TIDMENOG
RNS Number : 4675K
Energean PLC
02 September 2021
Energean plc
("Energean" or the "Company")
Results for Half Year Ended 30 June 2021
London, 2 September 2021 - Energean plc (LSE: ENOG TASE: ) is
pleased to announce its half-year results for the six months ended
30 June 2021 ("1H 2021").
Mathios Rigas, Chief Executive of Energean, commented:
"During 1H 2021, Energean delivered excellent operational and
financial progress, reflecting the transformational nature of the
acquisition of Edison E&P. Production is outperforming
guidance, translating into record financial performance and,
through successful execution of our gas- and returns-focused
strategy, we have achieved a significant milestone in our
transformation into a 200 kboed, $2 billion annual revenue
generating, sustainable dividend yielding, energy company. In
addition, we further strengthened and de-risked our balance sheet
by raising the largest ever EMEA energy international high yield
bond and remain fully-funded for all projects across our nine
countries of operation.
"Despite continued COVID-19 related challenges, we have
delivered solid progress on our flagship Karish gas development
project, which remains firmly on track to deliver first gas in
mid-2022. There are a number of potential acceleration measures
under active consideration and, at 31 August 2021, the workforce on
the Karish project was in excess of 1,700, an approximate 70%
month-on-month increase. Further growth in Israel will be delivered
through our (up to) five-well offshore growth programme, with the
Stena IceMax drilling rig commencing operations in 1Q-2022. The
programme targets an additional 1 billion boe, which has the
potential to double our reserve base with high quality resource
volumes that can be quickly, economically, and safely monetised.
Globally, gas prices are strong and we are assessing several
commercial opportunities to access international markets, as well
as the growing Israeli domestic market, if (and when) additional
gas resources become available to us.
"In the second half of the year, we look forward to continuing
to deliver our key gas development projects in Egypt and Italy,
which alongside commencement of the revised Epsilon project in
Greece, will provide further, substantial near-term growth and
value realisation in the Mediterranean region.
"The recently published Intergovernmental Panel on Climate
Change [1] report on the impacts of global warming made for stark
reading and emphasized the need for immediate action. As a
business, we have taken full responsibility for our own emissions
profile, showcased by publication of our first Climate Change
Policy, which outlines the short, medium, and long-term actions we
will take as part of our commitment to become a net zero emitter by
2050. In the first half of 2021, we reduced the carbon intensity of
our operations by more than 19% versus 2020 levels [2] ;
representing a 73% reduction versus our base year of 2019. This is
a trajectory we are committed to continuing, and we are
investigating all options to accelerate our net zero commitment
ahead of 2050, in recognition of the need for urgent and immediate
action."
Highlights - Operational
-- 1H 2021 average working interest production was 44.0 kboed
(72% gas), ahead of full year guidance of 38 - 42 kboed (71%
gas)
o Production outperformed guidance across all countries of
operation
o Demonstrates Energean's ability to maximise value from the
ex-Edison E&P assets and to successfully integrate Edison
E&P within six-months of transaction close
-- On track to deliver first gas from Karish in mid-2022
o On 31 July 2021, the project was 91.5% complete [3]
o Core focus on optimising and accelerating the timetable with
options being actively considered (and not reflected in the current
timetable)
-- On 31 August 2021, the workforce on the Energean Power FPSO
stood at more than 1,700 workers, up approximately 70%
month-on-month
-- Rig contract signed with Stena Drilling Limited ("Stena") for
2022-23 growth drilling programme, offshore Israel
o Targeting the de-risking of prospective recoverable resources
of over 1 billion [4] barrels of oil equivalent ("boe")
-- Awarded an Engineering, Procurement, Construction and
Installation (" EPCI ") contract to TechnipFMC to develop the North
East Almeyra (" NEA ")/North Idku (" NI ") project, shallow-water
offshore Egypt, in February 2021
o Project remains on track to deliver first gas in 2H 2022
o Project expected to deliver IRRs in excess of 30%
-- Cassiopea gas development project, Italy, 23% complete at 31
July 2021 and on track to deliver first gas in 1H 2024
-- Final Investment Decision ("FID") taken on the revised 53
MMbbls 2P + 2C Epsilon satellite tieback project, offshore
Greece
o First oil expected in 1H 2023 (subject to financing)
o Financing package expected to be finalised in 3Q 2021
Highlights - Corporate and ESG
-- Issued $2.5 billion of senior secured notes in March 2021 at
an average coupon rate of approximately 5.2%
o Significantly reducing financing risk on the Karish project,
as the project finance facility had been due to mature in 2022
o Extending average life of debt for Energean plc from
approximately 2.5 years at 30 June 2020 to approximately 6 years at
31 July 2021
-- Completed the highly accretive acquisition of the 30%
minority interest in Energean Israel Limited ("EISL") in February
2021
o Acquisition transacted at a 49% discount to CPR-derived
NPV10
o Increased 2P reserves across the portfolio to nearly 1 billion
boe (79% gas)
-- 1H 2021 Scope 1 and 2 carbon emissions of approximately 18
kg/boe, a significant step towards Energean's target of achieving
net zero emissions ahead of 2050, representing a:
o 19% reduction versus 2020 levels [5] ;
o 73% reduction versus 2019; and
o On track to beat previous 2021 guidance of 21 kg/boe by
approximately 15%
Highlights - Financial
-- Substantial year-on-year improvement in financial results,
demonstrating the magnitude and significance of the acquisition of
Edison E&P
o Revenues increased to $206 million (1H 2020: $2 million),
primarily due to the transformational nature of the acquisition of
Edison E&P
o Unit cost of production reduced by 44% to $15.4/boe (1H 2020:
$27.5/boe)
o Positive EBITDAX(6) of $75 million (1H 2020: negative $8.9
million)
o Positive operating cash flows of $53.1 million (1H 2020: $14.5
million outflow)
-- Cash, cash equivalents and restricted cash of $ 1.1 billion
at 30 June 2021 (restricted amounts represent $266 million)
o Providing significant financial flexibility
o Ensures all planned activities are fully-funded
1H 2021 1H 2020 Increase / (Decrease)
$m $m %
Average working interest
production (kboed) 44.0 2.1 1,995%
---------- -------- ----------------------
Sales and other revenue 205.5 2.1 9,686%
---------- -------- ----------------------
Cash cost of production
[6] 122.4 [7] 10.4 1,077%
---------- -------- ----------------------
Cash cost of production
per boe 15.4 27.5 (44%)
---------- -------- ----------------------
Cash S,G&A(6) 17.0 5.4 215%
---------- -------- ----------------------
Adjusted EBITDAX [8] 74.7 (8.9) 939%
---------- -------- ----------------------
Operating cash flow
[9] 53.1 (14.5) 466%
---------- -------- ----------------------
Development capital
expenditure 200.8 243.9 (18%)
---------- -------- ----------------------
Exploration capital
expenditure 29.2 5.3 451%
---------- -------- ----------------------
Decommissioning expenditure 1.7 - -
---------- -------- ----------------------
Net debt (including
restricted cash) 1,692.6 861.4 96%
---------- -------- ----------------------
Outlook
-- 2021 production guidance re-iterated at 38 - 42 kboed
-- 2021 development and production capital expenditure guidance
re-iterated as $470 - 550 million and exploration capital
expenditure guidance re-iterated as $55 - 70 million
-- 2021 emissions intensity guidance reduced by approximately
15% to 18 kg CO2/boe (from 21 kgCO2/boe)
-- Sailaway of the Energean Power FPSO from Singapore to Israel
in 1Q 2022 with first gas from Karish expected mid-2022
o Acceleration measures being considered for implementation
-- Commencement of the high-impact growth drilling campaign in 1Q 2022, starting with Athena
o First drilling results anticipated during 2Q 2022, marking a
catalyst-rich start to 2022
-- Continued progress on key gas development projects in Egypt (NEA / NI) and Italy (Cassiopea)
-- Finalisation of funding for the Epsilon project, Greece, and
commencement of the development programme, expected 2H 2021
-- Acceleration of the Green Prinos suite of projects
o Pre-Front-End Engineering Design ("pre-FEED") on the carbon
capture and storage ("CCS") project expected to commence in 2H
2021
-- Future dividend policy to be declared in due course
Enquiries
Kate Sloan, Head of IR, ECM and Communications Tel: +44 7917 608
645
Conference call
A conference call for analysts and investors will be held at
08:30am BST today. Please register your participation in this
morning's conference call at the following link. You will be given
the option to either participate via webcast or dial in.
Webcast: https://edge.media-server.com/mmc/p/htkhfoq4
Dial-In: +44 (0) 2071 928338
Dial-in (Israel only): 35308845
Confirmation code: 5530326
The presentation slides will be made available on the website
shortly www.energean.com .
Energean Operational Review
Production
1H 2021 average working interest production was 44.0 kboed (72%
gas), ahead of full year guidance, which is maintained at 38 - 42
kboed. This represents a substantial year-on-year increase,
reflecting the transformational nature of the acquisition of Edison
E&P and the successful, quick integration of the Edison E&P
portfolio into Energean despite the operational challenges posed by
COVID-19.
1H 2021 actuals FY 2021 guidance 1H 2020
Kboed Kboed Kboed
Egypt 31.4 27 - 30 -
---------------- ----------------- --------
Italy 10.2 9 - 10 -
---------------- ----------------- --------
Greece and Croatia 1.8 1.5 2.1
---------------- ----------------- --------
UK 0.6 0.5 -
---------------- ----------------- --------
Total production 44.0 38 - 42 2.1
---------------- ----------------- --------
Israel
Karish Project
Energean remains firmly on track to deliver first gas from the
Karish gas development project in mid-2022. At 31 July 2021, the
project was approximately 91.5% complete [10] .
