DJ Genel Energy PLC: Half-Year Results
Genel Energy PLC (GENL)
Genel Energy PLC: Half-Year Results
06-Aug-2020 / 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 2020
Genel Energy plc
Unaudited results for the period ended 30 June 2020
Genel Energy plc ('Genel' or 'the Company') announces its unaudited results
for the six months ended 30 June 2020.
Bill Higgs, Chief Executive of Genel, said:
"Genel's robust business model, which is designed to provide resilience in a
challenging environment, has demonstrated its value as the Company
negotiates the headwinds facing the sector in 2020. Our low-cost production
and the capital flexibility within our development programme have enabled us
to preserve the strength of our balance sheet even while investing in
growth. Given the lower oil price and overdue payments, the fact that we
still expect to end 2020 in a net cash position - even after dividend
distributions and making the investment to bring Sarta to production this
year - is a testament to our resilience, and we have today confirmed an
interim dividend of 5¢ per share."
Results summary ($ million unless stated)
H1 2020 H1 2019 FY 2019
Production (bopd, working interest) 32,100 37,400 36,250
Revenue 88.4 194.3 377.2
EBITDAX1 65.1 167.3 321.8
Depreciation and amortisation (82.6) (74.8) (158.5)
Exploration expense (1.3) (0.6) (1.2)
Impairment of oil and gas assets (286.3) - (29.8)
Impairment of trade receivables (34.9) - -
Operating (loss) / profit (340.0) 91.9 132.3
Underlying (loss) / profit2 (32.2) 76.6 134.9
Cash flow from operating activities 85.5 142.3 272.9
Capital expenditure 58.5 72.2 158.1
Free cash flow3 6.5 56.7 99.0
Dividends paid 41.3 27.4 27.4
Cash4 355.3 353.3 390.7
Total debt 300.0 300.0 300.0
Net cash5 57.2 55.8 92.8
Basic EPS (¢ per share) (128.9) 27.2 37.8
Underlying EPS (¢ per share)2 (11.7) 27.4 49.0
Average Brent oil price ($/bbl) 40 65 64
1) EBITDAX is operating (loss) /profit adjusted for the add back of
depreciation and amortisation ($82.6 million), exploration expense ($1.3
million), impairment of property, plant and equipment ($242.0 million),
impairment of intangible assets ($44.3 million) and impairment of trade
receivables ($34.9 million).
2) Underlying EPS is underlying profit (page 9) divided by weighted
average number of shares
3) Free cash flow is reconciled on page 10
4) Cash reported at 30 June 2020 excludes $3.1 million of restricted cash,
and takes into account the dividend paid in June
5) Reported cash less IFRS debt (page 10)
Highlights
· Cash of $355 million at 30 June 2020 ($353 million at 30 June 2019)
· Net cash of $57 million at 30 June 2020 (net cash of $56 million at 30
June 2019)
· $110 million received from the Kurdistan Regional Government ('KRG')
in H1 2020
· Updated payment mechanism introduced in April, under which the KRG
committed to settling monthly sales invoices by the middle of the
following month
· $121 million remains outstanding in relation to oil sales from
November 2019 to February 2020 - discussions continue with the KRG over
settlement arrangements
· Despite the monies outstanding, the fall in oil price and non-payment of
the override, $6.5 million of free cash flow was generated in H1 2020 due
to Genel's low-costs and resilient business model allowing flexible
expenditure
· Production cost of $2.9/bbl in H1 2020
· Capital expenditure of $58.5 million in H1 as spending cut due to the
external environment
· G&A costs of $6.6 million, a reduction of c.30% year-on-year, as
activity is rephased
· Production of 32,100 bopd in H1 2020, due in part to the impact of
COVID-19, coupled with payment uncertainty, resulting in reduced drilling
activity at the Tawke PSC
· Production averaged 33,000 bopd in July 2020, following fast tracking
of activity at the Tawke PSC against an improved backdrop
· Continued focus on safety: zero lost time incidents and zero losses of
primary containment in the period
· Impairments of $286 million largely due to reduction in Brent oil price
forecast
· Interim dividend of 5¢ per share confirmed (2019: 5¢ per share)
Outlook
· Genel's low-cost production, flexible capital investment programme, and
robust balance sheet makes it resilient to lower oil prices, and the
Company expects to retain a net cash position at the end of 2020 at the
prevailing oil price, while still investing in key growth assets
· Capex of c.$45 million expected in H2, with c.50% to be spent on moving
Sarta to production in Q4, where work has continued despite the challenges
resulting from COVID-19
· Genel continues discussions with the KRG regarding the recovery of the
$121 million receivable
Enquiries:
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 0900 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
No natural resources company has been immune from the impacts of COVID-19
and the resulting collapse in demand and fall in the oil price. In the face
of this material change in circumstances, we focused on controlling what is
within our power to control in the near-term, while continuing to build the
business fit for a future of fewer and better natural resources projects in
the long-term. In this regard our business model positions us well both now,
as we have a strong balance sheet and limited fixed capital expenditure, and
for the future.
