bopd, with production stabilising in the second half of the year, with Q4 2017 averaging 14,035 bopd, in line with Q3 2017 of 14,080 bopd. The implementation of a proactive well intervention and production optimisation programme helped slow the rate of production decline in the first half of 2017. The successful TT-29w well then led to a small increase in production, and average production in December 2017 of 15,068 bopd was the highest monthly average in H2.

The TT-29w well encountered a deeper free water level and more extensive oil bearing cretaceous reservoirs on the northern flank of the field than previously forecast. The results of the well are still being analysed, and will drive the 2018 drilling programme. The well intervention programme, focused on the provision of artificial lift and water shut off in existing wells, will continue throughout 2018. Drilling activity is set to resume in the second half of the year, with two wells scheduled targeting the flanks of the field.

Bina Bawi and Miran fields (100% working interest, operator)

In line with our capital allocation strategy, there was limited field activity in 2017, as Genel focused on our producing oil assets. The finalisation of PSC amendments and Gas Lifting Agreements was an important step, reasserting the opportunity ahead, which was then furthered in 2018 through the uplift in mean raw 2C gas resources to c.15 Tcf.

The gas development is in an almost unique position as an upstream project without volume or price risk. As such, Genel will focus its efforts in 2018 to characterise the remaining uncertainties, namely surface facilities and drilling capital expenditure, well deliverability and design, and operating costs. This work will be combined with that carried out by Baker Hughes in 2017, to deliver an optimised Field Development Plan that will help define the roadmap to unlocking the value of the assets.

Later in the year, Genel expects to undertake an extended well test of Bina Bawi-4, which will provide valuable data on well deliverability and gas composition.

The significant increase in gas resources detailed in the updated CPR helped to build momentum behind the development, and Genel will now maintain upstream readiness in alignment with progress on the midstream, engaging with potential farm-in partners for upstream participation at an optimal time to secure maximum value for Genel shareholders.

Exploration and appraisal


Onshore Somaliland, the acquisition of 2D seismic data on the SL-10B/13 (Genel 75% working interest, operator) and Odewayne (Genel 50% working interest, operator) blocks began in March 2017. This was acquired from the Somaliland government, after completing in January 2018 having acquired c.3,150 km in total. This was the first time that seismic has been obtained in this highly prospective area for over 25 years. Evidence of a thick Mesozoic rift basin provided encouraging results, and led to the targeted infill 2D seismic acquisition on the SL-10B/13 block. Processing of

the data has commenced. Seismic interpretation and the associated development of a prospect inventory, in turn guiding the optimal strategy to maximise future value, is expected to be completed by year-end.

Genel's prior commitment to drill one well on the Sidi Moussa licence (Genel 75% working interest, operator), offshore Morocco, has been replaced by an obligation to carry out a 3D seismic campaign across the acreage, significantly reducing anticipated expenditure. Planning is ongoing, with seismic acquisition set to begin in 2018, which is expected to materially de-risk the licence.


In 2017, Genel’s strong free cash flow generation, the RSA, and the successful reduction and extension of the Company’s debt has built a robust and simplified balance sheet.

Proceeds received in 2017 increased significantly from the prior year as a result of, first, the temporary CBP offset arrangement in the first half of the year and, subsequently, the RSA that was signed in August. The RSA formalised enhanced cash flow generation from Tawke PSC production into enduring contractual terms. In line with our focus on rigorous capital discipline, spend was prioritised on cash-generative producing assets, with non-production related capital expenditure minimised.

This increased cash flow generation, which the Company expects to sustain, together with the reduction in net debt and refinancing, leaves Genel well positioned for future growth.

Through the year, the Company has taken proactive and determined steps to deliver on the three key financial priorities that were set out in last year’s annual report:

  • Continue to work with the KRG for timely and full payments for oil deliveries, and for a transparent mechanism for reconciliation and recovery of the receivable
  • Continue to focus on all aspects of the Company’s cost base, whether capital, operating or administrative expenditure
  • Manage liquidity appropriately ahead of the 2019 maturity of the Company’s bond debt The key milestones in achieving these objectives are further explained in the following paragraphs.

In March, the Company’s confidence in consistent payments enabled the continuation of its proactive approach to rightsizing its debt by buying back $252.8 million nominal value of its bonds at an average 13% discount to par. This resulted in an accounting gain of $32.6 million, a reduction in total debt from $675.0 million to $421.8 million and a reduction in interest costs from over $50 million last year to just over $30 million.

In June, the Company received formal endorsement that capacity building payments due on proceeds received in the final quarter of 2016 and the first half of 2017 should be offset against the overdue receivable balance – this represented a cash benefit of $46.9 million.

In August, the Company successfully negotiated the RSA, converting its overdue receivable balance, which prior to the RSA was being recovered through an agreed 5% incremental take of gross revenues from the Tawke and Taq Taq PSCs, into contractual rights to benefit from increased shares of future revenue from the Tawke PSC (both the Tawke and Peshkabir fields). This benefit is received by way of:

(1)    the overriding royalty interest (‘ORRI’) of 4.5% of Tawke PSC gross revenue, which continues until July 2022; and

(2)    the waiver of CBP due on all proceeds received under the Tawke PSC, throughout the life of the licence.

Cash received from the RSA in 2017 amounted to $26.0 million, relating to sales made in August, September and October. The RSA also confirmed that the KRG reverted to making entitlement payments in line with the contractual terms of the PSC, rather than under the proxy mechanism that was used in 2016 and for the first half of 2017.

In December, the Company reduced its debt from $421.8 million to $300 million and extended the maturity from May 2019 to December 2022. The extended bonds pay a coupon of 10%.

Throughout the year the Company retained its focus on its cost base and disciplined capital allocation. Capital investment was focused on cost recoverable investment in production at Tawke and Taq Taq in order to maximise the benefit of the improving oil price and the improved cash flow generation explained above. As a result 74% of operating and capital expenditure incurred in the year was cost recoverable and consequently was received within circa three months of being incurred.

Operating expenditure at our producing assets was already one of the lowest in the world at around

$2/bbl – in 2017 the average operating expense per barrel remained at around the same level.

This careful cost management, together with the positive impact of the CBP offset in the first half of the year, the RSA in the second half of the year, and reduced interest cost, has resulted in a significant increase in free cash flow generation, which increased from $59 million in 2016 to $142 million in the current year. The Company aims to continue the generation of significant free cash flow in future years through an ongoing efficient allocation of capital, a focus on cost discipline, and the ongoing enhanced cash flows from the Tawke PSC.

The strong cash flow, together with the buyback of debt at a discount to par, has resulted in a reduction in net debt from $241 million at the start of the year to $135 million at year-end. This deleveraging of the balance sheet and increased financial capacity increases the resilience of the business and the options available to the Company going forward.

The fourth financial priority for 2017 was to secure equity and debt investment into the Miran and Bina Bawi licences. The Company has made further progress in evaluating the options to maximise the value of these licences for Genel; options which have increased as a result of the Company’s improved cash generation. Further appraisal work is now planned in order to evaluate the optimal timing for farm-out and/or to pursue sole development of near term cash generating opportunities in order to maximise value delivery for shareholders. CPR’s for both licences were updated in early 2018 and confirmed the oil and gas potential of these assets.

For 2018 the financial priorities of the Company are the following:

  • Maintenance of a strong balance sheet and management of liquidity runway throughout the development of the Miran and Bina Bawi fields
  • Continued focus on capital allocation, with prioritisation of highest value investment in assets with ongoing or near-term cash generation
  • Continued focus on cost optimisation and performance management
  • Selective investment in value accretive opportunities that provide visible cash generation and debt capacity

A summary of the financial results for the year is provided below, in addition there is some explanation of the RSA and how it is accounted for in the financial statements.

Financial results for the year

Income statement

Working interest production of 35,200 bopd was significantly reduced compared to last year (2016: 53,300 bopd), principally as a result of decline in Taq Taq through 2016 and in Q1 2017 before stabilising at around working interest production of 6,500 bopd.

Revenue has increased from $190.7 million to $228.9 million. The year-on-year increase has been caused principally by the improved revenue generation of the Tawke PSC following the RSA, which was effective from August, and generated incremental revenue of $48 million. The negative impact of lower production was partly offset by improved Brent oil price.

Production costs of $27.5 million decreased from last year (2016: $35.1 million) primarily as a result of lower use of consumables, personnel costs and well maintenance costs.

The Company reported a net gain arising from the RSA of $293.8 million. The RSA effectively saw the Company write-off its existing overdue receivable balance in exchange for the ORRI, a royalty income stream on Tawke PSC sales, and the waiver of CBPs that otherwise would have been due on proceeds received under the Tawke PSC. The net increase in the value of booked assets on the balance sheet of $293.8 million has been presented on the face of the income statement as ‘Net gain arising from the RSA’ – effectively representing the difference in value between the previous book value of receivables and the discounted cash flow value of the RSA.

