Full Year Results

RNS Number : 8740Q

Genel Energy PLC

03 March 2016

 

 3 March 2016

Genel Energy plc

Audited results for the year ended 31 December 2015

Genel Energy plc ('Genel' or 'the Company') announces its audited results for the year ended 31 December 2015.

Results summary

	2015	2014
Revenue ($million)	343.9	519.7
EBITDAX1 ($million)	279.4	410.6
Loss  before tax ($million)	(1,160.6)	(312.8)
Cash flow from operating activities ($million)	71.2	134.8
Capital expenditure	157.2	676.9
Free cash flow2 ($million)	(179.2)	(560.9)
Cash ($million)	455.3	489.1
EPS (cents per share)	(417.30)	(112.97)
Production (kbopd, working interest)	84.9	69.4

1.    EBITDAX is profit before interest, tax, depreciation, amortisation, impairment and exploration expense

2.   Free cash flow is cash flow from operating activities less capital expenditure and associated working capital movements

Key figures

·      2015 revenue of $344 million, down 34% due to the fall in the oil price more than offsetting higher production volumes

·      2015 production of 84,900 bopd, an increase of 22% on 2014

·      Impairment expense of $1,038 million recognised in relation to the Taq Taq PSC

·      2015 capital expenditure of $157 million, a reduction of 77% year-on-year

·      KRI cash proceeds of $148 million during 2015

·      Cash balances at 31 December 2015 stood at $455 million (2014: $489 million)

Outlook

·      Production and revenue guidance for 2016 is maintained at 60-70,000 bopd, and $200-275 million assuming a $45/bbl Brent oil price and at $160-220 million assuming a $35/bbl Brent oil price

·      KRI capital expenditure guidance for 2016 is unchanged at $80-120 million

·      The KRG Ministry of Natural Resources' statement of 1 February 2016 commits to regular and predictable oil export payments, based on monthly production entitlement

·      Additional monthly payments, initially equivalent to five percent of the gross monthly netback revenue of fields and set to rise as the oil price rebounds, will be made towards the recovery of the receivable

·      Regarding the gas development, contract awards are expected in April 2016 for the midstream pre-FEED,  technical consultancy study package, and the upstream development plan

Murat Özgül, Chief Executive of Genel, said:

"We recognise and share the disappointment of the recent Taq Taq reserves update. Both Taq Taq and Tawke remain low-cost oil fields by any global benchmark. The fields are set to be significantly cash generative going forward, with a discretionary investment programme aiming to maximise the value of the remaining reserves. Our 264 million barrels of net 2P reserves comprise a robust oil business well positioned in the current oil price environment.

The instigation of the new payment mechanism by the KRG Ministry of Natural Resources in February 2016 provided clarity over the timing and quantum of our monthly receipts for export payments, recognising our receivable and putting in place the process through which it will be recovered.

We are now starting to make real progress in the development planning for our KRI gas business. It remains a unique opportunity underpinned by a government signed gas sales agreement."

Enquiries:

Genel Energy Phil Corbett, Head of Investor Relations Andrew Benbow, Head of Public Relations

[phone]

Vigo Communications Patrick d'Ancona

[phone]

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

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 fifth preliminary statement. 2015 was a challenging year across the oil sector as a whole. The sustained low oil price has placed a significant strain on both the industry and the economy of the Kurdistan Region of Iraq.

As the external environment has deteriorated, we have been proactive in ensuring that your Company remains robust. Our production costs are amongst the lowest globally, and our asset base allows us to flex our capital expenditure programme to align with our cashflow and to preserve a robust balance sheet.

Despite the reserve reassessment and write down at Taq Taq, which is very disappointing, our asset base remains strong, with many years of production ahead of us.

Despite the difficulties of the external environment, 2015 saw record production for Genel, up 22%. Payments for pipeline exports in the second half of the year, followed by a payment mechanism being confirmed in 2016, both demonstrated the firm commitment of the Kurdistan Regional Government to fully compensate IOCs for all production, both in the past and going forward.

The Kurdistan Region of Iraq oil industry

The Kurdistan Region of Iraq remains safe and secure, and our operations have been unaffected by the ongoing presence of ISIS in Iraq and Syria. The ISIS offensives against the KRI in 2014 were successfully repelled, and the terrorist group was very much on the defensive throughout 2015. Significant ground was retaken by the Peshmerga, with the support of its allies, and ISIS has seen its supply lines cut and increasing pressure placed on those areas west of the KRI which remain under its control.

While we continue to monitor the situation, we do not expect ISIS to have any operational impact on the KRI oil industry going forward. The main impact ISIS has is on the economy of the region, with the funding of the Peshmerga and provision of support for refugees and internally displaced peoples ('IDPs') causing a strain on the KRG's financial position.

2015 began with the implementation of an agreement between Baghdad and Erbil promising an end to uncertainty about the KRG's economic situation, with promises of the transfer of a full monthly budget allocation to Erbil, and SOMO control all sales of crude from Ceyhan. Unfortunately, while exports from KRI fields ramped up, the budget transfers stalled, forcing the KRG to resume independent export sales.

The KRG has since successfully increased exports to record levels, hitting over 650,000 bopd and reaching a ready market of international purchasers. Unfortunately, the shortfall of revenue received in the first half of the year delayed payments to oil companies, a situation compounded by the low oil price and the necessity of funding the Peshmerga.

Against this backdrop, the receipt of four payments for pipeline exports pertaining to the last four months of 2015 was very encouraging. These initial payments, totalling c.$100 million, helped stabilise our receivable and maintain our robust balance sheet. We recognise the efforts that the KRG is making to meet its commitments to IOCs in a very difficult environment. The crystallisation of the payment mechanism in February 2016 was a very positive move, and has provided clarity over the quantum and certainty over the timing of future payments.

As these payments are forthcoming, our investment in the region will continue, with the aim of maximising the value of our oil fields and facilitating the investment required to drive the development of the gas business, a business that will help further transform the economy of the KRI.

Management changes

At a difficult time for the industry, it is vital that a company has a Board with the experience and expertise to help navigate through choppy waters and to monitor carefully the risk across our operations.

2015 saw the retirement of people who were integral in the establishment of Genel Energy as a respected London-listed company. Rodney Chase, my predecessor as Chairman, and Julian Metherell, former CFO, both made invaluable contributions and left Genel with a strong reputation, and the financial strength to prosper. Mark Parris and Murat Yazici also stepped down in 2015, and we wish both well.

In order to retain the knowledge of Genel Energy assets, the political and oil industry environment, and an in depth understanding of operating in the KRI, the Board decided that I would replace Rodney as Chairman, with Murat Özgül, previously President, Turkey and KRI, becoming Chief Executive.

Murat has overseen the development of our Kurdistan business to make Genel Energy into one of the largest independent oil producers on the London Stock Exchange, and there is nobody better qualified to progress the development of our world-class KRI gas fields.

Finally, the year also saw the retirement of our President, Mehmet Sepil. The Kurdistan Region of Iraq's oil industry would not be where it is today without the foresight and efforts of people like Mehmet.

Mehmet left a legacy of a company with unsurpassed relationships in the region, world-class assets, significant production and transformational growth opportunities. With Murat, and Julian's successor Ben Monaghan, we have the right management team, with the relevant and complementary skills, to drive the company forward and take advantage of these opportunities.

Responsible operations

Supporting and sustaining the communities in which we operate is fundamental to Genel Energy's success and our commitment to being a sustainable business. We take pride in the close relationship that we have with the KRG, with whom we have worked closely for almost 15 years.

With 1.8 million refugees boosting the population of the KRI by over 30%, the KRG, working with NGOs, has done an excellent job to avoid a catastrophic humanitarian incident. We have been glad to provide support to the KRG, while not ignoring the needs of communities we work in to ensure lasting benefit from our operations.

Well positioned in a low-price environment

To ensure the ongoing strength of the business even in a period of prolonged low oil prices, our focus will remain on retaining a strong balance sheet and robust cash position. The flexibility of our investment programme means that we have a fleet-footed business that can take advantage of an improving external environment.

With the unique potential offered by the gas business, and low-cost oil production that promises to be cash generative even in very low oil price scenarios, we continue to look to the future with confidence.