We have a business model designed for tough times, and we moved quickly to
rebase our spending appropriately for the external environment, reducing our
full-year capital expenditure forecast by c.$75 million to just over $100
million, and continuing to focus on managing costs elsewhere in the
business.
Given the external environment, we continued to allocate capital to those
areas that can provide the greatest returns and deliver shareholder value.
Due to the oil price and lack of certainty over the deferred receivable and
override payments, investing at Taq Taq is not currently a priority, and
work at Tawke has the ability to rapidly scale up as the external
environment improves. Despite the reduction in investment, production from
Tawke has been in line with internal expectations, and the significant
increase in production in July is an encouraging illustration of what can be
achieved once investment resumes.
The key focus of capital allocation in 2020 has been Sarta, where work is
continuing along a critical path to production in Q4. Genel is already the
only multi-licence producer in the KRI, and further diversifying production
by bringing Sarta into production with its tremendous growth potential is a
milestone that we are all looking forward to reaching.
It is a testament to our balance sheet and careful financial management
that, even with $121 million outstanding from the KRG for production in
November 2019 to February 2020 and override payments unpaid, we are able to
continue allocating capital to direct returns to shareholders, and our
interim dividend of 5¢ per share has been retained.
While the mechanism through which the receivable from the KRG will be
recovered has yet to be finalised, we are confident that a solution that
works for both parties will be found, as has been done in the past, and our
discussions with the KRG continue.
ESG
As the external environment has deteriorated due to COVID-19, it has not
lessened our focus on ESG. The safety of our workforce and contractors
remains a key priority, and we are pleased to continue our record of not
having a lost-time injury since 2015. We are also working hard on improving
our ESG activities, and better communicating the things that we already do
well.
We recognise that we have a long way to go, but are proud of our track
record in the KRI, where we have aimed to have a positive impact ever since
our operations started almost 15 years ago. In this time, we have funded and
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DJ Genel Energy PLC: Half-Year Results -2-
successfully delivered 245 social investment and community projects,
spending almost $60 million.
In the first half of the year we have become a member of both Transparency
International UK and TRACE, and become a signatory of the United Nations
Global Compact, supporting our aim of being a socially responsible
contributor to the global energy mix. Our sustainability report, due in
September, will provide further detail and enhanced disclosure on all ESG
aspects.
OPERATING REVIEW
The impact of COVID-19 led to a significant reduction in activity in 2020.
By this point of the year, we were expecting to have continued an active
drilling programme at Tawke and Peshkabir, to be drilling at Qara Dagh, and
for Sarta to be advancing towards production. The fall in the oil price and
the delay in receipt of payments from the KRG, resulted in an appropriate
reduction in expenditure at the Tawke PSC, while the direct impact of
COVID-19 on supply chains and the movement of people into the KRI forced us
to notify the KRG of the occurrence of a force majeure event preventing the
Company from being able to perform its contractual obligations as scheduled
at Qara Dagh.
Work has continued at Sarta, our key capital allocation priority in 2020,
and despite the challenges faced initial production is still expected later
this year.
Production
In line with internal expectations given the updated work plan.
(bopd) Gross Net Gross Net
production production production production
H1 2020 H1 2020 H1 2019 H1 2019
Tawke 59,790 14,950 71,700 17,920
Peshkabir 48,790 12,200 54,950 13,740
Taq Taq 11,260 4,950 13,150 5,780
Total 119,840 32,100 139,800 37,440
PRODUCING ASSETS
Tawke PSC (25% working interest)
Gross production from the Tawke licence averaged 108,580 bopd during the
first half of 2020, and 102,000 bopd during the second quarter of the year,
as the operator halted development activity to preserve cash at a time of
historically low and uncertain oil prices.
In June 2020, following the stabilisation of oil prices and export payments,
activity was fast tracked at the Tawke licence and production quickly
increased by 15,000 bopd month-on-month to raise average July 2020
production to 115,000 bopd.
The Peshkabir-to-Tawke gas reinjection project (the first enhanced oil
recovery project in the KRI) was commissioned in June, and aims to unlock
additional oil reserves at Tawke while significantly reducing gas flaring
and CO2 emissions at Peshkabir.
