Full Year Results

RNS Number : 9500A

Genel Energy PLC

30 March 2017

Genel Energy plc

Audited results for the year ended 31 December 2016

Genel Energy plc ('Genel' or 'the Company') announces its audited results for the year ended 31 December 2016.

Results summary ($ million unless stated)

	2016	2015

Production (bopd, working interest)	53,300	84,900
Revenue	190.7	343.9
EBITDAX¹	130.7	279.4
Depreciation	(128.9)	(172.5)
Impairment of exploration assets	(779.0)	(144.1)
Exploration expense	(36.1)	(28.9)
Impairment of property, plant and equipment	(218.3)	(1,038.0)
Impairment of receivables	(191.3)	-
Operating loss	(1,222.9)	(1,104.1)
Cash flow from operating activities	131.0	71.2
Capital expenditure²	61.2	157.2
Free cash flow³	59.1	(179.2)
Cash⁴	407.0	455.3
Net debt⁵	241.2	238.8
KRG receivable	253.5	422.9
EPS (¢ per share)	(448.60)	(417.30)

1. EBITDAX is earnings before interest, tax, depreciation, amortisation, exploration expense and impairment which is operating loss adjusted for the add back of depreciation ($128.9 million), exploration costs written off ($36.1 million) and any impairments ($1,188.6 million)

2. Capital expenditure is additions of intangible assets and additions of property, plant and equipment (oil and gas assets only)

3. Free cash flow 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)

4. Cash reported at 31 December 2016 excludes $19.5 million of restricted cash

5. Net debt is reported debt less cash

Highlights

· The KRG's February 2016 commitment to pay contractor export payments and address outstanding receivables led to a significant increase in cash proceeds during 2016

· $207 million cash proceeds were received in 2016 (2015: $148 million), with Genel generating $59 million in free cash flow (2015: $179 million outflow)

· $67 million in cash proceeds received in 2017 to date, representing full settlement of invoices for 2016 production

· 2016 net production averaged 53,300 bopd (2015: 84,900), at the lower end of revised guidance

· Strong liquidity position at the end of 2016, with unrestricted cash balances of $407 million ($455 million at end-2015)

Outlook

· Signature of amended PSCs and Gas Lifting Agreement in February 2017, with a focus now on concluding negotiations with potential partners

· Continued engagement with the KRG over accelerating the recovery of outstanding receivables

· Tawke 2017 production expected to average around year to date production levels of 111,000 bopd, in line with the Operator's guidance

· Peshkabir-2 Cretaceous discovery in early 2017 - accelerated appraisal and early production planning

· 2017 capex guidance for Taq Taq and Tawke reiterated at $50-75 million. KRI gas business and Africa exploration expenditure also reiterated at c.$50 million

· Bond buy-back announced today (see separate press release)

Murat Özgül, Chief Executive of Genel, said:

"While 2016 was a challenging year at Taq Taq, Tawke continues to produce at a stable level, and regular payments for our oil production in the Kurdistan Region of Iraq helped generate free cash flow in the year. The improved financial position of the Kurdistan Regional Government bodes well for a continuation of these payments.

The signing of definitive agreements in February 2017 allows us to focus on concluding negotiations with potential partners, helping unlock the significant value in our gas assets. We move into 2017 with clear priorities: maximising the value of our oil assets, accelerating the recovery of the receivable, and building on the increased momentum in the development of our gas assets."

Enquiries:

Genel Energy

Phil Corbett, Head of Investor Relations

Andrew Benbow, Head of Public Relations

+44 20 7659 5100

Vigo Communications

Patrick d'Ancona

+44 20 7830 9700

There will be a presentation for analysts and investors today at 1000 BST, with an associated webcast available on the Company's website, www.genelenergy.com.

This announcement includes inside information.

Disclaimer

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.

CHAIRMAN'S STATEMENT

I am pleased to welcome you to Genel Energy's sixth annual results statement.

Last year we spoke of Genel Energy's resilience, and 2016 saw this tested once again. There is now greater stability in the oil industry, and there are opportunities in the Genel portfolio that provide clear reasons for optimism going forward.

Following a difficult 2015 for the entire oil industry, after hitting a low in February 2016, the oil price and operating environment improved across the remainder of the year. For the Kurdistan Region of Iraq, an economy almost entirely dependent on income from its oil exports, these tailwinds have begun to make a difference.

At the start of the year the continued fall in the oil price, coupled with the financial cost of the fight against ISIS and the ongoing lack of budget transfers from Baghdad, placed a significant financial strain on the KRG. Despite this the KRG reaffirmed its commitment to pay exporters based on the contractual entitlements under the Production Sharing Contract governing each licence.

Payments for exports were made throughout the year, with over half a billion dollars paid for gross exports from Taq Taq and Tawke. This resulted in Genel generating free cash flow in the year, a testament to our low cost base and a notable achievement during a difficult time for the industry. The recovery in the oil price facilitates ongoing and regular payments, and provides a basis from which the KRG can turn its attention to progressing the gas development.

Despite the disappointment associated with the further impairments to our balance sheet, there remains significant value potential in the portfolio. Maximising the recovery of oil from our fields, the recovery of our full receivable entitlement, as well as the development of our gas assets, remain key priorities for Genel going forward.

KRI oil assets

Payments throughout 2016 enabled a resumption of investment at Taq Taq and Tawke. Tawke's production performance remains robust, and the asset is now the primary driver of value in Genel's oil business. We will work together with the operator, DNO, as the field continues to generate significant cash flow and value for the partners in years ahead.

The regularity of payments also allowed appraisal drilling at the nearby Peshkabir discovery, with very encouraging initial results. Further appraisal activity is planned for 2017, but we already believe the potential exists to add to our production going forward.

Challenges continue at the Taq Taq field, and production performance has been disappointing. Work done in 2016, and the first two months of 2017, helped to refine our understanding of the remaining potential. This regrettably led to a further write-down of reserves. Additional drilling in 2017, and further investment at the field, will be targeted and appropriate in order to maximise the recovery of remaining oil and generate positive cash flow from operations on an annual basis.

Momentum in the gas business

As we look ahead, of great encouragement is the momentum behind the development of the Miran and Bina Bawi gas fields. Across the industry, 2016 saw accelerated adoption of natural gas usage, with the Middle East recording the strongest regional growth rate. Turkey continues to be one of the largest gas consuming markets in the world, and its willingness to diversify supply away from the 88% it gets from just three countries provides a compelling reason for Turkey and the KRG to drive forward the development of Genel's fields. Miran and Bina Bawi alone have the potential to help meet a meaningful percentage of this demand.

The finalisation of documentation of the Production Sharing Contracts and Gas Lifting Agreements for both fields in February 2017 is a significant milestone.

There remain many challenges to bringing these assets to production, but this is a company-changing opportunity.

Management changes

In order to ensure that we have an appropriate team in place to best deliver on our strategy, Paul Schofield was appointed Chief Operating Officer in May 2016. With thirty five years' management and technical experience encompassing all aspects of the upstream oil and gas business, Paul has been a welcome addition to the team.

Jim Leng and Sir Graham Hearne retired from the Board during 2016, having both made valuable contributions in the establishment of Genel Energy as a respected London-listed company. It was a great pleasure working with them. Simon Lockett was added to the Board, bringing significant knowledge and experience of the oil sector.

Post-period end, we have also welcomed Tolga Bilgin to the Board.

Responsible operations

2016 was the tenth anniversary of Genel Energy drilling at Taq Taq, and we are proud of the work done to support the local community and the KRI as a whole in that time. Since drilling began Taq Taq has been a major source of revenue to the KRG, and we have also invested around $25 million on local community projects, funding over 178 separate projects, as well as currently providing employment to over 400 local people. This work continues, and is a credit to the team in the KRI.

As well as the local community, we take our responsibilities to our employees, contractors, and partners seriously. In 2016 we achieved our target of zero injuries across the business, something that we will strive to emulate in 2017 and beyond.

Outlook

We recognise that 2016 share price performance has been disappointing, and the Board and management team are focused on a strategy to reverse this trend. We retain high-impact onshore exploration opportunities in the portfolio, our oil fields remain cash flow generative, and our gas assets provide a very large scale opportunity that is rare for an independent E&P company.

The regularity of payments for our oil production, coupled with our confidence in them continuing throughout 2017 and beyond, provides us with optionality regarding our financial position. The Board will continue to assess the appropriate capital structure for the business as the framework for our gas development evolves ahead of our 2019 bond refinancing.

With the opportunities available in our portfolio we are confident that we have the strategy and team to grow the business in coming years. We look forward to updating you on progress throughout 2017.

CEO STATEMENT

The last three years have been a difficult period for Genel. The entire E&P sector struggled with a collapsing oil price environment, the Kurdistan Region of Iraq faced a challenging security situation, and our Taq Taq field has suffered from sharp production declines and subsequent reserve downgrades.

While acknowledging the recent disappointing share price performance and cumulative impact of impairments, there are now clearer opportunities for value creation than there have been for some time, driven by the significant opportunity afforded by our gas assets.

Genel has operated in the KRI, and worked alongside the Kurdistan Regional Government, for over a decade. We have acknowledged the difficult times that the KRG has faced economically, and the hard work that has delivered a working payment mechanism for oil exports.

2016 was a watershed for contractor payments, with Genel receiving $207 million in the year, an increase from $148 million in 2015. This led us to generate free cash flow after interest payments for the period, a notable performance at a time of low oil prices.

The willingness and ability of the Kurdistan Regional Government to make regular payments has been welcome at a time when they continue to implement significant austerity measures. Our key focus is the recovery of outstanding receivables. In February 2016 a mechanism was implemented by the KRG through which the receivable would begin to be recovered.

Alongside monthly payments for current sales based on a proxy for contractual PSC entitlement, the KRG agreed to make further payments equivalent to five percent of the monthly netback revenue derived from our producing fields towards the recovery of outstanding entitlements. This was a promising start, and we will continue to work with the KRG to build on this.

As part of its commitment to transparent governance, the KRG has engaged internationally recognised auditing firms to audit the KRI oil sector. This process will also cover unpaid entitlements to oil companies. We are confident that once this audit process is complete, the KRG will remain committed to the full settlement of unpaid entitlements in a timely fashion, and we remain focused on recovering the full amount of our receivable.

Building a transformational gas business

While the oil business continues to generate cash, the gas business is now moving forward towards development. In 2016, hampered by the KRG's economic crisis and regional geopolitical events, progress was slower than expected. Expenditure was accordingly kept to a minimum, with the Pre-FEED and upstream Gas Development Plan studies for the Miran and Bina Bawi fields being the focus of activity.

