DJ Genel Energy PLC: Half-Year Results
Genel Energy PLC (GENL)
Genel Energy PLC: Half-Year Results
06-Aug-2019 / 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.
6 August 2019
Genel Energy plc
Unaudited results for the period ended 30 June 2019
Genel Energy plc ('Genel' or 'the Company') announces its unaudited results
for the six months ended 30 June 2019.
Bill Higgs, Chief Executive of Genel, said:
"These results demonstrate the continued success of our strategy - highly
cash generative production underpins capital investment in growth
opportunities that deliver rapid returns and enables a compelling cash
return to shareholders through our dividend.
Our production grew 17% in H1 2019, and pro forma free cash flow rose to $76
million. This cash generation, and our strong balance sheet, allows us to
both increase investment in growing the business as well as returning cash
to shareholders via dividends. Accordingly, we have today announced an
interim dividend of $14 million.
Disciplined capital allocation remains at the core of our business. The
speed with which our investments pay back means that cash is quickly
recycled to create most value for shareholders. The cash that our production
generates funds work now underway at Sarta and Qara Dagh, with plenty left
over to both pay a dividend and seek new opportunities, as we progress
Genel's growth strategy."
Results summary ($ million unless stated)
H1 H1 FY
2019 2018 2018
Production (bopd, working interest) 37,400 32,100 33,700
Revenue 194.3 161.1 355.1
EBITDAX 1 167.3 137.4 304.1
Depreciation and amortisation (74.8) (63.6) (136.2)
Exploration (expense) / credit (0.6) (0.5) 1.5
Impairment of intangible assets - - (424.0)
Operating profit / (loss) 91.9 73.3 (254.6)
Cash flow from operating activities 142.3 125.1 299.2
Capital expenditure 72.2 34.1 95.5
Free cash flow2 56.7 70.1 164.2
Pro forma free cash flow2 75.6 70.1 164.2
Dividend payments 27.4 - -
Cash3 353.3 233.2 334.3
Total debt 300.0 300.0 300.0
Net cash (debt)4 55.8 (63.8) 37.0
Basic EPS (¢ per share) 27.2 21.3 (101.6)
Underlying EPS (¢ per share)1 59.9 49.2 109.0
1) EBITDAX is operating profit / (loss) adjusted for the add back of
depreciation and amortisation ($74.8 million) and exploration expense
($0.6 million). Underlying EPS is EBITDAX divided by the weighted average
number of ordinary shares
2) Free cash flow is set out on page 7 and does not include $18.9 million,
invoiced for Tawke production and due in June 2019 and received late on 9
July 2019, with the delay due to a change in the Operator's banking
arrangements. Pro forma free cash flow of $75.6 million includes this
payment.
3) Cash reported at 30 June 2019 excludes $10 million of restricted cash
and the $18.9 million noted above
4) Reported IFRS debt less cash
Highlights
· Working interest production averaged 37,400 bopd in H1 2019 (H1 2018:
32,100 bopd), an increase of 17% compared to H1 2018
· 8 wells completed in H1 2019, resulting in year-on-year production
increases at both the Tawke and Taq Taq PSCs
· Free cash generation of $57 million in H1 2019 (H1 2018: $70 million),
which increases to $76 million when including the post period receipt of
$19 million, with annual free cash flow yield of c.20% of current market
capitalisation
· Net cash of $56 million at 30 June 2019 (net debt of $64 million at 30
June 2018)
· Following the receipt of all payments relating to April 2019, Genel
had $390 million of cash as of 5 August 2019, a net cash position of $92
million
· Addition of Sarta and Qara Dagh to the portfolio in January 2019
provides near-term production and material future growth potential
· Maiden dividend distribution of 10¢ per share paid on 24 June 2019
· Interim dividend of 5¢ per share confirmed
· Genel retains an open mandate for a share buy-back programme of up to
$10 million, and will continue to review purchasing opportunities
Outlook
· Net production guidance in 2019 maintained at close to Q4 2018 levels of
36,900 bopd, an increase of c.10% year-on-year
· Drilling programme ongoing, with over 10 wells set to be completed by
early 2020
· Active discussions with the Kurdistan Regional Government ('KRG')
regarding Bina Bawi are ongoing, focused on agreeing the detailed
commercial terms for the integrated Phase 1 oil and gas development and
approval of the associated field development plans
· Work continuing at Sarta to prepare for production by the middle of 2020
· QD-2 well location agreed at Qara Dagh, well pad civil engineering work
set to begin
· Farm-out process relating to Somaliland acreage to begin in late Q3 2019
· Genel expects to generate material free cash flow in H2 2019, even while
investment in growth increases
· 2019 capital expenditure is expected to be towards the top end of the
$150-170 million guidance range
· Searches for a new Chairman and Chief Operating Officer are progressing
· The Company continues to actively pursue growth and is assessing
opportunities to make value-accretive additions to the portfolio
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.
CEO STATEMENT
Genel aims to be a world-class creator of shareholder value by growing
high-margin production through rapid development and an efficient use of
capital, recycling cash flows into an expanding asset portfolio with the
potential to deliver significant growth, while generating sufficient cash
throughout the investment cycle to fund a material and progressive dividend.
GENERATING CASH WHILE INVESTING IN GROWTH
The oil we produce is good quality, low-cost, and highly cash generative,
with a development model focused on optimising cost and minimising
development risk. This makes our business highly cash generative. Setting us
apart from the majority of our peers both within the region and outside, we
have been able to materially increase production without significant cash
out - in fact our asset portfolio generates material free cash flow even
while increasing production.
This is best illustrated by the Tawke PSC, where production at Peshkabir has
increased from 12,000 bopd at the end of 2017 to over 55,000 bopd. While
doing so Peshkabir continues to generate material free cash flow, adding $32
million in the first half of 2019. Overall, capital expenditure in the first
half of $72 million has nearly doubled from last year, but still free cash
flow increased year-on-year.
Our low-cost production also makes us resilient to oil price fluctuations,
and we generate cash at a low oil price. As an illustration, even if the
Brent oil price averaged $36/bbl in 2019 we would still generate sufficient
cash to pay our dividend of $40 million from free cash flow.
The level and speed of our cash generation allows us the optionality to
recycle capital into those areas that promise to create the maximum
shareholder value. The priority remains investing in our current producing
assets to underpin this cash generation, and subsequently spending is now
set to ramp up at Sarta and Qara Dagh.
