7 August 2018

Genel Energy plc

Unaudited results for the period ended 30 June 2018

 

Genel Energy plc ('Genel' or 'the Company') announces its unaudited results for the six months ended 30 June 2018.

 

Murat Özgül, Chief Executive of Genel, said:

"Genel continues to deliver on its focus. We are generating significant free cash flow, averaging over $10 million a month in the first half of 2018 and moving us rapidly towards a net cash position. The impressive performance we have seen at Peshkabir will further increase cash generation, and the ongoing appraisal success provides the potential for both production to exceed guidance and for proven and probable reserves to increase.

 

Growing cash generation provides a solid bedrock from which we are able to pursue multiple growth opportunities, with Bina Bawi oil offering exciting potential within the Genel portfolio.

 

With 11 wells currently drilling or to be drilled on our producing assets in the Kurdistan Region of Iraq in H2 2018, of which eight are expected to be completed and adding to production by the end of the year, we are well positioned to both add value through the drill bit and further bolster our financial strength."

 

Results summary ($ million unless stated)

 

	H1 2018	H1 2017	FY 2017
Production (bopd, working interest)	32,100	37,100	35,200
Revenue	161.1	87.1	228.9
Net gain arising from the RSA	-	-	293.8
EBITDAX1	137.4	64.7	475.5
Depreciation and amortisation	(63.6)	(45.7)	(117.4)
Exploration expense	(0.5)	(4.8)	(1.9)
Impairment of property, plant and equipment	-	-	(58.2)
Operating profit	73.3	14.2	298.0
Cash flow from operating activities	125.1	114.2	221.0
Capital expenditure	34.1	41.0	94.1
Free cash flow2	70.1	54.6	99.1
Cash3	233.2	245.7	162.0
Total debt	300.0	422.8	300.0
Net debt4	63.8	158.3	134.8
Basic EPS (¢ per share)	21.3	8.4	97.1

 

1. EBITDAX is earnings before interest, tax, depreciation, amortisation, exploration expense and impairment which is operating profit adjusted for the add back of depreciation and amortisation ($63.6 million), exploration expense ($0.5 million) and impairment of property, plant and equipment (nil)
2. Free cash flow is net cash generated from operating activities less cash outflow due to purchase of intangible assets ($10.5 million) and purchase of property, plant and equipment ($29.5 million) and interest paid ($15.0 million)
3. Cash reported at 30 June 2018 excludes $17.5 million of restricted cash 
4. Reported IFRS debt less cash

 

 

Highlights

• Net working interest production averaged 32,100 bopd in H1 2018, in line with guidance
• Peshkabir continues to exceed expectations, with the successful Peshkabir-4 and 5 wells boosting gross current field production to 35,000 bopd
  • Peshkabir-5 has successfully proved the westward extension of the field, with an increase in proven and probable reserves expected to follow
• Net working interest production currently c.35,500 bopd
• $151 million of cash proceeds received in H1 2018 (H1 2017: $139 million), boosted by the impact of the Receivable Settlement Agreement and a higher oil price, with strong free cash flow generation of $70 million
• Cash of $233 million at 30 June 2018 ($162 million at 31 December 2017)
• Net debt of $64 million at 30 June 2018 ($135 million at 31 December 2017)

 

Outlook

• 11 wells set to be under drilling operations across assets in the Kurdistan Region of Iraq in H2 2018, with eight expected to be completed and contributing to production by the end of the year
• Cash generation expected to remain strong in H2 2018, with monthly free cash flow of over $10 million
• Genel expects to be in a net cash position around the end of 2018
• Field development plan for Bina Bawi oil complete and set to be submitted to the Ministry of Natural Resources, with Bina Bawi and Miran gas plans to also be submitted in H2 2018

• 2018 guidance refined:
  • Production guidance of c.32,800 bopd reiterated, with the potential for this to be exceeded through an ongoing positive performance at Peshkabir and the resumption of drilling at Tawke and Taq Taq
  • Capital expenditure net to Genel is forecast to be $95-125 million (previously $95-140 million):

-          Tawke PSC and Taq Taq net to Genel of $70-80 million (previously $60-85 million), as work ramps up across both licences

-          Miran and Bina Bawi capex of $15-30 million (previously $25-40 million), as the work programme focuses on progression of the high-value oil opportunity at Bina Bawi

-          African exploration cost unchanged at$10-15 million, with the majority relating to seismic shooting offshore Morocco, which will be covered by restricted cash

-          Opex of c.$30 million and G&A of c.$15 million cash cost unchanged

 

For further information, please contact:

 

Genel Energy Andrew Benbow, Head of Communications	+44 20 7659 5100
Vigo Communications Patrick d'Ancona	+44 20 7390 0230

 

There will be a presentation for analysts and investors today at 0930 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. The information contained herein has not been audited and may be subject to further review.

OPERATING REVIEW

 

PRODUCTION

 

Net working interest production in H1 2018 averaged 32,100 bopd, in line with guidance.

 

(by PSC in bopd)	Export via pipeline	Refinery   sales1	Total           sales	Total production2	Genel net production
Tawke (inc. Peshkabir)	104,904	0.35	104,904	105,771	26,443
Taq Taq	11,603	1,182	12,785	12,769	5,618
Total	116,507	1,182	117,689	118,540	32,061

1 Refinery sales at Taq Taq denote sales to the Bazian refinery

2 Difference between production and sales relates to inventory movements

 

All sales during the period were invoiced at the wellhead export netback price.

 

KRI OIL ASSETS

Five wells were spud across our assets in the KRI in the period, four of which were on the Peshkabir field. Drilling work is heavily loaded towards the second half of the year, with 11 wells set to be under operation in H2 on our producing fields, with eight expected to be adding to production by the end of the year.

 

TAWKE PSC (25% working interest)

The Tawke PSC produced an average of 105,800 bopd in H1 2018, slightly down on H1 2017 (109,700 bopd), with additional production from the successful drilling campaign at the Peshkabir field coming post-period end. Current Tawke PSC production is c.121,000 bopd, with success from the remaining Peshkabir wells, and the resumption of drilling at the Tawke field, having the potential to further increase this figure.