The increase in revenue and the net gain arising from the RSA has resulted in EBITDAX increasing to

$475.5 million (2016: $130.7 million).

Depreciation of $83.3m (2016: $127.8 million) was reduced year-on-year as a result of lower production. Amortisation of Tawke intangibles is a new item arising from the RSA and resulted in an expense of $32.8 million.

Exploration expense of net $1.9 million is significantly decreased from last year (2016: $815.1 million), which included impairment of Miran, Bina Bawi and Chia Surkh ($779.0 million) and the accrual of the Morocco minimum work obligation ($33.0 million). The current year expense includes a credit of $16.0 million, which is comprised of the release of about half of the accrual relating to Morocco.

An impairment expense of $58.2 million (2016: $218.3 million) has been recorded in relation to the Taq Taq PSC. Whilst the results of TT-29 and the CPR are encouraging, the Company is still assessing the amount of capital expenditure and related returns that would be required to deliver the CPR 2P production profile.

The Company’s planned capital expenditure for Taq Taq results in a more conservative production profile than the 2P forecast from last year’s CPR, and is also lower than the 2P production profile from the latest CPR announced in February 2018.

General and administrative costs were $21.0 million (2016: $26.0 million), of which cash costs were

$16.9 million (2016: $17.4 million).

Finance income of $4.9 million (2016: $16.2 million) was comprised of $2.7 million discount unwind on trade receivables (2016: $14.2 million) and $2.2 million of bank interest income (2016: $2.0 million). Other finance expense of $28.0 million (2016: $10.0 million) was comprised of $3.7 million premium paid and $16.0 million accelerated discount unwind on redemption of the bonds (2016: $- million) together with non-cash discount unwind expense on liabilities of $8.3 million (2016: $10.0 million).

In the KRI, the Company is either exempt from tax or tax due has been paid on its behalf by the KRG from the KRG’s own share of revenues, resulting in no tax payment required or expected to be made by the Company. Tax presented in the income statement of $1.0 million relates to taxation of the Turkish and UK service companies.

Capital expenditure

Capital expenditure in the year was $94.1 million (2016: $61.2 million). Cost recovered spend on producing assets in the KRI was $59.5 million (2016: $40.3 million) with spend on exploration and appraisal assets amounting to $34.6 million (2016: $20.9 million), principally incurred on the Miran, Bina Bawi and Somaliland PSCs.

Cash flow and cash

Net cash flow from operations was $221.0 million (2016: $131.0 million). This was positively impacted by $86.5 million (2016: $53.9) of proceeds being received for the historic KRG receivable, and $176.8 million (2016: $153.4 million) received for current sales.

Free cash flow before interest was $141.8 million (2016: $59.1 million) and free cash flow after interest was $99.1 million (2016: $7.1 million). After which, $216.7 million (2016: $35.4 million) was used in March to buy back Company bonds with nominal value of $252.8 million (2016: $55.4 million), with a further $128.5 million spent on buying back Company bonds as part of the bond refinancing.

$18.5 million (2016: $19.5 million) of cash is restricted and therefore excluded from reported cash of $162.0 million (2016: $407.0 million). Overall there was a net decrease in cash of $245.1 million compared to a decrease of $47.8 million last year.


Total debt has been reduced from $675.0 million at the start of the year to $300.0 million of bonds maturing in December 2022 – this is reported under IFRS net of capitalised costs at $296.8 million (2016: $648.2 million) and results in net debt of $134.8 million (2016: $241.2million).

The bond has three financial covenant maintenance tests:

Financial covenant  Test  YE2017 
Net debt / EBITDAX  < 3.0  0.3 
Equity ratio (Total equity/Total assets)  > 40%  76% 
Minimum liquidity  > $30m  $162m 

Net assets

Net assets at 31 December 2017 were $1,609.8 million (2016: $1,333.4 million) and consist primarily of oil and gas assets of $1,847.9 million (2016: $1,538.7 million), trade receivables of $73.3 million (2016: $253.5 million) and net debt of $134.8 million (2016: $241.2 million).

Liquidity / cash counterparty risk management

The Company monitors its cash position, cash forecasts and liquidity on a regular basis. The Company holds surplus cash in treasury bills or on time deposits with a number of major financial institutions. Suitability of banks is assessed using a combination of sovereign risk, credit default swap pricing and credit rating.


No dividend (2016: nil) will be paid for the year ended 31 December 2017.

Going concern

The Directors have assessed that the Company’s forecast liquidity provides adequate headroom over forecast expenditure for the 12 months following the signing of the annual report for the period ended 31 December 2017 and consequently that the Company is considered a going concern.

Consolidated statement of comprehensive income

For the year ended 31 December 2017

  Note  2017  2016 
                  $m                         $m 
Revenue    228.9  190.7 
Production costs  (27.5)  (35.1) 
Depreciation and amortisation of oil assets  3                 (116.1)                (127.8) 
Gross profit  85.3  27.8 
Exploration expense  (1.9)  (815.1) 
Impairment of property, plant and equipment  (58.2)  (218.3) 
Impairment of receivables  (191.3) 
General and administrative costs  (21.0)  (26.0) 
Net gain arising from the RSA  10                   293.8                          
Operating profit / (loss)  298.0  (1,222.9) 
 Operating profit / (loss) is comprised of:       
EBITDAX    475.5  130.7 
Depreciation and amortisation  (117.4)  (128.9) 
Exploration expense  (1.9)  (815.1) 
Impairment of property, plant and equipment  (58.2)  (218.3) 
Impairment of receivables  (191.3) 
 Gain arising from bond buy back   15   32.6   19.2 
Finance income  4.9  16.2 
Bond interest expense  (35.5)  (51.0) 
Other finance expense  5                    (28.0)                  (10.0) 
Profit / (Loss) before income tax  272.0  (1,248.5) 
Income tax expense  6                      (1.0)                     (0.4) 
Profit / (Loss) and total comprehensive income / (expense)                271.0              (1,248.9) 
Attributable to:       
Shareholders’ equity                271.0              (1,248.9) 
                271.0              (1,248.9) 
Profit / (Loss) per ordinary share    ¢  ¢ 
Basic  97.1  (448.6) 
Diluted  96.7  (445.6) 

Consolidated balance sheet

At 31 December 2017

  Note  2017  2016 
    $m  $m 
Non-current assets       
Intangible assets  1,282.9  916.7 
Property, plant and equipment  565.0  622.0 
Trade and other receivables  10                         -                172.6 
  1,847.9  1,711.3 
Current assets       
Trade and other receivables  10  78.5  94.6 
Restricted cash  11  18.5  19.5 
Cash and cash equivalents  11                162.0                407.0 
  259.0  521.1 
Total assets             2,106.9            2,232.4 
Non-current liabilities       
Trade and other payables  12  (70.7)  (87.7) 
Deferred income  13  (36.1)  (39.2) 
Provisions  14  (29.3)  (23.0) 
Borrowings  15             (296.8)              (648.2) 
  (432.9)  (798.1) 
Current liabilities       
Trade and other payables  12  (59.4)  (95.3) 
Deferred income  13                  (4.8)                   (5.6) 
  (64.2)  (100.9) 
Total liabilities              (497.1)              (899.0) 
Net assets    1,609.8  1,333.4 
 Owners of the parent       
Share capital  17  43.8  43.8 
Share premium account    4,074.2  4,074.2 
Accumulated losses            (2,508.2)           (2,784.6) 
Total equity    1,609.8  1,333.4 

Consolidated statement of changes in equity

For the year ended 31 December 2017

Sharecapital                 $m                        Sharepremium$m                              Accumulatedlosses$m                    Totalequity$m 
At 1 January 2016  43.8  4,074.2  (1,543.2)  2,574.8 
Loss and total comprehensive expense  (1,248.9)  (1,248.9) 
Share-based payments  7.5  7.5 
At 31 December 2016 and 1 January 2017  43.8  4,074.2  (2,784.6)  1,333.4 
Profit and total comprehensive income  271.0  271.0 
Share-based payments  5.4  5.4 
At 31 December 2017                 43.8                 4,074.2                   (2,508.2)        1,609.8 