 

Chief Executive Officer's statement

Having been with Genel since 2008, and seen the Company grow significantly in that time, it is my pleasure to now detail the Company's performance for 2015 as Chief Executive Officer. Unfortunately, I do not write at a buoyant time for the oil industry.

The decline in the oil price placed a significant strain on the entire oil industry in 2015, and the price weakness has continued into 2016. For the Kurdistan Regional Government, despite tremendous success in boosting oil exports, the low oil price and cessation of budget transfers from Baghdad, coupled with the necessity of funding the Peshmerga and averting a humanitarian crisis through managing the influx of refugees into the KRI, has created serious financial challenges.

In this environment three things position Genel well for the future - oil production that is amongst the lowest cost globally, a robust balance sheet, and a tight control on costs. Despite the disappointing revision of our reserves at Taq Taq, Taq Taq and Tawke remain low-cost oil fields by any global benchmark. With 264 million barrels of net 2P reserves across our KRI portfolio, Genel has a robust oil business well positioned in the current oil price environment, and set to be significantly cash generative going forward.

Retaining our financial strength

Our strategy remains clear and focused, as we look to maximise the potential of our KRI oil assets and commercialise our KRI gas business, while seeking growth through the drill bit and the selective pursuit of value accretive M&A opportunities. This strategy is underpinned by our business model - central to which is the retention of a strong balance sheet.

In a challenging external environment it is never more important to retain financial strength, and ensuring that costs were kept to a minimum was a key focus of management in 2015. This focus saw a number of efficiency measures and cost reduction programmes implemented across the business, resulting in production costs and general and administrative costs falling by around 40% compared to 2014. Even without receiving full payment for our oil exports, cash receipts of $148 million local and export sales more than covered production costs, general and administrative costs, and bond interest during the year.

With the receipt of export payments in the fourth quarter of the year stabilising our receivable with the KRG and bolstering our cash position, we finished 2015 with cash balances of $455 million. 2016 cash spend at the Company level is forecast to average c.$20 million per month, showing our ability to withstand even a worst case oil price scenario.

Capital expenditure for 2015 totalled $157 million, a reduction of over $500 million on 2014, as we focused on development programmes at Taq Taq and Tawke.

Low-cost oil production

The development programmes helped drive production at Taq Taq and Tawke to record levels, with production up 22% year-on-year to 84,900 bopd. The low-cost nature of this production helps make Genel Energy a very resilient business, with our producing oil assets in the Kurdistan Region of Iraq benefiting from production costs forecast at less than $2/bbl in 2016.

While some of the lowest costs in the industry provide Genel with a solid foundation, in order to continue investing in the fields it is still vital that payments are received for oil produced. In August 2015, the Kurdistan Regional Government made a public statement that reiterated their commitment to make certain that oil companies are recompensed for their production. Despite the financial crisis facing the region, this commitment was matched by action, and we have received monthly payments for exports since September 2015. We have been a partner of the KRG for many years, and we recognise the efforts that have been made to meet its commitments in difficult circumstances.

Regular and predictable payments

This commitment to remunerating IOCs was confirmed on 1 February 2016, when the Ministry of Natural Resources issued a statement announcing that monthly payments will be based on the contractual entitlements under the production sharing contract governing each license. The statement also illustrated the mechanism through which IOC receivables will be paid off, as each month a percentage of the monthly netback field revenue (starting at 5%) will be used to reduce the outstanding amount. As the oil price rises, this percentage will increase.

The new payment schedule provides clarity over future revenues that was previously lacking, allowing us to tailor our field development plans and progress them with confidence.

The payment mechanism removes the uncertainty of 2015, when the KRG's ability to make sustained and predictable payments was hampered by the external environment. This uncertainty resulted in the prudent decision to reduce investment in our producing fields, suspending sub-surface investment.

We retain a significant level of flexibility over the investment that can be made at our producing fields, with the potential to insert electric submersible pumps in existing wells, side track existing wells, and drill new horizontal wells. The extent of this activity will reflect the quantum of export payments, which are now largely tied to the oil price, as well as the technical results of the ongoing work programme. Our 2016 capital expenditure guidance of $80-120 million illustrates this flexibility, and we will aim to progress our oil development in a way that is broadly cash flow neutral to Genel in the near-term.

Production is expected to be 60,000-70,000 bopd in 2016. The Taq Taq and Tawke entitlement achieves breakeven at a Brent oil price around $20 a barrel, and promises to be significantly cash generative as the external environment improves.

Taq Taq reserves revision

Given the significant ramp-up in production at the Taq Taq field in recent years and subsequent decline during 2015, Genel took the decision to review its reservoir model and its future investment profile for Taq Taq.

To support this analysis, we commissioned an updated Taq Taq competent persons report ('CPR') from McDaniel & Associates.  This internal review and the CPR are now largely complete. The result is that the initial proven and probable reserves in place at the field have been revised from the estimated 683 mmbbls (as of 30 June 2011)  to an estimated 356 mmbbls (as of 31 December 2015).

With Taq Taq having produced a total of 184 mmbbls up to the end of 2015, the remaining gross recoverable 2P reserves as of 31 December 2015 are therefore 172 mmbbls.

The vast majority of the original Taq Taq oil in place was reservoired within fractures in Cretaceous carbonate formations. The Cretaceous has three principal producing units - the Qamchuga, Kometan and Shiranish - with the Shiranish being the shallowest interval. Genel's internal Taq Taq review and the CPR process have focused on the fracture porosity within the Shiranish reservoir. Both processes have utilised recently acquired data to establish that the fracture porosity within the Shiranish is lower than estimated in the original McDaniel CPR from 30 June 2011.

The revision in reserves is of course disappointing, but Taq Taq still has significant low-cost production to come. The field has been crucial in the development of the Kurdistan Region of Iraq oil industry, and will continue to make an important contribution in the future.

Commercialising the gas business

As well as our oil production, the development of our Kurdistan Region of Iraq gas business also benefits from low costs. The onshore location and scale of the development means that it delivers an industry leading cost structure - with an estimated upstream capital and operating expenditure of less than $3/boe.

In September 2015, Genel completed the acquisition of OMV's 36% operated stake in the Bina Bawi field, consolidating the ownership structure across both Miran and Bina Bawi, streamlining project management and providing flexibility in meeting development goals.

The development of the fields is a unique opportunity, and promises to deliver significant value for shareholders. The fields are 300 km from Turkey, one of the world's fastest growing major gas markets with expected demand growth of 3% per year until 2020 at least. Turkish gas demand makes the KRI's gas reserves of far greater strategic importance than oil, and they provide Turkey with the opportunity of materially reducing their gas import costs.

Turkey currently consumes approximately 50 bcma of gas, of which more than half is provided by Russia. With the KRG set to provide 20 bcma, this gas will help to diversify, and indeed form the baseload of Turkish supply, at a cheaper price than all current imports.

The project is underpinned by the KRI-Turkey Gas Sales Agreement, and the development is now progressing on the ground in Turkey, with BOTAS having begun its tendering process for the construction of the Turkish stretch of the pipeline.

It is a world-class development with a committed government buyer for the gas in place. As such, the progress towards converting the PSC amendments and gas supply term sheets into fully termed documents has been slower than we anticipated, as the KRG has been focused on oil exports and the difficult economic situation.

At Miran and Bina Bawi, 2016 activity will focus on delivering the upstream gas development plan and geological/geophysical studies, and work will also commence on the front end engineering design and financing plans for the midstream gas processing. Capital expenditure for the gas project during 2016 is estimated at c.$25 million.

Portfolio management

Our portfolio benefits from not having expensive commitments, and our focus on costs meant that a restructuring of the asset portfolio had been undertaken even prior to the rebasing of expectations of future cash-generation from Taq Taq.

As part of our ongoing portfolio management and rigorous control on costs and capital efficiency we are concentrating time and investment on our producing and development assets, and have reshaped our exploration portfolio into a focused and low-expenditure, high-impact potential asset base.

As part of this process, the Ber Bahr and Dohuk licence interests in the KRI are in the process of relinquishment, as is the interest in the Adigala block in Ethiopia. Limited remaining prospectivity in the Cap Juby and Mir Left Moroccan assets, and a disappointing drilling result offshore Côte d'Ivoire, also resulted in the decision to exit these licences.