 

Production from the Tawke PSC benefits from the Receivable Settlement Agreement ('RSA'), and these increases bolster our already significant free cash flow generation.

 

Tawke field

Activity in H1 included ongoing workovers of existing wells, which has mitigated decline at the Tawke field in the last three months. Drilling will resume at the field in the second half of the year, with up to four production wells set to be spud. Two are scheduled as Jeribe producers, and up to two as Cretaceous producers.

 

Drilling will arrest production decline at Tawke, as expected with mature field infill drilling, with the overall objective to maximise production and cash-generation.

 

Peshkabir field

Peshkabir continues to exceed expectations, with the benefit of ongoing appraisal success increasing production in H2 2018. Peshkabir-4 is now adding to production at a stable rate of 12,000 bopd, with Peshkabir-5 adding a further 8,000 bopd, materially surpassing the operator's previously announced summer 2018 Peshkabir production target of 30,000 bopd. The field is currently producing c.35,000 bopd, with another four wells set to be completed in 2018.

 

Peshkabir-5 was drilled seven kilometres west of Peshkabir-3, and has successfully proved the westward extension of the field. As it was drilled in an area designated P3 (possible) reserves, should production continue to match current expectations then it would lead to an increase in proven and probable reserves at the field. With 217 MMboe of reserves booked in the in the P3 (possible) category as at the end of 2018, this increase is potentially significant.

 

Activity continues apace at Peshkabir. Two wells, Peshkabir-6 and Peshkabir-7, are now at target depth, with the former aiming to establish the Cretaceous oil/water contact and exploring the field's untested deeper Triassic formation, and the latter targeting infill production. Peshkabir-8 will also target further production, with Peshkabir-9 being drilled to test the eastern extension of the field, as we work with the operator to ascertain the full extent of Peshkabir's potential.

 

Given the potential for a material increase from current production levels, work is being undertaken on facilities at the field. The central processing facility, which has been brought across from Taq Taq and is expected onstream later this year, is set to ensure that surface capacity is sufficient to service production. 

 

Discussions are ongoing with the operator regarding the Enhanced Oil Recovery project, under which excess gas from Peshkabir would be used to boost oil production from the Tawke licence.

 

TAQ TAQ (44% working interest, joint operator)

Production at Taq Taq remained stable in H1 as the well intervention and production optimisation programme, focused on the provision of artificial lift and water shut off in existing wells, continued to give encouraging results.

 

The stabilisation of production provides a solid base from which to ramp up activity at the field. Work to analyse the result of the TT-29w well, which encountered a deeper free water level and more extensive oil bearing cretaceous reservoirs on the northern flank of the field than previously forecast, has now been completed. The results have helped in the formulation of an updated field development plan ('FDP'), which has now been completed and agreed with our field partners and the Ministry of Natural Resources.

 

Phase one of the FDP is a five well programme, starting towards the end of Q3, and ending in Q2 2019. The drilling programme will target the flanks in order to prove up the remaining potential of the field, starting with the TT-32 well, which will test the extent of oil to the north of the TT-29w well. The next well will then be drilled as a sidetrack on the western flank of the field, before the rig moves to the southern flank. Drill locations will follow depending on results.

 

Given the stabilisation of production at Taq Taq, we expect these wells to increase field production, with the benefits starting to be seen towards the end of the year. The field continues to generate meaningful free cash flow, boosted by an ongoing cost reduction programme.

 

BINA BAWI AND MIRAN (100% working interests and operator)

Work continues to unlock the transformational potential of the Bina Bawi and Miran licences. The focus in H1 has been on the progression of the high-value early oil development at Bina Bawi.

 

The field development plan for Bina Bawi oil has now been completed, and is set to be submitted to the Ministry of Natural Resources. The FDP confirms Genel's expectation that first oil would be achievable around six months after the final investment decision. Light oil (44-47◦ API) has already been tested at Bina Bawi, with the Bina Bawi-3 well having flowed at c.3,500 bopd. Phase one of the development would see the recompletion of this well, and a sidetrack of the Bina Bawi-1 well, both of which target the proven Mus reservoir, and would aim for a combined 5,000 bopd of initial production. The cost to first oil is estimated at c.$20 million.

 

Phase two, to be executed simultaneously to phase one, would be the drilling of up to four new wells, targeting a production plateau of 10-15,000 bopd, achievable a year from the beginning of work. Phase three would then constitute additional infill wells as required.

 

Oil production from Bina Bawi would benefit from cost-recovery of the significant capital outlay already made by Genel at Bina Bawi, and has the potential to add material cash flow. Discussions are ongoing with the Ministry of Natural Resources in order to expedite the development of Bina Bawi oil.

 

Genel estimates that 34 MMbbls of light oil is recoverable under the FDP, and would be converted to 2P reserves upon final investment decision.

 

In January 2018 Bina Bawi and Miran CPRs confirmed a c.45% uplift to gross 2C raw gas resources to 14.8 Tcf. The upstream part of the project has been materially de-risked, with 1C volumes more than sufficient for the gas volumes required under the gas lifting agreement. Following the CPR, further reservoir engineering has demonstrated the viability of high-rate gas wells, which in turn more than halves the number of wells required to produce the volumes under the gas lifting agreement, materially reducing the overall cost of the project.

 

A field development plan regarding Bina Bawi gas is set to be submitted to the Ministry of Natural Resources around the end of Q3 2018, with one for the Miran field around the end of the year.

 

Genel is ready to progress the upstream as required, with further investment to be made appropriate to progress on the midstream.

 

 

EXPLORATION

 

Onshore Somaliland, the processing of c.3,500 km of raw 2D seismic data on the SL-10B/13 (Genel 75% working interest, operator) and Odewayne (Genel 50% working interest, operator) is almost complete.  Analysis and interpretation is underway. Evidence of a thick Mesozoic rift basin continues to provide encouragement, and the first analysis of this highly-prospective region in over 25 years is expected to complete in Q4. A prospect inventory will then be developed, guiding the optimal strategy to maximise future value, with the potential to spud a well around the end of 2019.