Consolidated cash flow statement

For the year ended 31 December 2017

  Note  2017  2016 
    $m  $m 
Cash flows from operating activities       
Profit / (Loss) and total comprehensive income / (expense)    271.0  (1,248.9) 
Adjustments for:       
Gain on bond buy back  15  (32.6)  (19.2) 
Finance income  (4.9)  (16.2) 
Bond interest expense  35.5  51.0 
Other finance expense  28.0  10.0 
Taxation  1.0  0.4 
Depreciation and amortisation  117.4  128.9 
Exploration expense  1.9  815.1 
Impairment of property, plant and equipment  58.2  218.3 
Impairment of receivables  191.3 
Net gain arising from the RSA  10  (293.8) 
Other non-cash items  2.8  7.5 
Changes in working capital:       
Proceeds against overdue receivable    86.5  53.9 
Trade and other receivables    (52.5)  (49.6) 
Trade and other payables and provisions    0.6  (13.2) 
Cash generated from operations    219.1  129.3 
Interest received  2.2  2.0 
Taxation paid    (0.3)  (0.3) 
Net cash generated from operating activities    221.0  131.0 
Cash flows from investing activities       
Purchase of intangible assets    (26.8)  (20.7) 
Purchase of property, plant and equipment    (52.4)  (51.2) 
Restricted cash  11  1.0  (19.5) 
Net cash used in investing activities    (78.2)  (91.4) 
Cash flows from financing activities       
Repurchase of Company bonds  15  (216.7)  (35.4) 
Bond refinancing  15  (128.5) 
Interest paid    (42.7)  (52.0) 
Net cash used in financing activities    (387.9)  (87.4) 
Net decrease in cash and cash equivalents    (245.1)  (47.8) 
Foreign exchange income / (loss) on cash and cash equivalents    0.1  (0.5) 
Cash and cash equivalents at 1 January  11  407.0  455.3 
Cash and cash equivalents at 31 December  11  162.0  407.0 

Notes to the consolidated financial statements

  1. 1.  Summary of significant accounting policies

1.1     Basis of preparation

The consolidated financial statements of Genel Energy Plc (the Company) have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union and interpretations issued by the IFRS Interpretations Committee (together ’IFRS’); are prepared under the historical cost convention except as where stated; and comply with Company (Jersey) Law 1991. The significant accounting policies are set out below and have been applied consistently throughout the period.

Items included in the financial information of each of the Company‘s entities are measured using the currency of the primary economic environment in which the entity operates (the functional currency). The consolidated financial statements are presented in US dollars to the nearest million ($m) rounded to one decimal place, except where otherwise indicated.

For explanation of the key judgements and estimates made by the Company in applying the Company’s accounting policies, refer to significant accounting estimates and judgement on pages 20 and 22.

The Company provides non-Gaap measures to provide greater understanding of its financial performance and financial position. EBITDAX is presented in order for the users of the financial statements to understand the cash profitability of the Company, which excludes the impact of costs attributable to exploration activity, which tend to be one-off in nature, and the non-cash costs relating to depreciation, amortisation and impairments. Free cash flow is presented in order to show the free cash flow generated that is available for the Board to invest in the business. Net debt is reported in order for users of the financial statements to understand how much debt remains unpaid if the Company paid its debt obligations from its available cash. There have been no changes in related parties since last year-end and there are not significant seasonal or cyclical variations in the Company’s total revenues.

Going concern

At the time of approving the consolidated financial statements, the directors have a reasonable expectation that the Company has adequate resources to continue in operational existence for the 12 months from the balance sheet date and therefore its consolidated financial statements have been prepared on a going concern basis.

Foreign currency

Foreign currency transactions are translated into the functional currency of the relevant entity using the exchange rates prevailing at the dates of the transactions or at the balance sheet date where items are re- measured. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of comprehensive income within finance income or finance costs.


The consolidated financial statements consolidate the Company and its subsidiaries. These accounting policies have been adopted by all companies.


Subsidiaries are all entities over which the Company has control. The Company controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Company. They are deconsolidated from the date that control ceases. Transactions, balances and unrealised gains on transactions between companies are eliminated.

Joint arrangements

Arrangements under which the Company has contractually agreed to share control with another party, or parties, are joint ventures where the parties have rights to the net assets of the arrangement, or joint operations where the parties have rights to the assets and obligations for the liabilities relating to the arrangement. Investments in entities over which the Company has the right to exercise significant influence but has neither control nor joint control are classified as associates and accounted for under the equity method.

The Company recognises its assets and liabilities relating to its interests in joint operations, including its share of assets held jointly and liabilities incurred jointly with other partners.


The Company uses the acquisition method of accounting to account for business combinations. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date. The Company recognises any non-controlling interest in the acquiree at fair value at time of recognition or at the non-controlling interest‘s proportionate share of net assets. Acquisition-related costs are expensed as incurred.


Farm-out transactions relate to the relinquishment of an interest in oil and gas assets in return for services rendered by a third party or where a third party agrees to pay a portion of the Company’s share of the development costs (cost carry). Farm-in transactions relate to the acquisition by the Company of an interest in oil and gas assets in return for services rendered or cost-carry provided by the Company.

Farm-in/farm-out transactions undertaken in the development or production phase of an oil and gas asset are accounted for as an acquisition or disposal of oil and gas assets. The consideration given is measured as the fair value of the services rendered or cost-carry provided and any gain or loss arising on the farm-in/farm- out is recognised in the statement of comprehensive income. A profit is recognised for any consideration received in the form of cash to the extent that the cash receipt exceeds the carrying value of the associated asset.

Farm-in/farm-out transactions undertaken in the exploration phase of an oil and gas asset are accounted for on a no gain/no loss basis due to inherent uncertainties in the exploration phase and associated difficulties in determining fair values reliably prior to the determination of commercially recoverable proved reserves. The resulting exploration and evaluation asset is then assessed for impairment indicators under IFRS6.

1.2     Significant accounting judgements, estimates and assumptions

The preparation of the financial statements in accordance with IFRS requires the Company to make judgements and assumptions that affect the reported results, assets and liabilities. Where judgements and estimates are made, there is a risk that the actual outcome could differ from the judgement or estimate made. The Company has assessed the following as being areas where changes in judgements, estimates or assumptions could have a significant impact on the financial statements.

Estimation of future oil price

The estimation of future oil price has a significant impact throughout the financial statements, primarily in relation to the estimation of the recoverable value of property, plant and equipment, intangible assets and the gain arising from the RSA. It is also relevant to the assessment of going concern and the viability statement.

The Company’s forecast of average Brent oil price for future years is based on a range of publicly available market estimates and is summarised in the table below, with the 2022 price then inflated at 2% per annum.

$/bbl  2018  2019  2020  2021  2022 
Forecast  65  63  66  72  74 
Prior year forecast  60  68  72  76  78 

Estimation of hydrocarbon reserves and resources and associated production profiles

Estimates of hydrocarbon reserves and resources are inherently imprecise, require the application of judgement and are subject to future revision. The Company’s estimation of the quantum of oil and gas reserves and resources and the timing of its production and monetisation impact the Company’s financial statements in a number of ways, including: testing recoverable values for impairment; the calculation of depreciation and amortisation; assessing the cost and likely timing of decommissioning activity and associated costs and, in the current year, estimating the values of the intangible assets arising from the RSA. This estimation also impacts the assessment of going concern and the viability statement.

Proven and probable reserves are estimates of the amount of hydrocarbons that can be economically extracted from the Company’s assets. The Company estimates its reserves using standard recognised evaluation techniques. Generally, the Company considers proven and probable reserves (“2P” – generally accepted to have circa 50% probability) to be the best estimate for future production and quantity of oil within an asset when assessing its recoverable amount, and therefore usually forms the basis of calculating

depreciation and amortisation of oil and gas assets and testing for impairment. Assets assessed as 2P are generally classified as property, plant and equipment as development or producing assets and depreciated using the units of production methodology.

Hydrocarbons that are not assessed as 2P are considered to be resources and are classified as exploration and evaluation assets. These assets are expenditures incurred before technical feasibility and commercial viability is demonstrable. Estimates of resources for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and being depleted and are likely to contain estimates and judgements with a wide range of possibilities. These assets are considered for impairment under IFRS6.

Once a field commences production, the amount of proved reserves will be subject to future revision once additional information becomes available through, for example, the drilling of additional wells or the observation of long-term reservoir performance under producing conditions. As those fields are further developed, new information may lead to revisions.

Assessment of reserves and resources 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.

Change in accounting estimate

The Company has updated its estimated reserves and resources with the accounting impact summarised below under estimation of oil and gas asset values.

Estimation of oil and gas asset values

Estimation of the asset value of oil and gas assets is calculated from a number of inputs that require varying degrees of estimation. Principally oil and gas assets are valued by estimating the future cash flows based on a combination of reserves and resources, costs of appraisal, development and production, production profile and future sales price and discounting those cash flows at an appropriate discount rate.

Future costs of appraisal, development and production are estimated taking into account the level of development required to produce those reserves and are based on past costs, experience and data from similar assets in the region, future petroleum prices and the planned development of the asset. However, actual costs may be different from those estimated.

Discount rate is assessed by the Company using various inputs from market data, external advisers and internal calculations. A discount rate of 15% was used for impairment testing of the oil assets of the Company.