At Chia Surkh (Genel 40% working interest), the CS-12 appraisal well is scheduled to be drilled in H1 2016. The drilling will help refine the contingent resource estimate for the Chia Surkh licence. Genel will be carried by its partner for the costs of the CS-12 well.

Genel is therefore looking to the future with a portfolio that offers low-cost production, a transformational gas business, and highly prospective exploration acreage - with targeted and flexible spending allowing us to focus on those areas in which shareholder returns can be maximised.

Outlook

Genel will continue to focus on costs, running operations in the KRI on a broadly cash neutral basis. Despite the recent reserve revision at Taq Taq, the Company is well positioned in the Kurdistan Region of Iraq, with a flexibility that provides resilience to the ongoing downturn and the ability to capitalise on both existing and future opportunities.

The quantum of cash receipts will define activity levels, and the KRG has provided clarity over the regularity of future payments, which are set to continue even in this challenging environment. Should the oil price recover, as we expect it will, the level of payments will rise along with our entitlement, accelerating the recovery of our receivable. The new payment agreement will also allow us to progress our field development plans and maximise the value of our producing assets.

We continue to selectively pursue accretive M&A opportunities, although any transaction that we execute will be the result of careful screening and a robust internal process. We will only proceed with those that meet our strict criteria - complementing the existing KRI position without being detrimental to our balance sheet strength.

Despite the many market challenges, Genel Energy remains a resilient business, with opportunities in the portfolio promising significant future cash generation.

 

Operating review

PRODUCTION

Net working interest production in 2015 averaged 84,900 bopd, versus the 85-90,000 bopd guidance range. Production guidance for 2015 was originally set at 90-100,000 bopd, although this was revised lower in October 2015 on the back of Taq Taq and Tawke production declines, which were partly due to a suspension of drilling and completion activity during the year.

Notwithstanding these declines, 2015 production represented growth of 22% on 2014. This increase reflected a full year of oil exports by the KRG via the export pipeline through Turkey. In turn, this allowed both Taq Taq and Tawke to operate at or near surface processing capacity for most of the year.

During 2015 production from Taq Taq and Tawke was either exported by the KRG or sold into domestic markets. The majority (75%) of production was exported in 2015, reflecting the KRG's strategy of maximising revenues from the region's oil output. Sales to traders in the domestic market totalled 12% of total volumes sold, with the balance of production supplied to the Bazian refinery and Tawke topping plant.

Excluding volumes supplied from Taq Taq to the Bazian refinery, the Company expects that the primary sales route for production from Taq Taq and Tawke will continue to be exports by the KRG via Ceyhan in Turkey. However, if pipeline exports are interrupted, production from both fields can be sold into the KRI domestic market at short notice, for which payments have historically been received in advance and directly.

Sub-surface investment at both fields was significantly reduced during 2015, reflecting the uncertainty over the timing of export payments. Payments recommenced in September 2015, and development activity has resumed at the Taq Taq field in Q1 2016.

Actual production levels during 2016 will be subject to the level and phasing of investment during the year, which in turn will be influenced by the timing and quantum of payments for oil exported from Taq Taq and Tawke.

Company production guidance for 2016, which encompasses both firm and contingent activity at both fields, is 60-70,000 bopd. Based on this production guidance and planned activity programmes, 2016 accrued revenue is estimated at $200-275 million on a Brent price of $45/bbl. At $35/bbl Brent, 2016 accrued revenue is estimated at $160-220 million.

RESERVES AND RESOURCES

At 31 December 2015, Genel Energy's proven plus probable (2P) working interest reserves were 264 mmbbls (2014: 429 mmbbls), a 39% decrease year-on-year.

The principal factor in the downward revision to the Company's 2P reserves was a significant downgrade at the Taq Taq field.

Given the significant ramp-up in production at Taq Taq in recent years and subsequent declines seen during H2 2015, the Company announced in January 2016 a review of its reservoir model and future investment plans for the field. A Competent Person's Report by McDaniel & Associates ('McDaniel') was also commissioned as a third party validation of the internal work.

In its technical reserves assessment dated 27 February 2016, McDaniel calculated initial gross recoverable 2P reserves (referred to in the industry as Estimated Ultimate Recovery, or EUR) of 356 mmbbls at 31 December 2015. This compares to the original McDaniel assessment (as of 30 June 2011) of 683 mmbbls. Deducting gross production from the Taq Taq field at 31 December 2015 of 184 mmbbls results in gross remaining recoverable 2P reserves for the field at 31 December 2015 of 172 mmbbls. This figure compares to the 541 mmbbls remaining recoverable 2P reserves at 31 December 2014.

The main reason for the downgrade to the Taq Taq EUR was a revised assumption of the fracture porosity within the Shiranish formation, which is one of the three Cretaceous aged producing intervals which comprise the majority of the EUR in the Taq Taq field. This change significantly impacted the oil in place estimate for the Shiranish reservoir, in turn reducing recoverable reserves. In addition, McDaniel also reduced the expected contribution from the matrix porosity in the Cretaceous Shiranish, Kometan, and Qamchuqa reservoirs.

Tawke gross remaining recoverable 2P reserves at 31 December 2015 are estimated at 631 mmbbls. This figure is based on Tawke gross remaining recoverable 2P reserves at 31 December 2014 of 680 mmbbls (as published by Tawke operator DNO ASA) less 2015 gross production of 49 mmbbls. DNO ASA is currently performing its annual review of the Tawke field reserves with the results expected to be announced in March 2016.

Contingent resources increased by 21% to 1,252 mmboe (2014: 1,031 mmboe), mainly as result of the acquisition of a further 44% non-operated interest in the Bina Bawi field. This was only partially offset by minor revisions to the contingent resources associated with the reduction of Genel's interest in the Chia Surkh licence and the removal of the contingent resource associated with the Ber Bahr licence, which is in the process of relinquishment.

	Proven plus Probable (2P) reserves (mmboe)1,2	Contingent resources (mmboe)3	2P reserves and contingent resources (mmboe)
Start of 2015	429	1,031	1,460
Production	(31)	-	(31)
Net additions /revisions	(134)	221	87
End of 2015	264	1,252	1,516

1.     Proven plus probable 2P reserves at Taq Taq are based on the McDaniel technical reserves assessment dated 27 February 2016

2.     Tawke 2P reserves are based on the operator's reported figures at 31.12.2014 less 2015 production. The operator of the Tawke field, DNO ASA, is currently performing its annual review of the Tawke field reserves with the results expected to be announced in March 2016

3.     Contingent resources are based on both Genel Energy's estimates and independent reserve reports

KRI OIL ASSETS

Taq Taq (44% working interest, joint operator)

The Taq Taq field has been producing since 2006 and as a result of a multi-year investment programme in both production wells and surface facilities delivered compound annual growth of 29% between 2010 and 2015. As of 31 December 2015 the field had produced 184 mmbbls. Gross remaining recoverable 2P reserves at 31 December 2015 were estimated at 172 mmbbls by McDaniel in its technical reserves assessment dated 27 February 2016. The proven plus probable plus possible ('3P') reserves at 31 December 2015 were assessed by McDaniel at 416 mmbbls. Going forward, the Company's strategy at Taq Taq will be to maximise recovery of the 2P reserves through its discretionary investment programme, while also exploring opportunities to unlock upside potential by targeting prospective resources in the Cretaceous Qamchuqa reservoir.

The Taq Taq field produced a gross average of 116,000 bopd in 2015, compared to 103,000 bopd in 2014, representing 13% growth year-on-year. Production performance was strong in the first half of 2015, averaging 128,900 bopd on the back of high surface capacity utilisation as the KRG maximised exports through the KRI-Turkey pipeline. During the second half of 2015, production declined, averaging 104,000 bopd and ending the year at 85,000 bopd. These declines reflected reservoir underperformance and also reflected a suspension of sub-surface investment in the second half of the year as the Company waited for regular export payments to be established. During the year 63% of Taq Taq output was exported by the KRG through the KRI-Turkey pipeline, 27% was sold to the Bazian refinery with the remainder sold into the KRI domestic market.

