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Genel Energy PLC (GENL)
Genel Energy PLC: Half-Year Results
07-Aug-2018 / 07:00 GMT/BST
Dissemination of a Regulatory Announcement that contains inside information
according to REGULATION (EU) No 596/2014 (MAR), transmitted by EQS Group.
The issuer is solely responsible for the content of this announcement.
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 H1 FY
2018 2017 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 - - (58.2)
equipment
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 +44 20 7659 5100
Andrew Benbow, Head of Communications
Vigo Communications +44 20 7390 0230
Patrick d'Ancona
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 [1].
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 Export via Refinery Total Total Genel net
in bopd) pipeline sales1 sales productio productio
n2 n
Tawke 104,904 0.35 104,904 105,771 26,443
(inc.
Peshkabir
)
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 [2]
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 6 Year
months months
to 31
to 30 to 30 Dec
June June
2018 2017
2017
Notes $m $m $m
Revenue 3 161.1 87.1 228.9
Production costs 4 (12.1) (13.2) (27.5)
Depreciation and 4 (63.4) (44.8) (116.1)
amortisation of oil
assets
Gross profit 85.6 29.1 85.3
Exploration expense 4 (0.5) (4.8) (1.9)
Impairment of property, 4 - - (58.2)
plant and equipment
General and 4 (11.8) (10.1) (21.0)
administrative costs
Net gain arising from 2 - - 293.8
the RSA
Operating profit 73.3 14.2 298.0
Operating profit is
comprised of:
EBITDAX 137.4 64.7 475.5
Depreciation and (63.6) (45.7) (117.4)
amortisation
Exploration expense 4 (0.5) (4.8) (1.9)
Impairment of property, 4 - - (58.2)
plant and equipment
Gain arising from bond 11 - 32.6 32.6
buy back
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 59.3 23.5 271.0
comprehensive income
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
31 Dec
30 June 30 June 2017
2018 2017
Notes $m $m $m
Assets
Non-current assets
Intangible assets 8 1,264.1 930.2 1,282.9
Property, plant and 9 559.5 604.5 565.0
equipment
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 Share Accumulated losses Total
capital premium equity
$m $m $m $m
At 1 January 2017 43.8 4,074.2 (2,784.6) 1,333.4
Profit and total - - 23.5 23.5
comprehensive income
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 - - 271.0 271.0
comprehensive income
Share-based payments - - 5.4 5.4 5.4
At 31 December 2017 43.8 4,074.2 (2,508.2) 1,609.8
and 1 January 2018
Profit and total - - 59.3 59.3
comprehensive income
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
31 Dec
30 30 2017
June June
2018 2017
Notes $m $m $m
Cash flows from operating
activities
Profit and total 59.3 23.5 271.0
comprehensive income
Adjustments for:
Gain on bond buy - (32.6) (32.6)
back
Finance income (2.1) (3.4) (4.9)
Bond interest 15.0 20.9 35.5
expense
Other finance 1.1 5.8 28.0
expense
Taxation - - 1.0
Depreciation and 63.6 45.7 117.4
amortisation
Exploration expense 0.5 4.8 1.9
Impairment of - - 58.2
property, plant and
equipment
Net gain arising - - (293.8)
from the RSA
Other non-cash items 3.0 2.8 2.8
Changes in working
capital:
Proceeds against - 50.9 67.5
overdue receivable
Trade and other (10.2) 4.1 (33.5)
receivables
Trade and other (7.1) (9.0) 0.6
payables and
provisions
Cash generated from 123.1 113.5 219.1
operations
Interest received 2.1 0.8 2.2
Taxation paid (0.1) (0.1) (0.3)
Net cash generated 125.1 114.2 221.0
from operating
activities
Cash flows from
investing activities
Purchase of (10.5) (12.7) (26.8)
intangible assets
Purchase of (29.5) (23.4) (52.4)
property, plant and