Commercial discussions continue on Bina Bawi, and we are increasingly
confident of making sufficient progress to enable work on the ground to
begin next year, with the potential for Bina Bawi oil to also add to our
production in 2020. And we will continue to generate free cash flow even
after making these investments in growth.
A MATERIAL AND PROGRESSIVE DIVIDEND
With our strong cash generation, even while investing in growth and adding
assets to the portfolio, paying a dividend was the ultimate intended outcome
of our strategy. With our portfolio having the potential to double
production in coming years, and an M&A strategy focused on boosting
near-term cash generation, we see the baseline annual distribution of $40
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DJ Genel Energy PLC: Half-Year Results -2-
million as having the potential to grow on an annual basis.
FOCUS ON ESG
ESG continues to be a key focus of Genel, and we are committed to acting as
a socially responsible contributor to the global energy mix. On the
environmental side, we aim to minimise GHG emissions per barrel across the
portfolio. Working with DNO at Peshkabir, the reinjection of gas into the
Tawke field will eliminate routine flaring while having the added bonus of a
positive return on investment - another financial benefit that sets us apart
from some of our peers.
As work progresses on Sarta, we will keep emissions to a minimum ahead of
initiating a flares out programme in due course, and further our social
investment work. Previously this work has centred on the area surrounding
Taq Taq through work focusing on the environment, health, education, and
economic empowerment, and initiatives are set to get under way around Sarta
and Qara Dagh. Genel will continue to strive to ensure that the local
community benefits from the work we do in their community.
OPERATING REVIEW
PRODUCING ASSETS
Working interest production in H1 2019 averaged 37,400 bopd, a rise of 17%
year-on-year.
(by PSC Export via Refinery Total Total Genel net
in bopd) pipeline sales sales productio productio
n1 n
Tawke 127,070 - 127,070 126,650 31,660
(inc.
Peshkabir
)
Taq Taq 13,135 - 13,135 13,150 5,785
Total 140,205 - 140,205 139,800 37,445
1 Difference between production and sales relates to inventory movements
All sales during the period were invoiced at the wellhead export netback
price.
Tawke PSC (25% working interest)
Production from the Tawke PSC averaged 126,650 bopd, an increase of 20%
year-on-year and 12% on the FY 2018 figure. This performance was the result
of the success of Peshkabir, where production averaged 54,950 bopd.
Production from the Tawke PSC continues to be highly cash-generative,
contributing $87 million in free cash flow at an asset level.
The underlying well stock at the Tawke field has produced in line with
expectations. Drilling is required to offset natural field decline, and
three wells came onto production in the period. T-52 came on stream in
mid-February, and T-54 in April, and the two wells have averaged c.3,500
bopd in combined additional production. The T-55 well began adding to
production in June and will be followed by a further four confirmed
cretaceous producers, while the T-57 well will test the Jurassic potential
at Tawke. The field partners will also drill a programme of shallower Jeribe
wells.
Peshkabir continues to perform well, with success at both the P-9 and P-10
wells helping increase production. Surface facility work has also been
completed, and production from the P-2 and P-3 wells is now flowing through
the 50,000 bopd central processing facility. Trucking activity is set to be
eliminated following the commissioning of the 60,000 bopd pipeline to
Fishkabour, helping to reduce costs from an already low base.
The P-11 well is nearing completion, and three more wells are scheduled to
spud in 2019. Work on the enhanced oil recovery project wherein gas is piped
from Peshkabir to be injected into the Tawke reservoir, both eliminating
flaring and increasing recovery rates, is now underway and is expected to be
commissioned in H1 2020.
Taq Taq (44% working interest, joint operator)
Drilling on the flanks at Taq Taq continued to bear fruit in H1, and helped
production at the field average 13,150 bopd in H1 2019, an increase of 3%
year-on-year and 6% on the FY 2018 figure. The TT-32 well completed in
January on the northern flank of the field with an initial flow rate of
c.3,000 bopd. This was followed by the TT-20z well, on the western flank,
which entered production at a rate of 2,000 bopd. Both wells have recently
seen a decline in production and are now in line with Genel's expectations,
having been choked back to control water production.
The TT-33 well, on the southern flank, has tested water from three zones,
and has not flowed oil at any significant rate, demonstrating that the free
water level on the southern flank is higher than to the north. Going
forward, the field partners will continue to target the flanks of the field,
with a focus on horizontal wells to delay water production and maximise
recovery. Wells continue to provide a positive return on investment, and Taq
Taq generated $8.4 million of free cash flow in H1 2019. Two horizontal
wells are scheduled to be drilled on the northern flank of the field in the
second half of the year, and the TT-19x well is currently underway. Drilling
in the second half of the year aims to deliver year-on-year production
growth.
PRE-PRODUCTION ASSETS
Sarta (30% working interest)
To date, four exploration wells at Sarta have discovered hydrocarbons at
multiple intervals, from the Tertiary down to the Triassic. This contributes
to the Company's unrisked P50 gross resource estimate of c.500 MMbbls. Phase
1A represents a low-cost development of the Jurasssic Mus-Adaiyah
reservoirs. This phase is designed to recover 2P gross reserves of 34 MMbbls
through two existing wells (Sarta-2 and Sarta-3) both of which flowed at
c.7,500 bopd on test, and one additional development well to be drilled in
2021. Insights from production behaviour during this first phase, combined
with an appraisal and development well campaign planned for 2021, will
provide the technical foundation for prudent expansion investment decisions
aimed at maturing Sarta into a low cost, long-life, cash generative asset.
Construction work for the Phase 1A development is already underway. Civil
engineering work commenced in May ahead of mobilising the facility and
flowline contractors to the field. Production remains on track to begin in
the middle of 2020.
Qara Dagh (40% working interest, operator)
The Qara Dagh prospect was first tested by the vertical exploration well
QD-1 in 2011. The reservoir was encountered much deeper than prognosed and
operational issues meant the well was significantly overbalance when
drilling the reservoir, in so doing damaging the reservoirs ability to flow
hydrocarbons. Despite these setbacks QD-1 still tested a light oil from
Cretaceous fractured carbonates.