In H1 2015, two production wells (TT-23 and TT-24) were drilled and brought on production. At end 2015, a total of 28 wells had been drilled across the field, 24 of which were in the main Cretaceous reservoir and 4 in the shallower Tertiary Pilaspi reservoir. The 2016 firm activity programme envisages side-tracks to existing wells and workover operations to arrest production declines. Further activity, which is contingent on implementation of the 1 February 2016 monthly export payment mechanism, could see a horizontal production well drilled in the Cretaceous in addition to further workover operations and side-tracks of existing wells.

During 2015, good progress was made in the construction of the second central processing facility ('CPF 2'). CPF 2 is designed to process 90,000 bpd of oil and has 45,000 bpd of water handling capacity. CPF 2 will commence operations in Q2 2016.

Tawke (25% working interest)

The Tawke field produced a gross average of 135,000 bopd in 2015, compared to 91,000 bopd in 2014, representing 48% growth year-on-year. In H1 2015, wellhead, processing and pipeline capacity was successfully doubled to 200,000 bopd which allowed for a significant ramp-up in field production and exports through the KRI-Turkey pipeline. Peak production of 180,000 bopd was achieved in May 2015. During the second half of 2015, production declined, with the field exiting the year at 124,000 bopd. The decline reflects the suspension of sub-surface investment during H2 2015 as the Tawke partners waited for a regular export payment stream to be established. During the year 85% of Tawke sales were exported by the KRG through the KRI-Turkey pipeline, 13% was delivered into the KRI domestic market with the remainder being sold into the Tawke refinery.

In H1 2015, the final well (Tawke-30) of the approved development plan was drilled and brought onstream. As of end-2015, 30 production wells had been drilled at the field. The proposed 2016 work programme, which is contingent on export payments continuing, consists of further production wells and construction of water handling facilities at the existing central processing facility. The Tawke partners will also drill the Peshkabir-2 exploratory appraisal well in 2016.

KRI pipeline infrastructure

During 2015, the KRG continued to upgrade the capacity and integrity of the pipeline system through which oil is exported from the KRI to the port of Ceyhan on the Mediterranean coast. The pipeline consists of a number of sections. The first, from the Taq Taq field to the Khurmala Dome, has capacity of 150,000 bopd. The second section, from Khurmala to the KRI border, has capacity of 700,000 bopd. At the border, both the KRI pipeline and the dedicated export pipelines from the Tawke field, which have capacity in excess of 250,000 bopd, are tied into the 40-inch section of the Iraq-Turkey pipeline. The 40-inch section currently has 700,000 bopd of capacity. Pipelines on both the KRI and Turkey sides of the border have sufficient capacity to facilitate all current or future oil exports from Genel's fields.

KRI GAS ASSETS

Miran (75% working interest, operator) and Bina Bawi (80% working interest, operator)

During the first half of 2015, Genel continued its negotiations with the KRG on the commercial framework for the development of the Miran and Bina Bawi fields. Detailed term sheets for the upstream and midstream elements of the KRI gas project were signed in early H2 2015, replacing the original documentation announced in November 2014. The revised structure delivers complete alignment along the value chain, from the KRI-Turkey Gas Sales Agreement through the midstream to the upstream, and helps the KRG manage its obligations and de-risks the wider project. Genel expects to convert these term sheets into fully termed documents during Q2 2016.

In September 2015, the Company acquired OMV's 36% operated stake in the Bina Bawi field. Genel now has an 80% operated working interest in Bina Bawi. The consideration comprised an upfront payment of $5 million. A contingent payment of $70 million is payable once gas production exceeds agreed threshold volumes from the Miran and Bina Bawi fields. A further contingent payment of $75 million is payable two years after the date of the second payment. In consideration of the KRG agreeing to the transfer of OMV's stake in the Bina Bawi field, on completion Genel offset $25 million against monies owed by the KRG to Genel in respect of past expenses incurred on the Miran field.

Upstream

The main elements of the upstream gas structure are as follows

·      Genel will be sole contractor in both Miran and Bina Bawi with a 100% interest in both fields

·      The responsibilities of Genel will be drilling of gas wells, installation of flowlines and first stage condensate separation at Miran and Bina Bawi. The Company will also be responsible for development of the oil resources at Miran and Bina Bawi

·      Genel's entitlement share of the raw gas, first stage condensate and oil production from Miran and Bina Bawi will be dictated by the terms of an amended upstream PSC

Gross life of field capex for the upstream gas development is estimated at $2.9 billion, with $1 billion of this expected to be incurred before the onset of gas and first stage condensate production. Gross life of field capex for the development of the oil resources at Miran and Bina Bawi is estimated at $400 million, with $60 million of this expected to be incurred before first oil. This represents a combined oil and gas unit life of field development cost of less than $2 per barrel of oil equivalent ('boe'). Upstream opex remains estimated at less than $1/boe. Bids for the upstream development plan have been received, are being evaluated, and the contract is expected to be awarded in April.

In order to achieve the appropriate balance of risk and reward, as well as help fund the Miran and Bina Bawi upstream development, the Company intends to farm-down part of its existing equity interests in both fields.

 

Midstream

For the midstream gas processing plant, a company ('MidstreamCo') was created during 2015 and will be contracted by the KRG on a build, own, operate and transfer basis for the treatment facilities.  Genel is working with the KRG on the midstream development and is currently leading the engineering design process.

Genel is also leading efforts to secure an equity consortium and debt financing. During 2015, Genel mandated ING Bank as financial advisor on the midstream debt financing. Genel has also commenced discussions with potential midstream equity partners.

For the midstream, capex for two separate facilities, totalling 14 billion cubic metres per annum ('bcma') of raw gas (10 bcma sales gas) processing capacity at Miran and Bina Bawi, is estimated at c.$2.5 billion gross.

In December 2015, the Company initiated the pre-Front End Engineering Design (FEED) and technical consultancy study package tender for both the Miran and Bina Bawi gas treatment and processing facilities. Genel expects to award the pre-FEED contact in April 2016. The pre-FEED is expected to complete by end H1 2016 and will focus on site selection and technical design for the gas processing facilities at Miran and Bina Bawi. It will also result in a basic procurement matrix which will facilitate initial discussions with export credit agencies (ECAs) as part of the project financing solution.

Assuming satisfactory completion of the pre-FEED studies, the project will then progress to a full FEED study in H2 2016. Expression of Interest letters have been sent to eligible engineering, procurement and construction (EPC) contractors, with the $2.5 billion midstream cost and 30-36 month construction window verified by EPC contractor responses. The Company also intends to award the contract for the Environmental & Social Impact Assessment in Q2 2016.

Award of the EPC tender and final investment decision on the KRI gas project would follow successful delivery of the steps outlined above.

Development of the Miran and Bina Bawi oil resources is scheduled to commence in H1 2017, although sanctioning of this development activity is subject to continued export payments for oil production, prevailing oil prices and the success of any farm-down process.

During 2015, the Summail field on the Dohuk licence (Genel 40% working interest) ceased production following significant declines on the back of reservoir underperformance. The Summail facilities were subsequently decommissioned and the Company is in the process of relinquishing its interest in the Dohuk licence.

EXPLORATION AND APPRAISAL

A combination of the unsuccessful 2014 exploration programme and falling oil prices led to a decision in early 2015 to prioritise investment on the Company's producing and development assets. As a result, there was a significant reduction in exploration activity during the year, with only one well drilled across the portfolio.

Exploration for new accumulations of oil and gas remains a key element of Genel's strategy, as it has the potential to deliver resource to underpin future growth. In 2016, the focus will be on the upside potential in the existing KRI portfolio, where the Company will participate in exploratory appraisal wells on the Chia Surkh and Peshkabir structures. The Company will also continue to screen opportunities to acquire prospective acreage in its core areas, albeit with a focus on minimising upfront capital commitments.

KRI

In October 2015, Genel disposed of a 20% interest in the Chia Surkh Production Sharing Contract to its partner Petoil, thereby reducing its interest to 40%. As consideration for the sale of the 20% interest, Petoil will carry Genel's share of the costs associated with the Chia Surkh-12 ('CS-12') appraisal well. The total cost of the CS-12 well is estimated at c.$50 million, with drilling expected to commence in April 2016. The drilling will help refine the contingent resource estimate for the Chia Surkh licence, which is now estimated at 225 million barrels of oil equivalent.