In addition, the estimation of the recoverable amount of the Miran/Bina Bawi CGU, which is classified under IFRS as an exploration and evaluation intangible asset and consequently carries the inherent uncertainty explained above, includes the key assessment that the project will progress, which is outside of the control of management and is dependent on the progress of government to government discussions regarding supply of gas an sanctioning of development of both of the midstream for gas and the upstream for oil. Lack of progress could result in significant delays in value realisation and consequently a lower asset value.

Change in accounting estimate – Taq Taq PSC (property, plant and equipment)

Management assessment of Taq Taq production has resulted in a production profile forecast that is less favourable than the 2P production profile generated by the Competent Persons Report in Q1 2017 and also below the profile generated in Q1 2018. At this point in time, with full evaluation of the TT-29 well not completed, capital expenditure in the short term is not forecast to be in line with the CPR and consequently it is not appropriate to use the latest CPR 2P production profile for estimating the value of the asset. This has resulted in a reduction in the recoverable value of the Taq Taq PSC and, when combined with other inputs, such as oil price, results in an impairment expense of $58.2 million. If the 2P production profile from the Q1 2018 CPR had been used, the impairment would have been circa $20 million, circa $40 million lower than the reported impairment expense.

Estimation of netback price and entitlement used to calculate reported revenue, trade receivables and forecast future cash flows

Netback price is used to value the Company’s revenue, trade receivables and its forecast cash flows used for impairment testing and viability. It is the aggregation of realised price less transportation and handling costs. The Company does not have direct visibility on the components of the netback price realised for its oil because

sales are managed by the KRG, but invoices are currently raised for payments on account using a netback price agreed with the KRG. For revenue recognition, the Company has estimated the netback price using the methodology agreed with the KRG for raising invoices for all sales of oil: this results in a $12/bbl discount to Brent for Tawke; $12/bbl discount to Brent for Peshkabir; and a $5/bbl discount to Brent for Taq Taq.

The netback adjustment price agreed with the KRG may change in the future. A $1/bbl difference in netback price would impact current year revenue by circa $3 million and trade receivables by circa $1 million.

Overdue KRG receivables / RSA deal

On 23 August 2017 the Company signed documentation confirming an agreement had been reached with the KRG to put in place a definitive mechanism for the payment to the Company of trade receivables built up from overdue amounts with nominal value of $430 million owed for sales since mid-2014 (‘overdue KRG receivable’) together with nominal value of circa $300 million owed for export sales marketed by SOMO made before 2014, for which the Company has never recognised revenue (’overdue pre-2014 receivable’).

Until the RSA, the Company reported the overdue KRG receivable in the balance sheet at its amortised cost. Key inputs to the assessment of amortised cost were: oil price, production forecast and mechanism for payment. Estimates of oil price and production forecast were based on the inputs used for testing of property, plant and equipment for impairment. When estimating the payment mechanism, although the Company expected either an increase in payments, or an alternative structure to be agreed to accelerate payments, it was assessed that there was not sufficient evidence to support the use of anything other than the existing payment mechanism, which was 5% of the asset level revenue for the Tawke and Taq Taq licences. At the year-ended 31 December 2016, this resulted in the amortised cost being lower than carrying value and consequently the overdue KRG receivable was impaired to its reported book value of $207 million compared to its nominal value of $469 million.

In the current year, the RSA resulted in the overdue KRG receivable balance being waived and in return the Company received: (1) a 4.5% royalty interest on gross Tawke PSC revenue lasting for 5 years (“the ORRI);

(2) the waiver of capacity building payments due on all profit oil received under the Tawke PSC; and (3) the waiver of $4.6 million of amounts due to the KRG.

As the RSA occurred at arm's length, the fair value of the consideration received from the KRG described above, which is recognised as an intangible asset 'Tawke RSA', is considered to be equal to the fair value of the receivables. The Tawke RSA exceeds the carrying amount of receivables at the time of settlement resulting in a gain of $293.8 million being recognised in the profit or loss.

Assessing the fair value of both items requires the estimation of future oil price, production profile and reserves and the appropriate discount rate. Because management assess that the cash flows have the same risk profile as revenue generated from the Tawke PSC, the Company has assessed oil price, production profile, reserves and discount rate using the same methodology as those that would be used for the impairment testing of that property, plant and equipment cash generating unit as explained above, albeit at July 2017 rather than at year-end.

Change in accounting estimate

Previously the present value of trade receivable was estimated using the payment mechanism existing at the time – 5% of asset level revenue from the Tawke and Taq Taq licences. Following the RSA in August 2017, which is explained above, the Company estimated the present value of the overdue KRG receivable based on the new mechanism under which they expect it to be settled, which is a combination of the fair value of the ORRI and the fair value of the CBP waiver. This change in accounting estimate has resulted in the recognition of a gain in the income statement of $293.8 million which represents the difference in carrying value of the overdue KRG receivable at the time of derecognition and the value of the intangible assets for which it was exchanged.

Estimation of cost and timing of decommissioning cost

Key inputs to the reported decommissioning provision is the cost, timing and discount rate to apply to the cash flows. The cost has been estimated based on a report prepared by a third party in April 2017, with timing of costs estimated to be incurred between 2028 and 2038, from the latest life of field plans. The estimated cash flows have been discounted using a discount rate of 4%, which is estimated using a risk free rate adjusted for timing uncertainty.

Business combinations

The recognition of business combinations requires the excess of the purchase price of acquisitions over the net book value of assets acquired to be allocated to the assets and liabilities of the acquired entity. The Company makes judgements and estimates in relation to the fair value allocation of the purchase price.

The fair value exercise is performed at the date of acquisition. Owing to the nature of fair value assessments in the oil and gas industry, the purchase price allocation exercise and acquisition date fair value determinations require subjective judgements based on a wide range of complex variables at a point in time. The Company uses all available information to make the fair value determinations.

In determining fair value for acquisitions, the Company utilises valuation methodologies including discounted cash flow analysis. The assumptions made in performing these valuations include assumptions as to discount rates, foreign exchange rates, commodity prices, the timing of development, capital costs, and future operating costs. Any significant change in key assumptions may cause the acquisition accounting to be revised.

1.3   Accounting policies

The accounting policies adopted in preparation of these financial statements are consistent with those used in preparation of the annual financial statements for the year ended 31 December 2016.


Revenue for petroleum sales is recognised when the significant risks and rewards of ownership are deemed to have passed to the customer, it can be measured reliably and it is assessed as probable that economic benefit will flow to the Company. For exports this is when the oil enters the export pipe, for domestic sales this is when oil is collected by truck by the customer.

Revenue is recognised at fair value. The fair value is comprised of entitlement, which is earned under the terms of the relevant PSC; ORRI, which is earned on 4.5% of gross field revenue from the Tawke licence until July  2022;  and  royalty  income,  which  is  earned  on  the  Taq  Taq  licence  from   the   Company’s  partner. Entitlement has two components: cost oil, which is the mechanism by which the Company recovers its costs incurred on an asset, and profit oil, which is the mechanism through which profits are shared between the Company, its partners and the KRG. The Company pays capacity building payments on profit oil, which becomes due for payment once the Company has received the relevant proceeds. Profit oil revenue is always reported net of any capacity building payments that will become due. Capacity building payments due on Tawke profit oil receipts were waived from August 2017 onwards as part of the RSA. ORRI is calculated as 4.5% of Tawke PSC field revenue. Royalty income is earned on partner sales from the Taq Taq PSC and is recognised when it becomes due or, when received in advance, amortised in line with partner entitlement.

The Company’s oil sales are made to the KRG and are valued at a netback price, which is calculated from the estimated realised sales price for each barrel of oil sold, less selling, transportation and handling costs and estimates to cover additional costs. A netback adjustment is used to estimate the price per barrel that is used in the calculation of entitlement and is explained further in significant accounting estimates and judgements. The Company is not able to measure the tax that has been paid on its behalf and consequently revenue is not reported gross of income tax paid.

Intangible assets

Exploration and evaluation assets

Oil and gas assets classified as exploration and evaluation assets are explained under Oil and Gas assets below.

Other intangible assets

Other intangible assets that are acquired by the Company are stated at cost less accumulated amortisation and less accumulated impairment losses. Amortisation is expensed on a straight-line basis over the estimated useful lives of the assets of between 3 and 5 years from the date that they are available for use.

Intangible assets include the additional income streams arising from the Receivable Settlement Agreement effective from 1 August 2017, in exchange for trade receivables due from KRG for Taq Taq and Tawke past sales, recognised at cost and amortised on a units of production basis in line with the economic lives of the rights acquired, as further explained in Note 8.

Property, plant and equipment

The Company’s oil and gas assets classified as property, plant and equipment are explained under Oil and Gas assets below.

Other property, plant and equipment

Other property, plant and equipment are principally the Company’s leasehold improvements and other assets and are carried at cost, less any accumulated depreciation and accumulated impairment losses. Costs include purchase price and construction cost. Depreciation of these assets commences is expensed on a straight-line basis over their estimated useful lives of between 3 and 5 years from the date they are available for use.