The next tangible milestone on the development remains sailaway
of the FPSO from Singapore to Israel, currently expected in 1Q
2022. The journey from Singapore to Israel is expected to take
approximately 35 days, with hook-up and pre-first gas commissioning
then expected to take approximately three months.
Energean is actively working with its contractors to identify
and implement potential acceleration measures for the FPSO delivery
schedule, which are not reflected in the current timetable.
Following agreement of an incentivisation payment of $12 million by
Energean to Sembcorp in August 2021, workforce numbers on the
Energean Power FPSO have increased by approximately 70%, to more
than 1,700 at 31 August 2021.
Energean will update the market on whether it expects any
acceleration of the delivery timetable as and when it is
appropriate to do so.
% Completion at 31 July 2021
[11]
Production Wells 100.0
-----------------------------
FPSO 96.7
-----------------------------
Subsea 83.0
-----------------------------
Onshore 99.8
-----------------------------
Total 91.5
-----------------------------
Energean has signed 18 gas sales agreements (" Agreements ") for
the supply of 7.2 Bcm/yr of gas on plateau, representing almost
100% of total gas reserves volumes over the life of those
Agreements. All Agreements include provisions for floor pricing and
take-or-pay and / or exclusivity, providing a high level of
certainty over revenues from the Karish, Karish North and Tanin
projects over the next 16 years.
For one Agreement representing 0.2 Bcm/yr and commencing 2024,
the buyer has been unable to meet its conditions subsequent under
the Agreement and the parties have mutually agreed to terminate the
Agreement. This termination is not related to the project schedule.
Energean has identified a potential replacement buyer for these
volumes and expects to reach an Agreement shortly; Energean's main
current restriction to signing further Agreements is that it has
sold substantially all of its independently audited gas
reserves.
One Agreement, representing 0.8 Bcm/yr of gas supply, is at
potential risk of termination; however, if it is terminated,
Energean has identified multiple alternative routes to monetise
those gas volumes, including both domestic and international
markets, and is confident of profitably selling them. Other than
that one Agreement, Energean believes that all of its Agreements
are robust under the current first gas delivery timetable,
notwithstanding the delays experienced due to COVID-19-related
circumstances.
Growth Projects
In May 2021, Energean took FID on two high-return growth
projects, offshore Israel:
-- $70 million second oil train that will enable increased
production of approximately 5 million barrels of hydrocarbon
liquids per year at minimal incremental operating costs; and
-- $40 million second gas sales riser, which will enable gas
production at the full 8 Bcm/yr capacity of the FPSO
Both projects are progressing on schedule and are expected
onstream in summer 2023.
In June 2021, Energean signed a rig contract with Stena for the
drilling of up to five wells that will target derisking of unrisked
prospective resources of over 1 Bnboe [12] . The contract consists
of three firm wells plus two optional wells, with the first well
expected to spud in 1Q 2022. The firm wells are all expected to be
drilled during 2022 and consist of:
-- The Athena exploration well, located on Block 12, is situated
directly between the Karish and Tanin leases and is expected to be
the first well in the programme;
o Two factors support commercialisation of a Block 12 discovery.
Firstly, Block 12 was a new licence award to EISL in 2018; produced
volumes will therefore generate no royalty payments in respect of
EISL's original acquisition of the block. Secondly, the more
proximate location of the potential development to the expected
position of the FPSO will reduce like-for-like development costs
when compared with Tanin
-- The Karish North development well , a key part of the Karish North development; and
-- The Karish Main-04 appraisal well, which is expected to
target further prospective volumes within the Karish Main Block,
including the potential oil rim that was identified as part of the
Karish Main-03 development well drilling.
Energean is in the process of identifying and working up
commercialisation options in the event of discoveries being made as
part of the 2022-23 growth drilling programme and monetisation
options include both domestic and international markets.
Egypt
Working interest production from the Abu Qir area averaged 31.4
kboed (87% gas) during 1H 2021 with full year production guidance
maintained at between 27 - 30 kboed.
The shallow-water NEA/NI satellite tie-back project is
progressing in line with expectations, with first gas from one well
anticipated in 2H 2022 and from the remaining three wells in 1Q
2023. The project was sanctioned in January 2021 and an EPCI
contract for the four subsea wells and the associated tie-back to
the Abu Qir platform and associated infrastructure was awarded to
TechnipFMC in 1Q 2021.
Around the Abu Qir and NEA/NI assets, Energean is maturing
several near-field and infrastructure-led opportunities, including
the discovered NI-B field, as potential future drilling candidates.
In addition, prospect maturation continues across the wider
portfolio to unlock value from the substantial prospective resource
volumes identified, including in deeper liquids-rich horizons.
At 30 June 2021, net receivables (after provision for bad and
doubtful debts) in Egypt were $158.7 million (31 December 2020:
$148.8 million), of which $94.0 million (31 December 2020: $78.7
million) was classified as
overdue. Cash collection from EGPC during the period was $74.9 million.
Italy
Working interest production from Italy averaged 10.2 kboed (41%
gas) during 1H 2021 with full year production expected to be
between 9 - 10 kboed.
Production continues to outperform expectations following robust
operational performance across the operated oil portfolio,
including the Vega and Rospo Mare fields, in which Energean
increased its working interest to 100% in January 2021 following
the nil-cost acquisition from ENI.
The Cassiopea (Energean 40%) gas development project was
approximately 23% complete at 31 July 2021, with works to date
focused on permitting, contracting and procurement, alongside a
cost optimisation programme. First gas from the project is expected
in 1H 2024. Development of Cassiopea will commercialise 31 MMboe of
2P reserves (100% gas) and achieve peak production of approximately
10 kboed.
Greece
Working interest production from the Prinos field averaged 1.6
kboed (0% gas) during 1H 2021 with full year production expected to
be 1.5 kboed.
Prinos Area Development and Funding
In March 2021, the European Commission approved Greek state
support for a EUR100 million funding package for the Prinos area,
with Greek parliamentary ratification in May 2021. The full funding
package is expected to be in place in 3Q 2021 with commencement of
investment in the Epsilon project expected shortly thereafter.
In parallel, Energean has been evaluating a project to reinject
produced carbon dioxide from Prinos back into the reservoir to
reduce Scope 1 emissions from the field. The project has been
approved for financial support from the European Commission's
European Structural and Investment Funds ("ESIF").
"Green Prinos"
Extending the life of the Prinos production area through the
Epsilon development is key to Energean's longer-term ambition of
leveraging its subsurface knowledge and expertise in developing CCS
and eco-hydrogen projects, which are expected to be key
contributors to Energean's net zero strategy.
The Prinos CCS project proposal is to provide long-term storage
for carbon dioxide emissions captured from both local and more
remote emitters.
In 1H 2021, Energean submitted its CCS proposal to the Greek
government, with a view to inclusion within its recovery and
resilience plan, projects within which will qualify to receive
funding from the Recovery and Resilience fund over the period
2021-26. In June 2021, the European Commission granted approval for
the inclusion of the Greek CCS project within the fund.
A pre-FEED study for the CCS project is expected to commence in
2H 2021.
Rest of Portfolio
United Kingdom
1H 2021 production in the UK North Sea was 0.6 kboed (8% gas),
ahead of full year guidance of 0.5 kboed.
Drilling operations at the Glengorm South appraisal well were
safely completed in April 2021. The well contained no commercial
hydrocarbons and the well has been plugged and abandoned. The
existing Glengorm North discovery and the Glengorm Central
appraisal well are considered to be independent of the Glengorm
South appraisal well; the Glengorm Central appraisal well spudded
in May 2021.
Energean has received interest from third parties with respect
to the potential sale of its UK assets portfolio and is considering
its options.
Croatia
During 1H 2021, working interest production from the Izabela
field averaged 0.2 kboed (100% gas).
Evaluation of the results from the Irena appraisal well are
ongoing.
Energean Corporate Review
ESG
Net Zero
In 1H 2021, Energean published its first Climate Change Policy,
which defines the Group's actions to deliver upon its commitment to
become a net-zero emitter by 2050.
Energean also took further steps towards this commitment, and is
investigating an acceleration of its 2050 net-zero target,
reflecting both its commitment and the importance of the global
achievement of the goal. Energean's Scope 1 and 2 carbon emissions
intensity in 1H 2021 was estimated to be approximately 18 kg/boe, a
19% reduction versus 2020 emissions levels [13] ; a 73% reduction
versus the 2019 base measurement year; and approximately 15% below
full-year 2021 guidance of approximately 21 kg/boe.
Actions taken to date in 2021 include:
-- Agreements put in place for the purchase of electricity from
renewable sources at all operated sites in Italy. Energean sites in
Italy, Israel, Greece and Croatia now operate under this policy,
which has substantially reduced Energean's scope 2 emissions
-- Zero-routine flaring policy now fully effective across all operated sites
-- Significant progress on the "Green Prinos" suite of
initiatives, as described in the Operating Review, above. Energean
is assessing the potential to replicate these initiatives across
its portfolio
ESG Reporting and Ratings
Energean's 2020 Annual Report and Accounts, published in April
2021, marked Energean's first period of reporting in accordance
with the requirements of the Task Force on Climate Related
Financial Disclosure ("TCFD").
In June 2021, MSCI updated its rating for energean to AA, up
from A in the previous year.
In July 2021, Energean was rated at gold level by Israel's Maala
Index for the second year running. The Maala Index is an ESG rating
system and stock market index that rates the largest companies in
Israel on an annual basis.
Financing
In 1H 2021, Energean issued $2.5 billion of senior secured
notes, maturing in four tranches (2024, 2026, 2028 and 2031) and
with an average coupon rate of 5.2% and increasing the average life
of debt across Energean plc's portfolio to more than six years.