Re-evaluation of the structural model post QD-1, based on new 2D seismic
combined with fieldwork, indicates that the well was drilled on the
south-eastern flank of the prospect. The location for the second exploration
well, QD-2, has been chosen to test the structural crest c.10 km to the NW
of where QD-1 flowed oil to surface. QD-2 will be drilled with a deviated
trajectory through the same reservoir tested by QD-1 in order to maximise
fracture intersection. Managed pressure drilling is being considered to
minimise reservoir damage. Genel has undertaken a baseline Environmental,
Social and Health Impact Assessment study and will commence construction
work on the well pad and associated camp shortly. The QD-2 well is on track
to spud in H1 2020.
Bina Bawi and Miran (100% working interest, operator)
Negotiations between Genel and the KRG are ongoing regarding commercial
terms for a staged and integrated oil and gas development.
In line with Genel's strategy, the development of Bina Bawi (and in the
future, Miran) is set to be done in phases. Through disciplined allocation
of capital, Genel is focused on aligning stakeholders and setting the
framework for an attractive and investable project.
Genel and the KRG are now aligned on a phase one upstream project scope
delivering a reduced c.250 MMscfd raw gas. The KRG and Genel will jointly
fund the midstream gas development required to process the raw gas, partly
making use of revenues from the accelerated development of Bina Bawi oil.
Discussions are ongoing, with regular meetings taking place between the KRG
and Genel. Genel has recently made a formal proposal consistent with
previously negotiated terms, balancing initial returns from the development
of oil with the medium-term requirement for funding the midstream
development.
Genel is seeking approval for this proposal and the Bina Bawi field
development plan in order to commence with the oil development and
commission a FEED study for the award of an Engineering, Procurement,
Construction, Installation & Commissioning ('EPCIC') contract relating to
the midstream development. The latter would take around 12 months, and be
funded via the Bina Bawi oil development.
African exploration
Onshore Somaliland, interpretation of the 2018 2D seismic data together with
continued basin analysis has led to the maturation of a prospects and leads
inventory for the SL10B13 block (Genel 75% working interest and operator)
which confirms the longstanding view that the block has significant
hydrocarbon potential. A number of potentially high impact exploration
targets have been identified within play types directly analogous to the
prolific Yemeni rift basins.
Once these prospects and leads have been quantified in terms of volumetric
potential and associated geological risk the Company will initiate a
farm-out campaign, commencing late Q3 2019. This remains consistent with the
Company's capital allocation approach, as long-term reserves replacement
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from legacy African exploration assets is targeted through the lowest
possible capital outlay. On the Odewayne block further seismic processing is
continuing in order to complete the Company's understanding of the
prospectivity of the block. In both cases the minimum work commitments and
associated expenditure for the current licence periods has been met.
On the Sidi Moussa block offshore Morocco (Genel 75% working interest,
operator), processing of the multi-azimuth broadband 3D seismic survey
acquired in 2018 over the prospective portions of the block continues. This
completes the work obligations associated with the current licence period.
Once completed, the Company plans to initiate a farm-out campaign in Q1
2020, aimed at bringing a partner onto the licence prior to considering
further commitments. The Company is currently engaged in discussions with
the Moroccan Government with respect to the requisite licence time to
complete this forward plan.
FINANCIAL REVIEW
For 2019 the financial priorities of the Company are the following:
· Continued focus on capital allocation, with prioritisation of highest
value investment in assets with ongoing or near-term cash and value
generation
· Investment in lower risk development of opportunities with high
potential. This currently includes the delivery of first oil at Sarta and
drilling a well on a discovered resource at Qara Dagh. Investment at Bina
Bawi will be added should appropriate commercial terms and conditions be
reached
· Continued focus on acquiring assets with the potential to add
significant value to the Company through near to mid-term cash generation.
The objective is to establish a portfolio of assets that strengthens the
portfolio of Sarta, Qara Dagh and Bina Bawi oil in replacing and
increasing the Company's cash generation when the override royalty
agreement ends in Q3 2022, and also to augment gas development to grow
cash generation thereafter. Overall putting together a funnel that
supports continuing material free cash flow well into the next decade and
providing the basis for a progressive dividend
· Continued focus on the capital structure of the Company
· Genel is committed to distributing a minimum of $40 million in
dividends each year. Given the forecast free cash flow of the Company,
this figure is expected to grow
In the first half of the year, successful delivery of these priorities has
produced positive results. Pro forma free cash flow of $75.6 million, which
includes post period receipt of $18.9 million, represents an increase of 8%
on the prior year, despite the $5/bbl fall in Brent oil price and increased
investment of $30 million in production and pre-production assets:
(all figures $ million) H1 2019 H1 2018 FY 2018
Operating cash flow and other 142.3 125.1 299.2
Producing asset cost recovered capex (48.7) (29.5) (65.3)
Development capex (9.4) - -
Exploration and appraisal capex (12.2) (10.5) (39.7)
Interest and other (15.3) (15.0) (30.0)
Free cash flow 56.7 70.1 164.2
Cash received post period end 18.9 - -
Pro forma free cash flow 75.6 70.1 164.2
This increase in capital expenditure principally relates to increased
investment at Peshkabir and Sarta.
Peshkabir is our priority for capital allocation. Due to well productivity
and positive commercial terms, capital investment is recovered within three
months. Investment in this asset has resulted in the material increase in
production, currently c.55,000 bopd, increased central processing capacity
to 55,000 bopd and optimisation of costs by building pipeline transportation
to replace trucking, which reduces transportation costs by 50¢ per barrel.
Sarta represents significant growth potential, with current work focused on
building towards first oil in the middle of 2020.
Other spend in the year has been focused on preparation for drilling at Qara
Dagh, and drilling production wells and water disposal wells at Tawke,
Peshkabir and Taq Taq. We now plan to drill two additional wells at both
Peshkabir and Taq Taq, with capital expenditure expected to be towards the
top end of the previously provided range of $150-170 million.
In January we indicated our expectation of free cash generation of $100
million at $45/bbl. Since then we have added the Sarta and Qara Dagh assets.
With the additional capex on these assets estimated to be around $50
million, we now expect material free cash generation for the full year,
which excludes dividend payments, to be in excess of $100 million.
We will continue to be disciplined in our capital allocation and invest in
areas where we can deliver value. This applies both to allocation of capital
to the existing portfolio and also to assets or opportunities that we
acquire.
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.
Financial results for the half-year
Income statement
Working interest production of 37,400 bopd was higher than the first half
last year (H1 2018: 32,100 bopd), which principally benefited from more than
doubled Peshkabir production.