 

The 3D seismic campaign on the Sidi Moussa licence (Genel 75% working interest, operator), offshore Morocco, has now begun. Seismic acquisition is expected to be completed in the middle of Q4 2018.  Fast-track processing will begin ahead of the completion of this acquisition, as Genel de-risks the licence and assesses future activity.


FINANCIAL REVIEW

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

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

 

In the first half of the year, successful delivery of these priorities, together with an improving oil price, has produced positive results, with free cash flow of $70 million representing an increase of 28% on the previous year.

 

Our net debt has reduced significantly to $64 million compared to $135 million at the end of 2017 and we expect to be in a net cash position around the end of 2018.

 

We will continue to be disciplined in our capital allocation and invest in areas where we can deliver value. Currently this means investment in Peshkabir, where success will provide incremental cash generation in the second half, and our other producing assets, which also offer opportunities to increase near-term cash flow.

 

We will make further investment in Bina Bawi oil and our gas potential when we can see a clear roadmap to unlocking value. As there remains limited visibility on the gas developments at Bina Bawi and Miran, spend has been minimised, with the focus on completing the FDP for Bina Bawi oil.

 

Rigorous cost management is maintained across all operations, while ensuring spend is sufficient to take advantage of the growth opportunities in the portfolio.

 

A summary of the financial results for the year is provided below.

 

As regular payments for oil sales have now been received from the KRG for almost three years, the Company will cease to make monthly announcements, and will instead update on cash receipts as part of its standard corporate reporting schedule.

 

Financial results for the half-year

 

Income statement

Revenue has increased by 85% year-on-year, from $87.1 million to $161.1 million. This is principally a result of the improved revenue generation from the Tawke PSC arising from the RSA, which was signed in August 2017 and generated incremental revenue of $48.2 million in the first half of 2018.  Additional benefit has arisen from improved Brent oil price of $71/bbl (H1 2017: $52/bbl).

 

Working interest production of 32,100 bopd was lower than the first half last year (H1 2017: 37,100 bopd), which benefited from Taq Taq working interest daily production being around 5,000 bopd higher since around May 2017.

 

Production costs of $12.1 million (H1 2017: $13.2 million) are broadly in line with last year, with $/bbl staying around $2/bbl.

 

Depreciation and amortisation of oil assets has increased overall by $18.6 million as a result of the inclusion of amortisation of $28.8 million relating to intangible assets arising from the RSA. This was offset by a $10.2 million decrease in depreciation as a result of lower production.

 

 

General and administration costs were $11.8 million (H1 2017: $10.1 million), of which cash costs were $8.6 million (H1 2017: $6.4 million). Gross cost was reduced by 8% from the prior year, with the net increase caused primarily by movement in the exchange rates between sterling and US dollar.

 

Taxation

Under the KRI PSC's, tax due is paid on behalf of the Company 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.

 

Capital expenditure

Capital expenditure for the period was $34.1 million (H1 2017: $41.0 million). Cost recovered spend on producing assets in the KRI was $27.8 million (H1 2017: $28.1 million) with spend on exploration and appraisal assets amounting to $6.3 million (H1 2017: $12.9 million), principally incurred on the Miran PSC and the Bina Bawi PSC.

 

Cash flow and cash

Net cash flow from operations was increased as a result of higher revenue to $125.1 million (H1 2017: $114.2 million), with last year benefiting from $50.9 million of one-off positive working capital movements relating to the overdue KRG receivable.

 

Free cash flow after interest was $70.1 million (H1 2017: $54.6 million).

 

$17.5 million (H1 2017: $18.5 million) of cash is restricted and therefore excluded from reported cash of $233.2 million (H1 2017: $245.7 million). Overall, there was a net increase in cash of $71.1 million compared to a decrease of $161.1 million last period after $216.7 million of cash was used to buy back of Company bonds in H1 2017.

 

Debt

Reported IFRS debt was $297.0 million (31 December 2017: $296.8 million) and net debt was $63.8 million (31 December 2017: $134.8 million).

 

The bond has three financial covenant maintenance tests:

 

Financial covenant	Test	H1 2018
Net debt / EBITDAX (rolling 12 months)	< 3.0	0.1
Equity ratio (Total equity/Total assets)	> 40%	77%
Minimum liquidity	> $30m	$233m

 

Net assets

Net assets at 30 June 2018 were $1,672.9 million (31 December 2017: $1,609.8 million) and consist primarily of oil and gas assets of $1,823.6 million (31 December 2017: $1,847.9 million), trade receivables of $84.4 million (31 December 2017: $73.3 million) and net debt of $63.8 million (31 December 2017: $134.8 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 in treasury bills or on time deposits with a number of major financial institutions. Suitability of banks is assessed using a combination of sovereign risk, credit default swap pricing and credit rating.

 

Dividend

No interim dividend will be paid (H1 2017: nil) or is expected to be paid in the near future. 

 

 

 

 

Going concern

The Directors have assessed that the Company's forecast liquidity provides adequate headroom over forecast expenditure for the 12 months following the signing of the half-year condensed consolidated financial statements for the period ended 30 June 2018 and consequently that the Company is considered a going concern.

 

Principal risks and uncertainties

The Company is exposed to a number of risks and uncertainties that may seriously affect its performance, future prospects or reputation and may threaten its business model, future performance, solvency or liquidity. The following risks are the principal risks and uncertainties of the Company, which are not all of the risks and uncertainties faced by the Company: Development and recovery of reserves and resources; Commercialisation of KRI gas business; M&A activity; KRI natural resources industry; Payment for KRI sales; Regional risk; Corporate governance failure; Capital structure and financing; Local communities; and Health and safety risks. Further detail on each risk was provided in the 2017 Annual Report. There has been no change in principal risks and uncertainties since year-end.

 

Statement of directors' responsibilities

The directors confirm that these condensed interim financial statements have been prepared in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union and that the interim management report includes a true and fair review of the information required by DTR 4.2.7 and DTR 4.2.8, namely:

 

• an indication of important events that have occurred during the first six months and their impact on the condensed set of financial statements, and a description of the principal risks and uncertainties for the remaining six months of the financial year; and
• material related-party transactions in the first six months and any material changes in the related-party transactions described in the last annual report.