Taq Taq (44% working interest, joint operator)
Production at Taq Taq averaged 11,260 bopd in H1, in line with expectations
given the activity plan. As has been the case for some time, activity at Taq
Taq is focused on maximising cash generation and, given the oil price, the
TT-35 well, which completed in April, was the only well in the 2020 drilling
programme. This well initially added c.600 bopd to production, but is no
longer producing, following a mechanical issue.
Activity at the field will remain appropriate for the external environment
and aligned with our capital allocation priorities, and it is not expected
that there will be any further drilling activity in 2020.
PRE-PRODUCTION ASSETS
Sarta (30% working interest)
Despite the significant operational challenges caused by COVID-19, including
the closure of borders impacting supply chains and the movement of people
into the KRI, work has continued at Sarta, and first oil remains on target
for Q4 this year. Civil construction work at the field is materially
complete, with remaining work now focussing on the completion and
commissioning of the 20,000 bopd capacity early-production facility.
Production will begin following the recompletion of the Sarta-2 well,
re-entry of the Sarta-3 well, and commissioning of the facility through
which oil will be produced and processed ahead of tanker loading and
transport to the export pipeline at Khurmala.
With first oil now in sight, plans are well underway for the next stage of
the phase 1A pilot development, an appraisal programme which aims to fully
utilise the facility capacity and convert more of the 253 MMbbls of gross
resources assigned by ERCE to the Mus-Adaiyah-Butmah reservoirs into
reserves. A three well campaign is scheduled for 2021, with environmental
baselining underway ahead of construction of the well pads, in line with the
previously announced schedule. The first of these wells, S-6, is expected to
spud in Q1 and will be followed immediately by the S-1D well. While
focussing on the primary Mus-Adaiyah-Butmah reservoirs these wells are also
set to target additional reservoir intervals, a cost-efficient way to
maximise the gathering of information which will help inform the Company's
view of the wider potential of Sarta.
In order to minimise the time between appraisal success and monetisation the
field partners are investigating a range of options for oil production from
these 2021 wells.
Qara Dagh (40% working interest, operator)
Due to ongoing uncertainty caused by COVID-19, Genel notified the KRG of the
occurrence of a force majeure event preventing the Company from being able
to perform its contractual obligations as scheduled. Work continues to take
place to ensure that Genel is in the best possible position to start to
drill the QD-2 well once external conditions improve and the force majeure
event ceases. This has included the securing of an amendment to the rig
contract with Parker, in expectation of the future lifting of the force
majeure event, while from a community engagement perspective emergency food
aid has been provided to vulnerable groups within the Qara Dagh community,
and the construction of firebreaks in nearby agricultural land have been
funded.
Bina Bawi and Miran (100% working interest, operator)
As previously stated, Genel received documentation from the KRG in
mid-April, and then further documents were received in June. This
documentation did not adequately reflect the commercial concepts and risk
sharing that were expected for the development of Bina Bawi's gas and oil
resources.
Discussions are now taking place with the KRG at the highest level as Genel
seeks to progress the development of Bina Bawi.
African exploration
A farm-out process relating to the highly prospective SL10B13 block (100%
working interest and operator) in Somaliland began in Q4 2019 and while
conditions for farm-out have been challenging in the first half of 2020, a
number of companies continue to engage with the Company with respect to the
opportunity.
Regarding Morocco, and the Lagzira block (75% working interest and
operator), despite the logistical challenges posed by COVID-19 having caused
some delay to the completion of the 3D seismic processing project being
carried out by Western Geco, Genel continues to work towards a future
farm-out campaign aimed at bringing a partner onto the licence prior to
considering further commitments.
FINANCIAL REVIEW
Overview
The impact of COVID-19 has been significant. The resulting drop in oil
demand exacerbated the fall in oil price this year, which deteriorated from
around $60/bbl at the start of 2020 to a low of under $20/bbl in April.
Although the oil price has since improved, there remains significant
uncertainty as to how COVID-19 and its aftermath will impact economies, oil
demand and therefore oil price over the near and mid-term. This has caused
significant economic pressure on the KRG's finances, pressure that has
manifested itself in two ways: firstly, the deferral of payments owed by the
KRG for sales made in the four months from November 2019 to February 2020
inclusive, amounting to $121 million; secondly, the non-payment of the Tawke
override royalty from 1 March 2020.
It is clear that macro-economic uncertainty will extend into 2021 and likely
beyond, creating a challenging backdrop against which to progress our
business and seek to deliver on our commitment to run a business that is
resilient to downside scenarios, is cash generative, and delivers growth
when other oil and gas companies cannot.
All of the above means that the Company's business model, developed over the
past few years to be profitable at low prices and resilient at very low
prices, has been tested on its ability to:
· Progress value creative growth projects in a challenging environment;
· Demonstrate material flexibility in capital allocation, supporting the
generation of free cash flow even at low oil prices;
· Pay a dividend.