An updated view on discount rates, and the pace of the development timetable, amongst other factors, has led the Company to reduce the carrying value of the Miran and Bina Bawi fields in the Company's accounts from $1,448 million to $867 million. Despite this write-down, the development of our gas assets represents a huge opportunity for the Company, and for the Kurdistan Region of Iraq as a whole.

Indeed, while 2016 progress was slow, momentum has recently returned to the gas project. We are very pleased to have finalised documentation for the amended Miran and Bina Bawi Production Sharing Contracts and Gas Lifting Agreements. This was an important milestone allowing us to focus on the next step of concluding negotiations with potential partners, which will be the catalyst for pre-development activity to start in earnest in order to move the KRI gas project towards FID.

Our focus in 2017 is the positive conclusion of discussions with a strategic partner for the project, followed by a completion of the midstream agreement and financing of the gas processing facility.

The development of our Miran and Bina Bawi assets has the potential to be transformational for Genel, and we are focused on demonstrating the value proposition to the industry and market. Genel has been central to the Kurdistan Region of Iraq's development as an oil province, and we now look forward to playing the same role in the development of gas exports which will provide a huge boost to the KRG's economy.

Cash generative oil assets

Despite a period of export pipeline downtime in the first quarter of 2016, Tawke field performance remained strong, producing an average of 107,000 bopd in the year. Regular payments allowed investment in the field to restart in the first quarter and continue throughout the year, with the development programme offsetting natural well decline at the field.

Tawke reserve estimates also remain stable, with gross proved plus probable (2P) reserves estimated at 504 MMbbls, compared to 543 MMbbls at year-end 2015, with the difference between that and the prior year being primarily the production in 2016. The Tawke field is now our cornerstone oil asset. It remains a low cost field, and we look forward to working with DNO to maximise the cash generation and value of this key asset in the future. We expect that Tawke production in 2017 will average around year to date production levels, in line with the Operator's current view.

The Peshkabir discovery, under the Tawke PSC, provides potential upside. Following the discovery of Jurassic oil in the Peshkabir‑1 well in 2012, the Peshkabir-2 well, spudded in October 2016, discovered additional oil in the Cretaceous horizon in the southern flank of the field in early 2017.

The Tawke partners are considering a number of options to step up the appraisal of the new discovery, including the drilling of a third well in the second half of 2017. Options are also under consideration for possible early Peshkabir production from Peshkabir-2, incorporating oil transportation to the Tawke field's production facilities at Fishkabur 12 kilometres away.

Taq Taq field performance in 2016 was disappointing. It is both a mature and complex field, where the recent production decline has been faster than expected. Having produced over 200 million barrels of oil, the focus is now on maximising oil recovery while controlling costs, with an overall aim of generating positive cash flow from operations.

There remains continued uncertainty at the field over reserves estimation and future production rates, and the Company has removed guidance for Taq Taq in 2017. Ongoing work at Taq Taq is aimed at maximising oil recovery at Taq Taq and its value to Genel.

In 2016 capital expenditure totalled $61 million across Genel's entire business, a reduction of 30% on initial guidance and almost $100 million down on the prior year. Both fields continue to benefit from low capital and operating costs, and appropriate expenditure remains a key priority for Genel. As such, investment at both Taq Taq and Tawke will keep pace with the payments that we receive.

Development of reserves and resources

The reduction in the Company's 2P reserves at the end of 2016 primarily reflects the updated assessment of Taq Taq 2P reserves, a consequence of a reassessment of the gross rock volume above the oil water contact and fracture porosity in the undrained Cretaceous Shiranish reservoir. The Peshkabir Cretaceous discovery represents the best current prospect for near-term reserve bookings, and we look forward to spudding the Peshkabir-3 appraisal well in the second half of the year.

As with all aspects of the business, our focus on cost and value means we will prioritise those areas of the portfolio that meet our value creation criteria. In this regard, following the drilling of the CS-12 well and a subsequent review of licence prospectivity we have agreed the sale of our 40% interest in the Chia Surkh licence to Petoil, subject to KRG approval. On completion Petoil will pay Genel an initial consideration of $2 million, and an additional $25 million in staged payments contingent on future crude oil production from the Chia Surkh licence.

In line with our strategy to concentrate on low-cost, onshore activity with high-impact potential, we look forward to stepping up activity in Somaliland. The potential is significant - our licences cover an area the size of the entire KRI, with the geology analogous to the proven hydrocarbon province in Yemen. The acquisition of 2D seismic data on the Odewayne and SL-10B/13 blocks is now underway. The data will be acquired as part of a Somaliland government-owned project, with the Company purchasing the associated data from the government. We look forward to maturing prospects towards drilling in the medium term.

The Company is currently in discussions with the Moroccan government over the nature, scope, and timing of the activity related to the maximum future exploration commitment of c.$30 million.

Outlook

We have very clear priorities for the coming year. We will look to maximise recovery from our oil fields while controlling costs, with an overall aim of generating positive cash flow from operations. As ever, we continue to keep a close eye on our financial position, cost control is key across the business, and investment will match the payment environment.

We are encouraged by the frequency of payments in early 2017 and look forward to that continuing over the balance of 2017. We are focused on working with the KRG to accelerate the recovery of the receivable for the oil that we have produced in recent years. The KRG has already stated that an increase in the oil price would lead to an increase in the allocation of netback revenues paid to IOCs each month, and the improvement we have seen in their economic situation bodes well in this regard. The receipt of full cash entitlements remains our focus, although there are other options available.

2017 is a very important year for Genel and especially the development of the gas business. We are working with the KRG and in discussions with counterparties to move things rapidly forward, promising an improved future for Genel and the KRI.

OPERATING REVIEW

Production and sales

Net working interest production in 2016 averaged 53,300 bopd, at the lower end of the Company's 53-60,000 bopd guidance range, which was revised from 60-70,000 bopd in July 2016. Production declined by 37% year-on-year, with the underperformance versus initial guidance primarily a result of greater than anticipated declines at Taq Taq during the year.

Following a hiatus in drilling activity in the second half of 2015, development activity at both Taq Taq and Tawke resumed in early 2016 as the KRG's payment announcement provided confidence of ongoing cash receipts. Investment at Tawke helped to offset natural well declines at the field, with drilling activity at Taq Taq only partially mitigating natural well decline.

During 2016, the majority of production from both fields was exported by the KRG through the KRI-Turkey pipeline. The Taq Taq field also continued to supply the domestic Bazian refinery. Small volumes from both fields were also supplied into the domestic market, principally during downtime in the KRI-Turkey pipeline. All sales routes from both fields are currently invoiced at the same price under the terms of the February 2016 payment mechanism. The Company continues to expect that the majority of production from both fields will be exported by the KRG through the KRI-Turkey pipeline. The KRI domestic market does provide a secondary sales route in the event of meaningful disruptions to KRI-Turkey pipeline uptime.

The Company announced on 28 March 2017 that previous guidance for 2017 Taq Taq gross average production of 24-31,000 bopd had been removed given the ongoing uncertainties in reserves estimation and future production from the field. Consequently, the previous 35-43,000 bopd 2017 production guidance for the Company has also been removed.

Average 2017 year to date production for the Company is 40,000 bopd, representing its net share of Taq Taq and Tawke production.

Reserves and resources

At 31 December 2016, Genel's proven plus probable (2P) net working interest reserves were 161 MMbbls. In the 2015 Annual Report and Accounts, end-2015 2P net reserves were reported as 264 MMbbls. Shortly after publication of the Company's 2015 results, the Tawke operator updated its assessment of end-2015 Tawke reserves and resources, leading to a revision of the Company's end-2015 net 2P reserve position to 242 MMbbls (as stated in the table below). Compared to this latter figure, end-2016 net 2P reserves represent a 33% year-on-year reduction.

Reserves and resources development

	Remaining reserves (MMboe)				Resources (MMboe)
					Contingent				Prospective
	1P		2P		1C		2C
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
31 December 2015	447	123	777	242	1,065	798	2,186	1,552	3,433	1,994
Production	(61)	(19)	(61)	(19)	-	-	-	-	-	-
Acquisitions and disposals	-	-	-	-	-	-	-	-	-	-
Extensions and discoveries	-	-	-	-	-	-	48	12	-	-
New developments	-	-	-	-	-	-	-	-	-	-
Revision of previous estimates	(11)	(5)	(119)	(62)	15	13	(82)	(15)	492	317
31 December 2016	375	99	597	161	1,080	811	2,152	1,549	3,925	2,311

Year-end 2016 gross Tawke 2P reserves were estimated by the operator, DNO ASA, at 504 MMbbls, compared to 543 MMbbls at year-end 2015. The year-on-year change is explained by production in 2016 of 39 MMbbls. Genel's net share of Tawke 2P reserves at end-2016 is 126 MMbbls. At the Peshkabir field, gross 2P reserves at year-end 2016 were unchanged at 32 MMbbls (8 MMbbls net to Genel).

On 29 February 2016, the Company announced that the 2P initial gross recoverable reserves (referred to in the industry as Estimated Ultimate Recovery, or EUR) for the Taq Taq field had been downgraded from 683 MMbbls to 356 MMbbls. On 28 March 2017 the Company announced a further downward revision of Taq Taq 2P EUR to 267 MMbbls, implying gross 2P reserves of 61 MMbbls at year-end 2016 (from 172 MMbbls at year-end 2015). Genel's net share of Taq Taq 2P reserves at year-end 2016 is 27 MMbbls. The further reduction of 2P EUR for Taq Taq is a consequence of a reassessment of the gross rock volume above the oil water contact and fracture porosity in the undrained Cretaceous Shiranish reservoir, following an analysis of reservoir surveillance data and well performance from 2016 and the first two months of 2017.

Following a technical and commercial review of development planning for the Miran oil discovery, and capital allocation decisions across Genel's business, the Company has decided that it would be prudent to move Miran oil volumes from reserves to resources pending clarity on the nature and timing of partner(s) for the KRI gas business. This reduced 2P reserves by 23 MMbbls (net).

At 31 December 2016, Genel's 2C net contingent resources were 1,549 MMboe. In the 2015 Annual Report and Accounts, 31 December 2015 net 2C resources were reported as 1,252 MMboe. Shortly after publication of the Company's 2015 results, the Tawke operator updated its assessment of end-2015 Tawke reserves and resources, resulting in the Company's end-2015 2C net resources position being upgraded to 1,284 MMboe. Furthermore, a decision has been taken to include KRI gas business resource estimates on a raw gas instead of sales gas basis at end-2016. This, amongst other factors, results in a comparable end-2015 2C resource number of 1,552 MMboe. Compared to this latter figure, 31 December 2016 2C net resources were practically unchanged year-on-year.