 

The directors of Genel Energy plc are listed in the Genel Energy plc Annual Report for 31 December 2017. A list of current directors is maintained on the Genel Energy plc website: www.genelenergy.com

 

 

By order of the Board

 

Murat Ozgul

CEO

6 August 2018

 

Esa Ikaheimonen

CFO

6 August 2018

 

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.

 

Condensed consolidated statement of comprehensive income

For the period ended 30 June 2018

 

				6 months to 30 June 2018	6 months to 30 June 2017	Year to 31 Dec  2017
		Notes		$m	$m	$m
Revenue		3		161.1	87.1	228.9
Production costs		4		(12.1)	(13.2)	(27.5)
Depreciation and amortisation of oil assets		4		(63.4)	(44.8)	(116.1)
Gross profit				85.6	29.1	85.3
Exploration expense		4		(0.5)	(4.8)	(1.9)
Impairment of property, plant and equipment		4		-	-	(58.2)
General and administrative costs		4		(11.8)	(10.1)	(21.0)
Net gain arising from the RSA		2		-	-	293.8
Operating profit				73.3	14.2	298.0
Operating profit is comprised of:
EBITDAX				137.4	64.7	475.5
Depreciation and amortisation				(63.6)	(45.7)	(117.4)
Exploration expense		4		(0.5)	(4.8)	(1.9)
Impairment of property, plant and equipment		4		-	-	(58.2)
Gain arising from bond buy back		11		-	32.6	32.6
Finance income		5		2.1	3.4	4.9
Bond interest expense		5		(15.0)	(20.9)	(35.5)
Other finance expense		5		(1.1)	(5.8)	(28.0)
Profit before income tax				59.3	23.5	272.0
Income tax expense		6		-	-	(1.0)
Profit and total comprehensive income				59.3	23.5	271.0
Attributable to:
Shareholders' equity				59.3	23.5	271.0
				59.3	23.5	271.0
Profit per ordinary share
Basic			7	21.3	8.4	97.1
Diluted			7	21.2	8.4	96.7

 

 

Condensed consolidated balance sheet

At 30 June 2018

		30 June 2018	30 June 2017	31 Dec 2017
	Notes	$m	$m	$m
Assets
Non-current assets
Intangible assets	8	1,264.1	930.2	1,282.9
Property, plant and equipment	9	559.5	604.5	565.0
Trade and other receivables	10	-	127.1	-
		1,823.6	1,661.8	1,847.9
Current assets
Trade and other receivables	10	88.3	84.5	78.5
Restricted cash		17.5	18.5	18.5
Cash and cash equivalents	11	233.2	245.7	162.0
		339.0	348.7	259.0
Total Assets		2,162.6	2,010.5	2,106.9
Liabilities
Non-current liabilities
Trade and other payables		(74.5)	(93.0)	(70.7)
Deferred income		(33.8)	(39.0)	(36.1)
Provisions		(31.0)	(24.5)	(29.3)
Borrowings	11	(297.0)	(404.0)	(296.8)
		(436.3)	(560.5)	(432.9)
Current liabilities
Trade and other payables		(48.1)	(85.6)	(59.4)
Deferred income		(5.3)	(3.7)	(4.8)
		(53.4)	(89.3)	(64.2)
Total liabilities		(489.7)	(649.8)	(497.1)
Net assets		1,672.9	1,360.7	1,609.8
Owners of the parent
Share capital		43.8	43.8	43.8
Share premium account		4,074.2	4,074.2	4,074.2
Accumulated losses		(2,445.1)	(2,757.3)	(2,508.2)
Total equity		1,672.9	1,360.7	1,609.8

 

 

Condensed consolidated statement of changes in equity

For the period ended 30 June 2018

	Share capital	Share premium	Accumulated losses	Total equity
	$m	$m	$m	$m
At 1 January 2017	43.8	4,074.2	(2,784.6)	1,333.4
Profit and total comprehensive income	-	-	23.5	23.5
Share-based payments	-	-	3.8	3.8
At 30 June 2017	43.8	4,074.2	(2,757.3)	1,360.7
At 1 January 2017	43.8	4,074.2	(2,784.6)	1,333.4
Profit and total comprehensive income	-	-	271.0	271.0
Share-based payments	-	-	5.4	5.4 5.4
At 31 December 2017 and 1 January 2018	43.8	4,074.2	(2,508.2)	1,609.8
Profit and total comprehensive income	-	-	59.3	59.3
Share based payments	-	-	3.8	3.8
At 30 June 2018	43.8	4,074.2	(2,445.1)	1,672.9

 

 

Condensed consolidated cash flow statement

For the period ended 30 June 2018

 

					30 June 2018	30 June 2017	31 Dec 2017
		Notes			$m	$m	$m
Cash flows from operating activities
Profit and total comprehensive income					59.3	23.5	271.0
Adjustments for:
Gain on bond buy back					-	(32.6)	(32.6)
Finance income					(2.1)	(3.4)	(4.9)
Bond interest expense					15.0	20.9	35.5
Other finance expense					1.1	5.8	28.0
Taxation					-	-	1.0
Depreciation and amortisation					63.6	45.7	117.4
Exploration expense					0.5	4.8	1.9
Impairment of property, plant and equipment					-	-	58.2
Net gain arising from the RSA					-	-	(293.8)
Other non-cash items					3.0	2.8	2.8
Changes in working capital:
Proceeds against overdue receivable					-	50.9	67.5
Trade and other receivables					(10.2)	4.1	(33.5)
Trade and other payables and provisions					(7.1)	(9.0)	0.6
Cash generated from operations					123.1	113.5	219.1
Interest received					2.1	0.8		2.2
Taxation paid					(0.1)	(0.1)		(0.3)
Net cash generated from operating activities					125.1	114.2		221.0
Cash flows from investing activities
Purchase of intangible assets					(10.5)	(12.7)		(26.8)
Purchase of property, plant and equipment					(29.5)	(23.4)		(52.4)
Restricted cash					1.0	1.0		1.0
Net cash used in investing activities					(39.0)	(35.1)		(78.2)
Cash flows from financing activities
Repurchase of Company bonds					-	(216.7)		(216.7)
Bond refinancing					-	-		(128.5)
Interest paid					(15.0)	(23.5)		(42.7)
Net cash used in financing activities					(15.0)	(240.2)		(387.9)
Net increase / (decrease) in cash and cash equivalents					71.1	(161.1)		(245.1)
Foreign exchange income / (loss) on cash and cash equivalents					0.1	(0.2)		0.1
Cash and cash equivalents at 1 January					162.0	407.0		407.0
Cash and cash equivalents at period end			11		233.2	245.7	162.0

 

 

Notes to the condensed consolidated financial statements

 

1. Basis of preparation

 

The Company is a public limited company incorporated and domiciled in Jersey with a listing on the London Stock Exchange. The address of its registered office is 12 Castle Street, St Helier, Jersey, JE2 3RT.