Revenue has increased by 21% compared to H1 2018, from $161.1 million to
$194.3 million, with the decrease in the average Brent oil price of $66/bbl
(H1 2018: $71/bbl) being offset by the improvement in production. Production
costs of $18.1 million (H1 2018: $12.1 million) were higher due to increased
production, with opex per barrel at c.$2.7/bbl compared to c.$2.1/bbl in the
first half this year. The increase has been caused by trucking costs at
Peshkabir - we expect trucking to be replaced by the pipeline in the second
half of the year.
General and administration costs were $9.5 million (H1 2018: $11.8 million),
of which cash costs were $7.2 million (H1 2018: $8.6 million). The reduction
from the prior period is a result of higher capitalisation as capital
activity has increased, principally at Sarta and Qara Dagh.
The increase in revenue resulted in a net increase in EBITDAX of $29.9
million compared to last period.
(all figures $ million) H1 2019 H1 2018 FY 2018
Revenue 194.3 161.1 355.1
Operating costs (18.1) (12.1) (28.7)
G&A (excl. depreciation) (8.9) (11.6) (22.3)
EBITDAX 167.3 137.4 304.1
Depreciation and amortisation (74.8) (63.6) (136.2)
Exploration (expense) / credit (0.6) (0.5) 1.5
Impairment of intangible assets - - (424.0)
Operating profit / (loss) 91.9 73.3 (254.6)
EBITDAX is presented in order for the users of the financial statements to
understand the cash profitability of the Company, which excludes the impact
of costs attributable to exploration activity, which tend to be one-off in
nature, and the non-cash costs relating to depreciation, amortisation and
impairments. EBITDAX is used as the basis for underlying earnings per share,
for the reasons provided above.
Bond interest expense of $15.0 million was in line with prior year. Finance
income of $2.4 million (H1 2018: $2.1 million) was bank interest, finance
expense of $2.9 million (H1 2018: $1.1 million) included a non-cash discount
unwind expense on liabilities, and fees related to the bondholder waiver.
There is no taxation on operational profits: under the terms of the
Kurdistan Region of Iraq ('KRI') PSC's, corporate income tax due is paid on
behalf of the Company by the KRG from the KRG's own share of revenues,
resulting in no corporate income tax payment required or expected to be made
by the Company. Tax presented in the income statement of $0.4 million (H1
2018: nil) was related to taxation of the service companies. Depreciation
and amortisation of oil assets has increased overall by $10.8 million as a
result of higher production.
Capital expenditure
Capital expenditure is the aggregation of additions to property, plant and
equipment ($64.6 million) and intangible assets ($7.6 million) and is
reported to provide investors with an understanding of the quantum and
nature of investment that is being made in the business. Capital expenditure
for the period was $72.2 million, predominantly focused on production assets
and the Sarta PSC ($11.3m):
(all figures $ million) H1 2019 H1 2018 FY 2018
Cost recovered production capex 53.3 27.8 70.4
Pre-production capex - oil 11.3 - -
Pre-production capex - gas 5.6 5.7 12.0
Other exploration and appraisal capex 2.0 0.6 13.1
Capital expenditure 72.2 34.1 95.5
Cash flow, cash, net cash and debt
Free cash flow is presented in order to show the free cash generated that is
available for the Board to invest in the business. The measure provides the
reader a better understanding of the underlying business cash flows. Free
cash flow was $56.7m, with an overall increase in cash of $19.0m in the
period compared to an increase of $71.2 million last period:
(all figures $ million) H1 2019 H1 2018 FY 2018
Free cash flow 56.7 70.1 164.2
Dividend paid (29.0) - -
Purchase of shares (8.7) - -
Release of restricted cash and other - 1.1 8.1
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Net change in cash 19.0 71.2 172.3
Opening cash 334.3 162.0 162.0
Closing cash 353.3 233.2 334.3
Debt reported under IFRS (297.5) (297.0) (297.3)
Net cash / (debt) 55.8 (63.8) (37.0)
Closing cash of $353.3 million excludes restricted cash of $10.0 million (H1
2018: $17.5 million), which is also excluded from net cash at 30 June 2019
of $55.8 million. Net cash is reported in order for users of the financial
statements to understand how much cash remains if the Company paid its debt
obligations from its available cash on the period end date.
Reported IFRS debt was $297.5 million (31 December 2018: $297.3 million),
comprised of $300 million of bond debt less amortised costs. The bond pays a
10.0% coupon and matures in December 2022. The bond has three financial
covenant maintenance tests:
Financial covenant Test H1 2019
Net debt / EBITDAX (rolling 12 months)< 3.0 (0.2)
Equity ratio (Total equity/Total assets) > 40% 71%
Minimum liquidity > $30m $353m
A reconciliation of debt and cash is provided in note 11 to the financial
statements.
Net assets
Net assets at 30 June 2019 were $1,373.6 million (31 December 2018: $1,331.4
million) and consist primarily of oil and gas assets of $1,437.3 million (31
December 2018: $1,384.2 million), trade receivables of $116.6 million (31
December 2018: $94.8 million) and net cash of $55.8 million (31 December
2018: $37.0 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
Maiden dividend distribution of $27.4 million (2018: nil) paid to
shareholders in June 2019. An interim dividend of 5¢ per share has been
confirmed:
· Ex-dividend date: 12 December2019
· Record Date: 13 December 2019
· Payment Date: 8 January 2020
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 2019 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: the
development and recovery of oil reserves; reserve replacement;
commercialisation of the KRI gas business; M&A activity; the KRI natural
resources industry and regional risk; corporate governance failure; capital
structure and financing; local community support; the environmental impact
of oil and gas extraction; and health and safety risks. Further detail on
many of these risks was provided in the 2018 Annual Report. Since year-end,
the environmental impact of oil and gas extraction has been added to the
risk register, reflecting the increased focus on ESG issues.