The funds raised were used to both ensure that Energean's
projects in Israel are fully funded and also to refinance the
Group's outstanding project finance facility and term loan; drawn
amounts under these loans upon refinancing were $1,270 million and
$175 million, respectively. The refinancings removed a perceived
key risk on the Karish project consequent to the upcoming
maturities of those facilities. $266 million of proceeds have been
used to pre-fund certain reserve accounts, classified as restricted
cash within this report, with remaining proceeds earmarked for
capital expenditure on the Karish and Karish North projects, the
2022/2023 Israel exploration programme, to fund bond transaction
costs, outstanding amounts due to Kerogen relating to the
acquisition of the minority interest in EISL, and for general
corporate purposes.
2021 guidance
FY 2021
Consolidated net debt ($ million) 2,000
----------
Cost of Production (Operating Costs plus
Royalties)
----------
-
* Israel ($ million)
----------
* Egypt ($ million) 55 - 60
----------
* Italy ($ million) 95 - 105
----------
* Greece ($ million) 20 - 25
----------
* Croatia ($ million 5
----------
* UK North Sea ($ million) 20 - 25
----------
Total Cost of Production ($ million) 195 - 220
----------
Cash SG&A ($ million) 35 - 40
----------
Development and production capital expenditure
----------
* Israel ($ million) 350 - 400
----------
* Egypt ($ million) 60 - 70
----------
* Italy ($ million) 40 - 50
----------
* Greece and Croatia ($ million) 5 - 10
----------
* UK North Sea ($ million) 15 - 20
----------
Total Development & Production Capital
Expenditure ($ million) 470 - 550
----------
Exploration Expenditure
----------
* Israel ($ million) 10
----------
* Egypt ($ million) 0 - 5
----------
* Italy, Greece and Croatia ($ million) 5 - 10
----------
* UK North Sea ($ million) 40 - 45
----------
Total Exploration Expenditure ($ million) 55 - 70
----------
Decommissioning
----------
* UK North Sea 0
----------
* Italy 2 - 5
----------
Decommissioning expenditure ($ million) 2 - 5
----------
Energean Financial Review
Financial results summary
1H 2021 1H 2020 Change
Av. daily working interest production
(kboed) 44.0 2.1 1,995%
-------- -------- -------
Sales revenue ($m) 205.5 2.1 9,686%
-------- -------- -------
Realised oil price ($/boe) 47.3 9.1 419%
-------- -------- -------
Cash cost of production [14]
($m) 122.4 10.4 1,077%
-------- -------- -------
Cash cost of production per barrel
($/boe) 15.4 27.5 (44%)
-------- -------- -------
Cash SG&A [15] 17.0 5.4 215%
-------- -------- -------
Adjusted EBITDAX [16] ($m) 74.7 (8.8) 939%
-------- -------- -------
(Loss) after tax ($m) (35.7) (77.3) 54%
-------- -------- -------
Cash flow from operating activities
($m) 53.1 (14.5) 466%
-------- -------- -------
Capital expenditure ($m) 230.0 249.0 (8%)
-------- -------- -------
1H 2021 FY 2020 Change
Total borrowings ($m) 2,838.8 1,443.1 97%
-------- -------- -------
Cash and cash equivalents and
restricted cash ($m) 1,146.3 202.9 465%
-------- -------- -------
Net debt / (cash) ($m) (including
restricted cash) 1,692.6 1,240.1 36%
-------- -------- -------
Net debt / equity (%) 212.3% 103.8% 105%
-------- -------- -------
Revenue, production and commodity prices
Group working interest production averaged 44.0 kboed, an
increase of 1,990% for the period (1H 2020: 2.1 kboed), with the
Abu Qir field, offshore Egypt, accounting for approximately 70% of
total output. 1H 2021 revenue was $205.5 million, a 9,827% increase
for the period (1H 2020: $2.1 million), primarily due to the
transformational nature of the acquisition of Edison E&P, which
closed on 17 December 2020.
The increase in revenue for the period primarily reflects the
increased production levels of the Group following the acquisition
of Edison E&P, which closed on 17 December 2020. Revenues also
benefitted from a higher commodity price environment:
-- During 1H 2021, the average Brent oil price was $ 65.2 /bbl
versus $42.2/bbl in 1H 2020, the average PSV price was EUR21.2/MWH
(1H 2020: EUR9.3/MWH) and the average NBP price was GBp55.4/Therm
(1H 2020: GBp19.0/Therm)
-- This strength across commodity prices resulted in a 1H 2021
average realised price of $47.3/boe (1H 2020: $9.1/boe)
Depreciation, impairments and write-offs
Depreciation charges on production and development assets before
impairments increased by 184 % to $ 36.3 million (1H 2020: $12.8
million) due to the higher production levels generated by the Group
following the acquisition of Edison E&P, which closed on 17
December 2020.
On a per barrel of oil equivalent of production basis, this
represented an 86 % decrease to $ 4.6 /boe (1H 2020:
$33.7/boe).
During the period, no impairment charges were recognised (1H
2020: $63.0 million).
Other income and expenses
Other expenses of $3.1 million (1H 2020: $15.8 million) include
$1.5 million of one-off transaction costs in relation to the Edison
E&P acquisition (1H 2020: $8.4 million), and expected credit
losses, as well as losses from disposal of property, plant and
equipment of $0.3 million.
Other income of $3.6 million (1H 2020: $8.9 million) includes
$3.5 million that relate to reversal of prior period provisions and
$0.1 million of other income.
Other income in 1H 2020 included a $5.0 million termination fee
that was payable by Neptune Energy in relation to the termination
of its sale and purchase agreement to buy the UK North Sea and
Norwegian subsidiaries, prior to Energean's acquisition of Edison
E&P, and $3.9 million of other income related to waivers
obtained for specific accounts payable balances in the Greek
subsidiary.
Finance income / costs
Net finance costs in 1H 2021 were $42.2 million (1H 2020: net
finance income of $0.8 million), composed of $17.0 million (1H
2020: $3.0 million) of interest on borrowings after capitalisation,
$27.9 million (1H 2020: $0.5 million) of other debt arrangement
fees and other finance costs and $2.7 million of finance income (1H
2020: $4.4 million). The increase in finance and other arrangement
fees is due to arrangement fees for the $700 million term loan,
which was fully repaid during the period. The increase in other
finance costs is primarily due to unwinding costs on the
decommissioning provision, which has increased following the
acquisition of Edison E&P, combined with losses incurred on
interest rate derivatives.
Crude oil hedging
Energean has no commodity price hedges outstanding as of 30 June
2021 (1H 2020: $nil).
Taxation
Energean recorded tax expenses of $15.2 million in 1H 2021 (1H
2020 $21.8 million tax income), composed of corporation tax charges
amount $22.1 million and deferred tax income of $5.9 million.
Taxation expenses in the period ended 30 June 2021 include $21.5
million relating to taxes (non-cash in nature) being deducted at
source in Egypt plus deferred amounts of $5.9 million.
Operating cash flow
In 1H 20201, Energean recorded a cash inflow from operations
before changes in working capital of $ 48.6 million, versus a cash
outflow of $15.2 million in 1H 2020. After working capital
movements, the cash inflow in 1H 2021 was $ 53.1 million versus a
cash outflow of $14.5 million in 1H 2020. The year-on-year increase
in operating cash flow has been predominantly driven by the growth
in revenues delivered between the two periods. As discussed above,
the increase in revenues during the period is due to i) the
increased production levels of the Group following the acquisition
of Edison E&P; and ii) the higher commodity price
environment.
Non-IFRS measures
The Group uses certain measures of performance that are not
specifically defined under IFRS or other generally accepted
accounting principles. These non-IFRS measures include adjusted
EBITDAX, underlying cash cost of production and SG&A, capital
expenditure, net debt and gearing.
Adjusted EBITDAX
Adjusted EBITDAX is a non-IFRS measure used by the Group to
measure business performance. It is calculated as profit or loss
for the period, adjusted for discontinued operations, taxation,
depreciation and amortisation, share-based payment charge,
impairment of property, plant and equipment, other income and
expenses, net finance costs and exploration and evaluation
expenses. The Group presents adjusted EBITDAX as it is used in
assessing the Group's growth and operational efficiencies as it
illustrates the underlying performance of the Group's business by
excluding items not considered by management to reflect the
underlying operations of the Group.
1H 2021 1H 2020
$m $m
Adjusted EBITDAX [17] 74.7 (8.9)
-------- --------
Reconciliation to profit / (loss):
-------- --------
Depreciation and amortisation (36.3) (12.8)
-------- --------
Share-based payment charge (2.3) (1.2)
-------- --------
Impairment losses - (63.0)
-------- --------
Exploration and evaluation expense (1.0) (0.5)
-------- --------
Other expenses (3.1) (15.8)
-------- --------
Other income 3.6 8.9
-------- --------
Finance income 2.7 4.4
-------- --------
Finance cost (44.9) (3.6)
-------- --------
Net foreign exchange gain/(loss) (13.9) (6.6)
-------- --------
Taxation income / (expense) (15.2) 21.8
-------- --------
Profit / (loss) from continuing
operations (35.7) (77.3)
-------- --------
Cash Cost of production
Cash Cost of production is a non-IFRS measure that is used by
the Group as a useful indicator of the Group's underlying cash
costs to produce hydrocarbons. The Group uses the measure to
compare operational performance period-to-period, to monitor cost
and assess operational efficiency. Cash cost of production is
calculated as cost of sales, adjusted for depreciation and
hydrocarbon inventory movements.