In 2016, 2C resources attributable to the Chia Surkh PSC were reduced following a block wide assessment of volumes following the CS-12 drilling results. Elsewhere, net Peshkabir 2C resources of 12 MMboe were added following the Cretaceous discovery in early 2017. Net Miran oil 2C resources of 39 MMbbls were added to 2C following their removal from 2P reserves.

KRI oil assets

Tawke PSC (25% working interest)

The Tawke field produced a gross average of 107,000 bopd in 2016, compared to 135,000 bopd in 2015, representing a 21% decline year on year. The majority (98%) of sales from the field were by the KRG through the KRI-Turkey pipeline, with the remainder either being refined at the Tawke field or sold in the domestic market. A total of 33 development wells have been drilled at the field, with 28 of these currently producing. Surface facilities capacity is currently 200,000 bopd with water handling capacity of up to 16,000 bpd.

Following the KRG's February 2016 payment announcement, well intervention and drilling activity at Tawke field recommenced. In the first half of 2016, a workover programme on eight existing wells was implemented, which helped offset natural well declines. In the second half of the year, four new production wells were drilled, three of which were in the shallow Jeribe reservoir and the fourth in the main Cretaceous reservoir. Combined, these development wells added in excess of 10,000 bopd (sum of initial well rates) of new production for investment of $11 million, again offsetting declines from the existing well stock.

The firm programme for Tawke in 2017 includes two further development wells (T-35 and T-21N) in the main Cretaceous reservoir and two shallow Jeribe wells. Workovers of existing wells are also planned. Additional activity in 2017, which includes further Cretaceous and Jeribe wells, is contingent on reservoir performance and regular payments from the KRG for current sales and unpaid entitlements.

The Tawke field has produced an average of 111,000 bopd in 2017 year to date and is currently producing 108,000 bopd. The Company expects that the average Tawke production in 2017 will be around year to date production levels, in line with operator guidance.

Taq Taq (44% working interest, joint operator)

The Taq Taq field produced an average of 60,000 bopd in 2016, a 48% year-on-year decline. A total of 28 development wells have been drilled at the Taq Taq field.

During the year, 68% of field output was sold by the KRG through the KRI-Turkey pipeline, with a further 29% trucked to the domestic Bazian refinery and the remainder sold into the domestic market.

During 2016, three existing production wells were side-tracked. All three sidetracks (TT-27x, TT-07z and TT-16y) were a contributing a total of 9,000 bopd at year-end 2016, most of which was from the TT-16y well. Production rates from the other two sidetracks were lower than anticipated due to the well completions being compromised as a result of drilling and completion problems.

Notwithstanding the contribution from the side-track wells drilled in 2016, Taq Taq field production underperformed expectations in the year, primarily as a rising oil water contact in the Shiranish reservoir reduced the productivity from key wells. Following the analysis of reservoir surveillance data and well performance from 2016 and the first two months of 2017, assumptions on gross rock volume above the oil water contact and fracture porosity in the undrained Shiranish formation were reassessed. This resulted in a further reduction in gross proven and probable (2P) EUR from 356 MMbbls at end-2015 to 267 MMbbls at end-2016. These changes have been supported by McDaniel & Associates in its updated Competent Person's Report (CPR) dated 28 March 2017.

In addition, the Company has been working on an updated Field Development Plan ('FDP') for the Taq Taq field. The scope of this activity has been extended to incorporate the results of recent well performance and will be further refined on the back of future development activity. The strategy at Taq Taq is to maximise recovery from the field while controlling costs, with an overall aim of generating positive cash flow from operations.

The Taq Taq field has produced an average of 28,000 bopd in 2017 to date. The Company has previously stated that the field is reliant on production from a limited number of key wells - production is currently 19,000 bopd from 15 wells, with five of these wells accounting for 77% of field production. Recently, key producing wells have exhibited high rates of decline as a result of water breakthrough, exacerbating the decline rate across the field. Taq Taq field water production is currently 13,000 bpd, representing a water cut of c.40%, significantly less than total water handling capacity of 55,000 bwpd. The Company currently intends to announce Taq Taq field production on a monthly basis going forward.

The TT-29z well is currently drilling at the field and aims to reduce the uncertainty on the free water level in the north flank, which in turn will give better understanding on remaining reserves at this location. TT-29 will also target a shallower Tertiary anomaly which could add new reserves if successful. Operations on the well are scheduled to complete in mid-2017. In addition, the firm 2017 programme for Taq Taq comprises two sidetracks of existing Cretaceous producers, further development of the Pilaspi reservoir and ESP/jet pump installation.

The Company remains of the view that Taq Taq is under drilled on the flanks of the field. Accordingly, an opportunity register, which consists of new development well locations and remedial work on existing wells, is being prepared. The Company is working with its partner in the field to determine the optimal forward development programme. The partners have agreed to further refine the future activity as the results of ongoing development activity are known. Future activity levels at Taq Taq are also subject to the continuation by the KRG of regular payments for crude sales and historical receivables.

KRI gas assets

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

In 2016, Genel continued to work towards the commercialisation of the significant resource base at the Miran and Bina Bawi fields, currently estimated at 11 tcf (gross 2C basis) of raw gas. The focus during 2016 was on finalising the upstream PSCs and terms of gas supply to the midstream processing facilities. At the asset level, the focus was on preliminary engineering studies, with both the upstream Gas Development Plan and midstream pre-FEED awarded in mid-2016.

In February 2017, the Company announced that it had finalised Amended and Restated Production Sharing Contacts and Gas Lifting Agreements for the Miran and Bina Bawi fields. As a result, Genel's interests in both Miran and Bina Bawi increased to 100% (from 75% and 80% respectively). These changes are not reflected in year-end 2016 reserves and resources as they occurred after the reporting date of 31 December 2016.

The GLAs contain conditions precedent, which, inter alia, include the execution of final agreements on the midstream gas processing facilities and pipeline transportation, the execution of the financing documents and the completion of updated competent person's reports for Miran and Bina Bawi.

Both Genel and the KRG have the option to terminate the GLAs by February 2018. If the conditions precedent are not satisfied within 12 months, the KRG has a right to terminate the GLAs. In the event of termination, and a subsequent failure to conclude new gas lifting agreements within one year period, the KRG can also terminate the Miran and Bina Bawi PSCs. During the three year period following such a termination, Genel would have a right of first refusal to participate in the development of the Miran and Bina Bawi gas fields with a 49% working interest on the same terms offered to any third party. With this part of the gas documentation finalised, Genel is now focused on the next step of concluding negotiations with potential partners.

In mid-2016, the Company awarded the pre-Front End Engineering Study ('FEED') contract for the midstream facilities to Fluor and Gas Development Plan ('GDP') to Baker Hughes RDS. The midstream pre-FEED was completed in early 2017 and has identified a number of potential sites for the processing facilities at both Miran and Bina Bawi. In addition, an option to process gas from Miran and Bina Bawi at one plant located close to the Taq Taq field is under consideration. The next step in the midstream development planning entails a full FEED study and Environmental Impact Assessment.

The GDP, which has now been completed, has focussed on dynamic reservoir modelling, production profiles, drilling locations, well completion concepts and the subsurface reservoir management plan for Miran and Bina Bawi. The GDP is broadly supportive of the findings of the existing third party CPRs for Miran and Bina Bawi with respect to the level of contingent resources at both fields.

Capital expenditure estimates for the upstream development and midstream processing facilities are still at a very preliminary stage. In particular, further sub-surface work may be needed at both Miran and Bina Bawi to refine the distribution of resources across the fields, potential well locations, and well deliverability. The Company envisages that this activity, if implemented, would be funded as part of a farm-down of its 100% upstream interest in both fields. As a result, the Company believes that is appropriate that updated cost estimates for the gas project await finalisation of the partnership structure for both the upstream and midstream.

In 2016, the Company formally relinquished its 40% interest in the Dohuk licence.

Exploration and appraisal

Cost effective onshore E&A activity, both in the KRI and internationally, is an important part of the Company's growth strategy. This strategy yielded tangible success in early 2017 with the Cretaceous discovery at Peshkabir-2. Further appraisal of Peshkabir will be the focus in 2017, in addition to committed activity on the Africa exploration portfolio.

KRI

The Peshkabir-2 well was spudded in October 2016 to both appraise the 2012 Jurassic discovery and explore Cretaceous prospectivity 18 km to the west of the Tawke field. In January 2017, the Tawke partners announced that oil had been discovered in the Cretaceous, with the well flowing at a stable rate of 3,800 bopd of 28° API oil. The well has reached a planned depth of 3,500 metres and was completed to facilitate rigless testing of the Jurassic, during March and April 2017. The Tawke partners plan to appraise the Cretaceous discovery with the Peshkabir-3 well later in 2017, as well as investigate the potential for early production from Peshkabir-2 via the existing Tawke facilities. The Tawke operator's initial estimate of gross 2C contingent resources for the Peshkabir Cretaceous discovery is 48 MMboe.

The CS-12 exploratory appraisal well on the Chia Surkh licence spudded on 30 March 2016, with a view to refining the resource potential of the licence after the successful CS-10 and CS-11 wells in 2013. Genel was carried on its share of the CS-12 well costs by its partner Petoil. The well was drilled to a measured depth of 2,500 metres ahead of time and budget. The primary Oligocene and Eocene objectives proved to be water bearing. A testing programme in the previously proven Miocene section established a modest level of oil resources.

Following consideration of the well results and a review of the prospectivity on the licence, the Company signed a Sales and Purchase Agreement in January 2017 to transfer its 40% interest in the Chia Surkh licence to its partner, Petoil, which remains subject to approval by the Ministry of Natural Resources. Petoil will pay Genel an initial consideration of $2 million, and an additional $25 million in staged payments contingent on future crude oil production from a commercial development at Chia Surkh.

As part of a portfolio high-grading exercise, the Company's 40% working interest in the Ber Bahr licence is in the process of relinquishment.

Africa

Onshore Somaliland, the acquisition of 2D seismic data on the Odewayne (Genel 50%, operator) and SL-10B/13 (Genel 75%, operator) blocks commenced in March 2017. The data will be acquired as part of a Somaliland government owned speculative 2D seismic acquisition project, with the Company purchasing the associated data from the government. This new data is expected to deliver a step change in the company's understanding of this highly prospective but underexplored area. The current 2D seismic will satisfy the outstanding commitment in the current exploration phase on both licences. Any further activity beyond the current exploration phase is discretionary.

The Company is currently in discussions with the Moroccan government over the nature, scope and timing of the activity related to the maximum future exploration commitment of c.$30 million.