Our assessment is that our business model has stood up well to the
challenge. Much of the hard work done in previous years has positioned us
well: costs have had previous scrutiny so required optimisation rather than
a radical overhaul; and asset development plans had been set up within a
high capital flexibility model that mitigates financial risk, optimises cash
generation and expedites capital return and payback, so we were able to
adapt plans to the external environment.
The table below summarises our financial performance in the first half of
2020 (all figures $ million unless stated):
H1 2020 H1 2019 FY 2019
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Brent average oil price $40/bbl $65/bbl $64/bbl
Revenue 88.4 194.3 377.2
Opex (16.8) (18.1) (37.7)
G&A (excl. depreciation and (6.5) (8.9) (17.7)
amortisation)
EBITDAX 65.1 167.3 321.8
Producing asset capex (35.7) (53.3) (115.1)
Net cash interest1 (13.4) (12.6) (23.4)
Surplus before growth capex and dividend 16.0 101.4 183.3
Development capex (11.5) (11.3) (22.1)
Exploration and appraisal capex (11.3) (7.6) (20.9)
(Deficit) / Surplus (6.8) 82.5 140.3
Working capital and other 13.3 (25.8) (41.3)
Free cash flow 6.5 56.7 99.0
1 Net cash interest is bond interest payable less bank interest income (note
5)
· Our producing assets have delivered predictable production, and
liquidity has been preserved by taking quick steps to materially reduce
capex to a level appropriate to the oil price
· General and administration costs have been optimised
· The capital needs for Sarta first oil had already been optimised in line
with our business plan (low capital need, early cash generation), meaning
that even in this financial environment, we have been able to continue to
allocate capital to the project
· Force majeure declared at Qara Dagh, but we have continued to invest
where possible to position the project for a rapid and efficient restart
once force majeure is lifted and operating conditions permit
The overall result is that revenue generated in the period more than cover
our costs, resulting in a surplus of $16.0 million before investment in
growth. Our investment in growth projects, principally Sarta and Qara Dagh,
reduced that surplus to a deficit for the period of $6.8 million, with
working capital movements turning that deficit into a positive free cash
flow of $6.5 million. This has enabled the Company to preserve its balance
sheet strength, reporting net cash of $355 million. Despite not receiving
$120.8 million due in the period, this is a reduction of only $22 million
from the post-interim dividend cash number reported at 31 December 2019 of
$377 million.
Accounting impairments
Despite the business model proving to be resilient in the first half, there
has been a significant reduction in both near-term and long-term oil price
forecasts, with the change from the assumptions used for the previous
reporting period summarised in the table below:
$/bbl 2020 2021 2022 2023 2024
Forecast 40 43 50 55 60
Year-end forecast 65 67 68 72 73
The decrease in oil price, and to a significantly lesser extent the increase
in discount rate and deferral of some barrels into future periods as a
result of reduced activity, has resulted in a significant decrease in the
net present value of the Company's oil and gas assets. This has resulted in
a total impairment of $286.3 million.
In addition, there has been an impairment of $34.9 million to the $120.8
million nominal value of receivables owed by the KRG for sales made in the
four months from November 2019 to February 2020. The net present value has
been estimated for accounting purposes based on the initial communication
from the KRG, which indicates repayment would commence once oil price is
above $50/bbl. However, the mechanism for, and pace of, repayment has not
yet been agreed, and Genel expects to receive the nominal balance owed of
$120.8 million in full.
Resilient financial strength - well positioned to take advantage of an
unpredictable environment
With cash of $355 million, producing asset cash flows that cover corporate
and bond interest costs and fund pre-production investment, and Sarta
expected to be on production by the end of the year, the Company is well
positioned for 2021.
Genel will be ready to capitalise if the macro-environment starts to
improve, with a business that is already cash generative when investing in
pre-production growth projects and with a material receivable balance
expected to be recovered in line with the improvement in oil price. In a
downside scenario our business model and financial strength provides us with
an opportunity to take advantage both organically and inorganically: with
potential to drill Qara Dagh at a lower cost than might have been expected,
and the potential to acquire new assets that may become available due to the
financial stress on less resilient businesses.
Capital allocation and growth
As set out above, our business model supports the preservation of our
financial strength and has led us to generate cash even in a period with a
low oil price and irregular receipts of payments. Looking forward, due to
COVID-19 and the related oil price uncertainty, there remains a lack of
clarity on the mechanism for the recovery of the $121 million of monies owed
and the timing of the resumption of Tawke override payments. There is
therefore uncertainty over the timing and value of very material cash
inflows that were previously included in our base case near to mid-term
liquidity planning scenarios.