Under the terms of the disposal, Petoil has transferred $10 million to Genel in the form of security which will be released at different stages of well operations in accordance with cash calls, well completion and testing. The operatorship of the Chia Surkh PSC will also transfer from Genel to Petoil for the duration of the CS-12 well.

On the Tawke licence, the Peshkabir exploratory appraisal well is scheduled for H2 2016. The operator estimates 32 mmbbls and 225 mmbbls of 2P reserves and prospective resources respectively for the Peshkabir structure.

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

Africa

In December 2015, Genel announced that the Aigle-1X exploration well on the CI-508 licence offshore Côte d'Ivoire (Genel 24% working interest) had been plugged and abandoned after failing to encounter hydrocarbons. The completion of this well concluded Genel's committed Côte d'Ivoire drilling programme.

On the Sidi Moussa licence (Genel 60% working interest) offshore Morocco, work has continued to incorporate the results of the SM-1 well drilled in Q4 2014. A farm-out process has commenced as part of the Company's ongoing portfolio management activities, with encouraging levels of interest. Genel will consider its options regarding future activity on the Sidi Moussa licence once the farm-out process is concluded. The Company has agreed with the Moroccan authorities that commitments associated with the Mir Left licence be transferred to Sidi Moussa, with Genel subsequently withdrawing from Mir Left. The Company is also withdrawing from the Juby Maritime licence.

Onshore Somaliland the acquisition of 2D seismic data on the Odewayne (Genel 50%, operator) and SL-10B/13 (Genel 75%, operator) licences is proposed for 2016. The results of a surface seep study completed early in 2015 confirmed the outstanding potential offered by this huge acreage position (41,000 km²). Genel continues to support the government's efforts to provide the appropriate level of security in order to conduct future operations. Genel continues to seek a strategic partner for its Somaliland assets, in keeping with its strategy of balancing risk and reward and reducing upfront capital commitments.

After a review of licence potential, Genel has decided to exit its 44% working interest in the Adigala block onshore Ethiopia.

 

Chief Financial Officer's review

Results summary

	2015	2014
Revenue ($million)	343.9	519.7
EBITDAX1($million)	279.4	410.6
Loss before tax ($million)	(1,160.6)	(312.8)
Cash flow from operating activities ($million)	71.2	134.8
Capital expenditure ($million)	157.2	676.9
Free cash flow2 ($million)	(179.2)	(560.9)
Cash ($million)	455.3	489.1
Net assets ($million)	2,574.8	3,733.5
EPS (cents)	(417.30)	(112.97)

1.   EBITDAX is profit before interest, tax, depreciation, amortisation, impairment and exploration expense

2.     Free cash flow is cash flow from operating activities less capital expenditure and associated working capital movements

Results for the period 

For the year ended 31 December 2105, the Company reported revenue of $343.9 million (2014: $519.7 million), a loss before tax of $1,160.6 million (2014: $312.8 million loss) and a loss per share of 417.30 cents (2014: 112.97 cents loss). Free cash flow for the period was an outflow of $179.2 million (2014: outflow of $560.9 million).

Revenue

Revenue of $343.9 million (2014: $519.7 million) and EBITDAX of $279.4 million (2014: $410.6 million) decreased from the comparable period as a result of lower oil price despite higher production volumes.

Operating costs

Cost of sales of $208.3 million (2014: $203.1 million) is comprised of production costs of $36.3 million, reduced from $62.1 million in 2014 and depreciation charges of $172.0 million (2014: $141.0 million) which increased broadly in line with production levels.

Impairment of property, plant and equipment included $1,038.0 million relating to Taq Taq (2014: $80.9 million  relating to Dohuk).

Exploration costs written-off of $173.0 million (2014: $476.8 million) represent the write-off of expenditure principally relating to exploration activity in KRI, Morocco, Cote d'Ivoire and Ethiopia.

General and administrative costs amounted to $28.7 million (2014: $47.0 million) for the period.

Finance expense

Finance expense of $56.5 million (2014: $23.5  million) represents interest on the $730 million bond, together with $7.7 million of discount unwind (2014: $1.8 million)

Taxation

In the KRI, all corporation tax due has been paid on behalf of the Company by the KRG from the KRG's own share of revenues and there is no tax payment required or expected to be made. Tax presented in the income statement relates to taxation of the Turkish and UK service companies.

Dividend

No dividend (2014: nil) will be paid for the year ended 31 December 2015.

 

Capital expenditure

Capital expenditure in the year amounted to $157.2 million (2014: $676.9 million). Development spend of $109.2 million (2014: $193.4 million) was incurred on the producing assets in KRI with spend on exploration assets amounting to $48.0 million (2014: $480.8 million).

Cash flow

Net cash flow from operations was $71.2 million (2014: $134.8 million), which was impacted by an increase of $189.0 million in amounts due from the KRG. This together with capital expenditure of $250.4 million (2014: $676.9 million), which included significant working capital movements of net $93.2m relating principally to the payment of brought forward accruals relating to 2014 activity, resulted in a free cash outflow of $179.2 million (2014: $560.9 million). Net cash spend on acquisitions was $3.9 million (2014: $76.8 million). Financing raised from the issue of bonds raised a net $196.2 million with interest costs on the bond of $46.1 million and foreign exchange loss of $0.8 million on cash. Overall there was a net cash outflow of $33 million (2014: $210.6 million outflow) in the year.

Cash

At 31 December 2015, the Company had a cash balance of $455.3 million (2014: $489.1 million) and net debt of $238.8 million (2014: $2.3 million).

Acquisitions

The Company spent $5.0 million (2014: $76.8 million) on the acquisition of the additional 36% operated stake in the Bina Bawi field, thereby increasing the Company's interest to 80%. The consideration is comprised of: an upfront payment of net $3.9 million; a contingent payment of $70m payable once gas production exceeds certain threshold volumes from the Miran and Bina Bawi fields; and a second payment of $75m payable two years after the date of the contingent payment.

Net assets

Net assets at 31 December 2015 were $2,574.8 million (2014: $3,733.5 million) and consist primarily of oil and gas assets of $926.8 million (2014: $2,010.7 million), exploration and evaluation assets of $1,671.0 million (2014: $1,676.6 million) and net debt of $238.8 million (2014: $2.3 million net debt).

Liquidity / counterparty risk management

The Company monitors its cash position, cash forecasts and liquidity on a regular basis. The Company takes a conservative approach to cash management, with 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.

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 2015 for the Company to be considered a going concern.

Accounting policies

UK listed companies are required to comply with the European regulation to report consolidated statements that conform to International Financial Reporting Standards (IFRS) as adopted by the European Union. Principal accounting policies adopted by the Company and applicable for the period ended 31 December 2015 can be found in the 2015 annual report.

 

Condensed consolidated statement of comprehensive income

For the period ended 31 December 2015

	Notes	2015	2014
		$m	$m
Revenue		343.9	519.7
Production costs	3	(36.3)	(62.1)
Depreciation	3	(172.0)	(141.0)
Gross profit		135.6	316.6
Exploration costs written off	4	(173.0)	(476.8)
Impairment and write-off of property, plant and equipment		(1,038.0)	(80.9)
General and administrative costs		(28.7)	(47.0)
Operating loss		(1,104.1)	(288.1)
EBITDAX		279.4	410.6
Depreciation		(172.5)	(141.0)
Exploration costs written-off	4	(173.0)	(476.8)
Impairment and write-off of property, plant and equipment		(1,038.0)	(80.9)
Finance expense	5	(56.5)	(24.7)
Loss before income tax		(1,160.6)	(312.8)
Income tax expense	6	(1.0)	(1.5)
Loss for the period		(1,161.6)	(314.3)
Other comprehensive items		-	-
Total comprehensive expense for the period		(1,161.6)	(314.3)
Attributable to:
Shareholders' equity		(1,161.6)	(314.3)
		(1,161.6)	(314.3)
Earnings per ordinary share attributable to the ordinary equity holders of the Company
Basic earnings per share - cents per share	7	(417.30)	(112.97)
Diluted earnings  per share - cents per share	7	(417.30)	(112.97)