CHIEF FINANCIAL OFFICER'S REVIEW

Results summary ($ million unless stated)

	2016	2015

Production (bopd, working interest)	53,300	84,900
Revenue	190.7	343.9
EBITDAX¹	130.7	279.4
Depreciation	(128.9)	(172.5)
Impairment of exploration assets	(779.0)	(144.1)
Exploration expense	(36.1)	(28.9)
Impairment of property, plant and equipment	(218.3)	(1,038.0)
Impairment of receivables	(191.3)	-
Operating loss	(1,222.9)	(1,104.1)
Cash flow from operating activities	131.0	71.2
Capital expenditure²	61.2	157.2
Free cash flow³	59.1	(179.2)
Cash⁴	407.0	455.3
Net debt⁵	241.2	238.8
KRG receivable	253.5	422.9
EPS (¢ per share)	(448.60)	(417.30)

2. Capital expenditure is additions of intangible assets and additions of property, plant and equipment (oil and gas assets only)

3. Free cash flow 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)

4. Cash reported at 31 December 2016 excludes $19.5 million of restricted cash

5. Net debt is reported debt less cash

2016 was a challenging year for the oil sector globally as the price of Brent crude fell to $27/bbl in January before recovering to $55/bbl at the end of the year. These financial challenges were particularly felt by the KRI, with the oil price drop deepening its ongoing economic crisis, while the war with ISIS and the influx of displaced persons had an ongoing impact on the KRG's financial position, and in turn the ability to pay oil companies, including Genel, for both current production and past receivable balances. Despite these challenges significant progress was made during 2016 towards establishing a working payment system and, despite the macro headwinds and the decline in production at Taq Taq, the Company delivered positive free cash flow in the year.

This achievement is due to a combination of factors:

The resumption of regular payments for oil deliveries by the KRI

We received $153.4 million from the KRG for oil delivered by Genel during 2016. Whilst arrears remained outstanding for October, November and December deliveries at the end of the year, and the temporary payment system does not reflect our view of our entitlement, receiving nine payments for both Taq Taq and Tawke sales during 2016 represents significant progress from the 2015 payment backdrop. Since year-end the outstanding arrears for 2016 deliveries have been settled in full.

The initiation of payments towards recovery of the receivable

Total payments of $53.9 million were received by Genel towards repayment of the receivable during 2016. Whilst this initial payment stream is limited in comparison to the amount outstanding, we welcome both the initiation of the payment flows and the KRG's public commitment to increase the quantum as their financial situation improves.

Our low cost asset base and the structure of the Production Sharing Contracts

Our oil assets remain amongst the lowest cost in the world, with operating costs of less than $2.0/bbl in 2016. These low operating costs combine with efficient capital expenditure and appropriate fiscal terms to fairly balance risk and reward at different oil prices between the oil producers and the KRG.

The flexible nature of our capital expenditure

We have flexibility in our capital expenditures and are able to moderate spend on our producing assets to match payment flows, with our capital expenditure accordingly dropping 61% year-on-year. We have no committed capital in our gas business and so have also been able to match spending to the pace of the project.

A continued focus on costs across the business

We have maintained a tight control on costs and continue to ensure that we are structured and resourced appropriately for the external environment. Total headcount has fallen from 223 at the end of 2014 to 129 at the end of 2016, and total general and administrative costs have reduced from $47.0 million to $26.0 million over the same period.

There are elements of the 2016 accounts that warrant further comment:

Impairments to our producing assets

The further reduction in reserves and amended production outlook for Taq Taq, together with an increase in the discount rate applied to our impairment testing as a result of the continued regional financial challenges, has led to an impairment of $180.8 million. Our oil price assumptions for impairment purposes are set out on page 23 and we have provided sensitivities on the two key estimates in the relevant note. The change in discount rate and oil price has also impacted our carrying value of Tawke, resulting in an impairment of $37.5 million.

Impairments to our exploration assets, including the gas business

Genel has invested over $1.4 billion in the acquisition and early development of the Miran and Bina Bawi fields. They represent a very attractive and low cost gas project, close to market with a governmental buyer in place, with the potential to generate significant value for both the KRG and Genel. In light of a revised timing and phasing of the project to reflect slower progress towards a final investment decision than previously anticipated, we have reviewed our carrying value for gas for impairment purposes. This revised timing, together with the revisions to our discount rate and oil price assumptions detailed above, has resulted in an impairment charge of $581.3 million. We have also impaired Chia Surkh by $197.7 million following the CS-12 well result and the expected completion of the subsequent sale of our interest to Petoil.

Impairment to the receivable

We have again provided substantial disclosure around the accounting approach taken in relation to the receivable. Our accounting follows the commercial judgment that the KRG intends to repay the debt and has the capability to do so over time, given a rising oil price. The current mechanism of repayment is linked to a percentage of field netback revenues, and we have used an assumption of this percentage multiplied by forecast field production and oil price to calculate future cash flows and a present value. Given the higher oil price has not yet resulted in a higher percentage being applied by the KRG to field revenue we have reduced our future assumptions to a flat 5% payment for impairment purposes, in line with current levels. This assumption, together with the reduction in forecast Taq Taq production and amended oil prices results in a book impairment of $191.3 million. This has no impact whatsoever on our right to recover the amount due from the KRG, which we are entitled to recover in full, which is the nominal value of $515.9 million.

As we look to 2017 there is a clear set of financial priorities for the Company:

· Continue to press the KRG for timely and full payments for oil deliveries, and for a transparent mechanism for reconciliation and recovery of the receivable

· Secure equity and debt investment into the gas assets, thereby progressing the project towards first gas

· 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

Financial results for the year

Income statement

Production of 53,300 bopd was significantly reduced compared to last year (2015: 84,900 bopd). The combination of lower production, lower oil price and lower capex reducing cost oil by 44%, resulted in a 45% reduction in revenue to $190.7 million (2015: $343.9 million) and a 53% reduction to EBITDAX of $130.7 million (2015: $279.4 million).

Despite lower production, production costs of $35.1 million were broadly in line with last year ($36.3 million) as a result of lower capitalisation of costs due to lower capital activity. Lower production reduced depreciation of oil assets to $127.8 million (2015: $172.0 million).

Impairment of exploration assets includes $581.3 million relating to the Miran and Bina Bawi gas assets and the write-off of $197.7 million relating to the Chia Surkh licence following the drilling of CS-12. In addition, $36.1 million has been accrued relating to expenditures in the current year on exploration activity and exit/relinquishment of exploration licences.

Impairment of property plant and equipment was $218.3 million in 2016 (2015: $1,038.0 million relating to Taq Taq).

General and administrative costs were $26.0 million (2015: $28.7 million).

Finance income of $16.2 million (2015: $1.3 million) was comprised of $14.2 million discount unwind on trade receivables and $2.0 million of bank interest income. Finance expense of $61.0 million (2015: $57.8 million) was comprised of $51.0 million of bond interest together with non-cash discount unwind expense of $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 $0.4 million relates to taxation of the Turkish and UK service companies.

Capital expenditure

Capital expenditure in the year was $61.2 million (2015: $157.2 million). Cost recovered development spend of $40.3 million (2015: $109.2 million) was incurred on the producing assets in the KRI with spend on exploration and appraisal assets amounting to $20.9 million (2015: $48.0 million), principally incurred on the Miran and Bina Bawi PSCs.

Cash flow and cash

Net cash flow from operations was $131.0 million (2015: $71.2 million). This was positively impacted by $53.9 million (2015: nil) of proceeds being received for the KRG receivable, and $153.4 million (2015: $148.2 million) received for current sales. Operating expense, exploration expense and corporate costs amounted to a cash outflow of $56.3 million (2015: $87.0 million), with net payment of creditors resulting in a cash out flow of circa $20 million (2015: inflow circa $10 million).

Cash flows for capital spend on Taq Taq and Tawke was $51.2 million (2015: $120.2 million), with $20.7 million (2015: $130.2 million) cash out flow on exploration and evaluation assets - principally Miran and Bina Bawi.

Free cash flow was $59.1 million compared to a cash outflow of $179.2 million last year. After which, $35.4 million was used to buy back bonds with nominal value of $55.4 million and $52.0 million (2015: $46.1 million) was paid on bond interest expense.

$19.5 million of cash is restricted and therefore excluded from reported cash of $407.0 million (2015: $455.3 million). Overall there was a net decrease in cash of $47.8 million compared to a decrease of $33.0 million last year, which included bond issuance proceeds of $196.2 million.

Debt

The Company has $730.0 million of bonds maturing in 2019 in issuance, of which $55.4 million are held by the company resulting in total externally held debt of $674.6 million (2015: $730.0 million) and net debt of $241.2 million (2015: $238.8 million).

The bond has three financial covenant maintenance tests, which are summarised in the table below:

	YE2016
Net debt / EBITDAX < 3.0	1.8
Equity ratio > 40%	60%
Minimum liquidity > $75m (>$100m from May 2018)	407

Receivables

At 31 December 2016, the reported KRG receivable was $253.5 million (2015: $422.9 million), detailed disclosure is provided on this balance in the significant accounting estimates and judgements section of note 1 and in note 10 to the financial statements.

Net assets

Net assets at 31 December 2016 were $1,333.4 million (2015: $2,574.8 million) and consist primarily of oil and gas assets of $1,538.7 million (2015: $2,602.1 million), trade receivables of $253.5 million (2015: $422.9 million) and net debt of $241.2 million (2015: $238.8 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 held in government gilts or 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.

Dividend

No dividend (2015: nil) will be paid for the year ended 31 December 2016.

Going concern

The directors have assessed that the cash balance held provides the Company with adequate headroom over forecast operational and potential acquisition expenditure for the 12 months following the signing of the annual report for the period ended 31 December 2016 for the Company to be considered a going concern.