Oil and gas assets

Costs incurred prior to obtaining legal rights to explore are expensed to the statement of comprehensive income.

Exploration, appraisal and development expenditure is accounted for under the successful efforts method. Under the successful efforts method only costs that relate directly to the discovery and development of specific oil and gas reserves are capitalised as exploration and evaluation assets within intangible assets so long as the activity is assessed to be de-risking the asset and the Company expects continued activity on the asset into the foreseeable future. Costs of activity that do not identify oil and gas reserves are expensed.

All lease and licence acquisition costs, geological and geophysical costs and other direct costs of exploration, evaluation and development are capitalised as intangible assets or property, plant and equipment according to their nature. Intangible assets comprise costs relating to the exploration and evaluation of properties which the directors consider to be unevaluated until assessed as being 2P reserves and commercially viable.

Once assessed as being 2P reserves they are tested for impairment and transferred to property, plant and equipment as development assets. Where properties are appraised to have no commercial value, the associated costs are expensed as an impairment loss in the period in which the determination is made.

Development expenditure is accounted for in accordance with IAS 16–Property, plant and equipment. Assets are depreciated once they are available for use and are depleted on a field-by-field basis using the unit of production method. The sum of carrying value and the estimated future development costs are divided by total forecast 2P production to provide a $/barrel unit depreciation cost. Changes to depreciation rates as a result of changes in reserve quantities and estimates of future development expenditure are reflected prospectively.

The estimated useful lives of property, plant and equipment and their residual values are reviewed on an annual basis and changes in useful lives are accounted for prospectively. The gain or loss arising on the disposal or retirement of an asset is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in the statement of comprehensive income for the relevant period.

Where exploration licences are relinquished or exited for no consideration or costs incurred are neither de- risking nor adding value to the asset, the associated costs are expensed to the income statement.

Impairment testing of oil and gas assets is considered in the context of each cash generating unit. A cash generating unit is generally a licence, with the discounted value of the future cash flows of the CGU compared to the book value of the relevant assets and liabilities. As an example, the Tawke CGU is comprised of the Tawke RSA intangible asset, property, plant and equipment (relating to both the Tawke field and the Peshkabir field) and the associated decommissioning provision.

For the Miran PSC and Bina Bawi PSCs, these assets are tested as one CGU (the Miran/Bina Bawi CGU because of the alignment of equity interests and current strong linkage between the two assets when both the Company assesses delivery of its gas to the midstream and similarly when the midstream assesses its commitment of delivery of gas to Turkey. It may be that one asset is prioritised above the other, which would lead to an increase in value to one, increasing its forecast revenue, and an offsetting decrease in value to the other as its forecast revenue would decrease.

Subsequent costs

The cost of replacing part of an item of property and equipment is recognised in the carrying amount of the item if it is probable that the future economic benefits embodied within the part will flow to the Company, and its cost can be measured reliably. The net book value of the replaced part is expensed. The costs of the

day-to-day servicing and maintenance of property, plant and equipment are recognised in the statement of comprehensive income.


Leases in which a significant portion of the risks and rewards of ownership are retained by the lessor are classified as operating leases. Payments made under operating leases (net of any incentives received from the lessor) are expensed to the statement of comprehensive income on a straight-line basis over the period of the lease.

Financial assets and liabilities


The Company assesses the classification of its financial assets on initial recognition as either at fair value through profit and loss, loans and receivables or available for sale. The Company assesses the classification of its financial liabilities on initial recognition at either fair value through profit and loss or amortised cost.

Recognition and measurement

Regular purchases and sales of financial assets are recognised at fair value on the trade-date – the date on which the Company commits to purchase or sell the asset. Loans and receivables are subsequently carried at amortised cost using the effective interest method.

Trade and other receivables

Trade receivables are amounts due from crude oil sales, sales of gas or services performed in the ordinary course of business. If payment is expected within one year or less, trade receivables are classified as current assets otherwise they are presented as non-current assets. Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment.

Cash and cash equivalents

In the consolidated balance sheet and consolidated statement of cash flows, cash and cash equivalents includes cash in hand, deposits held on call with banks, other short-term highly liquid investments and includes the Company’s share of cash held in joint operations.

Interest-bearing borrowings

Borrowings are recognised initially at fair value, net of any discount in issuance and transaction costs incurred. Borrowings are subsequently carried at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the statement of comprehensive income over the period of the borrowings using the effective interest method.

Fees paid on the establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this case, the fee is deferred until the draw-down occurs. To the extent there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalised as a pre-payment for liquidity services and amortised over the period of the facility to which it relates.

Borrowings are presented as long or short-term based on the maturity of the respective borrowings in accordance with the loan or other agreement. Borrowings with maturities of less than twelve months are classified as short-term. Amounts are classified as long-term where maturity is greater than twelve months. Where no objective evidence of maturity exists, related amounts are classified as short-term.

Trade and other payables

Trade and other payables are recognised initially at fair value. Subsequent to initial recognition they are measured at amortised cost using the effective interest method.


Provisions are recognised when the Company has a present obligation as a result of a past event, and it is probable that the Company will be required to settle that obligation. Provisions are measured at the Company’s best estimate of the expenditure required to settle the obligation at the balance sheet date, and are discounted to present value where the effect is material. The unwinding of any discount is recognised as finance costs in the statement of comprehensive income.


Provision is made for the cost of decommissioning assets at the time when the obligation to decommission arises. Such provision represents the estimated discounted liability for costs which are expected to be incurred in removing production facilities and site restoration at the end of the producing life of each field. A corresponding cost is capitalised to property, plant and equipment and subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure attributable to changes in the estimates of the cash flow or the current estimate of the discount rate used are reflected as an adjustment to the provision.


Financial assets and liabilities are offset and the net amount reported in the balance sheet when there is a legally enforceable right to offset the recognised amounts and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously.


Oil and gas assets

The carrying amounts of the Company’s oil and gas assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists then the asset’s recoverable amount is estimated. The recoverable amount of an asset or cash generating unit is the greater of its value in use and its fair value less costs of disposal. For value in use, the estimated future cash flows arising from the Company’s future plans for the asset are discounted to their present value using a pre-tax discount rate that reflects market assessments of the time value of money and the risks specific to the asset. For fair value less costs of disposal, an estimation is made of the fair value of consideration that would be received to sell an asset less associated selling costs. Assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (cash generating unit).

The estimated recoverable amount is then compared to the carrying value of the asset. Where the estimated recoverable amount is materially lower than the carrying value of the asset an impairment loss is recognised. Non-financial assets that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.

Property, plant and equipment and intangible assets

Impairment testing of oil and gas assets is explained above. When impairment indicators exist for other non- financial assets, impairment testing is performed based on the higher of value in use and fair value less costs of disposal. The Company assets' recoverable amount is determined by fair value less costs of disposal.

Financial assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimate of future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortised cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. All impairment losses are recognised as an expense in the statement of comprehensive income. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognised.

Share capital

Ordinary shares are classified as equity.

Employee benefits

Short-term benefits

Short-term employee benefit obligations are expensed to the statement of comprehensive income as the related service is provided. A liability is recognised for the amount expected to be paid under short-term cash bonus or profit-sharing plans if the Company has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee and the obligation can be estimated reliably.

Share-based payments

The Company operates a number of equity-settled, share-based compensation plans. The economic cost of awarding shares and share options to employees is recognised as an expense in the statement of

comprehensive income equivalent to the fair value of the benefit awarded. The fair value is determined by reference to option pricing models, principally Monte Carlo and adjusted Black-Scholes models. The charge is recognised in the statement of comprehensive income over the vesting period of the award.

At each balance sheet date, the Company revises its estimate of the number of options that are expected to become exercisable. Any revision to the original estimates is reflected in the statement of comprehensive income with a corresponding adjustment to equity immediately to the extent it relates to past service and the remainder over the rest of the vesting period.

Finance income and finance costs

Finance income comprises interest income on cash invested, foreign currency gains and the unwind of discount on any assets held at amortised cost. Interest income is recognised as it accrues, using the effective interest method.

Finance expense comprises interest expense on borrowings, foreign currency losses and discount unwind on any liabilities held at amortised cost. Borrowing costs directly attributable to the acquisition of a qualifying asset as part of the cost of that asset are capitalised over the respective assets.


Under the terms of the KRI PSCs, the Company is not required to pay any cash taxes although it is uncertain whether the Company is exempt from tax or whether tax has been paid on its behalf. If tax has been paid on its behalf by the government, then it is not known at what rate tax has been paid due to uncertainty in relation to the workings of any existing tax payment mechanism. It is estimated that the tax rate would be between 0% and 40%. If tax has been paid it would result in a gross up of revenue with a corresponding debit entry to taxation expense with no net impact on the income statement or on cash. In addition, it would be assessed whether any deferred tax asset or liability was required to be recognised.