This emphasises the considerable extent to which our business model has been
tested and how durable it has proved to be. However, the quantum of the
uncertainty over timing of receipt of monies that we are contractually due
is significant and means that there is a very wide range of liquidity
outcomes ahead of us. The level of capital that is appropriate for the
Company to commit to its capital allocation priorities depends on its
confidence in the quantum and timing of future cash flows, and Genel
constantly reviews its capital allocation plans, aiming to deliver the
greatest returns and to preserve balance sheet strength.
The Company has a portfolio that contains assets with material value
creation possibilities, with discovered resource with the potential to add
incremental value to the share price greater than the current market
capitalisation of the Company. The higher our confidence in receipts, and
dependent on operating conditions, the more pace can be brought to the
development of these projects in the event that commercial, technical and
operational conditions support investment.
Dividend
In 2019, our confidence in our business plan to replace and grow producing
asset cash generation at value accretive cost was demonstrated by the
commencement of a sustainable and material dividend, and $41 million was
distributed to shareholders. The dividend remains a core part of our
business model, which is focused on growth and the protection of financial
strength. The financial strength of our business and the flexibility in our
cost base enabled us to reaffirm the final dividend at our full-year 2019
results, and we have retained our interim dividend of 5¢ per share.
Financial priorities and outlook
The table below summarises our progress against the 2020 financial
priorities of the Company as set out at our 2019 results.
FY2020 financial priorities Progress
· Maintaining our financial · Net cash expected to be
strength through existing maintained at year-end at
market conditions current oil price
· Continued focus on capital · Despite COVID-19 bringing
allocation, with material challenges:
prioritisation of highest progression towards Sarta
value investment in assets first oil in 2020 and
with ongoing or near-term investment in Qara Dagh
cash and value generation appraisal, once force majeure
removed, remain our key
capital allocation priorities
· Delivery of a 2020 work · A recut 2020 work programme
programme on time and on and budget preserving
budget, that is appropriate liquidity and reducing costs
to the external environment
· We are reducing spend on
controllable inputs
· Continued focus on · Management continues to seek
identifying and developing growth opportunities that fit
additional assets that offer the Company's capital
potential for significant structure and business model
value to the Company with
near to mid-term cash
generation, primarily to
further build the Company's
cash generation options when
the override royalty
agreement ends in Q3 2022
and provide the basis for
increasing the dividend in
the future
Our capital allocation philosophy remains the same, despite the recent fall
in oil price - invest in those projects with the potential to create most
shareholder value, targeting those assets that fit the criteria set out
previously.
In light of the likely macro volatility and uncertainty that lies ahead, in
order to maximise our ability to move quickly and deploy capital to take
advantage of prevailing conditions, the Board has decided to reverse its
previous decision to comply with premium listing rules. The principal impact
of this is that the Company will no longer apply chapter 10 of the Listing
Rules with respect to classifying transactions (such as acquisitions and
disposals) and so will have the benefit of being able to execute
transactions more efficiently, a significant advantage in the current
environment. See note 13 for more information.
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We will continue to be disciplined in our capital allocation and invest in
areas that can deliver most shareholder value. Rigorous cost management will
be maintained across all operations, ensuring spend is sufficient to take
advantage of the growth opportunities in the portfolio, and to maximise (net
present) value of the portfolio.
A summary of the financial results for the year is provided below.
Financial results for the period
Income statement
(all figures $ million) H1 2020 H1 2019 FY 2019
Production (bopd, working interest) 32,100 37,400 36,250
Profit oil 24.0 64.6 117.2
Cost oil 47.6 69.4 147.2
Override royalty 16.8 60.3 112.8
Revenue 88.4 194.3 377.2
Operating costs (16.8) (18.1) (37.7)
G&A (excl. depreciation and (6.5) (8.9) (17.7)
amortisation)
EBITDAX 65.1 167.3 321.8
Depreciation and amortisation (82.6) (74.8) (158.5)
Net interest (14.7) (15.5) (27.7)
Income tax expense - (0.4) (0.7)
Underlying (loss) / profit (32.2) 76.6 134.9
Impairment (321.2) - (29.8)
Exploration expense (1.3) (0.6) (1.2)
(Loss) / Profit (354.7) 76.0 103.9
Working interest production of 32,100 bopd decreased year-on-year (H1 2019:
37,400 bopd), principally as a result of lower average production from
Peshkabir, with the decrease in revenue from $194.3 million to $88.4
million, principally caused by:
· Lower Brent $62 million
· Lower capex resulting in lower cost oil $21 million
· Lower production $10 million
· Override unpaid from March onwards $10 million
Production costs of $16.8 million decreased from last period (H1 2019: $18.1
million) as a result of scaled back activity in producing assets. Production
cost per barrel increased from $2.7/bbl to $2.9/bbl due to decreased
production. General and administration costs were $6.6 million (H1 2019:
$9.5 million), of which corporate cash costs were $4.9 million (H1 2019:
$6.6 million). The reduction from the prior period is a result of
optimisation of costs and increased operational activity, principally at
Sarta and Qara Dagh. The decrease in revenue resulted in EBITDAX of $65.1
million (H1 2019: $167.3 million):
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. Underlying profit is presented in order to understand the
profitability of the recurring business, excluding the impact of items that
tend to be one off in nature, such as impairment and exploration
expenditure.