Consolidated statement of comprehensive income

For the period ended 31 December 2016

	Notes	2016	2015
		$m	$m

Revenue		190.7	343.9

Production costs	3	(35.1)	(36.3)
Depreciation of oil assets	3	(127.8)	(172.0)
Gross profit		27.8	135.6

Impairment of exploration assets	3	(779.0)	(144.1)
Exploration expense	3	(36.1)	(28.9)
Impairment of property, plant and equipment	3	(218.3)	(1,038.0)
Impairment of receivables	3	(191.3)	-
General and administrative costs	3	(26.0)	(28.7)
Operating loss		(1,222.9)	(1,104.1)


Operating loss is comprised of: EBITDAX		130.7	279.4
Depreciation	3	(128.9)	(172.5)
Impairment of exploration assets	3	(779.0)	(144.1)
Exploration expense	3	(36.1)	(28.9)
Impairment of property, plant and equipment	3	(218.3)	(1,038.0)
Impairment of receivables	3	(191.3)	-


Gain arising from bond buy back	15	19.2	-
Finance income	5	16.2	1.3
Finance expense	5	(61.0)	(57.8)
Loss before income tax		(1,248.5)	(1,160.6)
Income tax expense	6	(0.4)	(1.0)
Total comprehensive expense		(1,248.9)	(1,161.6)

Attributable to:
Shareholders' equity		(1,248.9)	(1,161.6)
		(1,248.9)	(1,161.6)

Loss per ordinary share		¢	¢
Basic	7	(448.60)	(417.30)
Diluted	7	(448.60)	(417.30)

Consolidated balance sheet

At 31 December 2016

	Notes	2016	2015
		$m	$m
Assets
Non-current assets
Intangible assets	8	916.7	1,672.7
Property, plant and equipment	9	622.0	929.4
Trade and other receivables	10	172.6	365.3
		1,711.3	2,967.4
Current assets
Trade and other receivables	10	94.6	79.0
Restricted cash	11	19.5	-
Cash and cash equivalents	11	407.0	455.3
		521.1	534.3

Total assets		2,232.4	3,501.7

Liabilities
Non-current liabilities
Trade and other payables	12	(87.7)	(78.0)
Deferred income	13	(39.2)	(46.0)
Provisions	14	(23.0)	(25.2)
Borrowings	15	(648.2)	(694.1)
		(798.1)	(843.3)
Current liabilities
Trade and other payables	12	(95.3)	(80.6)
Deferred income	13	(5.6)	(3.0)
		(100.9)	(83.6)

Total liabilities		(899.0)	(926.9)


Net assets		1,333.4	2,574.8

Owners of the parent
Share capital	17	43.8	43.8
Share premium account		4,074.2	4,074.2
Retained earnings		(2,784.6)	(1,543.2)
Total equity		1,333.4	2,574.8

Consolidated statement of changes in equity

For the period ended 31 December 2016

	Share capital $m	Share premium $m	Retained earnings $m	Total shareholders' equity $m	NCI $m	Total equity $m
At 1 January 2015	43.8	4,074.2	(392.3)	3,725.7	7.8	3,733.5

Total comprehensive expense	-	-	(1,161.6)	(1,161.6)	-	(1,161.6)
Share-based payments	-	-	2.9	2.9	-	2.9
Release of NCI¹	-	-	7.8	7.8	(7.8)	-
At 31 December 2015 and 1 January 2016	43.8	4,074.2	(1,543.2)	2,574.8	-	2,574.8

Total comprehensive expense	-	-	(1,248.9)	(1,248.9)	-	(1,248.9)
Share-based payments	-	-	7.5	7.5	-	7.5
At 31 December 2016	43.8	4,074.2	(2,784.6)	1,333.4	-	1,333.4

¹The non-controlling interest of $7.8m was released following the expiry of the C shares of Genel Energy Holding Company Limited.

Consolidated cash flow statement

For the period ended 31 December 2016

	Notes	2016	2015
		$m	$m
Cash flows from operating activities
Loss for the period		(1,248.9)	(1,161.6)
Adjustments for:
Gain on bond buy back	15	(19.2)	-
Finance income	5	(16.2)	(1.3)
Finance expense	5	61.0	57.8
Taxation	6	0.4	1.0
Depreciation and amortisation	3	128.9	172.5
Exploration expense		36.1	10.7
Impairment of exploration assets	3	779.0	144.1
Impairment of property, plant and equipment	3	218.3	1,038.0
Impairment of receivables	3	191.3	-
Other non-cash items		7.5	1.1
Changes in working capital:
Proceeds against overdue receivable		53.9	-
Trade and other receivables		(49.6)	(190.2)
Trade and other payables and provisions		(13.2)	(0.9)
Cash generated from operations		129.3	71.2
Interest received		2.0	1.0
Taxation paid		(0.3)	(1.0)
Net cash generated from operating activities		131.0	71.2

Cash flows from investing activities
Purchase of intangible assets		(20.7)	(130.2)
Purchase of property, plant and equipment		(51.2)	(120.2)
Restricted cash	11	(19.5)	-
Acquisition of intangibles		-	(3.9)
Net cash used in investing activities		(91.4)	(254.3)

Cash flows from financing activities
Repurchase of Company bonds	15	(35.4)	-
Net proceeds from bond issuance		-	196.2
Interest paid		(52.0)	(46.1)
Net cash generated from/(used in) financing activities		(87.4)	150.1

Net decrease in cash and cash equivalents		(47.8)	(33.0)
Foreign exchange loss		(0.5)	(0.8)
Cash and cash equivalents at 1st January	11	455.3	489.1
Cash and cash equivalents at 31 December	11	407.0	455.3

Notes to the consolidated financial statements

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") and are prepared under the historical cost convention except as where stated and comply with Jersey company law. The significant accounting policies are set out below and have been consistently applied 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 23 and 25.

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 accounts to understand the underlying 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 use to finance or invest in the business. Net debt is reported in order for users of the accounts 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 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.

Consolidation

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

Subsidiaries

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 neither control nor joint control are classified as associates.

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.

Acquisitions

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-in/farm-out

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 trade receivables. 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 2021 price then inflated at 2% per annum.

$/bbl	2017	2018	2019	2020	2021
Forecast	55	60	68	72	76
Prior year forecast	45	55	65	75	77

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 the carrying value of trade receivables. 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. Proven and probable reserves ("2P" - generally accepted to have circa 50% probability) are used for the assessment of the Company's assets classified as property, plant and equipment and therefore form the basis of testing for depreciation and testing for impairment. Under PRMS definition, 2P reserves only refers to projects that are currently justified for or are already in development.

Hydrocarbons that are not assessed as 2P are considered to be resources and are classified as exploration and evaluation assets. 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.

As a field goes into 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 and estimation of recoverable value of trade receivables.

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. Discount rates used for impairment testing are disclosed in the relevant note.

Change in accounting estimate - Oil assets (property, plant and equipment)

In early 2017, the Company updated its estimation of the reserves and production profiles of Taq Taq and Tawke and commissioned an update of the Competent Persons Report for Taq Taq and of the technical assessment for Tawke. This process has resulted in an amendment to the estimated oil reserves at Taq Taq, where estimated 2P oil reserves were reduced. These reserves assessments were used, together with updated estimates for the other components of the assessment, to perform impairment testing on both assets. In addition, the discount rate used for impairment testing of oil assets has increased from 12.5% to 15%. This increase reflects market perception of a sustained increase in KRI risk given continued political and financial uncertainty. The calculated present values of the assets have resulted in an impairment expense of $218.3 million. Sensitivities to oil price, discount rate and production are provided in note 9.

Change in accounting estimate - Gas assets (intangible assets)

The gas assets have been tested for impairment as a result of a revision to the assumed date of project sanction and phasing together with updated cost estimates. The combination of these factors has resulted in both a reduction and delay in the timing of the cash flows associated with the asset and a consequent reduction in its carrying value. In addition, the estimate of the discount rate used for impairment testing of gas assets has increased from 12.5% to 15%. This increase reflects investor perception of a sustained increase in both Turkish and KRI risk given the continued political and financial uncertainty in both countries. The revised estimates and assumptions have resulted in an impairment expense of $581.3 million. Sensitivities to oil price and discount rate are provided in note 8.

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. The Company does not have direct visibility on the components of the netback price because sales are managed by the KRG, but invoices are currently raised for payments on account using a netback price that has been temporarily agreed with the KRG for the purpose of receiving interim payments. For revenue recognition, the Company has estimated the netback price using the methodology agreed with the KRG for receiving these payments on account.

In line with its IOC payment process that began in September 2015 and was given structure by its announcement on 1 February 2016, the KRG has commenced an audit of cost, production and revenue, including detailed analysis of the components of netback. The Company expects to then reach agreement with the KRG on the appropriate netback adjustment to use in the calculation of the Company's entitlement under the PSC and the resulting trade receivable balance. The audit and reconciliation process began this year, but is not complete and may take some time and conversations with the KRG are ongoing.

The outputs of the reconciliation and settlement process may result in changes to the estimates made by the Company. A $1/bbl difference in netback price would impact current year revenue by circa $4 million and trade receivables by circa $4 million.

Estimation of the recoverable value of trade receivables

Trade receivables of $253.5 million relates to money owed by the KRG principally for export sales that were made after mid-2014. The KRG has stated publicly on a consistent basis that it intends to pay full entitlement following a reconciliation process.

When assessing the nominal value of the receivable the Company has taken into account the latest information on the entitlement it is owed under the PSC for oil that has been sold but not yet paid for. In addition, a calculation has been made for the interest that has accrued on the balance under the terms of the PSC at LIBOR plus 2%. The Company has excluded consideration of any value for export sales that were made before mid-2014 (including exports marketed by the State Oil Marketing Organisation ("SOMO") where payment is outstanding). The total unrecognised receivable balance relating to these sales excluding interest is estimated at circa $300m.

The Company expects that ultimately a reconciliation calculating full entitlement under the terms of the PSC will be agreed with the KRG - this reconciliation will form the basis for calculating amounts owed and for agreeing a mechanism to settle the balance.

Subject to the reconciliation process that has been started by the KRG, the Company is fully confident of its contractual right to the nominal value of the receivable. The Company expectation is that it will be settled with cash, although it is possible that the debt could be settled in a number of ways such as with assets or through an improvement in future contractual terms. The success and pace of the recovery of the balance depends on some or all of a number of factors, including: the financial environment in the KRI and the financial budget of the KRG; oil price; volumes of production from the KRI as a whole as well as from the Company's fields; and ongoing negotiations with regard to various sources of potential finance for the KRI.

On 1 February 2016, the KRG announced an interim mechanism to make monthly payments to the IOCs. The mechanism has two components: the first component is a proxy for monthly entitlement due under the terms of the PSC; the second component is intended to contribute towards repayment of the receivable. The contribution towards the receivable was set at and currently remains at 5% of field revenue. The KRG stated that it intends to increase this percentage as the oil price improves.

Previously when assessing the recoverable value of the receivable, the Company assessed that the percentage of field revenue paid towards the receivable would be increased to 10% from July 2017 and to 20% from January 2018. Whilst the KRG made the current 5% payments relatively consistently over the current year and at half year was broadly up to date, by year-end payments were two months in arrears against the agreed schedule. In addition, contrary to the KRG's stated intention to increase payments, there has been no increase in payments despite oil price increasing from $30/bbl in February 2016 to over $50/bbl. Although the Company expects either an increase in payments, or an alternative structure to be agreed to accelerate the recovery of the receivable, the Company has assessed that there is not sufficient evidence to offset existing contrary evidence and support the use of these expectations as assumptions for impairment testing. Consequently the Company has used the current basis of payment of 5% of field revenue for the purposes of assessing impairment and does not currently take into account the potential for increased payments or alternative methods of settling the balance.