Segmental reporting

IFRS8 requires the Company to disclose information about its business segments and the geographic areas in which it operates. It requires identification of business segments on the basis of internal reports that are regularly reviewed by the CEO, the chief operating decision maker, in order to allocate resources to the segment and assess its performance.

Related parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the party in making financial or operational decisions. Parties are also related if they are subject to common control. Transactions between related parties are transfers of resources, services or obligations, regardless of whether a price is charged and are disclosed separately within the notes to the consolidated financial information.

New standards

Effective 1 January 2017, the Company has adopted the following standards and amendments to standards: Amendments to IAS 7 - Statement of Cash Flows, Amendments to IAS 12 Income Taxes and Annual Improvements to IFRS Standards 2014-2016 Cycle – financial information for held for sale assets. The adoption of these standards and amendments has had no material impact on the Company’s results or financial statement disclosures.

The Group has not early adopted any standard, amendment or interpretation that was issued but is not yet effective.

The following new accounting standards and amendments to existing standards have been issued by the IASB and endorsed by the EU have yet to be adopted by the Group: IFRS 15 - Revenue from Contracts with Customers (effective 1 January 2018), IFRS 9 - Financial Instruments (effective 1 January 2018), IFRS 16 - Leases (effective 1 January 2019), Amendments to IFRS 2 - Classification and Measurement of Share Based Payments (effective 1 January 2018), Amendments to IAS 40 - Transfers of Investment Property (effective 1 January 2018), and Annual Improvements to IFRS Standards 2014-2016 Cycle – exemptions and investment accounting (effective 1 January 2018).

The Company has assessed the impact of IFRS 15 – Financial Instruments, IFRS 9 – Revenue from Contracts with Customers and IFRS 16 – Leases on its financial statements. IFRS 15 requires a 5-step approach, which is definition of the customer, performance obligations, price, allocation of price into performance obligations

and recognising the revenue when the conditions are met. The Company’s single performance obligation in its contract with customers is the delivery of crude oil at a pre-determined netback adjustment to Dated Brent and the control is transferred to the buyer at the metering point when the revenue is recognised. Therefore, the Company does not expect a material impact when IFRS 15 is adopted. The Company has also reviewed the implications of IFRS 9 when it becomes in effect. The accounting treatment of the buyback of Company bonds and the replacement of its existing bonds maturing 2019 with bonds that mature in 2022, which is described further in Note 15 is in line with the IFRS 9 derecognition of financial liabilities and no further transitional adjustment is required when IFRS 9 is adopted. Further, the impact of changes to impairment model from incurred credit losses to expected credit loss model with the revised standard is considered to be low due to the trade receivables balance being at a normal level, with no issues with payment in the last two years. The Company reviewed its leases under IFRS 16. The leases are mostly short term and/or low value, which will not require significant changes under the new standard. As a result, the Company concluded that these new standards are not expected to have a material impact on the results or financial statements of the Company as at 31 December 2017.

The following new accounting standards, amendments to existing standards and interpretations have been issued but are not yet effective and have not yet been endorsed by the EU: IFRIC 22 - Foreign Currency Transactions and Advance Consideration (effective 1 January 2018), Amendments to IFRS 9 Financial Instruments (effective 1 January 2019), Amendments to IAS 28 – Investments in Associates and Joint Ventures (effective 1 January 2019), Annual Improvements to IFRS Standards 2015-2017 (effective 1 January 2019), IFRIC 23 – Uncertainty over Income Tax Treatments (effective 1 January 2019) and Amendments to IAS 19 – Employee Benefits (effective 1 January 2019).

2.  Segmental information

The Company has three reportable business segments: Oil, Miran/Bina Bawi (‘MBB’) and Exploration (‘Expl.’). Capital allocation decisions for the oil segment are considered in the context of the cash flows expected from the production and sale of crude oil. The oil segment is comprised of the producing fields on the Tawke PSC and the Taq Taq PSC, which are located in the KRI and make sales predominantly to the KRG. The Miran/Bina Bawi segment is comprised of the oil and gas upstream and midstream activity on the Miran PSC and the Bina Bawi PSC, which are both in the KRI – this was previously labelled as the ‘Gas’ segment. The exploration segment is comprised of exploration activity, principally located in Somaliland and Morocco.

For the period ended 31 December 2017

  Oil  MBB  Expl.  Other  Total 
  $m  $m  $m  $m  $m 
Revenue  228.9  228.9 
Cost of sales      (143.6)                   -                      -                   -          (143.6) 
Gross profit  85.3  85.3 
Exploration (expense) / credit  (4.6)  2.7  (1.9) 
Impairment of property, plant and equipment  (58.2)  (58.2) 
Impairment of receivables 
Net gain arising from the RSA  293.8  293.8 
General and administrative costs                 -                   -                      -         (21.0)            (21.0) 
Operating profit / (loss)  320.9  (4.6)  2.7  (21.0)  298.0 
Operating profit / (loss) is comprised of           
EBITDAX  495.2  (19.7)  475.5 
Depreciation and amortisation  (116.1)  (1.3)  (117.4) 
Exploration (expense) / credit  (4.6)  2.7  (1.9) 
Impairment of property, plant and equipment  (58.2)  (58.2) 
Impairment of receivables 
 Gain arising from bond buy back   -   -   -   32.6   32.6 
Finance income  2.7  2.2  4.9 
Bond interest expense  (35.5)  (35.5) 
Other finance expense          (1.1)            (0.1)                     -         (26.8)            (28.0) 
Profit / (Loss) before tax  322.5  (4.7)  2.7  (48.5)  272.0 
 Capital expenditure   59.5   15.5   19.1   -   94.1 
Total assets  1,057.9  860.8  34.0  154.2  2,106.9 
Total liabilities  (84.3)  (75.3)  (32.4)  (305.1)  (497.1) 

Revenue includes $33.9 million (2016: nil) arising from the ORRI. Total assets and liabilities in the other segment are predominantly cash and debt balances. ‘Other’ includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items.

For the period ended 31 December 2016

  Oil  MBB  Expl.  Other  Total 
               $m                $m                      $m               $m                $m     
Revenue  190.7  190.7 
Cost of sales                                                                        (162.9)                   -                          -                    -           (162.9) 
Gross profit  27.8  27.8 
Exploration expense  (582.0)  (233.1)  (815.1) 
Impairment of property, plant and equipment  (218.3)  (218.3) 
Impairment of receivables  (191.3)  (191.3) 
General and administrative costs                                               -                   -                          -          (26.0)             (26.0) 
Operating loss  (381.8)  (582.0)  (233.1)  (26.0)  (1,222.9) 
Operating loss is comprised of           
EBITDAX  155.7  (25.0)  130.7 
Depreciation  (127.9)  (1.0)  (128.9) 
Exploration expense  (582.0)  (233.1)  (815.1) 
Impairment of property, plant and equipment  (218.3)  (218.3) 
Impairment of receivables  (191.3)  (191.3) 
 Gain arising from bond buy back   -   -   -   19.2   19.2 
Finance income  14.3  1.9  16.2 
Bond interest expense  (51.0)  (51.0) 
Other finance expense                                                         (1.1)            (0.1)                          -             (8.8)              (10.0) 
Loss before tax  (368.6)  (582.1)  (233.1)  (64.7)  (1,248.5) 
Capital expenditure  40.3  12.4  8.5  61.2 
Total assets  933.1  872.5  59.7  367.1  2,232.4 
Total liabilities  (93.3)  (97.9)  (47.3)  (660.5)  (899.0) 

Total assets and liabilities in the other segment are predominantly cash and debt balances. ‘Other’ includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items.