1H 2021 1H 2020
$m $m
Cost of sales 147.6 17.9
-------- --------
Less:
-------- --------
Depreciation 33.8 11.6
-------- --------
Change in inventory (8.6) (4.1)
-------- --------
Cost of production 122.4 10.4
-------- --------
Total production for the period
(MMboe) 7.9 0.4
-------- --------
Cost of production per boe ($/boe) 15.4 27.5
-------- --------
Cash Selling, General & Administrative Expense
(SG&A)
Cash SG&A eliminates certain non-cash accounting adjustments
to the Group's SG&A. Underlying cash SG&A is defined as
Administrative and Selling and distribution expenses, excluding
depletion and amortisation of assets and share-based payment charge
that are included in SG&A.
1H 2021 1H 2020
$m $m
-------- --------
Administrative expenses 21.7 6.9
-------- --------
Selling and distribution expenses 0.1 0.1
-------- --------
Less:
-------- --------
Depreciation 2.5 0.4
-------- --------
Share-based payment charge included
in SG&A 2.3 1.2
-------- --------
Cash SG&A 17.0 5.4
-------- --------
Energean incurred Cash S,G&A costs of $17.0 million in 1H
2021. This represents a 216% increase versus the comparable period
last year (1H 2020: $5.4 million) and is due to increased staffing
and administrative costs following the acquisition of Edison
E&P and efforts associated with developing the Group's
portfolio of projects.
Capital expenditure
Capital Expenditure is defined as additions to property, plant
and equipment and intangible exploration and evaluation assets,
cash lease payments made in the period, less lease asset additions,
asset additions due to decommissioning provisions, capitalised
share-based payment charge, capitalised borrowing costs and certain
other non-cash adjustments. The Directors believe that capital
expenditure is a useful indicator of the Group's organic
expenditure on oil and gas development assets, exploration and
evaluation assets incurred during a period because it eliminates
certain accounting adjustments such as capitalised borrowing costs
and decommissioning asset additions.
1H 2021 1H 2020
-------- -----------
$m $m
-------- -----------
Additions to property, plant and
equipment 317.8 279.8
-------- -----------
Additions to intangible exploration
and evaluation assets 30.3 6.8
-------- -----------
Less:
-------- -----------
Capitalised borrowing cost 114.0 40.6
-------- -----------
Leased assets additions and modifications 12.3 0.9
-------- -----------
Lease payments related to capital
activities (5.8) (4.7)
-------- -----------
Capitalised share-based payment
charge 0.2 0.0
-------- -----------
Capitalised depreciation 0.1 0.3
-------- -----------
Change in environmental rehabilitation
provision (2.5) 0.5
-------- -----------
Total capital expenditures 230.0 249.0
-------- -----------
Movement in working capital (60.0) (5.8)
-------- -----------
Cash capital expenditures per the
cash flow statement 170.0 243.2 [18]
-------- -----------
The breakdown of capital expenditures during 1H 2021 and 1H 2020
was as follows:
1H 2021 1H 2020
Capital expenditure Capital expenditure
$m $m
-------------------- --------------------
Development and Production
-------------------- --------------------
Israel 161.8 235.3
-------------------- --------------------
Egypt 17.5 -
-------------------- --------------------
Italy 11.4 -
-------------------- --------------------
Greece & Croatia 3.8 2.5
-------------------- --------------------
UK 5.3 -
-------------------- --------------------
Other 1.0 1.0
-------------------- --------------------
Total 200.8 243.5
-------------------- --------------------
Exploration and Appraisal
-------------------- --------------------
Israel 3.7 4.8
-------------------- --------------------
Egypt 0.3 -
-------------------- --------------------
Italy 2.0 -
-------------------- --------------------
Greece & Croatia 0.4 0.3
-------------------- --------------------
UK 22.5 -
-------------------- --------------------
Other 0.3 0.4
-------------------- --------------------
Total 29.2 5.5
-------------------- --------------------
Net cash / debt and gearing ratio
Net debt is defined as the Group's total borrowings less cash
and cash equivalents and restricted cash held for loan repayments.
Management believes that net debt is a useful indicator of the
Group's indebtedness, financial flexibility and capital structure
because it indicates the level of borrowings after taking account
of any cash and cash equivalents that could be used to reduce
borrowings. The Group defines capital as total equity and
calculates the gearing ratio as net debt divided by capital.
Net debt reconciliation 1H 2021 1H 2020
$m $m
Current borrowings 19.0 38.0
-------- --------
Non-current borrowings 2,819.8 1,055.8
-------- --------
Total borrowings 2,838.8 1,093.9
-------- --------
Less: Cash and cash equivalents 880.0 232.5
-------- --------
Restricted cash held for loan repayment 266.2 -
-------- --------
Net (Funds)/Debt [19] 1,692.6 861.4
-------- --------
Total equity 797.5 1,184.7
-------- --------
Gearing ratio 212.3% 72.7%
-------- --------
Term Loan
On 13 January 2021, Energean signed an 18-month, $700 million
term loan facility agreement with J.P. Morgan AG and Morgan Stanley
Senior Funding, Inc, the primary uses of which were to accelerate
the Karish North development and to fund the up-front consideration
for the acquisition of the minority interest in Energean Israel. At
the same time, Energean also agreed with the existing lenders of
its $1.45 billion project finance facility to extend its maturity
by nine months, from December 2021 to September 2022. This term
loan was refinanced using proceeds from the bond issuance discussed
below.
Refinancing
On 24 March 2021, Energean Israel Finance Limited issued a $2.5
billion bond, split into four equal tranches with maturities in
2024, 2026, 2028 and 2031.
On 29 April 2021, the gross proceeds were released from a
segregated escrow account following the satisfaction of release
conditions, including the receipt of regulatory approvals and the
registration of certain pledges. Part of the proceeds from the
issuance were used to refinance the term loan (discussed above) and
Energean Israel's $1.45 billion project finance facility. As at the
date of refinancing, drawn amounts under the term loan and project
finance facility were $175 million and $1,270 million,
respectively.
Principal risks and uncertainties
Effective risk management is fundamental to achieving Energean's
strategic objectives and protecting its personnel, assets,
shareholder value and reputation. The Board has overall
responsibility for determining the nature and extent of the risks
it is willing to take in achieving the strategic objectives of the
Group and ensuring that such risks are managed effectively. A key
aspect of this is ensuring the maintenance of a sound system of
internal control and risk management. For all the known risks
facing the business, Energean attempts to minimise the likelihood
and mitigate the impact. Energean has a zero-tolerance approach to
financial fraud or ethics non-compliance and ensures that HSE risks
are managed to levels that are as low as reasonably
practicable.
Overview of key risks and key changes since 31 December 2020
The Group's principal risks for the remaining 6 months of the
year and key changes since 31 December 2020 are set out below. For
further information on key risks, please refer to Energean's 2020
Annual Report and Accounts:
Strategic risks
#1 Progress key development projects in Israel
Principal risk: Delay to first gas at Karish.
1H 2021 movement: This risk increased in 1H 2021. Following the
re-introduction of enhanced COVID-19 related restrictions in
Singapore for part of 1H 2021, the Energean Power FPSO is now
expected to sailaway from Singapore to Israel in 1Q 2022 with first
gas in mid-2022.
Energean is working on a number of contingency measures in the
event that there are further outbreaks and variants of COVID-19 in
Singapore that lead to the reintroduction of measures that could
impact upon the first gas timetable.
Project completion has now reached 91.5% as of 31 July 2021; the
closer to completion the project gets, the lower the risk of
material delays. Energean is working with its contractors to ensure
completion of the project as soon as is possible.
#2 Market risk in Israel
Principal risk: The potential for Israeli gas market oversupply
may result in offtake being at the take-or-pay level of existing
gas sales and purchase agreements and could result in the failure
to secure new GSPAs.
1H 2021 movement: This risk increased in 1H 2021. The market
environment is competitive, and the Leviathan field continues to
increase its supply of gas, alongside production from Tamar,
contributing to market oversupply and a decline in Israeli domestic
gas prices towards the price floor set by Energean. Nevertheless,
Energean's gas sales and purchase agreements continue to remain the
most commercially attractive supply option to domestic gas buyers
in Israel, with a weighted average gas price of approximately
$4.0/MMbtu.
#3 Progress key development projects
Principal risk: Delayed delivery of future development projects
(including NEA / NI in Egypt, Cassiopea in Italy and Karish North
in Israel).
1H 2021 movement: This risk decreased in 1H 2021. Energean has
made good progress on its Karish North (Israel) and NEA/NI (Egypt)
gas developments since taking FID in January 2021, with both
projects on schedule and on budget and with no delays envisaged.
The Cassiopea project was approximately 23% complete at 31 July
2021 and first gas continues to be expected in 1H 2024. The passage
of time and delivery of projects in line with expectations is the
key driver of the reduction in this risk.
#4 Deliver exploration success and reserve addition
Principal risk: Lack of new commercial discoveries and reserves
replacement.
1H 2021 movement: This risk remained static in 1H 2021. Energean
has developed a well-defined exploration plan for its 2022-23
drilling programme, offshore Israel, which will target the
derisking of unrisked prospective recoverable resources of over 1
Bnboe. In May 2021, the Company signed a contract with Stena at an
attractive day rate for the drilling of three firm wells and two
optional wells, with the first well expected to spud in 1Q
2022.
#5 Portfolio integration
Principal risk: Failure to successfully integrate Edison E&P
into Energean's day-to-day business activities resulting in limited
financial, social and environmental benefits.
1H 2021 movement: This risk decreased in 1H 2021. Energean
continues to successfully implement its integration roadmap and has
identified areas of synergy across the combined business.
Implementation of the end-state operating model remains on target
for year-end 2021.
Operational risks
#1 Production performance
Principal risk: Underperformance at core producing assets in
Egypt and Italy.