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 2018. A list of current directors is maintained on
the Genel Energy plc website: www.genelenergy.com [2]
By order of the Board
Bill Higgs
CEO
5 August 2019
Esa Ikaheimonen
CFO
5 August 2019
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 2019
6 6 Year
months months
to 31
to 30 to 30 Dec
June June
2019 2018
2018
Notes $m $m $m
Revenue 3 194.3 161.1 355.1
Production costs 4 (18.1) (12.1) (28.7)
Depreciation and 4 (74.2) (63.4) (134.5)
amortisation of oil assets
Gross profit 102.0 85.6 191.9
Exploration (expense) / 4 (0.6) (0.5) 1.5
credit
Impairment of intangible 4 - - (424.0)
assets
General and administrative 4 (9.5) (11.8) (24.0)
costs
Operating profit / (loss) 91.9 73.3 (254.6)
Operating profit / (loss)
is comprised of:
EBITDAX 167.3 137.4 304.1
Depreciation and (74.8) (63.6) (136.2)
amortisation
Exploration (expense) / 4 (0.6) (0.5) 1.5
credit
Impairment of intangible 4 - - (424.0)
assets
Finance income 5 2.4 2.1 4.4
Bond interest expense 5 (15.0) (15.0) (30.0)
Other finance expense 5 (2.9) (1.1) (3.2)
Profit / (loss) before 76.4 59.3 (283.4)
income tax
Income tax expense 6 (0.4) - (0.2)
Profit / (loss) and total 76.0 59.3 (283.6)
comprehensive income /
(expense)
Attributable to:
Shareholders' equity 76.0 59.3 (283.6)
76.0 59.3 (283.6)
Profit / (loss) per ordinary ¢ ¢ ¢
share
Basic 7 27.2 21.3 (101.6)
Diluted 7 27.1 21.2 (101.6)
Condensed consolidated balance sheet
At 30 June 2019
31 Dec
30 June 30 June 2018
2019 2018
Notes $m $m $m
Assets
Non-current assets
Intangible assets 8 796.1 1,264.1 818.4
Property, plant and 9 641.2 559.5 565.8
equipment
1,437.3 1,823.6 1,384.2
Current assets
Trade and other receivables 10 125.6 88.3 99.4
Restricted cash 11 10.0 17.5 10.0
Cash and cash equivalents 11 353.3 233.2 334.3
488.9 339.0 443.7
Total Assets 1,926.2 2,162.6 1,827.9
Liabilities
Non-current liabilities
Trade and other payables (120.8) (74.5) (76.8)
Deferred income (28.1) (33.8) (31.9)
Provisions (34.7) (31.0) (32.9)
Borrowings 11 (297.5) (297.0) (297.3)
(481.1) (436.3) (438.9)
Current liabilities
Trade and other payables (65.3) (48.1) (52.6)
Deferred income (6.2) (5.3) (5.0)
(71.5) (53.4) (57.6)
Total liabilities (552.6) (489.7) (496.5)
Net assets 1,373.6 1,672.9 1,331.4
Owners of the parent
Share capital 43.8 43.8 43.8
Share premium account 4,046.6 4,074.2 4,074.2
Accumulated losses (2,716.8) (2,445.1) (2,786.6
)
Total equity 1,373.6 1,672.9 1,331.4
Condensed consolidated statement of changes in equity
For the period ended 30 June 2019
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DJ Genel Energy PLC: Half-Year Results -5-
Share Share Accumulated losses Total
capital premium equity
$m $m $m $m
At 1 January 2018 43.8 4,074.2 (2,508.2) 1,609.8
Profit and total - - 59.3 59.3
comprehensive
income
Share-based - - 3.8 3.8
payments
At 30 June 2018 43.8 4,074.2 (2,445.1) 1,672.9
At 1 January 2018 43.8 4,074.2 (2,508.2) 1,609.8
(Loss) and total - - (283.6) (283.6)
comprehensive
(expense)
Share-based - - 5.2 5.4 5.2
payments
At 31 December 43.8 4,074.2 (2,786.6) 1,331.4
2018 and 1 January
2019
Profit and total - - 76.0 76.0
comprehensive
income
Share-based - - 2.5 2.5
payments
Purchase of shares - - (8.2) (8.2)
to satisfy share
awards
Purchase of - - (0.5) (0.5)
treasury shares
Dividend payment - (27.6)1 - (27.6)
At 30 June 2019 43.8 4,046.6 (2,716.8) 1,373.6
1 The Companies (Jersey) Law 1991 does not define the expression "dividend"
but refers instead to "distributions". Distributions may be debited to any
account or reserve of the Company (including share premium account).
Condensed consolidated cash flow statement
For the period ended 30 June 2019
31 Dec
30 30 2018
June June
2019 2018
Notes $m $m $m
Cash flows from operating
activities
Profit / (Loss) and total 76.0 59.3 (283.6)
comprehensive income /
(expense)
Adjustments for:
Finance income 5 (2.4) (2.1) (4.4)
Bond interest 5 15.0 15.0 30.0
expense
Other finance 5 2.9 1.1 3.2
expense
Taxation 0.4 - 0.2
Depreciation and 4 74.8 63.6 136.2
amortisation
Exploration expense 4 0.6 0.5 (1.5)
/ (credit)
Impairment of 4 - - 424.0
intangible assets
Other non-cash items (1.4) 3.0 4.9
Changes in working
capital:
(Increase) / (21.8) (11.1) (21.5)
decrease in trade
receivables
(Increase) / - 0.9 (1.1)
decrease in other
receivables
Increase / (3.7) (7.1) 9.2
(decrease) in trade
and other payables
Cash generated from 140.4 123.1 295.6
operations
Interest received 5 2.4 2.1 4.4
Taxation paid (0.5) (0.1) (0.8)
Net cash generated 142.3 125.1 299.2
from operating
activities
Cash flows from
investing activities
Purchase of (12.2) (10.5) (39.7)
intangible assets
Purchase of (58.1) (29.5) (65.3)
property, plant and
equipment
Restricted cash 11 - 1.0 8.5
Net cash used in (70.3) (39.0) (96.5)
investing activities
Cash flows from
financing activities
Dividends paid to 11 (27.4) - -
company's
shareholders
Dividend related (1.6) - -
expenses
Purchase of shares (8.2) - -
for employee share
trust
Purchase of treasury 11 (0.5) - -
shares
Lease payments 13 (0.3) - -
Interest paid (15.0) (15.0) (30.0)
Net cash used in (53.0) (15.0) (30.0)
financing activities
Net increase / 19.0 71.1 172.7
(decrease) in cash
and cash equivalents
Foreign exchange - 0.1 (0.4)
income / (loss) on
cash and cash
equivalents
Cash and cash 334.3 162.0 162.0
equivalents at 1
January
Cash and cash 11 353.3 233.2 334.3
equivalents at
period end
Notes to the condensed consolidated financial statements
1) Basis of preparation
Genel Energy Plc - registration number: 107897 (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 2019 and six months ended 30 June 2018 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 2019. 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 2018, which have
been prepared in accordance with IFRS as adopted by the European Union. The
annual financial statements for the period ended 31 December 2018 were
approved by the board of directors on 19 March 2019. 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 2018 has been extracted
from the audited accounts.