3.  Operating costs

  2017  2016 
                  $m                        $m 
Production costs  27.5  35.1 
Depreciation of oil and gas property, plant and equipment  83.3  127.8 
Amortisation of oil and gas intangible assets                  32.8                           
Cost of sales                143.6                    162.9 
Exploration expense                     1.9                    815.1 
Impairment of property, plant and equipment (note 9)                  58.2                    218.3 
Impairment of receivables (note 10)                         -                    191.3 
 Corporate cash costs   16.9   17.4 
Corporate share based payment expense  2.8  7.5 
Depreciation and amortisation of corporate assets                     1.3                        1.1 
General and administrative expenses                  21.0                      26.0 
Exploration expense relates to movements in accruals for costs or obligations relating to licences where 
there is ongoing activity or that have been, or are in the process of being, relinquished. 
 Fees payable to the Company’s auditors: 
2017                   2016 
                $m                       $m 
Audit of consolidated and subsidiary financial statements                                                           0.6                    0.4 
Tax and advisory services                                                                                                                 0.1                    0.1 
Total fees                                                                                                                                             0.7                    0.5 
 4. Staff costs and headcount 
2017                   2016 
                  $m                  $m 
Wages and salaries                                                                                                                            20.6                  20.9 
Social security costs                                                                                                                            1.0                    1.2 
Share based payments                                                                                                                      5.4                    7.5 
                 27.0                  29.6 
Average headcount was: 
  2017        number               2016number 
Turkey  65  73 
KRI  15  19 
UK  17  21 
Somaliland                      24                          24 
                    121                       137 
  1. 5.  Finance expense and income
  2017  2016 
                  $m                         $m 
Bond interest payable  (35.5)  (51.0) 
Unwind of discount on liabilities / premium paid on bond buyback                (28.0)                   (10.0) 
Finance expense                (63.5)                   (61.0) 
Bank interest income  2.2  2.0 
Unwind of discount on trade receivables                     2.7                      14.2 
Finance income                     4.9                      16.2 

Bond interest payable is the cash interest cost of Company bond debt. In December 2017, the Company extended the maturity of $300.0 million of its bonds and redeemed bonds with a nominal value of $121.8 million. This resulted in the derecognition of the existing debt balance and recognition of an expense of $19.7 million, comprised of $3.7 million relating to the premium paid and $16.0 million accelerated discount unwind.

6.  Income tax expense

Current tax expense is incurred on the profits of the Turkish and UK services companies. Under the terms of the KRI PSCs, the Company is not required to pay any cash taxes as explained in note 1.

7.  Earnings per share


Basic earnings per share is calculated by dividing the profit attributable to equity holders of the Company by the weighted average number of shares in issue during the period.

                         2017                       2016 
Profit / (Loss) attributable to equity holders of the Company ($m)  271.0  (1,248.9) 
Weighted average number of ordinary shares – number 1  279,013,724  278,395,190 
Basic earnings / (loss) per share – cents per share  97.1  (448.6) 

1Excluding shares held as treasury shares


The Company purchases shares in the market to satisfy share plan requirements so diluted earnings per share is only adjusted for restricted shares not included in the calculation of basic earnings per share:

                   2017                   2016 
Profit/(Loss) attributable to equity holders of the Company ($m)  271.0  (1,248.9) 
Weighted average number of ordinary shares – number1  279,013,724  278,395,190 
Adjustment for performance shares, restricted shares and share options  1,234,474  1,853,008 
Total number of shares  280,248,198  280,248,198 
Diluted earnings / (loss) per share – cents per share  96.7  (445.6) 

1 Excluding shares held as treasury shares

8.  Intangible assets

Exploration andevaluationassets   TawkeRSA   Other assets    Total 
                        $m                            $m                 $m                     $m 
At 1 January 2016  1,671.0  6.3  1,677.3 
Additions  20.9  20.9 
Discount unwind of contingent consideration  9.8  9.8 
Exploration expense                                                                                    (204.3)                               -                     -             (204.3) 
Balance at 31 December 2016 and 1 January 2017  1,497.4  6.3  1,503.7 
Additions  34.6  0.2  34.8 
ARO provision  2.5  2.5 
Additions (note 10)  425.1  425.1 
Discount unwind of contingent consideration  (22.3)  (22.3) 
Transfer to property, plant and equipment1  (22.8)  (22.8) 
Exploration expense                                                                                     (17.7)                               -                     -                (17.7) 
Balance at 31 December 2017                                                                 1,471.7                      425.1                6.5            1,903.3 
 Accumulated amortisation and impairment         
At 1 January 2016  (4.6)  (4.6) 
Amortisation charge for the period  (1.1)  (1.1) 
Exploration expense                                                                                    (581.3)                               -                     -             (581.3) 
At 31 December 2016 and 1 January 2017                                            (581.3)                               -              (5.7)             (587.0) 
Amortisation charge for the period  (32.8)  (0.6)  (33.4) 
Exploration expense                                                                                                -                                -                     -                        
At 31 December 2017                                                                                (581.3)                      (32.8)              (6.3)             (620.4) 
Net book value         
At 31 December 2017  890.4  392.3  0.2  1,282.9 
At 31 December 2016                                                                                   916.1                               -                 0.6                916.7 

1 Peshkabir asset, which is a part of Tawke PSC, was transferred from intangible assets to property, plant and equipment following the successful results and fast development of the field.

Exploration and evaluation assets are principally the Company’s PSC interests in exploration and appraisal assets in the Kurdistan Region of Iraq, comprised of the Miran (book value: $535.3 million, 2016: $528.6 million) and Bina Bawi (book value: $323.1 million, 2016: $338.4 million) gas assets. Further explanation on oil and gas assets is provided in the significant accounting judgements, estimates and assumptions in note 1. Tawke RSA cash flows arise from the RSA, details of which are provided in note 1 and note 10.

The sensitivities below provide an indicative impact on net asset value of a change in long term Brent, discount rate or production and reserves, assuming no change to any other inputs.


  Bina Bawi /Miran$m   Tawke RSA$m 
Long term Brent +/- $5/bbl  +/- 90  +/- 7 
Discount rate +/- 2.5%  +/- 260  +/- 30 
Production and reserves +/- 10%  +/- 78  +/- 47 
  1. 9.  Property, plant and equipment
  Oil and gasassets  Otherassets   Total 
                     $m                      $m                        $m 
At 1 January 2016  2,558.9  8.9  2,567.8 
Additions                    40.3                          -                      40.3 
At 31 December 2016 and 1 January 2017  2,599.2  8.9  2,608.1 
Addition  59.5  0.5  60.0 
ARO provision  3.6  3.6 
Transfer from intangible assets1  22.8  22.8 
Other                    (1.2)                         -                     (1.2) 
At 31 December 2017  2,683.9  9.4  2,693.3 
Accumulated depreciation and impairment       
At 1 January 2016  (1,632.1)  (6.3)  (1,638.4) 
Depreciation charge for the period  (127.8)  (1.6)  (129.4) 
Impairment               (218.3)                          -                 (218.3) 
At 31 December 2016 and 1 January 2017  (1,978.2)  (7.9)  (1,986.1) 
Depreciation charge for the period  (83.3)  (0.7)  (84.0) 
Impairment                  (58.2)                         -                   (58.2) 
At 31 December 2017            (2,119.7)                  (8.6)             (2,128.3) 
Net book value       
At 31 December 2017  564.2  0.8  565.0 
At 31 December 2016                  621.0                     1.0                   622.0 

1 Peshkabir asset, which is a part of Tawke PSC, was transferred from intangible assets to property, plant and equipment following the successful results and fast development of the field.

Oil and gas assets are the Company’s investments in the Tawke (book value: $477.8 million, 2016: $481.2 million) and Taq Taq PSCs (book value: $86.4 million, 2016: $139.8 million) in the KRI, further explanation on oil and gas assets is provided in the significant accounting judgements, estimates and assumptions in note 1. The Taq Taq PSC has been impaired by $58.2 million – further explanation is provided in note 1. A reasonably possible change in oil price assumptions would result in impairment for the Tawke CGU.

The sensitivities below provide an indicative impact on net asset value of a change in long term Brent, discount rate or production and reserves, assuming no change to any other inputs.


  Taq Taq$m  Tawke$m 
Long term Brent +/- $5/bbl  +/- 2  +/- 16 
Discount rate +/- 2.5%  +/- 5  +/- 40 
Production and reserves +/- 10%  +/- 9  +/- 45 
  1. 10.   Trade and other receivables
  2017  2016 
                   $m                        $m 
Trade receivables – non current  172.6 
Trade receivables – current  73.3  80.9 
Other receivables and prepayments                   5.2                      13.7 
                  78.5                    267.2 

Trade receivables are amounts owed by the KRG for oil sales. The balance owed has reduced significantly in the period as a result of the RSA, which is explained in the significant accounting judgements, estimates and assumptions in note 1. The RSA has resulted in a gain, which is comprised of the following items:

Gain arising from RSA  289.2 
Write-off of trade receivable balance  (425.1) 
Recognition of Tawke intangible assets (ORRI + CBP waiver)  425.1 
Waiver of related obligations arising from RSA                   4.6 
Net gain arising from the RSA               293.8 

The $293.8 million gain increased the book value of overdue receivables to $425.1 million (nominal value of c.

$730 million), which was written off and replaced by the Tawke RSA intangible asset at cost of $425.1 million.

For comparison purposes, assuming that the agreement had been completed in the beginning of 2017, it is estimated that revenue would have been $59.2 million higher this year.