1H 2021 movement: This risk decreased in 1H 2021. Production
continues to outperform following robust operational performance
across Energean's combined portfolio. Working interest production
averaged 44.0 kboed in 1H 2021, around 10% above the mid-point of
guidance of 38 - 42 kboed.
#2 JV misalignment
Principal risk: Misalignment with JV operators.
1H 2021 movement: This risk decreased in 1H 2021, due to
Energean's increased working interest position in the Vega and
Rospo Mare fields, offshore Italy, following the acquisition from
ENI, plus good progress having been made on the Cassiopea project,
offshore Italy.
Financial risks
#1 Maintaining liquidity and solvency
Principal risk: Insufficient liquidity and funding capacity.
1H 2021 movement: This risk decreased in 1H 2021. In April 2021,
the $1.45 billion project finance facility and $700 million term
loan were refinanced following a $2.5 billion issuance of senior
secured notes. The bond is split into four equal tranches with
maturities in 2024, 2026, 2028 and 2031. This optimised debt
structure substantially extends the maturity profiles and provides
additional near-term flexibility to the Group. Strengthening of
commodity prices also helped to decrease this risk.
#2 Egypt receivables
Principal risk: Recoverability of revenues and receivables in
Egypt.
1H 2021 movement: This risk remained static in 1H 2021. Cash
collection from EGPC during the period was $74.9 million. This was
approximately $10 million lower than expected cash collection, the
difference being primarily due to timing of collection.
#3 Decommissioning liability
Principal risk: Higher than expected decommissioning costs and
acceleration of abandonment schedules
1H 2021 movement: This risk remained static in 1H 2021. No
additional decommissioning liabilities were incurred year-to-date
and Energean is working on reducing decommissioning liabilities
Climate change risks
#1 Failure to manage the risk of climate change and to adapt to
the energy transition
Principal risk: Climate change policy, technological
development, changing consumer behaviour and reputational
damage.
1H 2021 movement: This risk increased in 1H 2021. The climate
change agenda is an ever-increasing area of focus globally and is
of critical importance to Energean as it evolves the business and
works towards achieving its 2050 net zero target with respect to
Scope 1 and 2 emissions. Failure to progress this target could
impact the commerciality of the portfolio, lead to loss of licence
to operate and result in limited access to/increased cost of
capital.
Energean mitigates this risk through ongoing monitoring of key
performance indicators by Management. Progress demonstrated in 2021
includes:
-- ESG ratings maintained in the top quartile.
-- Awarded 'Gold' by Maala in July 2021 for a second consecutive year.
-- Three core initiatives being rolled out across all operated
sites, including switching to purchasing of 'green' electricity,
introduction of a zero-routine-faring policy and establishment of
procedures to reduce methane emissions.
-- Technical feasibility studies are ongoing for carbon capture
and storage, and eco-hydrogen projects in Prinos in Greece, in
conjunction with evaluation of the wider portfolio for such
projects.
#2 Physical risks related to climate change
Principal risk: Disruption to operations and/or development
projects due to severe weather (both acute and chronic).
1H 2021 movement: This risk remained static in 1H 2021.
External risks
#1 Geopolitical events
Principal risk: Political and fiscal uncertainties in the
Eastern Mediterranean.
1H 2021 movement: This risk remained static in 1H 2021.
#2 Global pandemic
Principal risk: Operational uncertainties and HSE incidents due
to COVID-19 pandemic.
1H 2021 movement: This risk remained static in 1H 2021.
Emerging risks
Energean faces a number of uncertainties that have the potential
to be material to its long-term strategy but cannot be fully
defined as a specific risk at present, and therefore cannot be
fully assessed or managed. These emerging risks typically have a
long-time horizon, such as earlier and increased decommissioning
liabilities in the UK and Italy, and elsewhere where the Company
operates; increased calls for cash or letter of credit guarantees
to be put in place; inadequate management of reserves and
production risk resulting in poor returns and impairment.
In 1H 2021, the Group identified the increasing threat from
misalignment of national and regional energy transition legislation
and direct impacts from unanticipated business interruption, for
example due to production downtime or one-off events, emerging
risks that will be actively assessed and monitored.
Events since 30 June 2020
Compensation to gas buyers due to late supply:
During August 2021 and in accordance with the GSPAs signed with
a group of gas buyers, the Group has agreed to pay compensation to
these counterparties due to the fact the gas supply date is taking
place beyond a certain date as defined in the GSPAs (being 30 June
2021). The compensation will be paid on a monthly basis starting on
August 2021 and is estimated at approx. US$23 million. The
compensation is accounted as variable purchase consideration under
IFRS 15 hence recognised once production commences and gas is
delivered to the offtakers
Gas buyer request for arbitration:
During August 2021 a gas buyer sent a request to the
International Court of Arbitration ("ICC") asking for arbitration
on its rights of termination due to the fact the gas supply date is
taking place beyond a certain date which defined in the GSPA. If
the agreement it is terminated, the Group has identified multiple
alternative routes to monetise those gas volumes (being 0.8
Bcm/yr), including both domestic and international markets, and
hence is confident of profitably selling them
Going Concern Statement
The Group carefully manages its risk to a shortage of funds by
monitoring its funding position and its liquidity risk. The going
concern assessment covers for the period to 30 September 2022 'the
Forecast Period'.
Cash forecasts are regularly produced based on, inter alia, the
Group's latest life of field production and budgeted expenditure
forecasts, management's best estimate of future commodity prices
(based on recent published forward curves) and the Group's
borrowing facilities. The Base Case conservatively assumes first
gas from Karish in July 2022, Brent at $70/bbl for the period 1
September to 31 December 2021 and $65/bbl for the period 1 January
to 30 September 2022, PSV (Italian gas price) at an average of
EUR25/MWH for the period 1 September 2021 to 31 December 2021 and
EUR20/MWH for the period January 2022 to 30 September 2022.
In addition, on a regular basis, the Group performs sensitivity
tests of its liquidity position for negative impacts that may
result from changes to the macro-economic environment such as a
fall in commodity price or increase in interest rate. The Group
also looks at the impact of changes or deferral of key projects
and/or portfolio rationalisation. This is done to identify risks to
liquidity and covenant compliance and enable management to
formulate appropriate and timely mitigation strategies in order to
manage the risk of funding shortfalls or covenant breaches and to
safeguard the Group's ability to continue as a going concern.
Specifically, the Group tested the following sensitivities:
-- Reduction in Commodity Prices over the Forecast Period (10%
applied to PSV prices and 7.5% to Brent prices)
-- decrease in projected collection of EGPC receivables over the Forecast Period
-- delay in Israel first gas by 3 months to October 2022, which
Energean management believes has a low probability of occurring
given the acceleration and mitigation measures currently under
consideration and the evolution of the COVID-19 situation
A reasonable worst case including a combination of all above
sensitivities
The Group also ran a reverse stress test to stress the
combination of lower Brent price, lower PSV (Italian Gas Price) and
reduced collection of EGPC receivables and assess the impact of
this combination on the Group's liquidity and covenants associated
with its banking facilities. Energean believes that this
combination of scenarios holds a low probability of occurrence.
Should a more extreme downside scenario occur, appropriate
mitigating actions that are in management's control and can be
executed in the necessary timeframe could be taken such as a
tightening o f operating cost and reductions/postponement of other
discretionary exploration and development expenditures. The Group's
cash and cash equivalents at 30 June 2021 were $880 million
(excluding restricted cash amounts of $266 million).
In terms of the Group's Borrowing Facilities, the following was
considered in the context of the Group's liquidity and covenant
compliance over the Forecast Period.
Karish Field Development, Israel:
-- Consistent with the Group's plans to implement new financing
as the Karish development approaches first gas in mid-2022,
Energean issued a $2.5 billion Bond to (i) refinance its $1.45
billion Project Finance Facility (ii) cancel and replace the $700m
Term Loan which was drawn to fund the acquisition of Kerogen's
minority interest in Energean Israel, (iii) fund future capital and
exploration expenditure in Israel, including Karish and Karish
North and (iv) for general corporate purposes of the Group. On 29
April 2021 the Group satisfied the escrow release conditions, as a
result the proceeds of the Offering were released from the escrow
account.
Greek RBL:
-- In March 2021, the Group agreed a waiver with its lenders
under the EBRD reserve-based lending facility whereby there are no
more Borrowing Base redeterminations and the facility effectively
converts to an amortising term loan with repayments weighted
towards the second half of 2022 to 2024. Covenants under the
Subordinated Loan Agreement are also waived until December
2022.
Egypt RBL:
The current Borrowing Base redetermination is expected to be
completed in September 2021 . Given the strong commodities prices
and the higher production achieved from the Borrowing Base Assets
we do not expect any reduction to the Borrowing Base when the
redetermination exercise is completed.
In forming an assessment on the Group's ability to continue as a
going concern and its review of the forecasted cashflow of the
Group over the Forecast Period (from the date of approval of the
interim condensed consolidated financial statements) the Board has
made significant judgements about:
-- Reasonable sensitivities appropriate for the current status
of the business and the wider macro environment; and
the Group's ability to implement the mitigating actions, if
required, is within the Group's control, which would further
safeguard the Group's liquidity and covenant compliance.
After careful consideration, the Directors are satisfied that
the Group has sufficient financial resources to continue in
operation for the foreseeable future, for a period up to 30
September 2022. For this reason, they continue to adopt the going
concern basis in preparing the consolidated financial
statements.
Statement of Directors' responsibilities
The Directors confirm that to the best of their knowledge:
1) The condensed set of financial statements has been prepared
in accordance with IAS 34 'Interim Financial Reporting' as adopted
in the UK;
2) The interim management report contains a fair review of the
information required by DTR 4.2.7RR (indication of important events
during the first six months and description of principal risks and
uncertainties for the remaining six months of the year);
3) The interim management report includes a true and fair review
of the information required by DTR 4.2.8R (disclosure of related
parties' transactions and changes therein).