The carrying value of trade receivables is compared to the present value of the forecast monthly contributions using the effective interest rate for the period in which the revenue was recognised. For the period over which the receivable was recognised, the Company has assessed the effective interest rate to be between 8% and 13% using an adjusted prevailing Iraqi government 2028 bond as a proxy, resulting in a blended rate of 8.3%.

Change in accounting estimate

As explained above, for the purposes of impairment testing the Company has assumed the percentage of field revenue paid towards the receivable is fixed at the current mechanism of 5%. When combined with the updated production, reserves and oil price outlook this resulted in an impairment of $191.3 million.

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

Revenue

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 due under the terms of the PSC and royalty income. 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. Royalty income is earned on partner sales from the Taq Taq field 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.

Income tax arising from the Company's activities under production sharing contracts is settled by a third party at no cost and on behalf of the Company. However 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 (predominately software) 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.

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. 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 derisking nor adding value to the asset, the associated costs are expensed to the income statement.

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

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

Classification

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

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.

Decommissioning

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.

Offsetting

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.

Impairment

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.

For the purpose of impairment testing, 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 if the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount. 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 to sell.

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.

Explanation of impairment testing of trade receivables is provided under significant accounting estimates and judgements.

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.

Taxation

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 2016, the Company has adopted the following amendments to standards: Annual improvements to IFRSs 2012-2014 Cycle; Amendments to IFRS 10 Consolidated Financial Statements; Amendments to IFRS 11 Joint Arrangements; Amendments to IFRS 12 Disclosure of Interests in Other Entities; Amendments to IAS 1 Presentation of Financial Statements; Amendments to IAS 16 Property, Plant and Equipment; Amendments to IAS 27 Separate Financial Statements; Amendments to IAS 28 Investments in Associates and Joint Ventures; Amendments to IAS 38 Intangible Assets. The adoption of these amendments has had no material impact on the Company's results or financial statement disclosures.

The following new standards issued by the IASB and endorsed by the EU have yet to be adopted by the Group: IFRS 9 Financial Instruments (effective 1 January 2018); IFRS 15 Revenue from Contracts with Customers (effective 1 January 2018). The Company's review of IFRS15 and IFRS9 is underway but is not yet completed, with neither currently expected to have a material impact on the results or financial statements of the Company.

The following new accounting standards and amendments to existing standards have been issued but are not yet effective and have not yet been endorsed by the EU: IFRS 16 Leases (effective 1 January 2019); Amendments to IFRS 2 Share Based Payments (effective 1 January 2018); Amendments to IAS 7 Statement of Cash Flows (effective 1 January 2017); Amendments to IAS 12 Income Taxes (effective 1 January 2017); Clarifications to IFRS 15 Revenue from Contracts with Customers (effective 1 January 2018). The Company is currently assessing the impact of adopting the new accounting standards noted above on its audited consolidated financial statements. The Group has not early adopted any other standard, amendment or interpretation that was issued but is not yet effective.

2. Segmental information

The Company has three reportable business segments: oil, gas and exploration. Capital expenditure decisions for the oil segment are considered in the context of the cash flows expected from the production and sale of crude oil. The segments have been changed from geographical to asset type in order to better reflect how the Chief Operating Decision Maker now considers the deployment of capital. The oil segment is comprised of the producing assets, Taq Taq and Tawke, which are located in the KRI and make predominantly all sales to the KRG; the gas segment is comprised of the upstream and midstream activity on Miran and Bina Bawi also in the KRI; the exploration segment is comprised of the company's exploration activity, principally located in the KRI, Somaliland and Morocco.

For the period ended 31 December 2016

	Oil	Gas	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	-	(0.7)	(35.4)	-	(36.1)
Impairment of exploration assets	-	(581.3)	(197.7)	-	(779.0)
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)	(1,122.9)

Operating loss is comprised of

EBITDAX	155.7	-	-	(25.0)	130.7
Depreciation	(127.9)	-	-	(1.0)	(128.9)
Exploration expense	-	(0.7)	(35.4)	-	(36.1)
Impairment of exploration assets	-	(581.3)	(197.7)	-	(779.0)
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
Finance expense	(1.1)	(0.1)	-	(59.8)	(61.0)
Loss before tax	(368.6)	(582.1)	(233.1)	(64.7)	(1,248.5)


Capital expenditure	40.6	12.1	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)

For the period ended 31 December 2015

	Restated¹ Oil	Restated¹ Gas	Restated¹ Expl.	Restated¹ Other	Restated¹ Total
	$m	$m	$m	$m	$m

Revenue	343.9	-	-	-	343.9
Cost of sales	(208.3)	-	-	-	(208.3)
Gross profit	135.6	-	-	-	135.6

Exploration expense	-	-	(28.9)	-	(28.9)
Impairment of exploration assets	-	-	(144.1)	-	(144.1)
Impairment of property, plant and equipment	(1,038.0)	-	-	-	(1,038.0)
General and administrative costs	(2.6)	-	-	(26.1)	(28.7)
Operating loss	(905.0)	-	(173.0)	(26.1)	(1,104.1)

Operating loss is comprised of

EBITDAX	305.0	-	-	(25.6)	279.4
Depreciation	(172.0)	-	-	(0.5)	(172.5)
Exploration expense	-	-	(28.9)	-	(28.9)
Impairment of exploration assets	-	-	(144.1)	-	(144.1)
Impairment of property, plant and equipment	(1,038.0)	-	-	-	(1,038.0)

Finance income	-	-	-	1.3	1.3
Finance expense	(0.9)	(0.1)	-	(56.8)	(57.8)
Loss before tax	(905.9)	(0.1)	(173.0)	(81.6)	(1,160.6)


Capital expenditure	109.2	18.3	29.7	-	157.2
Total assets	1,438.2	1,430.5	256.1	376.9	3,501.7
Total liabilities	(105.5)	(87.5)	(23.4)	(710.5)	(926.9)

¹The Company has changed its assessment of segments as explained above and consequently has restated its prior year segmental reporting.

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. All of the oil and gas segments are located in the KRI, with the exploration segment located principally in the KRI, Somaliland and Morocco. All revenue relates to sales made to the KRG.

3. Operating costs

2016

2015

Production costs

35.1

36.3

Depreciation and amortisation of oil and gas assets

127.8

172.0

Cost of sales

162.9

208.3

Impairment of exploration assets

779.0

144.1

Exploration expense

36.1

28.9

Exploration costs

815.1

173.0

Impairment of property, plant and equipment (note 9)

218.3

1,038.0

Impairment of receivables (note 10)

191.3

Corporate cash costs

17.4

26.7

Corporate share based payment expense

7.5

1.5

Depreciation and amortisation of corporate assets

1.1

0.5

General and administrative expenses

26.0

28.7

Depreciation has reduced as a result of a lower carrying value of assets and lower production volumes, offset by an increase in estimates of future capital expenditure. Corporate cash costs have reduced as a result of restructuring programmes. The expensing of the cost of share based payments and depreciation and amortisation of corporate assets has increased as a result of reduced capitalisation because of reduced capital activity. Impairment of exploration assets is explained in note 8. Exploration expense relates to 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:

	2016	2015
	$m	$m
Audit of consolidated financial statements and subsidiary accounts	0.4	0.4
Tax and advisory services	0.1	0.2
Total fees	0.5	0.6

4. Staff costs and headcount

	2016	2015
	$m	$m
Wages and salaries	20.9	38.1
Social security costs	1.2	2.9
Share based payments	7.5	2.7
	29.6	43.7

Reduction in staff costs caused by the restructuring programme have been partly offset by a normalised share based payment charge following the reversal of previously expensed costs due to the lapsing of options associated with leavers. Average headcount was:

2016

2015

Turkey

102

KRI

Somaliland

137

183

5. Finance expense and income

	2016	2015
	$m	$m

Bond interest payable	(51.0)	(50.1)
Unwind of discount on liabilities	(10.0)	(7.7)
Finance expense	(61.0)	(57.8)

Bank interest income	2.0	1.3
Unwind of discount on trade receivables	14.2	-
Finance income	16.2	1.3

Annual bond interest has increased because there has been a full year of interest payable on the $230 million nominal value of bonds issued in March 2015, offset by the buyback of $55.4m nominal value of bonds in March 2016 (see note 15).

6. Taxation

A taxation charge of $0.4 million (2015: $1.0 million) was made in the Turkish and UK services companies. All other corporation tax due has been paid on behalf of the Company by the government from the government's share of revenues and there is no tax payment required or expected to be made by the Company.

7. Earnings per share

Basic

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.

	2016	2015

Loss attributable to equity holders of the Company ($m)	(1,248.9)	(1,161.6)

Weighted average number of ordinary shares - number ¹	278,395,190	278,351,746
Basic earnings per share - cents per share	(448.60)	(417.30)

¹Excluding the purchase of own shares now held as treasury shares

Diluted

Because the Company reported a loss in both years, diluted EPS is anti-dilutive and therefore diluted EPS is the same as basic EPS.

	2016	2015

Loss attributable to equity holders of the Company ($m)	(1,248.9)	(1,161.6)

Weighted average number of ordinary shares - number¹	278,395,190	278,351,746
Adjustment for performance shares, restricted shares and share options	1,853,008	1,896,452
Total number of shares	280,248,198	280,248,198
Diluted earnings per share - cents per share	(448.60)	(417.30)

¹ Excluding the purchase of own shares now held as treasury shares

8. Intangible assets

	Exploration and evaluation assets	Other assets	Total
	$m	$m	$m
Cost
At 1^st January 2015	1,676.6	5.8	1,682.4
Acquisitions	101.0	-	101.0
Additions	48.0	0.5	48.5
Other	2.4	-	2.4
Exploration costs written off	(144.1)	-	(144.1)
Transfer to property, plant and equipment (note 9)	(12.9)	-	(12.9)
Balance at 31 December 2015 and 1^st January 2016	1,671.0	6.3	1,677.3

Additions	20.9	-	20.9
Discount unwind of contingent consideration	9.8	-	9.8
Impairment of exploration assets and transfer to assets held for sale	(199.7)	-	(199.7)
Exploration costs written off	(4.6)	-	(4.6)
Balance at 31 December 2016	1,497.4	6.3	1,503.7


Accumulated amortisation and impairment
At 1^st January 2015	-	(3.1)	(3.1)
Amortisation charge for the period	-	(1.5)	(1.5)
At 31 December 2015 and 1 January 2016	-	(4.6)	(4.6)
Amortisation charge for the period	-	(1.1)	(1.1)
Impairment of gas assets	(581.3)	-	(581.3)
At 31 December 2016	(581.3)	(5.7)	(587.0)

Net book value
At 31^st December 2016	916.1	0.6	916.7
At 31^st December 2015	1,671.0	1.7	1,672.7

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: $528.6 million, 2015: $754.9 million) and Bina Bawi (book value: $338.4 million, 2015: $671.9 million) gas assets; and its interest in licences in Somaliland. Impairment of Miran and Bina Bawi is explained in significant accounting estimates and judgements in note 1. In addition, costs of $197.7 million have been written off in relation to the Chia Surkh licence following the drilling of CS-12. The Company has agreed to sell the asset for an initial consideration of $2.0 million, with further consideration of up to $25 million contingent on the asset achieving specified production milestones - completion is conditional on KRG consent being obtained. The balance has been transferred to assets held for sale within debtors. The net book value of $0.6 million (2015: $1.7 million) of other assets is principally software.