Depreciation of $51.6 million (H1 2019: $39.7 million) and Tawke intangibles
amortisation of $30.9 million (H1 2019: $34.5 million) increased as a result
of a combination of decrease in production profile and higher estimated
future costs on the Tawke PSC (depreciation/bbl: $8.6/bbl (H1 2019:
$5.8/bbl), noting that these costs are fully recoverable.
An impairment expense of $254.7 million for Tawke CGU, $31.6 million for Taq
Taq and $34.9 million for trade receivables was booked which is explained
further in note 2 (H1 2019: nil).
Bond interest expense of $15.0 million was in line with the prior period.
Finance income of $1.6 million (H1 2019: $2.4 million) was bank interest
income. Other finance expense of $1.3 million (H1 2019: $2.9 million)
included a non-cash discount unwind expense on liabilities.
In relation to taxation, under the terms of the KRI production sharing
contracts, 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 was related to taxation of the service companies (H1
2020: nil, H1 2019: $0.4 million).
Capital expenditure
Capital expenditure is the aggregation of spend on production assets ($35.7
million) and pre-production assets ($22.8 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 $58.5 million, predominantly focused on production assets and the
Sarta PSC ($11.5 million) and Qara Dagh ($4.4 million):
(all figures $ million) H1 2020 H1 2019 FY 2019
Cost recovered production capex 35.7 53.3 115.1
Pre-production capex - oil 11.5 11.3 22.1
Pre-production capex - gas 5.9 5.6 11.9
Other exploration and appraisal capex 5.4 2.0 9.0
Capital expenditure 58.5 72.2 158.1
Cash flow, cash, net cash and debt
Gross proceeds received was $110.0 million (H1 2019: $167.5 million), of
which $22.9 million (H1 2019: $54.2 million) was received for the override
royalty.
(all figures $ million) H1 2020 H1 2019 FY 2019
Brent average oil price $40/bbl $65/bbl $64/bbl
Operating cash flow 85.5 142.3 272.9
Producing asset cost recovered capex (38.1) (48.7) (105.1)
Development capex (11.6) (9.4) (18.7)
Exploration and appraisal capex (13.7) (12.2) (26.5)
Restricted cash (0.1) - 7.0
Interest and other (15.5) (15.3) (30.6)
Free cash flow 6.5 56.7 99.0
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 before dividend was $6.5 million, with an overall decrease in cash
of $35.4 million in the period (H1 2019: $19.0 million increase).
(all figures $ million) H1 2020 H1 2019 FY 2019
Free cash flow 6.5 56.7 99.0
Dividend paid (incl. expenses) (41.3) (29.0) (29.0)
Purchase of shares (0.7) (8.7) (13.5)
Other 0.1 - (0.1)
Net change in cash (35.4) 19.0 56.4
Opening cash 390.7 334.3 334.3
Closing cash 355.3 353.3 390.7
Debt reported under IFRS (298.1) (297.5) (297.9)
Net cash / (debt) 57.2 55.8 92.8
Closing cash of $355.3 million and net cash of $57.2 million (H1 2019: $55.8
million) exclude restricted cash of $3.1 million (H1 2019: $10.0 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 $298.1 million (31 December 2019: $297.9 million),
comprised of $300 million of bond debt less amortised costs. The bond pays a
10.0% coupon and matures in December 2022. A reconciliation of debt and cash
is provided in note 11 to the financial statements.
The bond has three financial covenant maintenance tests:
Financial covenant Test H1 2020
Net debt / EBITDAX< 3.0 (0.3)
Equity ratio (Total equity/Total assets) > 40% 64%
Minimum liquidity > $30m $355m
Net assets
Net assets at 30 June 2020 were $1,005.7 million (31 December 2019: $1,386.1
million) and consist primarily of oil and gas assets of $1,107.5 million (31
December 2019: $1,412.5 million), trade receivables of $90.2 million (31
December 2019: $150.2 million) and net cash of $57.2 million (31 December
2019: $92.8 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
Interim dividend distribution of $13.6 million was paid in January 2020, and
a final dividend distribution of $27.7 million in June 2020 (June 2019:
$27.4 million).