Mathios Rigas Panos Benos
Chief Executive Officer Chief Financial Officer
01 September 2021 01 September 2021
Forward looking statements
This announcement contains statements that are, or are deemed to
be, forward-looking statements. In some instances, forward-looking
statements can be identified by the use of terms such as
"projects", "forecasts", "anticipates", "expects", "believes",
"intends", "may", "will" or "should" or, in each case, their
negative or other variations or comparable terminology.
Forward-looking statements are subject to a number of known and
unknown risks and uncertainties that may cause actual results and
events to differ materially from those expressed in or implied by
such forward-looking statements, including, but not limited to:
general economic and business conditions; demand for the Company's
products and services; competitive factors in the industries in
which the Company operates; exchange rate fluctuations;
legislative, fiscal and regulatory developments; political risks;
terrorism, acts of war and pandemics; changes in law and legal
interpretations; and the impact of technological change.
Forward-looking statements speak only as of the date of such
statements and, except as required by applicable law, the Company
undertakes no obligation to update or revise publicly any
forward-looking statements, whether as a result of new information,
future events or otherwise. The information contained in this
announcement is subject to change without notice.
INDEPENT REVIEW REPORT TO ENERGEAN PLC
Conclusion
We have been engaged by Energean plc (the Company) to review the
condensed set of financial statements in the half-yearly financial
report for the six months ended 30 June 2021 which comprises the
consolidated income statement, the consolidated statement of
comprehensive income, the consolidated statement of financial
position, the consolidated statement of changes in equity, the
consolidated statement of cash flows and the related explanatory
notes 1 to 29. We have read the other information contained in the
half yearly financial report and considered whether it contains any
apparent misstatements or material inconsistencies with the
information in the condensed set of financial statements.
Based on our review, nothing has come to our attention that
causes us to believe that the condensed set of financial statements
in the half-yearly financial report for the six months ended 30
June 2021 is not prepared, in all material respects, in accordance
with UK adopted International Accounting Standard 34 and the
Disclosure Guidance and Transparency Rules of the United Kingdom's
Financial Conduct Authority.
Basis for Conclusion
We conducted our review in accordance with International
Standard on Review Engagements 2410 (UK and Ireland) "Review of
Interim Financial Information Performed by the Independent Auditor
of the Entity" issued by the Auditing Practices Board. A review of
interim financial information consists of making enquiries,
primarily of persons responsible for financial and accounting
matters, and applying analytical and other review procedures. A
review is substantially less in scope than an audit conducted in
accordance with International Standards on Auditing (UK) and
consequently does not enable us to obtain assurance that we would
become aware of all significant matters that might be identified in
an audit. Accordingly, we do not express an audit opinion.
As disclosed in note 2, the annual financial statements of the
Group will be prepared in accordance with UK adopted IFRSs. The
condensed set of financial statements included in this half-yearly
financial report has been prepared in accordance with UK adopted
International Accounting Standard 34, "Interim Financial
Reporting".
Responsibilities of the directors
The directors are responsible for preparing the half-yearly
financial report in accordance with the Disclosure Guidance and
Transparency Rules of the United Kingdom's Financial Conduct
Authority.
Auditor's Responsibilities for the review of the financial
information
In reviewing the half-yearly report, we are responsible for
expressing to the Company a conclusion on the condensed set of
financial statements in the half-yearly financial report. Our
conclusion is based on procedures that are less extensive than
audit procedures, as described in the Basis for Conclusion
paragraph of this report.
Use of our report
This report is made solely to the Company in accordance with
guidance contained in International Standard on Review Engagements
2410 (UK and Ireland) "Review of Interim Financial Information
Performed by the Independent Auditor of the Entity" issued by the
Auditing Practices Board. To the fullest extent permitted by law,
we do not accept or assume responsibility to anyone other than the
Company, for our work, for this report, or for the conclusions we
have formed.
Ernst & Young LLP
London
1 September 2021
Interim Condensed Consolidated Income Statement
Six months ended 30 June 2021
------------------------------------------------
30 June (Unaudited)
2021 2020
$'000 $'000
------------------------------------- ------ ---------- -----------
Notes
Revenue 5 205,466 2,070
Cost of Sales 6(a) (147,640) ( 17,934 )
------------------------------------- ------ ---------- -----------
Gross profit/(loss) 57,826 ( 15,864 )
Administrative expenses 6(b) (21,668) (6,853)
Selling and distribution expenses 6(c) (102) (72)
Exploration and evaluation expenses 6(d) (1,041) (529)
Impairment of property, plant
and equipment 11 - (63,005)
Other expenses 6(e) (3,071) ( 15,843 )
Other income 6(f) 3,571 8,914
------------------------------------- ------ ---------- -----------
Operating profit/(loss) 35,515 (93,252)
Finance Income 7 2,700 4,383
Finance Costs 7 (44,912) (3,563)
Net foreign exchange loss 7 (13,787) (6,637)
------------------------------------- ------ -----------
Loss before tax (20,484) (99,069)
Taxation income / (expense) 9 (15,174) 21,801
------------------------------------- ------ ---------- -----------
Loss from continuing operations (35,658) (77,268)
------------------------------------- ------ ---------- -----------
Attributable to:
Owners of the parent (35,550) (76,826)
Non-controlling Interests (108) (442)
------------------------------------- ------ -----------
(35,658) (77,268)
===================================== ====== ========== ===========
Basic and diluted total loss per share (cents per share)
----------------------------------------------------------------------
Basic 10 ($0.20) ($0.43)
Diluted 10 ($0.20) ($0.43)
------------------------------------- ------ ---------- -----------
Interim Condensed Consolidated Statement of Comprehensive Income
Six months ended 30 June 2021
------------------------------------------------------------------------------------
30 June (Unaudited)
2021 2020
$'000 $'000
---------------------------------------- -------- ------------ ----------------
Loss for the period (35,658) (77,268)
-------------------------------------------------- ------------ ----------------
Other comprehensive income:
Items that may be reclassified
subsequently to profit or loss
Cash Flow hedges
Gain/(loss) arising in the period 2,278 (11,530)
Reclassification to profit and
loss upon repayment of related
borrowings 4,641 -
Income tax relating to items
that may be reclassified to
profit or loss (1,591) 2,652
Exchange difference on the translation
of foreign operations, net of
tax (6,576) (1,075)
-------------------------------------------------- ----------------
Other comprehensive profit/(loss)
after tax (1,248) (9,953)
-------------------------------------------------- ------------ ----------------
Total comprehensive loss for
the period (36,906) (87,221)
================================================== ============ ================
Total comprehensive loss attributable
to:
Owners of the parent (36,800) (84,116)
Non-controlling Interests (106) (3,105)
-------------------------------------------------- ----------------
(36,906) (87,221)
================================================= ============ ================
Interim Condensed Consolidated Statement of Financial Position
As at 30 June 2021
---------------------------------------------------------------
-----------------------------------------------------------------------------------
30 June
2021 (Unaudited) 31 December
2020
Notes $'000 $'000
--------------------------------------- ------- ------------------ -------------
ASSETS
Non-current assets
Property, plant and equipment 11 3,375,231 3,107,272
Intangible assets 12 286,201 275,816
Equity-accounted investments 4 4
Other receivables 17 31,552 31,568
Deferred tax asset 13 128,498 126,056
Restricted cash 15 100,000 -
--------------------------------------- ------- ------------------ -------------
3,921,486 3,540,716
--------------------------------------- ------- ------------------ -------------
Current assets
Inventories 16 78,016 73,019
Trade and other receivables 17 281,985 318,339
Restricted cash 15 166,241 -
Cash and cash equivalents 14 880,017 202,939
1,406,259 594,297
--------------------------------------- ------- ------------------ -------------
Total assets 5,327,745 4,135,013
--------------------------------------- ------- ------------------ -------------
EQUITY AND LIABILITIES
Equity attributable to owners of
the parent
Share capital 18 2,368 2,367
Share premium 18 915,388 915,388
Merger reserve 139,903 139,903
Other reserve 17,577 1,792
Foreign currency translation reserve (6,618) (42)
Share-based payment reserve 15,893 13,419
Retained earnings (294,063) (144,734)
Equity attributable to equity holders
of the parent 790,448 928,093
--------------------------------------- ------- ------------------ -------------
Non-controlling interests 19 - 266,299
--------------------------------------- ------- ------------------ -------------
Total equity 790,448 1,194,392
--------------------------------------- ------- ------------------ -------------
Non-current liabilities
Borrowings 20 2,819,809 330,092
Deferred tax liabilities 13 70,151 68,609
Retirement benefit liability 21 6,695 7,839
Provisions 22 855,004 881,535
Other payables 23 348,818 177,193
4,100,477 1,465,268
--------------------------------------- ------- ------------------ -------------
Current liabilities
Trade and other payables 23 402,420 355,454
Current portion of borrowings 20 19,020 1,112,984
Derivative financial instruments 8 2,405 6,915
Provisions 22 12,975 -
436,820 1,475,353
--------------------------------------- ------- ------------------ -------------
Total liabilities 4,537,297 2,940,621
--------------------------------------- ------- ------------------ -------------
Total equity and liabilities 5,327,745 4,135,013
--------------------------------------- ------- ------------------ -------------
Interim Condensed Consolidated Statement of Changes in Equity
Six months ended 30 June 2021
--------------------------------------------------------------