There have been no changes in related parties since year-end and no related
party transactions that had a material effect on financial position or
performance in the period. There are not significant seasonal or cyclical
variations in the Company's total revenues.
Going concern
The Company regularly evaluates its financial position, cash flow forecasts
and its covenants by sensitizing with a range of scenarios which
incorporates change in oil prices, discount rates, production volumes as
well as capital and operational spend. As a result, the Directors have
assessed that the Company's forecast liquidity provides adequate headroom
over its forecast expenditure for the 12 months following the half-year
condensed consolidated financial statements for the period ended 30 June
2019 and consequently that the Company is considered a going concern.
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 2018.
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 or
estimates could have a significant impact on the financial statements.
Significant estimates
The following are the critical estimates that the directors have made in the
process of applying the Company's accounting policies and that has the most
significant effect on the amounts recognised in the financial statements.
Estimation of hydrocarbon reserves and resources and associated production
profiles and costs
Estimates of hydrocarbon reserves and resources are inherently imprecise 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, cost
and monetisation impact the Company's financial statements in a number of
ways, including: testing recoverable values for impairment; the calculation
of depreciation, amortisation and assessing the cost and likely timing of
decommissioning activity and associated costs.
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.
Assets assessed as proven and probable reserves ("2P" - generally accepted
to have circa 50% probability) are generally classified as property, plant
and equipment as development or producing assets and depreciated using the
units of production methodology. The Company considers its best estimate for
future production and quantity of oil within an asset based on a combination
of internal and external evaluations and uses this as the basis of
calculating depreciation and amortisation of oil and gas assets and testing
for impairment.
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
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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.
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 nominal discount rate
of 12.5% is used when assessing the impairment testing of the Company's oil
assets.
In addition, estimation of the recoverable amounts of both Miran and Bina
Bawi CGUs, which are classified under IFRS as exploration and evaluation
intangible assets and consequently carry the inherent uncertainty explained
above, include the key assessment that the projects 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 and 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.
Estimation of future oil price and netback 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. It is
also relevant to the assessment of going concern.
Netback price is used to value the Company's revenue, trade receivables and
its forecast cash flows used for impairment testing. 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.
The trade receivable is recognised when the control on oil is transferred to
the customer at the metering point, as this is the time the consideration
becomes unconditional. The trade receivable reflects the Company's
entitlement based on the netback price and oil transferred.
Acquisitions of Sarta and Qara Dagh PSCs
On 28 February 2019 the Company completed the acquisition of a 30% interest
in the Sarta PSC, with an economic date of 1 January 2019. Shortly after
acquisition date, final investment decision ("FID") was taken on phase 1A
development, resulting in the recognition of gross 2P reserves at the asset
level of 34mmbbls, of which the Company's share was 10mmbbls. The interest
has been accounted for as an asset acquisition under IAS 16, with the result
being the recognition of a development asset, reflecting the acquired 2P
reserves. Consideration for the asset is a combination of cost recoverable
carry and a milestone success payment and has been assessed based on the 2P
reserves that have been recognised.
On the same date, the Company also completed the acquisition of a 40%
interest in the Qara Dagh PSC. Consideration on the asset is cost
recoverable carry arrangement on one well.
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.
Joint arrangements
Arrangements under which the Company has contractually agreed to share
control with another party, or parties, are joint ventures where the parties
have rights to the net assets of the arrangement, or joint operations where
the parties have rights to the assets and obligations for the liabilities
relating to the arrangement. Investments in entities over which the Company
has the right to exercise significant influence but has neither control nor
joint control are classified as associates and accounted for under the
equity method.
The Company recognises its assets and liabilities relating to its interests
in joint operations, including its share of assets held jointly and
liabilities incurred jointly with other partners.
Farm-in/farm-out
Farm-out transactions relate to the relinquishment of an interest in oil and
gas assets in return for services rendered by a third party or where a third
party agrees to pay a portion of the Company's share of the development
costs (cost carry). Farm-in transactions relate to the acquisition by the
Company of an interest in oil and gas assets in return for services rendered
or cost-carry provided by the Company.
Farm-in/farm-out transactions undertaken in the development or production
phase of an oil and gas asset are accounted for as an acquisition or
disposal of oil and gas assets. The consideration given is measured as the
fair value of the services rendered or cost-carry provided and any gain or
loss arising on the farm-in/farm-out is recognised in the statement of
comprehensive income. A profit is recognised for any consideration received
in the form of cash to the extent that the cash receipt exceeds the carrying
value of the associated asset.
Farm-in/farm-out transactions undertaken in the exploration phase of an oil
and gas asset are accounted for on a no gain/no loss basis due to inherent
uncertainties in the exploration phase and associated difficulties in
determining fair values reliably prior to the determination of commercially
recoverable proved reserves. The resulting exploration and evaluation asset
is then assessed for impairment indicators under IFRS 6.
New Standards
The following new accounting standards, amendments to existing standards and
interpretations are effective on 1 January 2019. Amendments to IFRS 9 -
Prepayment Features with Negative Compensation, Amendments to IAS 28 -
Long-term Interests in Associates and Joint Ventures, Amendments to IAS 19 -
Plan Amendment, Curtailment or Settlement, IFRIC 23 - Uncertainty over
Income Tax Treatments, Annual Improvements to IFRS Standards 2015-2017
Cycle. The adoption of these standards and amendments has had no impact on
the Company's results or financial statement disclosures.
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 References to the Conceptual
Framework in IFRS Standards (effective 1 Jan 2020), Amendment to IFRS 3
Business Combinations (effective 1 Jan 2020) and Amendments to IAS 1 and IAS
8: Definition of Material (effective 1 Jan 2020).
Changes in accounting policies
IFRS 16 - Leases, which became effective by 1 January 2019, requires the
lessee to recognise 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 has adopted IFRS 16 retrospectively from 1
January 2019, but has not restated comparatives for the 2018 reporting
period, as permitted under the specific transitional provisions in the
standard. The reclassifications and the adjustments arising from the new
leasing rules are therefore recognised in the opening balance sheet on 1
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January 2019 and further explained in Note 13.