 

The half-year condensed consolidated financial statements for the six months ended 30 June 2018 and six months ended 30 June 2017 are unaudited and have been prepared in accordance with the Disclosure and Transparency Rules of the Financial Conduct Authority and with IAS 34 'Interim Financial Reporting' as adopted by the European Union and were approved for issue on 6 August 2018. They do not comprise statutory accounts within the meaning of Article 105 of the Companies (Jersey) Law 1991.  The half-year condensed consolidated financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2017, which have been prepared in accordance with IFRS as adopted by the European Union. The annual financial statements for the period ended 31 December 2017 were approved by the board of directors on 21 March 2018. The report of the auditors was unqualified, did not contain an emphasis of matter paragraph and did not contain any statement under the Companies (Jersey) Law 1991. The financial information for the year to 31 December 2017 has been extracted from the audited accounts.

 

The Company provides non-Gaap measures to provide greater understanding of its financial performance and financial position. EBITDAX is presented in order for the users of the financial statements to understand the 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 invest in the business. Net debt is reported in order for users of the financial statements to understand how much debt remains unpaid if the Company paid its debt obligations from its available cash. There have been no changes in related parties since 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 half-year condensed 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.  

 

2. Accounting policies

 

The accounting policies adopted in preparation of these half-year condensed consolidated financial statements are consistent with those used in preparation of the annual financial statements for the year ended 31 December 2017.

 

The preparation of these half-year condensed consolidated 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.

 

Significant accounting judgements, estimates and assumptions

In preparing these half-year condensed consolidated financial statements, the following significant estimates and judgements have been made:

 

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 net gain arising from the RSA for the year ended 31 December 2017. It is also relevant to the assessment of going concern and the viability statement.

 

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

 

 

$/bbl	2019	2020	2021	2022
HY 2018 forecast	63	66	72	74
YE 2017 forecast	63	66	72	74

 

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 and assessing the cost and likely timing of decommissioning activity and associated costs. This estimation also impacts the assessment of going concern and the viability statement.

 

Proven and probable reserves are estimates of the amount of hydrocarbons that can be economically extracted from the Company's assets. The Company estimates its reserves using standard recognised evaluation techniques. Generally, the Company considers proven and probable reserves ("2P" - generally accepted to have circa 50% probability) to be the best estimate for future production and quantity of oil within an asset when assessing its recoverable amount, and therefore this usually forms the basis of calculating depreciation, amortisation of oil and gas assets and testing for impairment. Assets assessed as 2P are generally classified as property, plant and equipment as development or producing assets and depreciated using the units of production methodology.

 

Hydrocarbons that are not assessed as 2P are considered to be resources and are classified as exploration and evaluation assets. These assets are expenditures incurred before technical feasibility and commercial viability is demonstrable. Estimates of resources for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and being depleted and are likely to contain estimates and judgements with a wide range of possibilities. These assets are considered for impairment under IFRS 6.

 

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

 

Assessment of reserves and resources are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves.

 

Estimation of oil and gas asset values

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

 

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

 

Discount rate is assessed by the Company using various inputs from market data, external advisers and internal calculations. A discount rate of 12.5% was used for impairment testing of the oil assets of the Company.

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

 

Change in accounting estimate - discount rate for assessing recoverable amount of producing assets

Following the significant change in the macro geo-political, economic and industry environment, the Company has updated the discount rate used for assessing the recoverable amount of its producing assets from 15% to 12.5%. This has had no impact on the financial statements, although it has a positive impact on the recoverable amount of both the Tawke CGU and the Taq Taq CGU. At the end of last year, the Company disclosed that a 2.5% change in discount rate would have a $70 million impact on the recoverable amount of the Tawke CGU and a $5 million impact on the Taq Taq CGU. The disclosures for the half-year are provided in note 9.

 

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

Netback price is used to value the Company's revenue, trade receivables and its forecast cash flows used for impairment testing and viability. It is the aggregation of realised price less transportation and handling costs. The Company does not have direct visibility on the components of the netback price realised for its oil because sales are managed by the KRG, but invoices are currently raised for payments on account using a netback price agreed with the KRG.

 

Change in accounting estimate - netback price

The Company has increased the estimated netback price adjustment by $1/bbl using the methodology agreed with the KRG for raising invoices for all sales of oil, effective from 1 August 2017. Netback adjustments to Brent are now estimated as $13/bbl discount for the Tawke PSC (2017: $12/bbl) and a $6/bbl discount for the Taq Taq PSC (2017: $5/bbl). This has resulted in a decrease of $3.6 million to H1 2018 revenue, of which $2.2 million relates to 2017. At the end of last year, the Company disclosed that a $5/bbl change in Long-term Brent would impact the Tawke CGU by $23 million and the Taq Taq CGU by $2 million, so a $1/bbl change in netback adjustment has an impact of around $5 million in total across the two CGUs. The netback adjustment price agreed with the KRG may change in the future. A $1/bbl difference in netback price would impact current year revenue and trade receivables by circa $4 million with disclosures on the sensitivities of the recoverable amount of producing assets provided in note 9.

 

Tawke RSA intangible asset

On 23 August 2017 the Company signed documentation confirming an agreement had been reached with the KRG to put in place a definitive mechanisms for the payment to the Company of trade receivables built up from overdue amounts with nominal value of $469 million owed for sales since mid-2014 ('overdue KRG receivable') together with nominal value of circa $300 million amounts owed for export sales marketed by SOMO made before 2014 for which the Company has never recognised revenue ('overdue pre-2014 receivable').