Equity
component Share
of based
Share Other convertible payment Translation Non
Share Premium Reserve bonds reserve Reserve Retained Merger Controlling
Capital [20] [21] [22] [23] [24] earnings reserve Total Interests Total
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
At 1 January
2021 2,367 915,388 1,792 - 13,419 (42) (144,734) 139,903 928,093 266,299 1,194,392
-------- -------- -------- ------------ -------- ------------ ---------- -------- ---------- ------------ ----------
Loss for the
period - - - - - - (35,550) - (35,550) (108) (35,658)
Hedges , net
of tax - - 5,326 - - - - - 5,326 2 5,328
Exchange
difference
on the
translation
of foreign
operations - - - - - (6,576) - - (6,576) - (6,576)
Total
comprehensive
income - - 5,326 - - (6,576) (35,550) - (36,800) (106) (36,906)
-------- -------- -------- ------------ -------- ------------ ---------- -------- ---------- ------------ ----------
Transactions
with owners
of the company
Employee share
schemes (note
24) 1 - - - 2,474 - - - 2,475 2,475
Acquisition
of
non-controlling
Interests
[25] - - - 10,459 - - (113,779) - (103,320) (266,193) (369,513)
At 30 June
2021 2,368 915,388 7,118 10,459 15,893 (6,618) (294,063) 139,903 790,448 - 790,448
======== ======== ======== ============ ======== ============ ========== ======== ========== ============ ==========
Interim Condensed Consolidated Statement of Changes in Equity
Six months ended 30 June 2021
--------------------------------------------------------------
Share
Share based Non
Share Premium Other payment Translation Retained Merger Controlling
Capital (18) Reserve(19) reserve(21) Reserve(22) earnings reserve(23) Total Interests Total
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
At 1 January (19,2 ( 53,320 259,72 1,2 60
2020 2,367 915,38 8 5,86 2 10,094 64 ) ) 139,903 1,0 01,030 2 , 752
======== ========= ============ ============ ============ ========== ============ =========== ============ ==========
Loss for the
period - - - - - (76,825) - (76,825) (442) (77,267)
Cash flow
hedge ,
net of tax - - (6,215) - - - - (6,215) (2,663) (8,878)
Exchange
difference
on the
translation
of foreign
operations - - - - (1,075) - - (1,075) - (1,075)
Total
comprehensive
income - - (6,215) - (1,075) (76,825) - (84,115) (3,105) (87,220)
-------- --------- ------------ ------------ ------------ ---------- ------------ ----------- ------------ ----------
Transactions
with
owners of the
company - - - - - - - - - -
Share capital
increase
in subsidiary - - - - - - - - 9,750 9,750
Employee share
schemes
(note 24) - - - 1,363 - - - 1,363 - 1,363
At 30 June
2020 2,367 915,388 (353) 11,457 (20,339) (130,145) 139,903 918,278 266,367 1,184,645
======== ========= ============ ============ ============ ========== ============ =========== ============ ==========
Interim Condensed Consolidated Statement of Cash Flows
Six months ended 30 June 2021
------------------------------------------------------------------------------
30 June (Unaudited)
2021 2020
Note $'000 $'000
------------------------------------------- ------- ------------ ----------
Operating activities
------------------------------------------- ------- ------------ ----------
(99,06 9
Loss before taxation (20,484) )
Adjustments to reconcile profit/(loss)
before taxation to net cash provided
by operating activities:
Depreciation , depletion and amortisation 11, 12 36,343 12,787
Impairment loss on property, plant
and equipment 11 - 63,005
Impairment on asset held for sale 11 - 4,935
Loss from the sale of property, 36 -
plant and equipment
Defined benefit expenses 21 (1,120) (192)
Finance income 7 (2,700) (4,383)
Finance costs 7 44,912 3,563
Non-cash revenues from Egypt ([26]) (21,577) -
Other liabilities derecognised 6(f) - (3,839)
Movement in provisions 22 483 -
Other income 6 (3,602) -
Share-based payment charge 24 2,474 1,332
Net foreign exchange gain/(loss) 7 13,787 6,637
------------------------------------------- ------- ------------ ----------
Cash flow from/(used in) operations
before working capital adjustments 48,552 (15,224)
------------------------------------------- ------- ------------ ----------
Increase in inventories (5,185) (4,012)
Decrease in trade and other receivables 42, 392 4,565
(Decrease)/Increase in trade and
other payables ( 33,082 ) 225
------------------------------------------- ------- ------------ ----------
Cash inflow/(outflow) from operations 52,677 (14,446)
Income tax paid 388 (55)
------------------------------------------- ------- ------------ ----------
Net cash inflow/(outflow) from
operating activities 53,065 (14,501)
------------------------------------------- ------- ------------ ----------
Investing activities
Payment for purchase of property,
plant and equipment (141,182) (231,178)
Payment for exploration and evaluation,
and other intangible assets (28,818) (12,077)
Acquisition of a subsidiary 4 (3,335) -
Movement in restricted cash 15 (266,241) -
Proceeds from disposal of property,
plant and equipment - 150
Interest received 861 470
------------------------------------------- ------- ------------ ----------
Net cash used in investing activities (438,715) (242,635)
------------------------------------------- ------- ------------ ----------
Financing activities
Drawdown of borrowings 20 293,000 200,000
Repayment of borrowings 20 (1,452,509) (19,021)
Senior secured notes Issuance 20 2,500,000 -
Transaction costs related to Senior (37,218) -
secured notes paid
Proceeds from capital increases
by non-controlling interests 19 - 9,750
Acquisition of non-controlling
interests 19 (175,000) -
Transaction costs related to acquisition (1,677) -
of non-controlling interest
Repayment of obligations under
leases (5,875) (4,713)
Finance cost paid for deferred
license payments (3,494) (3,993)
Finance costs paid (55,641) (40,367)
------------------------------------------- ------- ------------ ----------
Net cash inflow from financing
activities 1,061,586 141,656
------------------------------------------- ------- ------------ ----------
Net increase / (decrease) in cash
and cash equivalents 675,936 (115,480)
------------------------------------------- ------- ------------ ----------
Cash and cash equivalents at beginning
of the period 202,939 354,419
Effect of exchange rate fluctuations
on cash held 1,142 (6,480)
------------------------------------------- ------- ------------ ----------
Cash and cash equivalents at end
of the period 14 880,017 232,459
------------------------------------------- ------- ------------ ----------
1. Corporate Information
Energean plc (the 'Company') was incorporated in England &
Wales on 8 May 2017 as a public company with limited liability,
under the Companies Act 2006. Its registered office is at 44 Baker
Street, London W1U 7AL, United Kingdom. The Company and all
subsidiaries controlled by the Company, are together referred to as
"the Group".
The Group has been established with the objective of
exploration, production and commercialisation of crude oil and
natural gas in Greece, Israel, North Africa and the wider Eastern
Mediterranean.
The Group's core assets and subsidiaries as of 30 June 2021 are
presented in note 29.
2. Basis of preparation
2.1 Basis of preparation
As a result of the UK's withdrawal from the European Union on 31
December 2020, the financial statements of the Group for the year
ending 31 December 2021 will be prepared under UK-adopted
International Accounting Standards. Accordingly, the unaudited
condensed consolidated interim financial statements for the six
months ended 30 June 2021 included in this interim report have been
prepared in accordance with UK-adopted International Accounting
Standard 34 'Interim Financial Reporting', and unless otherwise
disclosed have been prepared on the basis of the same accounting
policies and methods of computation as applied in the Group's
Annual Report for the year ended 31 December 2020.
The interim condensed consolidated financial statements have
been prepared on a historical cost basis and are presented in US
Dollars, which is also the Company's functional currency, rounded
to the nearest thousand dollars ($'000) except as otherwise
indicated.
The US dollar is the currency that mainly influences sales
prices and revenue estimates, and also highly affects the Group's
operations. The functional currencies of the Group's main
subsidiaries are as follows: for Energean E&P Holdings Ltd,
Energean Oil & Gas S.A, Energean Montenegro, Energean Italy Spa
and Energean International E&P Spa, is Euro, for Energean
International Limited, Energean Capital Ltd, Energean Egypt Ltd and
Energean Israel Limited is US$.
Comparative figures for the period to 30 June 2020 and 31
December 2020 are for the period ended on that date.
The interim financial statements do not constitute statutory
accounts of the Group within the meaning of Section 435 of the
Companies Act 2006 and do not include all the information and
disclosures required in the annual financial statements. The
interim financial statements should be read in conjunction with the
Group's Annual Report and Accounts for the year ended 31 December
2020, which were prepared in accordance with IFRSs in conformity
with the requirements of the Companies Act 2006 and which have been
filed with the Registrar of Companies. The auditor's report on
those financial statements was unqualified with no reference to
matters to which the auditor drew attention by way of emphasis and
no statement under s498(2) or s498(3) of the Companies Act
2006.
Going concern
The Group carefully manages its risk to a shortage of funds by
monitoring its funding position and its liquidity risk. The going
concern assessment covers for the period to 30 September 2022 'the
Forecast Period'.
Cash forecasts are regularly produced based on, inter alia, the
Group's latest life of field production and budgeted expenditure
forecasts, management's best estimate of future commodity prices
(based on recent published forward curves) and the Group's
borrowing facilities. The Base Case conservatively assumes first
gas from Karish in July 2022, Brent at $70/bbl for the period 1
September to 31 December 2021 and $65/bbl for the period January to
September 2022, PSV (Italian gas price) at an average of EUR25/MWH
for the period 1 September to 31 December 2021 and EUR20/MWH for
the period January to September 2022.
In addition, on a regular basis, the Group performs sensitivity
tests of its liquidity position for negative impacts that may
result from changes to the macroeconomic environment such as a fall
in commodity price or increase in interest rate. The Group also
looks at the impact of changes or deferral of key projects and/or
portfolio rationalisation. This is done to identify risks to
liquidity and covenant compliance and enable management to
formulate appropriate and timely mitigation strategies in order to
manage the risk of funding shortfalls or covenant breaches and to
safeguard the Group's ability to continue as a going concern.