Sensitivities

Miran

Bina Bawi

Brent +/- $10/bbl

69 / (74)

14 / (14)

Discount rate +/- 2.5%

141 / (106)

127 / (93)

9. Property, plant and equipment

	Oil and gas assets	Other assets	Total
	$m	$m	$m
Cost
At 1^st January 2015	2,432.8	9.2	2,442.0
Additions	109.2	-	109.2
Transfer from intangible assets (see note 8)	12.9	-	12.9
Other	4.0	(0.3)	3.7
At 31 December 2015 and 1^st January 2016	2,558.9	8.9	2,567.8

Addition	40.3	-	40.3
At 31 December 2016	2,599.2	8.9	2,608.1

Accumulated depreciation and impairment
At 1^st January 2015	(422.1)	(4.7)	(426.8)
Depreciation charge for the period	(172.0)	(1.6)	(173.6)
Impairment	(1,038.0)	-	(1,038.0)
At 31 December 2015 and 1^st 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	(1,978.2)	(7.9)	(1,986.1)

Net book value
At 31 December 2016	621.0	1.0	622.0
At 31 December 2015	926.8	2.6	929.4

Oil and gas assets comprise principally the Company's share of oil assets at the Taq Taq and Tawke producing fields in the Kurdistan Region of Iraq. Impairment of Taq Taq and Tawke is explained in significant accounting estimates and judgements in note 1.

Sensitivities

	Taq Taq $m	Tawke $m
Carrying value	140	481
Long term Brent +/- $10/bbl	+/- 8	+/- 24
Discount rate +/- 2.5%	+/- 9	+/- 40
Production and reserves +/- 10%	+/- 16	+/- 36

10. Trade and other receivables

	2016	2015
	$m	$m
Trade receivables - non current	172.6	365.3
Trade receivables - current	80.9	57.6
Other receivables and prepayments	13.7	21.4
	267.2	444.3

Trade receivables are monies owed by the KRG for export sales made via the KRG pipeline since mid-2014. The total amount owed by the KRG is estimated to be $515.9 million. For the significant balance that is overdue, caused by non-payment in the past, the Company has calculated its carrying value assuming the percentage of field revenue paid towards the receivable is fixed at the current mechanism of 5%. This assumption has been combined with updated production, reserves and oil price outlook, resulting in the carrying value of trade receivables being $253.5 million. Further information is provided in in the significant accounting estimates and judgements in note 1.

Ageing of trade receivables

Under the terms of the PSC, payment is due within 30 days. Proceeds received are allocated between current and past sales in accordance with the allocation provided by the KRG under the current payment mechanism. Proceeds allocated to the receivable are allocated on a first-in-first-out basis.

Period ended 31 December 2016

Year of sale of

amounts overdue

Not due

2016

2015

2014

Total

Trade receivables at 31 December 2016

207

254

Year-ended 31 December 2015

Year of sale of amounts overdue

Not due

2015

2014

Total

Trade receivables at 31 December 2015

168

232

423

Movement on trade receivables in the period

	2016 $m	2015 $m
Carrying value at 1 January	422.9	232.9
Revenue excl. royalty	186.2	338.6
Net proceeds	(182.8)	(148.2)
Discount unwind	14.2	-
Impairment	(191.3)	-
Other	4.3	(0.4)
Carrying value at period end	253.5	422.9

Recovery of the carrying value of the receivable

Explanation of the assumptions and estimates in testing the KRG receivable for impairment are provided in note 1. The estimated recovery of the carrying value of the receivable based on the existing mechanism is summarised in the following table, which summarises the cash flows arising on payments being received based on 5% of field revenue:

	2017	2018	2019	2020+	Total
Nominal balance recovered in the period	81	36	41	159	317
Net present value of total cash flows					254

Sensitivities

The key sensitivity to the carrying value of trade receivables is the KRG prioritisation of payments of amounts owed to IOCs. The KRG has paid 5% of field revenue through 2016. It is the Company's assumption that the KRG will continue to pay IOCs and if a combination of oil price, KRG production volumes and KRG cost reductions increase KRG cash generation, the KRG will increase the percentage of field revenue paid towards the receivable.

Impairment testing is sensitive to a number of inputs, but principally: the cash generated from field revenue; and the percentage of field revenue paid towards the receivable.

Cash generated from field revenue

Cash generated from field revenue is an output of production volumes in the period, netback derived from Brent oil price and timing of payments. The sensitivity of the carrying value of the receivable to changes in cash generated from field revenue is provided in the table below:

	-20%	-10%	Base	+10%	+20%

Current payment mechanism (5%)	236	245	254	261	269

Percentage of field revenue paid towards the receivable

Impairment testing assumes that the receivable is recovered from a percentage of field revenues. In the downside case this would be nil - either through interrupted production or non-payment by the KRG. The Company have analysed KRG cash generation and estimate that it is possible that the KRG will increase payments towards the receivable in the future. Sensitivity to a stepped increase in payments is provided below:

	% of field revenue paid towards receivable				NPV at different effective interest rates
	2017	2018	2019	2020+	Base less 2.5%	Base 8.3%¹	Base plus 2.5%
Current payment mechanism	5%	5%	5%	5%	269	254	240
Stepped increase in payments	5%	10%	15%	20%	404	378	355

¹The weighted average rate is 8.3%, see significant accounting estimates and judgements for further explanation

Fair value

The fair value of the receivable, based on the current 5% payment mechanism, has been estimated as circa $200 million. The Company assess the KRG receivable to be categorised as Level 3 under IFRS13. Fair value has been calculated using the cash flows assuming 5% of field revenue is paid towards the receivable, from 2P production profiles using the price deck disclosed in the accounting policies note. The resulting cash flows are discounted using the estimated appropriate discount rate for the KRG receivable. The discount rate is estimated by taking the discount rate calculated for current KRG sales using the approach outlined in the significant accounting estimates and judgements section of the accounting policies note and adding an additional premium to reflect the inferior credit quality of the receivable to the KRG's current sales.

Amounts owed for export sales marketed by the Federal Government of Iraq

In addition to the trade receivables owed by the KRG for sales made principally from mid- 2014, the Company is owed monies for export sales that were made prior to mid-2014. These were export sales made through the FGI controlled pipe and consequently the marketing and collection of cash was controlled by the State Oil Marketing Organisation (SOMO) of the FGI. No revenue or receivable has been recognised for these sales because the directors assessed that it was not probable that economic benefit would flow - consequently it is also not considered for the purposes of impairment testing of trade receivables. It is estimated that the Company is owed circa $300 million excluding interest for these export sales.

11. Cash and cash equivalents and restricted cash

	2016	2015
	$m	$m

Cash and cash equivalents	407.0	455.3
Restricted cash	19.5	-
	426.5	455.3

Cash is primarily held on time deposit with major financial institutions or in US Treasury. Restricted cash of $19.5 million is principally related to the Company's exploration activities in Morocco.

12. Trade and other payables

	2016	2015
	$m	$m

Trade payables	13.6	15.1
Other payables	37.3	15.2
Accruals	49.4	50.3
Deferred consideration for Bina Bawi asset	82.7	78.0
	183.0	158.6

Non-current	87.7	78.0
Current	95.3	80.6
	183.0	158.6

The Company's 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.

Deferred consideration includes a balance of $82.7m originally recognised at its discounted fair value. The nominal value of this balance is $145.0 million and its payment is contingent on gas production at the Bina Bawi asset meeting a certain volume threshold. The unwind of the deferred consideration is capitalised against the asset and the balance reassessed at each balance sheet date.

13. Deferred income

	2016	2015
	$m	$m

Non-current	39.2	46.0
Current	5.6	3.0
	44.8	49.0

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

	2016	2015
	$m	$m

Balance at 1^st January	25.2	19.4
Interest unwind	0.9	0.8
Additions	0.6	5.0
Reversal	(3.7)	-
Balance at 31 December	23.0	25.2

Non-current	23.0	25.2
Current	-	-
Balance at 31 December	23.0	25.2

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 2031 and 2039.

15. Borrowings and net debt

	1 Jan 2016	Bond buy back	Discount unwind	Net other changes in cash	31 Dec 2016
	$m	$m	$m	$m	$m
2014 Bond issue maturing May 2019	694.1	(54.6)	8.7	-	648.2
Cash	(455.3)	35.4	-	12.9	(407.0)
Net Debt	238.8	(19.2)	8.7	12.9	241.2

In March 2016, the Company repurchased $55.4 million nominal value of its own bonds for net cash of $35.4m. The purchased bonds had a book value of $54.6 million and have been retained by the Company with it being most likely that the bonds will be cancelled. Consequently Company net debt was reduced by $19.2 million and the $730 million bond is reported net of the $55.4m nominal value of bonds held by the Company. The bond is reported net of unamortised discount on issuance and issuance costs. The fair value of the net $675m bond at 31 December 2016 was $549 million (FY2015: fair value of $730 million bond was $511m).

	1 Jan 2015	New Bond Issue	Merger of bonds	Discount unwind	Net other changes in cash	31 Dec 2015
	$m	$m	$m	$m	$m	$m
2014 Bond issue maturing May 2019	491.4	-	196.2	6.5	-	694.1
2015 Bond issue maturing May 2019	-	196.2	(196.2)	-	-	-
Cash	(489.1)	(196.2)	-	-	230.0	(455.3)
Net Debt	2.3	-	-	6.5	230.0	238.8

On 10 April 2015, the Company issued a new $230m bond with a maturity of May 2019 and an annual coupon rate of 7.5% payable twice annually. The new bond was then merged with the existing $500m bond maturing May 2019, resulting in a merged $730m nominal value bond with a maturity date of May 2019 paying coupon of 7.5%.

16. Financial Risk Management

Financial risk factors

Credit risk

Credit risk is managed on a Company basis, except for credit risk relating to trade receivable balances, which is explained in significant accounting estimates and judgements in note 1.