equipment
Restricted cash 1.0 1.0 1.0
Net cash used in (39.0) (35.1) (78.2)
investing activities
Cash flows from
financing activities
Repurchase of - (216.7) (216.7)
Company bonds
Bond refinancing - - (128.5)
Interest paid (15.0) (23.5) (42.7)
Net cash used in (15.0) (240.2) (387.9)
financing activities
Net increase / 71.1 (161.1) (245.1)
(decrease) in cash
and cash equivalents
Foreign exchange 0.1 (0.2) 0.1
income / (loss) on
cash and cash
equivalents
Cash and cash 162.0 407.0 407.0
equivalents at 1
January
Cash and cash 11 233.2 245.7 162.0
equivalents at
period end
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
Expl. Total
Oil MBB Other
$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) / - (0.2) (0.3) - (0.5)
credit
General and administrative - - - (11.8) (11.8)
costs
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 (63.4) - - (0.2) (63.6)
amortisation
Exploration (expense) / - (0.2) (0.3) - (0.5)
credit
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
Expl. Total
Oil MBB Other
$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) / - (1.9) (2.9) - (4.8)
credit
Impairment of property, - - - - -
plant and equipment
General and administrative - - - (10.1) (10.1)
costs
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 (44.8) - - (0.9) (45.7)
amortisation
Exploration expense - (1.9) (2.9) - (4.8)
Impairment of property, - - - - -
plant and equipment
Gain arising from bond buy - - - 32.6 32.6
back
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
Expl. Total
Oil MBB Other
$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) / - (4.6) 2.7 - (1.9)
credit
Impairment of property, (58.2) - - - (58.2)
plant and equipment
Net gain arising from the 293.8 - - - 293.8
RSA
General and administrative - - - (21.0) (21.0)
costs
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 (116.1) - - (1.3) (117.4)
amortisation
Exploration (expense) / - (4.6) 2.7 - (1.9)
credit
Impairment of property, (58.2) - - - (58.2)
plant and equipment
Gain arising from bond buy - - - 32.6 32.6
back
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 6 months to Year to 31
30 June 2018 30 June 2017 December 2017
$m $m $m
Production costs 12.1 13.2 27.5
Depreciation of oil 34.6 44.8 83.3
and gas property,
plant and equipment
Amortisation of oil 28.8 - 32.8
and gas intangible
assets
Cost of sales 75.5 58.0 143.6
Exploration expense 0.5 4.8 1.9
Impairment of - - 58.2
property, plant and
equipment (note 9)
Corporate cash costs 8.6 6.4 16.9
Corporate share based 3.0 2.8 2.8
payment expense
Depreciation and 0.2 0.9 1.3
amortisation of
corporate assets
General and 11.8 10.1 21.0
administrative
expenses
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 6 months to 30 Year to 31
June 2018 June 2017 December 2017
$m $m $m
Bond (15.0) (20.9) (35.5)
interest
payable
Unwind of (1.1) (5.8) (28.0)
discount
on
liabilitie
s /
premium
paid on
bond
buyback
Finance (16.1) (26.7) (63.5)
expense
Bank 2.1 0.7 2.2
interest
income
Unwind of - 2.7 2.7
discount
on trade
receivable
s
Finance 2.1 3.4 4.9
income
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 Year
month to 31
s to Decemb
30 er
June 2017
2017
$m $m $m
Profit attributable to equity 59.3 23.5 271.0
holders of the Company ($m)
279,025,723 278,3 279,01
95,19 3,724
0
Weighted average number of
ordinary shares - number 1
Basic earnings per share - cents 21.3 8.4 97.1
per share
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 Year
month to 31
s to Decemb
30 er
June 2017
2017
$m $m $m
Profit attributable to equity holders of 59.3 23.5 271.0
the Company ($m)
279,025, 278,3 279,01
723 95,19 3,724
0
Weighted average number of ordinary