The Tawke RSA intangible asset was recognised at the estimated fair value of its cost, which is sensitive to oil price, discount rate and production profile:

Tawke RSA intangible asset  425.1 
Long term Brent +/- $5/bbl  +/- 10 
Discount rate +/- 2.5%  +/- 28 
Production and reserves +/- 10%  +/- 36 

Ageing of trade receivables

 Period ended 31 December 2017    Year of sale of            amounts overdue               
  Not due          $m                 2017$m              2016$m              2015$m            Total$m     
Trade receivables at 31 December 2017  73  73 

Under the Tawke and Taq Taq PSCs, payment for entitlement is due within 30 days. Since February 2016, a track record of payments being received 3 months after invoicing, which has been assessed as the established operating cycle under IAS1 The fair value of trade receivables is broadly in line with the carrying value.

  Period ended 31 December 2016     Year of sale of            amounts overdue                
  Not due          $m                 2016$m              2015$m              2014$m            Total$m     
Trade receivables at 31 December 2016  17  30  207  254 

Movement on trade receivables in the period

  2017              $m                   2016$m 
Carrying value at 1 January  253.5  422.9 
Revenue excl. royalty income  224.4  186.2 
Net proceeds  (262.7)  (182.8) 
Discount unwind  2.7  14.2 
Impairment  (191.3) 
Net gain arising from the RSA  293.8 
Write-off of overdue KRG receivable in exchange for intangible assets  (425.1) 
Other           (13.3)                    4.3 
Carrying value at 31 December              73.3                253.5 
  1. 11.   Cash and cash equivalents and restricted cash
  2017  2016 
                   $m                        $m 
Cash and cash equivalents  162.0  407.0 
Restricted cash                 18.5                      19.5 
               180.5                    426.5 

Cash is primarily held on time deposit with major financial institutions or in US Treasury. Restricted cash of

$18.5 million relates principally to exploration activities in Morocco.

12.   Trade and other payables

  2017  2016 
                   $m                        $m 
Trade payables  7.5  13.6 
Other payables  17.2  32.3 
Accruals  39.9  49.4 
Contingent consideration                 65.5                      87.7 
               130.1                    183.0 
Non-current  70.7  87.7 
Current                 59.4                      95.3 
               130.1                    183.0 

Payables are predominantly short-term in nature or are repayable on demand and, as such, for these payables there is minimal difference between contractual cash flows related to the financial liabilities and their carrying amount.

Contingent consideration includes a balance of $60.5 million (2016: $82.7 million) recognised at its discounted fair value, which has been re-estimated in the year resulting in a reduction that has been deducted from the book value of Miran/Bina Bawi intangible assets. The nominal value of this balance is $145.0 million and its payment is contingent on gas production at the Bina Bawi and Miran assets meeting a certain volume threshold. The unwind of the discount is capitalised against the relevant intangible assets.

13.   Deferred income

  2017  2016 
                  $m                         $m 
Non-current  36.1  39.2 
Current                   4.8                        5.6 
                 40.9                      44.8 

Deferred income relates to payments received in the past relating to future revenue and is recognised in line with the explanation provided in the revenue section of the accounting policies note.

14.   Provisions

  2017  2016 
                  $m                         $m 
Balance at 1 January  23.0  25.2 
Interest unwind  0.9  0.9 
Additions  6.1  0.6 
Reversal                 (0.7)                       (3.7) 
Balance at 31 December                 29.3                       23.0 
Non-current  29.3  23.0 
Current                        -                            
Balance at 31 December                 29.3                       23.0 

Provisions cover expected decommissioning and abandonment costs arising from the Company’s assets. The decommissioning and abandonment provision is based on the Company’s best estimate of the expenditure required to settle the present obligation at the end of the period discounted at 4%. The cash flows relating to the decommissioning and abandonment provisions are expected to occur between 2028 and 2038.

15.   Borrowings and net debt

    1 Jan 2017   Discount unwind    Buyback    Refinance  Net otherchanges in cash    31 Dec 2017 
  $m  $m  $m  $m  $m  $m 
2019 Bond 7.5%  648.2  22.9  (249.3)  (421.8) 
2022 Bond 10.0%  296.8  296.8 
Cash  (407.0)  216.7  128.5  (100.2)  (162.0) 
Net Debt  241.2  22.9  (32.6)  3.5  (100.2)  134.8 

In March 2017, the Company repurchased $252.8 million nominal value of its own bonds for net cash of

$216.7 million - the purchased bonds had a book value of $249.3 million resulting in Company net debt reducing by $32.6 million.

In June 2017, the Company cancelled these bonds, together with the $55.4 million nominal value of bonds repurchased in March 2016, resulting in a reduction in total outstanding debt from $730 million to $421.8 million.

In December 2017, the Company completed its refinancing of the bonds by reducing the outstanding bond debt from $421.8 million to $300 million by way of an early redemption of $121.8 million for cash of $125.5 million. The maturity of the $300 million nominal value of remaining bonds was extended to December 2022, with some other changes in terms. The refinancing has been accounted for under IAS39 as an extinguishment and consequently has resulted in a net finance expense of $19.7 million, representing the acceleration of the recognition of the associated discount unwind expense and the premium paid for the early redemption of the bonds.

The fair value of the bonds is materially in line with the carrying value.

    1 Jan 2016   Discount unwind    Buyback  Net otherchanges in cash    31 Dec 2016 
                   $m                     $m                 $m                    $m                        $m 
2019 Bond 7.5%  694.1  8.7  (54.6)  648.2 
Cash            (455.3)                          -               35.4                  12.9                (407.0) 
Net Debt               238.8                     8.7            (19.2)                  12.9                   241.2 

In March 2016, the Company repurchased $55.4 million nominal value of its own bonds for net cash of $35.4 million. The purchased bonds had a book value of $54.6 million and consequently Company net debt was reduced by $19.2 million.

16.   Financial Risk Management

Credit risk

Credit risk arises from cash and cash equivalents, trade and other receivables and other assets. The carrying amount of financial assets represents the maximum credit exposure. The maximum credit exposure to credit risk at 31 December was:

  2017$m  2016$m 
Trade and other receivables  76.8  265.8 
Cash and cash equivalents  162.0  407.0 
  238.8  672.8 

Credit risk for trade receivables is explained in note 10 and relates to there being a single customer. There are no receivables overdue at the period end and no provision for doubtful debt has been made. Cash is deposited in US treasury bills or term deposits with banks that are assessed as appropriate based on, among other things, sovereign risk, CDS pricing and credit rating. Credit risk is managed on Company basis.

Liquidity risk

The Company is committed to ensuring it has sufficient liquidity to meet its payables as they fall due. At 31 December 2017 the Company had cash and cash equivalents of $162.0 million (2016: $407.0 million).

Oil price risk

The Company’s revenues are calculated from Dated Brent oil price, and a $5/bbl change in average Dated Brent would result in a profit before tax change of $12 million. Sensitivity of the carrying value of its assets to oil price risk is provided in notes 8 and 9.

Currency risk

As substantially all of the Company’s transactions are measured and denominated in US dollars, the exposure to currency risk is not material and therefore no sensitivity analysis has been presented.

Interest rate risk

The Company reported borrowings of $296.8 million (2016: $648.2 million) in the form of a bond maturing in December 2022, with fixed coupon interest payable of 10% on the nominal value of $300 million. Although interest is fixed on existing debt, whenever the Company wishes to borrow new debt or refinance existing debt, it will be exposed to interest rate risk. A 1% increase in interest rate payable on a balance similar to the existing debt of the Company would result in an additional cost of $3 million per annum.

Capital management

The Company manages its capital to ensure that it remains sufficiently funded to support its business strategy and maximise shareholder value. The Company’s short term funding needs are met principally from the cash flows generated from its operations and available cash of $162.0 million.

17.   Share capital

                     SVOS                         VOS                  TotalOrdinary Shares 
At 1 January 2016 – fully paid1  29,621,685  250,626,513  280,248,198 
Conversion of suspended voting ordinary shares on 24 February 2016 as a result of a sale of 27,339,017 voting ordinary shares by affiliated shareholders to third parties between 22 September 2015 and 13 February 2016  (29,621,685)  29,621,685 
At 31 December 2016, 1 January 2017 and 31December 2017 – fully paid1                             -         280,248,198        280,248,198 

1Voting ordinary shares includes 1,234,474 (2016: 1,853,008) treasury shares

On the sale of voting ordinary shares from an affiliated shareholder to a third party, the affiliated shareholders have a right of conversion of suspended voting ordinary shares to voting ordinary shares in order to maintain their voting ordinary share percentage at just below 30% of the Company. Details of those sales and resulting conversions are set out below.

Between the 22 September 2015 and 13 February 2016 27,339,017 voting ordinary shares were transferred from affiliated shareholders to third parties. On 24 February 2016 29,621,685 suspended voting ordinary shares were converted to ordinary shares in accordance with the terms of the suspended voting ordinary shares.

There have been no changes to the authorised share capital since it was determined to be 10,000,000,000 ordinary shares of £0.10 per share.

Source: EvaluateEnergy® ©2021 EvaluateEnergy Ltd