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 31st December was:

	2016 $m	2015 $m
Trade and other receivables	265.8	440.1
Cash and cash equivalents	407.0	455.3
	672.8	895.4

Credit risk for trade receivables is explained in note 10. There are no other 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.

Liquidity risk

The Company is committed to ensuring it has sufficient liquidity to meet its payables as they fall due. At 31 December 2016 the Company had cash and cash equivalents of $407.0 million (2015: $455.3 million) - see note 11.

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 $648.2 million (2015: $694.1 million) in the form of a bond maturing in May 2019, with fixed coupon interest payable of 7.5% on the nominal value of $675 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 $6.8m 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 $407.0 million.

17. Share capital

	Suspended Voting Ordinary shares	Voting Ordinary shares	Total Ordinary Shares

At 1 January 2015 - fully paid¹	33,538,301	246,709,897	280,248,198

Conversion of suspended ordinary voting shares on 13 February 2015 as a result of a sale of 2,000,000 and 1,400,000 voting ordinary shares by affiliated shareholders to third parties on 10 December 2014 and 16 December 2014 respectively	(3,916,616)	3,916,616	-

At 31 December 2015 and 1 January 2016	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 - fully paid¹	-	280,248,198	280,248,198

1. Voting ordinary shares includes 1,853,008 (2015: 1,865,720) 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.

On 13 February 2015 3,916,616 suspended voting ordinary shares were converted to voting 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.

18. Share based payments

The Company has three share-based payment plans: a performance share plan, restricted share plan and a share option plan. The main features of these share plans are set out below.

Key features	PSP	RSP	SOP
Form of awards	Performance shares. The intention is to deliver the full value of vested shares at no cost to the participant (e.g. as conditional shares or nil-cost options).	Restricted shares. The intention is to deliver the full value of shares at no cost to the participant (e.g. as conditional shares or nil-cost options).	Market value options. Exercise price is set equal to the average share price over a period of up to 30 days to grant.
Performance conditions	Performance conditions will apply. For awards granted to date, these are based on relative TSR measured against a Group of industry peers over a three-year period.	Performance conditions may or may not apply. For awards granted to date, there are no performance conditions.	Performance conditions may or may not apply. For awards granted to date, there are no performance conditions.
Vesting period	Awards will vest when the Remuneration Committee determine whether the performance conditions have been met at the end of the performance period.	Awards typically vest over three years.	Awards typically vest after three years. Options are exercisable until the 10th anniversary of the grant date.
Dividend equivalents	Provision of additional cash/shares to reflect dividends over the vesting period may or may not apply. For awards granted to date, dividend equivalents do not apply.	Provision of additional cash/shares to reflect dividends over the vesting period may or may not apply. For awards granted to date, dividend equivalents do not apply.	Provision of additional cash/shares to reflect dividends over the vesting period may or may not apply. For awards granted to date, dividend equivalents do not apply.

In 2016, awards were made under the performance share plan and restricted share plan, no awards were made under the share option plan, the numbers of outstanding shares under the PSP, RSP and SOP as at 31st December 2016 are set out below:

	PSP Options (nil cost)	RSP Options (nil cost)	SOP	CEO award (nil cost)
Outstanding at the beginning of the year	1,748,823	968,138	325,727	375,000
Granted during the year	3,399,136	2,118,008	-	-
Forfeited / lapsed during the year	(794,621)	(334,429)	(89,131)	-
Exercised during the year	-	(275,308)	-	-
Outstanding at the end of the year	4,353,338	2,476,409	236,596	375,000

Exercisable at the end of the year	102,131	63,802	140,088	93,750

The range of exercise prices for share options outstanding at the end of the period is nil to 1,046.00p. The weighted average remaining contractual life of the outstanding share options is 2 years. The blended exercise price for SOPs is 890p.

Fair value of options granted has been measured either by use of the Black-Scholes pricing model or by use of a formula based on past calculations. The model takes into account assumptions regarding expected volatility, expected dividends and expected time to exercise. In the absence of sufficient historical volatility for the Company, expected volatility was estimated by analysing the historical volatility of FTSE-listed oil and gas producers over the three years prior to the date of grant. The expected dividend assumption was set at 0%. The risk-free interest rate incorporated into the model is based on the term structure of UK Government zero coupon bonds. The inputs into the fair value calculation for RSP and PSP awards granted in 2015 and fair values per share using the model were as follows:

	RSP 7/5/2016	RSP 8/5/2016	RSP 19/9/2016	PSP 7/5/2016	PSP 8/5/2016
Share price at grant date	125p	110p	110p	125p	125p
Exercise price	-	-	-	-	-
Fair value on measurement date	125p	110p	110p	32p	32p
Expected life	1-3 years	1-3 years	1-3 years	3-6 years	3-6 years
Expected dividends	-	-	-	-	-
Fair value on measurement date	125p	110p	110p	32p	32p
Share price at balance sheet date	72p	72p	72p	72p	72p
Change in share price between grant date and 31 December 2016	-36%	-23%	-23%	-36%	-36%

The weighted average fair value for PSP awards granted in the period is 32p and for RSP awards granted in the period is 125p.

Total share based payment charge for the year was $7.5m (2015:$2.9 million), which is fixed using the share price at the date of grant. In the previous year the charge included the reversal of previously expensed costs principally caused by the non-vesting of options.

19. Capital commitments and operating lease commitments

Under the terms of its PSCs and JOAs, the Company has certain commitments that are generally defined by activity rather than spend. The Company's capital programme for the next few years is explained in the operating review and is in excess of the activity required by its PSCs and JOAs.

The Company leases temporary production and office facilities under operating leases. During the period ended 31 December 2016 $3.8 million (2015: $4.0 million) was expensed to the statement of comprehensive income in respect of these operating leases.

Drill rigs are leased on a day-rate basis for the purpose of drilling exploration or development wells. The aggregate payments under drilling contracts are determined by the number of days required to drill each well and are capitalised as exploration or development assets as appropriate.

The Company had no material outstanding commitments for future minimum lease payments under non-cancellable operating leases.

20. Related parties

The directors have identified related parties of the Company under IAS24 as being: the shareholders; members of the Board; and members of the executive committee, together with the families and companies, associates, investments and associates controlled by or affiliated with each of them. The compensation of key management personnel including the directors of the Company is as follows:

	2016 $m	2015 $m
Board remuneration	1.0	1.8
Key management emoluments and short-term benefits	7.4	9.0
Share-related awards	0.1	1.6
	8.5	12.4

There are no other significant related party transactions.

21. Subsidiaries and joint arrangements

For the period ended 31^st December 2016 the principal subsidiaries and joint operations of the Company were the following:

Entity name	Country of Incorporation	Ownership % (ordinary shares)
Genel Energy Holding Company Limited ¹	Jersey	100
Genel Energy Finance Plc²	UK	100
Genel Energy Finance 2 Plc¹	Jersey	100
Genel Energy Finance 3 Plc²	UK	100
Genel Energy Netherlands Holding 1 Cooperatief B.A. ³	Netherlands	100
Genel Energy Netherlands Holding 2 B.V. ³	Netherlands	100
Genel Energy International Ltd⁴	Anguilla	100
Taq Taq Operating Company Limited⁴	BVI	55
Genel Energy Miran Bina Bawi Limited²	UK	100
A&T Petroleum Company Limited⁵	Cayman Islands	100
Genel Energy Africa Exploration Limited²	UK	100
Genel Energy Africa Limited ²	UK	100
Genel Energy Exploration 2 Limited²	UK	100
Genel Energy Limited²	UK	100
Genel Energy Somaliland Limited²	UK	100
Genel Energy Gas Company Limited¹	UK	100
Phoenicia Energy Company Limited⁶	Malta	100
Genel Energy UK Services Limited²	UK	100
Genel Energy Yonetim Hizmetleri Anonim Sirketi⁷	Turkey	100
Genel Energy Petroleum Services Limited²	UK	100
Barrus Petroleum Limited⁸	Isle of Man	100
Barrus Petroleum Cote d'Ivoire Sarl⁹	Cote d'Ivoire	100
Taq Taq Petoleum Refinery Company Limited¹⁰	BVI	100
Taq Taq Drilling Company Limited¹¹	BVI	55

¹Registered office is 12 Castle Street, St Helier, Jersey JE2 3RT

²Registered office is Fifth floor, 36 Broadway, London SW1H 0DB

³Registered office is Prins Bernhardplein 200, 1097 JB, Amsterdam, Netherlands

⁴Registered office is PO Box 1338. Maico Building, The Valley, Anguilla and is a joint operation service company through which the Company jointly operates the Taq Taq PSC with its partner

⁵Registered office is PO box 309 Ugland House, Grand Cayman, KY1-1104, Cayman Islands

⁶Registered office is 85 St John Street, Valletta, VLT 1165, Malta

⁷Registered office is Next Level İş Merkezi, , Eskişehir Yolu, , Dumlupınar Bulvarı, No:3A-101, Söğütözü, Ankara, 06500, Turkey

⁸Registered office is 6 Hope Street, Castletown, IM9 1AS, Isle of Man

⁹Registered office is 7 Boulevard Latrille Cocody, 25 B.P. 945 Abidjan 25, Cote d'Ivoire

¹⁰Registered office is Ellen L Skelton Building, Fishers Lane, Road Town, Tortola, BVI

¹¹Registered office is 3^rd Floor, Geneva Place, Waterfront Drive, PO Box 3175, Road Town, Tortola, BVI

22. Annual report

Copies of the 2016 annual report will be despatched to shareholders in April 2017 and will also be available from the Company's registered office at 12 Castle Street, St Helier, Jersey JE2 3RT and at the Company's website- www.genelenergy.com.

23. Statutory accounts

The financial information for the year ended 31 December 2016 contained in this preliminary announcement has been audited and was approved by the board on 29 March 2017. The financial information in this statement does not constitute the Company's statutory accounts for the years ended 31 December 2016 or 2015. The financial information for 2016 and 2015 is derived from the statutory accounts for 2015, which have been delivered to the Registrar of Companies, and 2016, which will be delivered to the Registrar of Companies and issued to shareholders in April 2017. The auditors have reported on the 2016 and 2015 accounts; their report was unqualified and did not include a reference to any matters to which the auditors drew attention by way of emphasis without qualifying their report. The statutory accounts for 2016 are prepared in accordance with International Financial Reporting Standards (IFRS) as adopted for use in the European Union. The accounting policies (that comply with IFRS) used by Genel Energy plc are consistent with those set out in the 2015 annual report.

This information is provided by RNS

The company news service from the London Stock Exchange

END

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Thursday, 16th May 2024

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