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 2018. 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, development field on
Sarta PSC and appraisal field on Qara Dagh 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. 'Other'
includes corporate assets, liabilities and costs, elimination of
intercompany receivables and intercompany payables, which are non-segment
items.
6 months ended 30 June 2019
Expl. Total
Oil MBB Other
$m $m $m $m $m
Revenue from contracts 188.7 - - - 188.7
with customers
Revenue from other sources 5.6 - - - 5.6
Cost of sales (92.3) - - - (92.3)
Gross profit 102.0 - - - 102.0
Exploration (expense) / - (0.2) (0.4) - (0.6)
credit
General and administrative - - - (9.5) (9.5)
costs
Operating profit / (loss) 102.0 (0.2) (0.4) (9.5) 91.9
Operating profit / (loss)
is comprised of
EBITDAX 176.2 - - (8.9) 167.3
Depreciation and (74.2) - - (0.6) (74.8)
amortisation
Exploration (expense) / - (0.2) (0.4) - (0.6)
credit
Finance income - - - 2.4 2.4
Bond interest expense - - - (15.0) (15.0)
Other finance expense (1.0) (0.1) - (1.8) (2.9)
Profit / (loss) before tax 101.0 (0.3) (0.4) (23.9) 76.4
Capital expenditure 64.6 5.6 2.0 - 72.2
Total assets 1,082.9 467.4 35.1 340.8 1,926.2
Total liabilities (146.0) (88.5) (12.6) (305.5) (552.6)
Revenue from contracts with customers includes $54.7 million (30 June 2018:
$48.2 million, 31 December 2018: $105.4 million) arising from the 4.5%
royalty interest on gross Tawke PSC revenue ending at the end of July 2022
("the ORRI"). Total assets and liabilities in the other segment are
predominantly cash and debt balances.
6 months ended 30 June 2018
Expl. Total
Oil MBB Other
$m $m $m $m $m
Revenue from contracts 158.9 - - - 158.9
with customers
Revenue from other sources 2.2 - - - 2.2
Cost of sales (75.5) - - - (75.5)
Gross profit 85.6 - - - 85.6
Exploration expense - (0.2) (0.3) - (0.5)
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)
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 / (loss) 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)
Total assets and liabilities in the other segment are predominantly cash and
debt balances.
For the period ended 31 December 2018
Expl. Total
Oil MBB Other
$m $m $m $m $m
Revenue from contracts 350.3 - - - 350.3
with customers
Revenue from other 4.8 - - - 4.8
sources
Cost of sales (163.2) - - - (163.2)
Gross profit 191.9 - - - 191.9
Exploration (expense) / - (0.4) 1.9 - 1.5
credit
Impairment of intangible - (424.0) - - (424.0)
assets
General and - - - (24.0) (24.0)
administrative costs
Operating profit / (loss) 191.9 (424.4) 1.9 (24.0) (254.6)
Operating profit / (loss)
is comprised of
EBITDAX 326.4 - - (22.3) 304.1
Depreciation and (134.5) - - (1.7) (136.2)
amortisation
Exploration (expense) / - (0.4) 1.9 - 1.5
credit
Impairment of intangible - (424.0) - - (424.0)
assets
Finance income - - - 4.4 4.4
Bond interest expense - - - (30.0) (30.0)
Other finance expense (1.7) (0.2) - (1.3) (3.2)
Profit / (Loss) before 190.2 (424.6) 1.9 (50.9) (283.4)
income tax
Capital expenditure 70.4 12.0 13.1 - 95.5
Total assets 1,015.4 457.7 35.5 319.3 1,827.9
Total liabilities (89.1) (84.4) (16.1) (306.9) (496.5)
Total assets and liabilities in the other segment are predominantly cash and
debt balances.
4. Operating costs
******************
6 months to 6 months to Year to 31
30 June 2019 30 June 2018 December 2018
$m $m $m
Production costs 18.1 12.1 28.7
Depreciation of oil 39.7 34.6 72.4
and gas property,
plant and equipment
Amortisation of oil 34.5 28.8 62.1
and gas intangible
assets
Cost of sales 92.3 75.5 163.2
Exploration expense / 0.6 0.5 (1.5)
(credit)
Impairment of - - 424.0
intangible assets
(note 8)
Corporate cash costs 7.2 8.6 17.4
Corporate share-based 1.7 3.0 4.9
payment expense
Depreciation and 0.6 0.2 1.7
amortisation of
corporate assets
General and 9.5 11.8 24.0
administrative
expenses
5) Finance expense and income
6 months to 30 6 months to 30 Year to 31
June 2019 June 2018 December 2018
$m $m $m
Bond (15.0) (15.0) (30.0)
interest
payable
Other (2.9) (1.1) (3.2)
finance
expense
Finance (17.9) (16.1) (33.2)
expense
Bank 2.4 2.1 4.4
interest
income
Finance 2.4 2.1 4.4
income
Bond interest payable is the cash interest cost of Company bond debt. Other
finance expense primarily relates to the discount unwind on the bond and the
asset retirement obligation provision.
6. Income tax expense
*********************
Current tax expense is incurred on the profits of the Turkish and UK
services companies. Under the terms of KRI PSC's, corporate income tax due
is paid on behalf of the Company by the KRG from the KRG's own share of
revenues, resulting in no corporate income tax payment required or expected
to be made by the Company. It is not known at what rate tax is paid, but it
is estimated that the current tax rate would be between 15% and 40%. If this
was known it may result in a gross up of revenue with a corresponding debit
entry to taxation expense with no net impact on the income statement or on
cash. In addition, it would be necessary to assess whether any deferred tax
asset or liability was required to be recognised.
7. Earnings per share
*********************
Basic
Basic earnings per share is calculated by dividing the profit attributable
to equity holders of the Company by the weighted average number of shares in
issue during the period.