 

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

 

In 2017, the RSA resulted in the overdue KRG receivable balance being waived and in return the Company received: (1) a 4.5% royalty interest on gross Tawke PSC revenue lasting for 5 years ("the ORRI); (2) the waiver of capacity building payments due on all profit oil received under the Tawke PSC; and (3) the waiver of $4.6 million of amounts due to the KRG. As the RSA occurred at arm's length, the fair value of the consideration received from the KRG described above, which was recognised as an intangible asset 'Tawke RSA', was considered to be equal to the fair value of the receivables. The Tawke RSA exceeded the carrying amount of receivables at the time of settlement resulting in a gain of $293.8 million being recognised in the profit or loss.

 

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

 

Estimation of cost and timing of decommissioning cost

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

 

Business combinations

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

 

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

 

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

 

New Standards

The new accounting standards and amendments to existing standards have been adopted by the Group effective 1 January 2018: IFRS 15 - Revenue from Contracts with Customers, IFRS 9 - Financial Instruments, Amendments to IFRS 2, and Amendments to IAS 40. The adoption of these standards and amendments has had no material impact on the Company's results or financial statement disclosures.

 

Revenue recognition now requires definition of the customer, performance obligations and the price and allocation of price into performance obligations. The Company's performance obligation in its contract with the single customer is the delivery of crude oil at a pre-determined netback adjustment to dated Brent and the control is transferred to the buyer at the metering point when the revenue is recognised. As a result, adoption of IFRS 15 had no material change to the presentation and measurement of the Company revenue in the interim financial statements. The Company's accounting treatment of the buyback of bonds in 2017 were in line with IFRS 9 hence no transitional adjustments were required. The impact of changes to the impairment model from incurred credit losses to expected credit loss model under IFRS 9 is immaterial since the trade receivables balance are at a consistent level compared to the established operating cycle, with no issues with payment in the c.3 years. IFRS 16, which becomes effective by 1 January 2019, requires the lessee to recognize the right to use the asset and the liability, depreciate the associated asset, re-measure and reduce the liability through lease payments; unless the underlying leased asset is of low value and/or short term in nature. The Company is not considering early application of the Standard. The Company's leases are mostly low value or short term in nature. The work is currently underway to assess the financial statements impact of adopting IFRS 16, which is estimated to affect both assets and liabilities by less than c.$1 million.

 

The following new accounting standards, amendments to existing standards and interpretations have been issued but are not yet effective and have not yet been endorsed by the EU: Amendments to IFRS 9 Financial Instruments (effective 1 January 2019), Amendments to IAS 28 - Investments in Associates and Joint Ventures (effective 1 January 2019), Annual Improvements to IFRS Standards 2015-2017 (effective 1 January 2019), IFRIC 23 - Uncertainty over Income  Tax Treatments (effective 1 January 2019) and Amendments to IAS 19 - Employee Benefits (effective 1 January 2019). None of these standards have been early adopted.

 

Financial risk factors

The Company's activities expose it to a variety of financial risks: credit risk, currency risk, interest risk and liquidity risk. Since the half-year condensed consolidated financial statements do not include all financial risk management information and disclosures required in the annual financial statements; they should be read in conjunction with the Company's annual financial statements as at 31 December 2017. There have been no significant changes in any risk management policies since year end.

 

3.  Segmental information

 

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

 

6 months ended 30 June 2018

 

	Oil	MBB	Expl.	Other	Total
	$m	$m	$m	$m	$m
Revenue	161.1	-	-	-	161.1
Cost of sales	(75.5)	-	-	-	(75.5)
Gross profit	85.6	-	-	-	85.6
Exploration (expense) / credit	-	(0.2)	(0.3)	-	(0.5)
General and administrative costs	-	-	-	(11.8)	(11.8)
Operating profit / (loss)	85.6	(0.2)	(0.3)	(11.8)	73.3
Operating profit / (loss) is comprised of
EBITDAX	149.0	-	-	(11.6)	137.4
Depreciation and amortisation	(63.4)	-	-	(0.2)	(63.6)
Exploration (expense) / credit	-	(0.2)	(0.3)	-	(0.5)
Finance income	-	-	-	2.1	2.1
Bond interest expense	-	-	-	(15.0)	(15.0)
Other finance expense	(0.8)	(0.1)	-	(0.2)	(1.1)
Profit before tax	84.8	(0.3)	(0.3)	(24.9)	59.3
Capital expenditure	27.8	5.7	0.6	-	34.1
Total assets	1,049.6	869.5	33.8	209.7	2,162.6
Total liabilities	(82.1)	(79.8)	(27.3)	(300.5)	(489.7)

 

Revenue includes $48.2 million (30 June 2017: nil, 31 December 2017: $33.9 million) arising from the ORRI. Total assets and liabilities in the Other segment are predominantly cash and debt balances. 'Other' includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items.

 

6 months ended 30 June 2017

 

	Oil	MBB	Expl.	Other	Total
	$m	$m	$m	$m	$m
Revenue	87.1	-	-	-	87.1
Cost of sales	(58.0)	-	-	-	(58.0)
Gross profit	29.1	-	-	-	29.1
Exploration (expense) / credit	-	(1.9)	(2.9)	-	(4.8)
Impairment of property, plant and equipment	-	-	-	-	-
General and administrative costs	-	-	-	(10.1)	(10.1)
Operating profit / (loss)	29.1	(1.9)	(2.9)	(10.1)	14.2
Operating profit / (loss) is comprised of
EBITDAX	73.9	-	-	(9.2)	64.7
Depreciation and amortisation	(44.8)	-	-	(0.9)	(45.7)
Exploration expense	-	(1.9)	(2.9)	-	(4.8)
Impairment of property, plant and equipment	-	-	-	-	-
Gain arising from bond buy back	-	-	-	32.6	32.6
Finance income	2.7	-	-	0.7	3.4
Bond interest expense	-	-	-	(20.9)	(20.9)
Other finance expense	(0.6)	(0.1)	-	(5.1)	(5.8)
Profit / (Loss) before tax	31.2	(2.0)	(2.9)	(2.8)	23.5
Capital expenditure	28.1	7.5	5.4	-	41.0
Total assets	845.3	883.5	59.9	221.8	2,010.5
Total liabilities	(94.4)	(98.4)	(45.7)	(411.3)	(649.8)

 

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

 

For the period ended 31 December 2017

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

 

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.