shares - number 1
Adjustment for performance shares, 1,222,47 - 1,234,
restricted shares and share options 5 474
Total number of shares 280,248, 278,3 280,24
198 95,19 8,198
0
Diluted earnings per share - cents per 21.2 8.4 96.7
share
1Excluding shares
held as treasury
shares
8. Intangible assets
********************
Exploration and Tawke Other Total
evaluation assets
RSA assets
$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 5.3 - - 5.3
contingent
consideration
Exploration expense (4.6) - - (4.6)
Balance at 30 June 1,511.0 - 6.6 1,517.6
2017
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 (22.3) - - (22.3)
contingent
consideration
Transfer to property, (22.8) - - (22.8)
plant and equipment
Exploration expense (17.7) - - (17.7)
Balance at 31 1,471.7 425.1 6.5 1,903.3
December 2017 and 1
January 2018
Additions 6.3 - - 6.3
Discount unwind of 3.9 - - 3.9
contingent
consideration
Non-cash additions 0.4 - - 0.4
for ARO/IFRS2
Exploration expense (0.5) - - (0.5)
Balance at 30 June 1,481.8 425.1 6.5 1,913.4
2018
Accumulated
amortisation and
impairment
At 1 January 2017 (581.3) - (5.7) (587.0)
Amortisation charge - - (0.4) (0.4)
for the period
At 30 June 2017 (581.3) - (6.1) (587.4)
At 1 January 2017 (581.3) - (5.7) (587.0)
Amortisation charge - (32.8) (0.6) (33.4)
for the period
At 31 December 2017 (581.3) (32.8) (6.3) (620.4)
and 1 January 2018
Amortisation charge - (28.8) (0.1) (28.9)
for the period
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 22.8 - 22.8
assets1
Other (1.2) - (1.2)
At 31 December 2017 and 1 2,683.9 9.4 2,693.3
January 2018
Additions 27.8 - 27.8
Non-cash additions for 1.4 - 1.4
ARO/IFRS2
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 (44.8) (0.5) (45.3)
period
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 (83.3) (0.7) (84.0)
period
Impairment (58.2) - (58.2)
At 31 December 2017 and 1 (2,119.7) (8.6) (2,128.3)
January 2018
Depreciation charge for the (34.6) (0.1) (34.7)
period
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 30 June 2017 31 Dec
$m
2018 2017
$m $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 Year in which amounts overdue
ended
30 June
2018
were recognised
Not due 2018 2017 2016 Total
$m $m $m $m $m
Trade receivables at 84.4 - - - 84.4
30 June 2018
Period Year in which amounts overdue
ended
31
Decembe
r 2017 were recognised
Not due 2017 2016 2015 Total
$m $m $m $m $m
Trade receivables at 73.3 - - - 73.3
31 December 2017
Movement on trade receivables in the period
30 30 31 Dec
June June
2018
2017
2017
$m
$m
$m
Carrying value at 1 73.3 253.5 253.5
January
Revenue excl. royalty 158.9 84.7 224.4
income
Net proceeds (147.8) (139.3) (262.7)
Discount unwind - 2.7 2.7
Impairment - - -
Net gain arising from - - 293.8
the RSA
Write-off of overdue - - (425.1)
KRG receivable in
exchange for
intangible assets
Other - 0.1 (13.3)
Carrying value at 84.4 201.7 73.3
period end
11. Borrowings and net debt
30 June 2018
1 Jan 2018 Discoun Buyback Other Net other 30 June
t changes 2018
unwind in cash
$m $m $m $m $m $m
2022 296.8 0.1 - 0.1 - 297.0
Bond
10.0%
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 Discount Buyback Refinance Net 31 Dec
2017 unwind other 2017
changes
in cash
$m $m $m $m $m $m
2019 Bond 648.2 22.9 (249.3) (421.8) - -
7.5%
2022 Bond - - - 296.8 - 296.8
10.0%
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
ISIN: JE00B55Q3P39
Category Code: IR
TIDM: GENL
LEI Code: 549300IVCJDWC3LR8F94
Sequence No.: 5841
EQS News ID: 711361
End of Announcement EQS News Service
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August 07, 2018 02:04 ET (06:04 GMT)
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