6 months to 30 June 2019 6 Year to
months 31
to 30 December
June 2018
2018
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$m $m $m
Profit / 76.0 59.3 (283.6)
(Loss)
attributable
to equity
holders of
the Company
($m)
Weighted 279,435,346 279,02 279,065,7
average 5,723 17
number of
ordinary
shares -
number 1
Basic 27.2 21.3 (101.6)
earnings /
(loss) per
share -
cents 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 6 months to Year to 31
30 June 2019 30 June 2018 December 2018
$m $m $m
Profit / (Loss) 76.0 59.3 (283.6)
attributable to
equity holders of
the Company ($m)
Weighted average 279,435,346 279,025,723 279,065,717
number of ordinary
shares - number 1
Adjustment for 812,852 1,222,475 1,182,481
performance shares,
restricted shares
and share options
Total number of 280,248,198 280,248,198 280,248,198
shares
Diluted earnings / 27.1 21.2 (101.6)
(loss) per share -
cents per 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 2018 1,471.7 425.1 6.5 1,903.3
Additions 6.3 - - 6.3
Discount unwind of 3.9 - - 3.9
contingent
consideration
Other (0.1) - - (0.1)
At 30 June 2018 1,481.8 425.1 6.5 1,913.4
At 1 January 2018 1,471.7 425.1 6.5 1,903.3
Additions 25.1 - 0.3 25.4
Discount unwind of 8.1 - - 8.1
contingent
consideration
Other (11.7) - - (11.7)
At 31 December 2018 1,493.2 425.1 6.8 1,925.1
and 1 January 2019
Additions 7.6 - 0.4 8.0
Discount unwind of 4.3 - - 4.3
contingent
consideration
Other - - - -
At 30 June 2019 1,505.1 425.1 7.2 1,937.4
Accumulated
amortisation and
impairment
At 1 January 2018 (581.3) (32.8) (6.3) (620.4)
Amortisation charge - (28.8) (0.1) (28.9)
for the period
At 30 June 2018 (581.3) (61.6) (6.4) (649.3)
At 1 January 2018 (581.3) (32.8) (6.3) (620.4)
Amortisation charge - (62.1) (0.2) (62.3)
for the period
Impairment (424.0) - - (424.0)
At 31 December 2018 (1,005.3) (94.9) (6.5) (1,106.7
and 1 January 2019 )
Amortisation charge - (34.5) (0.1) (34.6)
for the period
At 30 June 2019 (1,005.3) (129.4) (6.6) (1,141.3
)
Net book value
At 30 June 2018 900.5 363.5 0.1 1,264.1
At 31 December 2018 487.9 330.2 0.3 818.4
At 30 June 2019 499.8 295.7 0.6 796.1
30 Jun 31
Dec
2019 2018
CGU carrying value $m $m
Bina Bawi PSC Discovered gas and oil, 347.4 338.7
appraisal
Miran PSC Discovered gas and oil, 117.9 116.2
appraisal
Somaliland PSC Exploration 33.4 33.0
Qara Dagh PSC Exploration / Appraisal 1.1 -
Exploration and 499.8 487.9
evaluation assets
Tawke overriding royalty 188.5 217.5
Tawke capacity building payment waiver 107.2 112.7
Tawke RSA assets 295.7 330.2
The table below shows the indicative sensitivity of the Bina Bawi CGU net
present value to changes to long term Brent, discount rate or production and
reserves, assuming no change to other inputs.
$m
Long term Brent +/- $5/bbl +/- 13
Discount rate +/-2.5% +/- 101
Production and reserves +/- 10% +/- 32
9. Property, plant and equipment
********************************
Development
assets
Producing Other
assets
assets Total
$m $m $m $m
Cost
At 1 January 2018 2,683.9 - 9.4 2,693.3
Additions 27.8 - - 27.8
Non-cash additions 1.4 - - 1.4
for ARO/share-based
payments
At 30 June 2018 2,713.1 - 9.4 2,722.5
At 1 January 2018 2,683.9 - 9.4 2,693.3
Additions 70.4 - 0.2 70.6
Non-cash additions 2.9 - - 2.9
for ARO/share-based
payments
At 31 December 2018 2,757.2 - 9.6 2,766.8
and 1 January 2019
Asset acquisitions - 49.4 - 49.4
Additions 53.3 11.3 - 64.6
Right-of-use assets - - 1.9 1.9
(note 13)
Net change in - (1.9) - (1.9)
payable
Non-cash additions 1.6 - - 1.6
for ARO/share-based
payments
At 30 June 2019 2,812.1 58.8 11.5 2,882.4
Accumulated
depreciation and
impairment
At 1 January 2018 (2,119.7) - (8.6) (2,128.
3)
Depreciation charge (34.6) - (0.1) (34.7)
for the period
At 30 June 2018 (2,154.3) - (8.7) (2,163.
0)
At 1 January 2018 (2,119.7) - (8.6) (2,128.
3)
Depreciation charge (72.4) - (0.3) (72.7)
for the period
At 31 December 2018 (2,192.1) - (8.9) (2,201.
and 1 January 2019 0)
Depreciation charge (39.7) - (0.5) (40.2)
for the period
At 30 June 2019 (2,231.8) - (9.4) (2,241.
2)
Net book value
At 30 June 2018 558.8 - 0.7 559.5
At 31 December 2018 565.1 - 0.7 565.8
At 30 June 2019 580.3 58.8 2.1 641.2
30 Jun 31 Dec
2019 2018
CGU $m $m
carrying
value
Tawke PSC Oil production 488.5 478.2
Taq Taq Oil production 91.8 86.9
PSC
Producing 580.3 565.1
assets
Sarta PSC Oil development 58.8 -
Asset acquisitions of $49.4 million relates to the Sarta PSC. Further
explanation on oil and gas assets is provided in the significant accounting
judgements and estimates in note 2. The sensitivities below provide an
indicative impact on net present value of a change in long term Brent,
discount rate or production and reserves, assuming no change to any other
inputs.
Taq Taq CGU Tawke CGU
$m $m
Long term Brent +/- $5/bbl +/- 3 +/- 28
Discount rate +/-2.5% +/- 5 +/- 52
Production and reserves +/-10% +/- 9 +/- 71
10. Trade and other receivables
30 June 30 June 2018 31 Dec
$m
2019 2018
$m $m
Trade receivables 116.6 84.4 94.8
Other receivables and prepayments 9.0 3.9 4.6
125.6 88.3 99.4
Trade receivables are amounts owed for the revenue from contracts with
customers. The Company reports trade receivables net of any capacity
building payables (30 June 2019: $4.2 million 31 December 2018: $1.9
million).
Under the Tawke and Taq Taq PSCs, payment for entitlement is due within 30
days. Since February 2016, a track record of payments being received three
months after invoicing has been established, and consequently three months
has been assessed as the established operating cycle under IAS 1. At 30 June
2019, $18.9M relating to the entitlement arising from the Tawke PSC had not
been received. This was caused by operator banking issues, with the balance
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