 

4.         Operating costs

 

	6 months to 30 June 2018	6 months to 30 June 2017	Year to 31 December 2017
	$m	$m	$m
Production costs	12.1	13.2	27.5
Depreciation of oil and gas property, plant and equipment	34.6	44.8	83.3
Amortisation of oil and gas intangible assets	28.8	-	32.8
Cost of sales	75.5	58.0	143.6
Exploration expense	0.5	4.8	1.9
Impairment of property, plant and equipment (note 9)	-	-	58.2
Corporate cash costs	8.6	6.4	16.9
Corporate share based payment expense	3.0	2.8	2.8
Depreciation and amortisation of corporate assets	0.2	0.9	1.3
General and administrative expenses	11.8	10.1	21.0

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.

 

 

5. Finance expense and income  

 

	6 months to 30 June 2018		6 months to 30 June 2017		Year to 31 December 2017
	$m		$m		$m
Bond interest payable	(15.0)		(20.9)		(35.5)
Unwind of discount on liabilities / premium paid on bond buyback	(1.1)		(5.8)		(28.0)
Finance expense	(16.1)		(26.7)		(63.5)
Bank interest income	2.1		0.7		2.2
Unwind of discount on trade receivables	-		2.7		2.7
Finance income	2.1		3.4		4.9

 

6.         Income tax expense

 

A taxation charge is incurred on the profits of the Turkish and UK services companies. All corporation tax due on petroleum sales is 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.

 

Under the terms of the KRI PSCs, the Company is not required to pay any cash taxes with tax paid on its behalf by the government. It is not known at what rate tax is paid, but it is estimated that the current tax rate would be between 15% and 40%. If this was known 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 necessary to assess whether any deferred tax asset or liability was required to be recognised.

 

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.

 

	6 months to 30 June 2018			6 months to 30 June 2017	Year to 31 December 2017
	$m			$m	$m
Profit attributable to equity holders of the Company ($m)		59.3		23.5	271.0
Weighted average number of ordinary shares - number 1		279,025,723		278,395,190	279,013,724
Basic earnings per share - cents per share		21.3		8.4	97.1
1Excluding shares held as treasury shares

Diluted

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

 

 

	6 months to 30 June 2018		6 months to 30 June 2017	Year to 31 December 2017
	$m		$m	$m
Profit attributable to equity holders of the Company ($m)		59.3	23.5	271.0
Weighted average number of ordinary shares - number 1		279,025,723	278,395,190	279,013,724
Adjustment for performance shares, restricted shares and share options		1,222,475	-	1,234,474
Total number of shares		280,248,198	278,395,190	280,248,198
Diluted earnings per share - cents per share		21.2	8.4	96.7
1Excluding shares held as treasury shares

 

8.         Intangible assets

	Exploration and evaluation assets	Tawke RSA	Other assets	Total
	$m	$m	$m	$m
Cost
At 1 January 2017	1,497.4	-	6.3	1,503.7
Additions	12.9	-	0.3	13.2
Discount unwind of contingent consideration	5.3	-	-	5.3
Exploration expense	(4.6)	-	-	(4.6)
Balance at 30 June 2017	1,511.0	-	6.6	1,517.6
At 1 January 2017	1,497.4	-	6.3	1,503.7
Additions	34.6	-	0.2	34.8
ARO provision	2.5	-	-	2.5
Additions (note 10)	-	425.1	-	425.1
Discount unwind of contingent consideration	(22.3)	-	-	(22.3)
Transfer to property, plant and equipment	(22.8)	-	-	(22.8)
Exploration expense	(17.7)	-	-	(17.7)
Balance at 31 December 2017 and 1 January 2018	1,471.7	425.1	6.5	1,903.3
Additions	6.3	-	-	6.3
Discount unwind of contingent consideration	3.9	-	-	3.9
Non-cash additions for ARO/IFRS2	0.4	-	-	0.4
Exploration expense	(0.5)	-	-	(0.5)
Balance at 30 June 2018	1,481.8	425.1	6.5	1,913.4
Accumulated amortisation and impairment
At 1 January 2017	(581.3)	-	(5.7)	(587.0)
Amortisation charge for the period	-	-	(0.4)	(0.4)
At 30 June 2017	(581.3)	-	(6.1)	(587.4)
At 1 January 2017	(581.3)	-	(5.7)	(587.0)
Amortisation charge for the period	-	(32.8)	(0.6)	(33.4)
At 31 December 2017 and 1 January 2018	(581.3)	(32.8)	(6.3)	(620.4)
Amortisation charge for the period	-	(28.8)	(0.1)	(28.9)
At 30 June 2018	(581.3)	(61.6)	(6.4)	(649.3)
Net book value
At 30 June 2017	929.7	-	0.5	930.2
At 31 December 2017	890.4	392.3	0.2	1,282.9
At 30 June 2018	900.5	363.5	0.1	1,264.1

 

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: $537.3 million, 2017: $535.3 million) and Bina Bawi (book value: $330.9 million, 2017: $323.1 million) gas assets. Further explanation on oil and gas assets is provided in the significant accounting judgements, estimates and assumptions in note 1.

 

Tawke RSA cash flows arise from the RSA, details of which are provided in note 1.