The Board is recommending no change in the interim dividend of 5¢ per share
(2019: 5¢ per share), a total distribution of c.$13.6 million. Total
dividends declared in 2020 amount to $41.3 million (2019: $40.8 million),
representing 15¢ per share (2019: 15¢ per share). The payment timetable for
the interim dividend is below:
· Ex-dividend date: 12 November 2020
· Record Date: 13 November 2020
· Payment Date: 11 December2020
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 2020 and consequently that the Company is considered a
going concern. In assessing going concern, the Directors have assessed that
prolonged prevalence of COVID-19 may have a further negative impact on the
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DJ Genel Energy PLC: Half-Year Results -5-
oil price and in turn revenues, operational activity and receipt of amounts
owed. The Company's low run rate costs, flexible capital programme, and
strong cash position provide appropriate mitigation of the reduction of cash
inflows that COVID-19 may cause for the going concern basis to remain
appropriate.
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; a deterioration in the external
environment caused by COVID-19; 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 2019 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, along with the
impact of COVID-19.
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 2019. 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 2020
Esa Ikaheimonen
CFO
5 August 2020
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 2020
6 months 6 months Year
to 30 June to 30 June to 31 Dec
2020 2019
2019
Note $m $m $m
Revenue 3 88.4 194.3 377.2
Production costs 4 (16.8) (18.1) (37.7)
Depreciation and 4 (82.5) (74.2) (157.1)
amortisation of oil
assets
Gross (loss) / (10.9) 102.0 182.4
profit
Exploration expense 4 (1.3) (0.6) (1.2)
Impairment of 4,8 (44.3) - -
intangible assets
Impairment of 4,9 (242.0) - (29.8)
property, plant and
equipment
Impairment of trade 4,10 (34.9) - -
receivables
General and 4 (6.6) (9.5) (19.1)
administrative costs
Operating (loss) / (340.0) 91.9 132.3
profit
Operating (loss) /
profit is comprised
of:
EBITDAX 65.1 167.3 321.8
Depreciation and 4 (82.6) (74.8) (158.5)
amortisation
Exploration expense 4 (1.3) (0.6) (1.2)
Impairment of 4,8 (44.3) - -
intangible assets
Impairment of 4,9 (242.0) - (29.8)
property, plant and
equipment
Impairment of trade 4,10 (34.9) - -
receivables
Finance income 5 1.6 2.4 6.6
Bond interest 5 (15.0) (15.0) (30.0)
expense
Other finance 5 (1.3) (2.9) (4.3)
expense
(Loss) / Profit (354.7) 76.4 104.6
before income tax
Income tax expense 6 - (0.4) (0.7)
(Loss) / Profit and (354.7) 76.0 103.9
total comprehensive
(expense) / income
Attributable to:
Shareholders' equity (354.7) 76.0 103.9
(354.7) 76.0 103.9
(Loss) / Profit per ¢ ¢ ¢
ordinary share
Basic 7 (128.9) 27.2 37.8
Diluted 7 (128.9) 27.1 37.4
Underlying1 (11.7) 27.4 49.0
1. Underlying profit is reconciled on page 9
Condensed consolidated balance sheet
At 30 June 2020
30 June 2020 30 June 2019 31 Dec 2019
Note $m $m $m
Assets
Non-current assets
Intangible assets 8 716.0 796.1 775.6
Property, plant and 9 391.5 641.2 636.9
equipment
1,107.5 1,437.3 1,412.5
Current assets
Trade and other 10 98.3 125.6 157.4
receivables
Restricted cash 3.1 10.0 3.0
Cash and cash 355.3 353.3 390.7
equivalents
456.7 488.9 551.1
Total assets 1,564.2 1,926.2 1,963.6
Liabilities
Non-current
liabilities
Trade and other (124.7) (120.8) (118.8)
payables
Deferred income (26.8) (28.1) (26.7)
Provisions (39.0) (34.7) (37.4)
Borrowings 11 (298.1) (297.5) (297.9)
(488.6) (481.1) (480.8)
Current liabilities
Trade and other (66.9) (65.3) (91.7)
payables
Deferred income (3.0) (6.2) (5.0)
(69.9) (71.5) (96.7)
Total liabilities (558.5) (552.6) (577.5)
Net assets 1,005.7 1,373.6 1,386.1
Owners of the parent
Share capital 43.8 43.8 43.8
Share premium account 4,005.4 4,046.6 4,033.4
Accumulated losses (3,043.5) (2,716.8) (2,691.1)
Total equity 1,005.7 1,373.6 1,386.1
Condensed consolidated statement of changes in equity
For the period ended 30 June 2020
Share Share Accumulated Total equity
capital premium losses
$m
$m $m $m
At 1 January 43.8 4,074.2 (2,786.6) 1,331.4
2019
Profit and - - 76.0 76.0
total
comprehensive
income
Share-based - - 2.5 2.5
payments
Purchase of - - (8.2) (8.2)
shares to
satisfy share
awards
Purchase of - - (0.5) (0.5)
treasury
shares
Dividend - (27.6)1 - (27.6)
payment
At 30 June 43.8 4,046.6 (2,716.8) 1,373.6
2019