 

Condensed consolidated balance sheet

At 31 December 2015

	Notes	2015	2014
		$m	$m
Assets
Non-current assets
Intangible assets	8	1,672.7	1,679.3
Property, plant and equipment	9	929.4	2,015.2
Trade and other receivables	10	365.3	-
		2,967.4	3,694.5
Current assets
Trade and other receivables	10	79.0	303.7
Cash and cash equivalents	11	455.3	489.1
		534.3	792.8
Total assets		3,501.7	4,487.3
Liabilities
Non-current liabilities
Trade and other payables	12	(78.0)	(5.0)
Deferred income	13	(46.0)	(47.8)
Provisions	14	(25.2)	(19.4)
Long-term borrowings	15	(694.1)	(491.4)
		(843.3)	(563.6)
Current liabilities
Trade and other payables	12	(80.6)	(184.0)
Deferred income	13	(3.0)	(6.2)
		(83.6)	(190.2)
Total liabilities		(926.9)	(753.8)
Net assets		2,574.8	3,733.5
Owners of the parent
Share capital	16	43.8	43.8
Share premium account		4,074.2	4,074.2
Retained earnings		(1,543.2)	(392.3)
Total shareholders' equity		2,574.8	3,725.7
Non-controlling interest		-	7.8
Total equity		2,574.8	3,733.5

 

Condensed consolidated statement of changes in equity

	Share capital $m	Share premium $m	Retained earnings $m	Total attributable to equity holders $m	Non-controlling interest $m	Total equity $m
At 1 January 2014	43.8	4,074.2	(21.6)	4,096.4	7.8	4,104.2
Loss and total comprehensive expense for the period	-	-	(314.3)	(314.3)	-	(314.3)
Transactions with shareholders:
Share-based payment transactions	-	-	6.8	6.8	-	6.8
Purchase of own shares for ESOP1	-	-	(39.2)	(39.2)	-	(39.2)
Purchase of own shares2	-	-	(24.0)	(24.0)	-	(24.0)
At 31 December 2014 and 1 January 2015	43.8	4,074.2	(392.3)	3,725.7	7.8	3,733.5
Loss and total comprehensive expense for the period	-	-	(1,161.6)	(1,161.6)	-	(1,161.6)
Transactions with shareholders:
Share-based payment transactions	-	-	2.9	2.9	-	2.9
Release of non-controlling interest3	-	-	7.8	7.8	(7.8)	-
At 31 December 2015	43.8	4,074.2	(1,543.2)	2,574.8	-	2,574.8

1.   Purchase of shares in the open market to satisfy the Company's commitments under various employee share plans.

2.   Purchase of own shares in the open market and held as treasury shares

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

 

Condensed consolidated cash flow statement

For the period ended 31 December 2015

	Notes	2015	2014
		$m	$m
Cash flows from operating activities
Loss for the period		(1,161.6)	(314.3)
Adjustments for:
Finance expense	5	56.5	24.7
Taxation		1.0	1.5
Depreciation and amortisation	3	172.5	144.3
Exploration costs written off		154.8	471.1
Impairment of property, plant and equipment		1,038.0	80.9
Other non-cash items		1.1	6.8
Changes in working capital:
Trade and other receivables		(190.2)	(287.8)
Trade and other payables and provisions		(0.9)	8.1
Cash generated from operations		71.2	135.3
Interest received		1.0	1.0
Taxation paid		(1.0)	(1.5)
Net cash generated from operating activities		71.2	134.8
Cash flows from investing activities
Purchase of intangible assets	8	(130.2)	(482.1)
Purchase of property, plant and equipment	9	(120.2)	(194.8)
Acquisition of intangibles	17	(3.9)	(76.8)
Net cash used in investing activities		(254.3)	(753.7)
Cash flows from financing activities
Purchase of ESOP shares		-	(39.2)
Purchase of own shares		-	(24.0)
Net proceeds from bond issuance		196.2	490.3
Interest paid*		(46.1)	(18.8)
Net cash generated from financing activities		150.1	408.3
Net decrease in cash and cash equivalents		(33.0)	(210.6)
Foreign exchange loss		(0.8)	-
Cash and cash equivalents at 1st January		489.1	699.7
Cash and cash equivalents at 31 December 2015		455.3	489.1

*The presentation of the prior year cash flows has been amended to include interest expense as part of financing activities.

In the year the Company acquired an additional interest in Bina Bawi. Consideration included gross $145.0 million of deferred consideration.

Notes to the condensed financial statements

1. Significant accounting policies and estimates

The preparation of the financial statements in accordance with IFRS requires management 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. Management has assessed the following as being areas where changes in estimates or assumptions could have a significant impact on the financial statements.

Estimation of oil and gas reserves

Reserves and resources impact the Company's financial statements in a number of ways, including: the calculation of depreciation and amortisation; testing for impairment; determining the timing of decommissioning activity and associated costs and going concern and viability.

Estimates of oil and gas reserves are inherently imprecise, require the application of judgement and are subject to future revision.

Proven and probable reserves are estimates of the amount of oil and gas that can be economically extracted from oil and gas assets. The Company estimates its reserves using standard recognised evaluation techniques. Proven and probable reserves are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves. Future development costs are estimated taking into account the level of development required to produce the reserves.

In general, 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.

Future development costs used in impairment testing and depreciation of oil and gas properties

Certain classes of property, plant and equipment related to oil and gas exploration and production activities are depreciated using a unit-of-production method over 2P reserves. Since 2P reserves assume future development
cost to access the proved and probable reserves, an estimate of future development costs is required for the calculation of depreciation.

The Company's estimation of future development costs is based on past costs, experience and data from similar assets in the region, future petroleum prices and the Company's plans to develop its assets. However, actual costs may be different from those estimated. Changes in estimates of reserve quantities and/or estimates of future development expenditure are reflected prospectively in the depreciation and amortisation calculation.

Estimation of realised export price used to calculate reported revenue and trade receivables

Export sales are accrued using a netback, principally comprised of the estimated realised sales price for each barrel of oil sold, less selling, transportation and handling costs and estimates to cover additional costs. The Company does not have direct visibility on the components of netback because sales are managed by the KRG. As no reconciliation has been performed and agreed with the KRG, management has estimated the price or cost for each component of netback. For each component of netback, management has made its best estimate  of prices or costs based on a range communicated by the KRG. Management has estimated the costs outlined above at the higher end of the likely range, reflecting uncertainties in actual realised netback.

Actual realised sales price used to calculate netback and entitlement when a reconciliation is performed with the KRG may be different to the estimate made by management.

Trade receivables

The Company reported trade receivables of $422.9 million owed by the KRG principally for export sales that were made after 2014. The KRG has stated publicly on a consistent basis that it intends to fully repay the debt.  On 1 February 2016, the KRG announced an interim measure whereby monthly payments to IOCs would be made based on an agreed mechanism. The mechanism has been put in place with the objective of simplifying the calculation of a monthly payment that will include an element that is a proxy for entitlement for the month, together with an element that is intended to contribute towards repayment of the receivable. The KRG has stated that it intends to increase the repayment contribution as the oil price improves.

Management expect 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 the final settlement of the balance.

The Company assess the receivable balance as fully recoverable, with management expectation that it will be settled with cash, although it is possible that the debt could be settled in a number of ways. 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; and ongoing negotiations with regard to various sources of potential finance. Management does not have direct visibility on the working capital of the KRG or its budget constraints, but continues to monitor the position based on its regular conversations with the KRG.

Management has compared the carrying value of trade receivables reported in the balance sheet to its fair value.  When assessing fair value, management has taken into account a range of inputs related to likely pricing of domestic, government refinery and export sales, interest accruing at LIBOR plus 2% in line with the PSC and management's assessment of the likely timing of discounted cash flows.

No revenue or receivable has been recognised for export sales that were made before 2014 (including exports marketed by SOMO) where payment is outstanding; the total unrecognised receivable balance is estimated at circa $340m.