 

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

 

Sensitivities

		Bina Bawi / Miran	Tawke RSA
		$m	$m
Long term Brent +/- $5/bbl		+/- 90	+/- 9
Discount rate +/-2.5%		+/- 260	+/- 30
Production and reserves +/- 10%		+/- 78	+/- 52

9. Property, plant and equipment

	Oil and gas assets	Other assets	Total
	$m	$m	$m
Cost
At 1 January 2017	2,599.2	8.9	2,608.1
Additions	28.1	0.2	28.3
At 30 June 2017	2,627.3	9.1	2,636.4
At 1 January 2017	2,599.2	8.9	2,608.1
Additions	59.5	0.5	60.0
ARO provision	3.6	-	3.6
Transfer from intangible assets1	22.8	-	22.8
Other	(1.2)	-	(1.2)
At 31 December 2017 and 1 January 2018	2,683.9	9.4	2,693.3
Additions	27.8	-	27.8
Non-cash additions for ARO/IFRS2	1.4	-	1.4
At 30 June 2018	2,713.1	9.4	2,722.5
Accumulated depreciation and impairment
At 1 January 2017	(1,978.2)	(7.9)	(1,986.1)
Depreciation charge for the period	(44.8)	(0.5)	(45.3)
Other	(0.5)	-	(0.5)
At 30 June 2017	(2,023.5)	(8.4)	(2,031.9)
At 1 January 2017	(1,978.2)	(7.9)	(1,986.1)
Depreciation charge for the period	(83.3)	(0.7)	(84.0)
Impairment	(58.2)	-	(58.2)
At 31 December 2017 and 1 January 2018	(2,119.7)	(8.6)	(2,128.3)
Depreciation charge for the period	(34.6)	(0.1)	(34.7)
At 30 June 2018	(2,154.3)	(8.7)	(2,163.0)
Net book value
At 30 June 2017	603.8	0.7	604.5
At 31 December 2017	564.2	0.8	565.0
At 30 June 2018	558.8	0.7	559.5

Oil and gas assets are the Company's investments in the Tawke (book value: $475.4 million, 2017: $477.8 million) and Taq Taq PSCs (book value: $83.4 million, 2016: $86.4 million) in the KRI, further explanation on oil and gas assets is provided in the significant accounting judgements, estimates and assumptions in note 1.

 

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

 

Sensitivities

	Taq Taq	Tawke
	$m	$m
Long term Brent +/- $5/bbl	+/- 3	+/- 19
Discount rate +/-2.5%	+/- 6	+/- 45
Production and reserves +/-10%	+/- 9	+/- 43

 

10. Trade and other receivables

	30 June 2018 $m	30 June 2017 $m	31 Dec 2017 $m
Trade receivables - non-current	-	127.1	-
Trade receivables - current	84.4	74.6	73.3
Other receivables and prepayments	3.9	9.9	5.2
	88.3	211.6	78.5

 

Trade receivables are amounts owed for oil sales to the KRG, which is the only customer.

 

Ageing of trade receivables

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

 

Period ended 30 June 2018				Year in which amounts overdue were recognised
				Not due $m	2018 $m	2017 $m	2016 $m	Total $m
Trade receivables at 30 June 2018				84.4	-	-	-	84.4

 

Period ended 31 December 2017				Year in which amounts overdue were recognised
				Not due $m	2017 $m	2016 $m	2015 $m	Total $m
Trade receivables at 31 December 2017				73.3	-	-	-	73.3

 

Movement on trade receivables in the period

			30 June 2018 $m	30 June 2017 $m	31 Dec 2017 $m
Carrying value at 1 January		73.3		253.5		253.5
Revenue excl. royalty income		158.9		84.7		224.4
Net proceeds		(147.8)		(139.3)		(262.7)
Discount unwind		-		2.7		2.7
Impairment		-		-		-
Net gain arising from the RSA		-		-		293.8
Write-off of overdue KRG receivable in exchange for intangible assets		-		-		(425.1)
Other		-		0.1		(13.3)
Carrying value at period end		84.4		201.7		73.3

 

 

11. Borrowings and net debt

30 June 2018

	1 Jan 2018	Discount unwind	Buyback	Other	Net other changes in cash	30 June 2018
	$m	$m	$m	$m	$m	$m
2022 Bond 10.0%	296.8	0.1	-	0.1	-	297.0
Cash	(162.0)	-	-	-	(71.2)	(233.2)
Net Debt	134.8	0.1	-	0.1	(71.2)	63.8

 

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

 

31 December 2017

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

 

In March 2017, the Company repurchased $252.8 million nominal value of its own bonds for net cash of $216.7 million - the purchased bonds had a book value of $249.3 million resulting in Company net debt reducing by $32.6 million. 

 

In June 2017, the Company cancelled these bonds, together with the $55.4 million nominal value of bonds repurchased in March 2016, resulting in a reduction in total outstanding debt from $730 million to $421.8 million. Ongoing annual interest expense is consequently reduced to $31.6 million. The fair value of the $421.8 million nominal value of the bonds at 30 June 2017 was $373 million (31 December 2016: $549 million).

 

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

 

12. Capital commitments and operating lease commitments

 

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

 

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 30 June 2018 $0.7 million (30 June 2017: $0.6 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.

 

 

Independent review report to Genel Energy plc

Report on the half-year financial statements

Our conclusion

We have reviewed Genel Energy plc's half-year financial statements (the "interim financial statements") in the half-year results of Genel Energy plc for the 6 month period ended 30 June 2018. Based on our review, nothing has come to our attention that causes us to believe that the interim financial statements are not prepared, in all material respects, in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union and the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

What we have reviewed

The interim financial statements comprise:

         the condensed consolidated balance sheet as at 30 June 2018;

         the condensed consolidated statement of comprehensive income for the period then ended;

         the condensed consolidated cash flow statement for the period then ended;

         the condensed consolidated statement of changes in equity for the period then ended; and

         the explanatory notes to the interim financial statements.

The interim financial statements included in the half-year results  have been prepared in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union and the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

As disclosed in note 1 to the interim financial statements, the financial reporting framework that has been applied in the preparation of the full annual financial statements of the Group is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the European Union.

Responsibilities for the interim financial statements and the review

Our responsibilities and those of the directors

The half-year results, including the interim financial statements, is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-year results in accordance with the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

 

Our responsibility is to express a conclusion on the interim financial statements in the half-year results based on our review. This report, including the conclusion, has been prepared for and only for the company for the purpose of complying with the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority and for no other purpose. We do not, in giving this conclusion, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

What a review of interim financial statements involves

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures.

 

A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and, consequently, does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

 

We have read the other information contained in the half-year results and considered whether it contains any apparent misstatements or material inconsistencies with the information in the interim financial statements.

PricewaterhouseCoopers LLP

Chartered Accountants

London

6 August 2018