At 1 January 43.8 4,074.2 (2,786.6) 1,331.4
2019
Profit and - - 103.9 103.9
total
comprehensive
income
Share-based - - 5.1 5.1
payments
Purchase of - - (8.2) (8.2)
shares to
satisfy share
awards
Purchase of - - (5.3) (5.3)
treasury
shares
Dividends - (40.8) - (40.8)
provided for
or paid1
At 31 December 43.8 4,033.4 (2,691.1) 1,386.1
2019 and 1
January 2020
Loss and total - - (354.7) (354.7)
comprehensive
expense
Share-based - - 3.0 3.0
payments
Purchase of - - (0.7) (0.7)
shares for
employee share
awards
Dividends - (28.0) - (28.0)
provided for
or paid1
At 30 June 43.8 4,005.4 (3,043.5) 1,005.7
2020
1 The Companies (Jersey) Law 1991 does not define the expression "dividend"
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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 2020
30 June 2020 30 June 2019 31 Dec 2019
Note $m $m $m
Cash flows from
operating activities
(Loss) / Profit and (354.7) 76.0 103.9
total comprehensive
(expense) / income
Adjustments for:
Net finance expense 5 14.7 15.5 27.7
Taxation 6 - 0.4 0.7
Depreciation and 4 82.6 74.8 158.5
amortisation
Exploration expense 4 1.3 0.6 1.2
Impairment of 4 44.3 - -
intangible assets
Impairment of 4 242.0 - 29.8
property, plant and
equipment
Impairment of 4 34.9 - -
receivables
Other non-cash items (0.3) (1.4) (2.4)
Changes in working
capital:
Decrease / (Increase) 22.0 (21.8) (55.4)
in trade receivables
Decrease / (Increase) 0.1 - (0.2)
in other receivables
(Decrease) / Increase (2.7) (3.7) 3.3
in trade and other
payables
Cash generated from 84.2 140.4 267.1
operations
Interest received 5 1.6 2.4 6.6
Taxation paid (0.3) (0.5) (0.8)
Net cash generated 85.5 142.3 272.9
from operating
activities
Cash flows from
investing activities
Purchase of (13.7) (12.2) (26.5)
intangible assets
Purchase of property, (49.7) (58.1) (123.8)
plant and equipment
Movement in (0.1) - 7.0
restricted cash
Net cash used in (63.5) (70.3) (143.3)
investing activities
Cash flows from
financing activities
Dividends paid to (41.3) (29.0) (29.0)
company's
shareholders,
including expenses
Purchase of shares (0.7) (8.2) (8.2)
for employee share
trust
Purchase of treasury - (0.5) (5.3)
shares
Lease payments (0.5) (0.3) (0.6)
Interest paid (15.0) (15.0) (30.0)
Net cash used in (57.5) (53.0) (73.1)
financing activities
Net (decrease) / (35.5) 19.0 56.5
increase in cash and
cash equivalents
Foreign exchange gain 0.1 - (0.1)
/ (loss) on cash and
cash equivalents
Cash and cash 390.7 334.3 334.3
equivalents at 1
January
Cash and cash 355.3 353.3 390.7
equivalents at 31
December
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 2020 and six months ended 30 June 2019 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 2020. 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 2019, which have
been prepared in accordance with IFRS as adopted by the European Union. The
annual financial statements for the period ended 31 December 2019 were
approved by the board of directors on 18 March 2020. 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 2019 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 compliance with financial covenants by considering multiple
combination of oil price, discount rates, production volumes, payments,
capital and operational spend scenarios. As a result, the Directors have
assessed that the Company's forecast liquidity provides adequate headroom
over its forecast expenditure for the 12 months from the date of signing the
half-year condensed consolidated financial statements for the period ended
30 June 2020 and consequently that the Company is considered a going
concern.
2. Summary of significant 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 2019.
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 judgements
Apart from those involving estimations (which are dealt with separately
below), there are no significant judgements 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.
Significant estimates
The following are the significant 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. 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.
Assets assessed as proven and probable reserves 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 reserves 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.
Change in accounting estimate
The Company has updated its estimated production profiles with the
accounting impact summarised below under estimation of oil and gas asset
values.
Estimation of oil and gas asset values
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