Decommissioning costs

Provision for decommissioning represents the present value of decommissioning costs relating to the oil and gas interests, which are expected to be incurred at the end of field life, currently estimated to be in the period 2031 - 2039. These provisions have been created based on the Company's internal estimates. Assumptions, based on the current economic environment, have been made which management believe are a reasonable basis upon which to estimate the future liability. Those estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual decommissioning costs will ultimately depend upon future market prices for the necessary decommissioning works required, which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend upon future oil and gas prices, which are inherently uncertain.

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. Management uses all available information to make the fair value determinations.

In determining fair value for the acquisition, the Company has utilised 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.

 

2. Segmental information

The Company has two reportable business segments, which are its oil and gas exploration and production business in the KRI and its oil and gas exploration business in Africa. Capital expenditure decisions for the Kurdistan segment are considered in the context of the cash flows expected from the production and sale of crude oil. Capital expenditure for the Africa segment is considered in the context of the available cash of the Company. Finance income is not considered part of a business segment and forms part of the reconciliation to the reported numbers.

For the period ended 31 December 2015

	Kurdistan	Africa	Other	Total Reported
	$m	$m	$m	$m
Revenue	343.9	-	-	343.9
Cost of sales	(208.3)	-	-	(208.3)
Gross profit	135.6	-	-	135.6
Exploration costs written- off	(69.1)	(103.9)	-	(173.0)
Impairment and write-off of property, plant and equipment	(1,038.0)	-	-	(1,038.0)
General and administrative costs	(1.5)	-	(27.2)	(28.7)
Operating profit  loss	(973.0)	(103.9)	(27.2)	(1,104.1)
Finance expense	(1.0)	-	(55.5)	(56.5)
Loss before tax	(974.0)	(103.9)	(82.7)	(1,160.6)
Capital expenditure	139.3	17.9	-	157.2
Total assets	3,080.6	43.8	377.3	3,501.7
Total liabilities	(195.5)	(21.1)	(710.3)	(926.9)

General and administrative costs represent non-segmental items related to head office activities. Total assets and liabilities in the other segment are predominantly cash and debt balances.

For the period ended 31 December 2014

	Kurdistan	Africa	Other	Total Reported
	$m	$m	$m	$m
Revenue	519.7		-	519.7
Cost of sales	(203.1)	-	-	(203.1)
Gross profit	316.6	-	-	316.6
		-
Exploration costs written- off	-	(476.8)	-	(476.8)
Impairment and write-off of property, plant and equipment	(80.9)	-	-	(80.9)
General and administrative costs	(1.9)	-	(45.1)	(47.0)
Operating profit / (loss)	233.8	(476.8)	(45.1)	(288.1)
Finance expense	(0.9)	-	(23.8)	(24.7)
Profit/(Loss) before tax	232.9	(476.8)	(68.9)	(312.8)
Capital expenditure	331.2	343.0	2.7	676.9
Total assets	3,946.1	115.1	426.1	4,487.3
Total liabilities	(168.1)	(78.8)	(506.9)	(753.8)

General and administrative costs represent non-segmental items related to head office activities. Total assets and liabilities in the other segment are predominantly cash and debt balances.

3. Operating costs

	2015	2014
	$m	$m
Depreciation and amortisation of oil and gas assets	172.0	141.0
Production costs	36.3	62.1
Cost of sales	208.3	203.1
Share based payment charge	1.5	4.0
Depreciation and amortisation of other fixed assets	0.5	0.5
Other administrative costs	26.7	42.5
General and administrative expenses	28.7	47.0
Fees payable to the Company's auditors for:
Audit of parent company and consolidated financial statements	0.4	0.4
Tax services	0.2	0.3
Total fees	0.6	0.7

4. Exploration costs written off

	2015	2014
	$m	$m
Write off of previously capitalised exploration costs	144.1	471.1
Current year exploration expenses	28.9	5.7
	173.0	476.8

Write off of previously capitalised exploration costs includes costs previously capitalised principally in relation to the following licences: Ber Bahr, Morocco Mir Left, Cote d'Ivoire and Ethiopia. Current year exploration expenses  relate principally to work commitments and costs incurred on assets that the Company has exited or is in the process of exiting.

5. Finance expense / income 

	2015	2014
	$m	$m
Interest on bank deposits	1.3	0.6
Interest payable on bond	(50.1)	(23.5)
Unwind of discounts	(7.7)	(1.8)
	(56.5)	(24.7)

6. Taxation

A taxation charge of $1.0 million (2014: $1.5 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.

 

The tax paid by the government in accordance with the terms of the KRI PSCs would usually be presented as a gross up of revenue and a corresponding taxation expense in the statement of comprehensive income with no cash outflow. In the results for the periods ended 31 December 2015 and 31 December 2014, no presentation of taxation expense with an equivalent gross up for revenue has been accounted for because it has not been possible to measure reliably the amount of taxation paid on behalf of the Company because of uncertainties over how the amount of taxation should be calculated. This is an accounting presentational issue and there is no taxation to be paid. For the same reason, it has not been possible to assess whether it is necessary to gross up assets for deferred tax.

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.

	2015	2014
Profit  for the period attributable to equity holders of the Company - $ million	(1,161.6)	(314.3)
Weighted average number of ordinary shares - number 1	278,351,746	278,177,070
Basic earnings per share - cents per share	(417.30)	(112.97)

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

Diluted

As the Company reported a loss in both periods there are no dilutive adjustments to be made

8. Intangible assets

	Exploration and evaluation assets	Other assets	Total
	$m	$m	$m
Cost
At 1st January 2014	1,630.9	4.5	1,635.4
Acquisitions (note19)	76.8	-	76.8
Transfer to property, plant and equipment (note 9)	(40.8)	-	(40.8)
Write-off	(471.1)	-	(471.1)
Additions	480.8	1.3	482.1
Balance at 31 December 2014 and 1st 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
Transfer to property, plant and equipment (note 9)	(12.9)	-	(12.9)
Disposals and exploration costs written off	(144.1)	-	(144.1)
Balance at 31 December 2015	1,671.0	6.3	1,677.3
Accumulated amortisation and impairment
At 1st January 2014	-	(1.5)	(1.5)
Amortisation charge for the period	-	(1.6)	(1.6)
At 31 December 2014 and 1 January 2015	-	(3.1)	(3.1)
Amortisation charge for the period	-	(1.5)	(1.5)
At 31 December 2015	-	(4.6)	(4.6)
Net book value
At 31st December 2015	1,671.0	1.7	1,672.7
At 31 December 2014	1,676.6	2.7	1,679.3

The exploration write-off represents exploration expenditure in respect of Ber Bahr, Cote d'Ivoire, Angola, Malta and Morocco (Sidi Moussa, Mir Left and Juby Maritime fields), now expensed to the income statement.

Exploration and evaluation assets are comprised of the Company's PSC interests in exploration and appraisal assets in the Kurdistan Region of Iraq. Exploration and evaluation assets are not amortised as they are not available for use but are assessed for impairment indicators annually under IFRS 6.

The net book value of $1.7 million (2014: $2.7 million) of other assets is principally software.

 

9. Property, plant and equipment

	Oil and gas assets	Other assets	Total
	$m	$m	$m
Cost
At 1st January 2014	2,279.5	7.8	2,287.3
Additions	193.4	1.4	194.8
Write-off	(80.9)		(80.9)
Transfer from intangible assets (see note 8)	40.8	-	40.8
At 31 December 2014 and 1st January 2015	2,432.8	9.2	2,442.0
Addition	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	2,558.9	8.9	2,567.8
Accumulated depreciation and impairment
At 1st January 2014	(281.1)	(3.0)	(284.1)
Depreciation charge for the period	(141.0)	(1.7)	(142.7)
At 31 December 2014 and 1st 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	(1,632.1)	(6.3)	(1,638.4)
Net book value
At 31 December 2015	926.8	2.6	929.4
At 31 December 2014	2,010.7	4.5	2,015.2

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. Other assets include leasehold improvements, office furniture and motor vehicles.

Property, plant and equipment is assessed annually for impairment indicators and if impairment indicators exist the assets are then assessed for impairment. In the current year, sustained low oil price and production that was lower than expectation represented indicators of impairment for the Company's two producing oil assets: Taq Taq and Tawke. Impairment assessments for both assets were prepared on a value in use basis using discounted future cash flows based on estimated 2P reserves profiles. The key assumptions used for the impairment testing were:

		Discount rate	Short-term Brent oil price 2016/2017	Long-term Brent oil price from 2020
Kurdistan		12.5%	$40 - 45/bbl	$75/bbl

The Taq Taq asset was impaired by $1,038 million following a reduction in reserves and long term oil price. For the Tawke asset, where there was no impairment, a $5/bbl change in  Brent oil price assumption would result in an impairment of circa $50 million; and a 1% change in discount rate assumption would result in impairment a circa $25 million.

 

10. Trade and other receivables

	2015	2014
	$m	$m
Trade receivables- non current	365.3	-
Trade receivables- current	57.6	232.9
Other receivables	17.2	49.4
Prepayments	4.2	21.4
	444.3	303.7

 

Trade receivables are monies owed by the KRG, principally for export sales. Although the trade receivable balance is due for payment, management has assessed that, based on current price of oil and the current payment mechanism in place, it is unlikely that the full balance will be recovered before the end of 2016. Management has therefore classified the balance expected to be recovered in the year, based on current oil prices, as current, with the remainder of the balance presented as non-current. The pace of recovery of the balance owed may vary according to a number of factors, including oil price. Further information is provided in in the Significant accounting estimates and judgements in note 1.

11. Cash and cash equivalents

	2015	2014
	$m	$m
Cash and cash equivalents	455.3	489.1
	455.3	489.1

Cash is primarily held on time deposit with major financial institutions or in US Treasury. Cash includes the Company's share of cash held in its joint operations and $21.0 million (2014: $166.1 million) of restricted cash used as cash collateral on letters of credit and performance guarantees.

12. Trade and other payables

	2015	2014
	$m	$m
Trade payables	15.1	69.0
Other payables	15.2	16.5
Accruals	50.3	98.5
Deferred consideration	78.0	5.0
	158.6	189.0
Non-current	78.0	5.0
Current	80.6	184.0
	158.6	189.0

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 $73.0m. The principal 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 discount on the deferred consideration will be capitalised against the asset and the balance reassessed at each balance sheet date.

13. Deferred income

	2015	2014
	$m	$m
Non-current	46.0	47.8
Current	3.0	6.2
	49.0	54.0

Deferred income is royalty income received in advance for the Taq Taq PSC. The deferred income is recognised in the statement of comprehensive income in a manner consistent with how the royalty income becomes due. Once the deferred income has been fully recognised, the joint operating partner will recommence cash payment for the royalty.

14. Provisions

	2015	2014
	$m	$m
Balance at 1st January	19.4	16.9
Interest unwind	0.8	0.8
Additions	5.0	1.7
Balance at 31 December	25.2	19.4
Non-current	25.2	19.4
Current	-	-
Balance at 31 December	25.2	19.4

Non-current provisions cover expected decommissioning and abandonment costs resulting from the net ownership interests in petroleum and natural gas assets, including well sites and gathering systems. The decommissioning and abandonment provision is based on management's best estimate of the expenditure required to settle the present obligation at the end of the period.

The cash flows relating to the decommissioning and abandonment provisions are expected to occur between 2031 and 2039. The provision is the discounted present value of the cost, using existing technology at current prices.

15. Long-term borrowings and net debt

	1 Jan 2015	New Bond	Merger of bonds	Discount unwind	Net Cash Outflow and FX	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

The Company completed the issue of senior unsecured Bonds on 26 March 2015 on the same commercial terms and coupon as the existing bonds issued 14 May 2014. The bonds were priced in line with the trading level of the existing bonds and consequently were issued at a discount. Post-issuance, the new bonds were merged with the existing bonds resulting in a merged senior unsecured $730 million bond with a coupon rate of 7.5% ($54.8m per annum) payable on a biannual basis. The fair value of the $730 million bond at 31 December 2015 was $511m million (at 31 December  2014 , the fair value of the $500 million bond was $452 million).

 

16. Share capital

	Suspended Voting  Ordinary shares	Voting Ordinary shares	Total  Ordinary Shares
At 1st January 2014	47,166,873	233,081,325	280,248,198
Sale of 3,250,000 ordinary shares by affiliated shareholders to third parties on 27th January 2014 and 21th February 2014	(4,642,857)	4,642,857	-
Sale of 2,170,000 ordinary shares by affiliated shareholders to third parties on 10th March 2014	(3,100,000)	3,100,000	-
Sale of 1,120,000 and 3,000,000 ordinary shares by affiliated shareholders to third parties on 2nd July 2014 and 7th July 2014 respectively	(5,885,715)	5,885,715	-
At 31 December 2014 and 1 January 2015  - fully paid1	33,538,301	246,709,897	280,248,198
Conversion of 3,916,616 suspended ordinary voting shares on 13th February 2015  as a result of a sale of 2,000,000 and 1,400,000 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  - fully paid1	29,621,685	250,626,513	280,248,198

1.   Voting ordinary shares includes 1,865,720 (2014: 2,006,362) treasury shares

On the sale of voting ordinary shares from an affiliated shareholder to a third party, the affiliated shareholders 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.

On 13th 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.

On 27th January 2014 2,250,000 voting ordinary shares were transferred from affiliated shareholders to third parties.

On 21st February 2014 a further 1,000,000 voting ordinary shares were transferred from affiliated shareholders to third parties. On 7th March 2014 4,642,857 suspended voting ordinary shares were converted to voting ordinary shares in accordance with the terms of the suspended voting ordinary shares.

On 10th March 2014 2,170,000 voting ordinary shares were transferred from affiliated shareholders to third parties and on the 11th March 2014 3,100,000 suspended voting ordinary shares were converted to voting ordinary shares in accordance with the terms of the suspended voting ordinary shares.

On 2nd July 2014, 1,120,000 voting ordinary shares were transferred from affiliated shareholders to third parties.

On 7th July 2014 a further 3,000,000 voting ordinary shares were transferred from affiliated shareholders to third parties.

 On 24th July 2014, 5,885,715 suspended voting ordinary shares were converted to voting ordinary shares in accordance with the terms of the suspended voting ordinary shares.

On 10th December 2014 2,000,000 voting ordinary shares were transferred from affiliated shareholders to third parties.

On 16th December 2014 a further 1,400,000 voting ordinary shares were transferred from affiliated shareholders to third parties.

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.

17. Acquisitions

On 22 September 2015 the Company acquired a 36% operated stake in the Bina Bawi field, thereby increasing its interest to 80%. The consideration comprises an upfront payment of $5m; a contingent payment of $70m is payable once gas production exceeds certain threshold volumes from the Miran and Bina Bawi fields; a second contingent payment of $75m is payable two years after the date of the second payment. In addition, in consideration for the KRG approving the transaction, the Company released the KRG from monies owed of $25 million, which was owed in relation to past expenses incurred on the Miran field and accrued after KRG exercised its back in right in September 2013.

	Bina Bawi 2015
	$m
Intangible assets	101.0
Liabilities	(1.5)
Cash acquired	1.1
Fair value of assets acquired	100.6

In order to recognise deferred consideration at its fair value, the balance has been discounted using an estimate for the credit risk of the Company by using the implied cost of debt of the Company at the time of the transaction. This has resulted in in a balance of $70.6 million being recognised at the acquisition date.

18. 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 has a work obligation of $33.0 million in relation to the Sidi Moussa licence.

The Company leases temporary production and office facilities under operating leases. During the period ended 31 December 2015 $4.0 million (2014: $5.1 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.

19. Annual report

Copies of the 2015 annual report will be despatched to shareholders in March 2015 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.

20. Statutory accounts

The financial information for the year ended 31 December 2015 contained in this preliminary announcement has been audited and was approved by the board on 2 March 2015.

The financial information in this statement does not constitute the Company's statutory accounts for the years ended 31 December 2015 or 2014. The financial information for 2015 and 2014 is derived from the statutory accounts for 2014, which have been delivered to the Registrar of Companies, and 2015, which will be delivered to the Registrar of Companies and issued to shareholders in March 2015. The auditors have reported on the 2015 and 2014 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 2015 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 2014 annual report.

 

END

 

 

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