Specifically, the Group tested the following sensitivities:
-- Reduction in Commodity Prices over the Forecast Period (10%
applied to PSV prices and 7.5% to Brent prices)
-- Decrease in projected collection of EGPC receivables over the Forecast Period
-- Delay in Israel 1(st) gas by 3 months to October 2022, which
Energean management believes has a low probability of occurring
given the acceleration and mitigation measures currently under
consideration and the evolution of the COVID-19 situation
-- A reasonable worst case including a combination of all above sensitivities
The Group also ran a reverse stress test to stress the
combination of lower Brent price, lower PSV (Italian Gas Price) and
reduced collection of EGPC receivables, and assess the impact of
this combination on the Group's liquidity and covenants associated
with its banking facilities. Energean believes that this
combination of scenarios holds a low probability of occurrence.
Should a more extreme downside scenario occur, appropriate
mitigating actions that are in management's control and can be
executed in the necessary timeframe could be taken such as a
tightening of operating cost and reductions/postponement of other
discretionary exploration and development expenditures. The Group's
cash and cash equivalents at 30 June 2021 are $880 million.
In terms of the Group's Borrowing Facilities, the following was
considered in the context of the Group's liquidity and covenant
compliance over the Forecast Period.
Karish Field Development, Israel:
-- Consistent with the Group's plans to implement new financing
as the Karish development approaches first gas in mid-2022,
Energean issued a $2.5 billion Bond to (i) refinance its $1.45
billion Project Finance Facility (ii) cancel and replace the $700m
Term Loan which was drawn to fund the acquisition of Kerogen's
minority interest in Energean Israel, (iii) fund future capital and
exploration expenditure in Israel, including Karish and Karish
North and (iv) for general corporate purposes of the Group. On 29
April 2021 the Group satisfied the escrow release conditions, as a
result the proceeds of the Offering were released from the escrow
account.
Greek RBL:
-- In March 2021, the Group agreed a waiver with its lenders
under the EBRD reserve-based lending facility whereby there are no
more Borrowing Base Redeterminations and the facility effectively
converts to an amortising term loan with repayments weighted
towards the second half of 2022 to 2024. Covenants under the
Subordinated Loan Agreement are also waived until December
2022.
Egypt RBL:
-- The current Borrowing Base redetermination is expected to be
completed in September 2021 . Given the strong commodities prices
and the higher production achieved from the Borrowing Base Assets
we do not expect any reduction to the Borrowing Base when the
redetermination exercise is completed.
In forming an assessment on the Group's ability to continue as a
going concern and its review of the forecasted cashflow of the
Group over the Forecast Period (from the date of approval of the
interim condensed consolidated financial statements) the Board has
made significant judgements about:
-- Reasonable sensitivities appropriate for the current status
of the business and the wider macro environment; and
-- The Group's ability to implement the mitigating actions, if
required, is within the Group's control, which would further
safeguard the Group's liquidity and covenant compliance.
After careful consideration, the Directors are satisfied that
the Group has sufficient financial resources to continue in
operation for the foreseeable future, for a period up to 30
September 2022. For this reason, they continue to adopt the going
concern basis in preparing the consolidated financial
statements.
New and amended accounting standards and interpretations
The accounting policies adopted in the preparation of the
unaudited interim condensed consolidated financial statements are
consistent with those followed in the preparation of the Group's
annual consolidated financial statements for the year ended 31
December 2020, except for the adoption of the new standards and
interpretations effective as of 1 January 2021. None of the
amendments that are effective as of 1 January 2021 had a
significant impact on the Group's interim condensed consolidated
financial statements.
The Group has not early adopted any standard, interpretation or
amendment that has been issued but is not yet effective as at 1
January 2021. Several amendments and interpretations apply for the
first time in 2021, but do not have an impact on the interim
condensed consolidated financial statements of the Group.
Interest Rate Benchmark Reform - Phase 2: Amendments to IFRS 9,
IAS 39, IFRS 7, IFRS 4 and IFRS 16
The amendments provide temporary reliefs which address the
financial reporting effects when an interbank offered rate (IBOR)
is replaced with an alternative nearly risk-free interest rate
(RFR). The amendments include the following practical
expedients:
-- A practical expedient to require contractual changes, or
changes to cash flows that are directly required by the reform, to
be treated as changes to a floating interest rate, equivalent to a
movement in a market rate of interest -- Permit changes required by
IBOR reform to be made to hedge designations and hedge
documentation without the hedging relationship being
discontinued
-- Provide temporary relief to entities from having to meet the
separately identifiable requirement when an RFR instrument is
designated as a hedge of a risk component
The Group intends to use the practical expedients in future
periods if they become applicable.
2.2 Approval of accounts
These unaudited condensed interim consolidated financial
statements were approved by the Board of Directors on 1 September
2021.
3. Segmental Reporting
The information reported to the Group's Chief Executive Officer
and Chief Financial Officer (together the Chief Operating Decision
Makers) for the purposes of resource allocation and assessment of
segment performance is focused on four operating segments: Europe,
(including Greece, Italy, UK, Croatia), Israel, Egypt and New
Ventures (Montenegro and Malta).
The Group's reportable segments under IFRS 8 Operating Segments
are Europe, Israel and Egypt. Segments that do not exceed the
quantitative thresholds for reporting information about operating
segments have been included in Other. In 2020, before the
acquisition of Edison E&P, the Group had no activities in Egypt
and the Europe segment comprised only Greece (including the Prinos
and Epsilon production asset, Katakolo non-producing assets and
Ioannina and Aitoloakarnania exploration assets).
Segment revenues, results and reconciliation to profit before
tax
The following is an analysis of the Group's revenue, results and
reconciliation to profit/(loss) before tax by reportable
segment:
Europe Israel Egypt Other & Total
intercompany
transactions
$'000 $'000 $'000 $'000 $'000
------------------------------- ---------- ---------- ---------- -------------- ----------
Six months ended 30
June 2021 (unaudited)
Revenue from Oil 70,736 - 27,431 - 98,167
Revenue from Gas 34,765 - 70,929 - 105,694
Petroleum products sales 492 - - - 492
Rendering of services 5,228 - - (4,115) 1,113
Total revenue 111,221 - 98,360 (4,115) 205,466
Adjusted EBITDAX(25) 9,685 (1,563) 69,113 (2,584) 74,651
Reconciliation to profit
before tax:
Depreciation and amortisation
expenses (21,586) (50) (14,256) (451) (36,343)
Share-based payment charge (431) (122) - (1,699) (2,252)
Exploration and evaluation
expenses (630) - - (411) (1,041)
Impairment loss on property, - - - - -
plant and equipment
Other expense (1,458) (28) (88) (1,497) (3,071)
Other income 2,887 0 641 43 3,571
Finance income 1,667 1,808 676 (1,451) 2,700
Finance costs (10,797) (9,436) (624) (24,055) (44,912)
Net foreign exchange
gain/(loss) 2,879 (727) (1,055) (14,884) (13,787)
Profit/(loss) before
income tax (17,784) (10,118) 54,407 (46,989) (20,484)
Taxation income / (expense) 3,342 2,571 (21,535) 448 (15,174)
Profit/(loss) from continuing
operations (14,442) (7,547) 32,872 (46,541) (35,658)
------------------------------- ---------- ---------- ---------- -------------- ----------
Six months ended 30
June 2020 (unaudited)
Revenue from Oil 1,914 - - 1,914
Revenue from Gas - - - - -
Petroleum products sales 3,425 - - (3,269) 156
Total revenue 5,339 - - (3,269) 2,070
Adjusted EBITDAX [27] (4,584) (2,084) - (2,180) (8,848)
Reconciliation to profit
before tax: -
Depreciation and amortisation
expenses (12,448) (149) - (190) (12,787)
Share-based payment charge (13) (39) - (1,102) (1,154)
Exploration and evaluation
expenses (183) - - (346) (529)
Impairment loss on property,
plant and equipment (63,005) - - - (63,005)
Other expense (6,995) (385) - (8,463) (15,843)
Other income 3,913 - - 5,001 8,914
Finance income 4,094 169 - 120 4,383
Finance costs (3,449) (26) - (88) (3,563)
Net foreign exchange
gain/(loss) (262) 243 - (6,618) (6,637)
Profit before income
tax (82,932) (2,271) - (13,866) (99,069)
Taxation income / (expense) 20,999 413 - 389 21,801
Profit from continuing
operations (61,933) (1,858) - (13,477) (77,268)
------------------------------- ---------- ---------- ---------- -------------- ----------
The following table presents assets and liabilities information
for the Group's operating segments as at 30 June 2021 and 31
December 2020, respectively:
Europe Israel Egypt Other & intercompany Total
transactions
$'000 $'000 $'000 $'000 $'000
--------------------------- ----------- ------------ ---------- ----------------------- ----------
Six months ended
30 June 2021 (unaudited)
Oil & Gas properties 559,283 2,436,742 332,738 (12,716) 3,316,047
Other fixed assets 30,043 687 25,343 3,111 59,184
Intangible assets 137,702 93,337 21,498 33,664 286,201
Trade and other
receivables 108,640 8,652 161,777 2,916 281,985
Deferred tax asset 103,049 0 25,448 1 128,498
Other assets 940,530 732,623 36,401 (453,724) 1,255,830
Total assets 1,879,247 3,272,041 603,205 (426,748) 5,327,745
Trade and other
payables 165,465 174,699 58,331 3,925 402,420
Borrowings 150,923 2,459,910 0 227,996 2,838,829
Decommissioning
provision 816,153 34,708 - 0 850,861
Other current liabilities 164,508 2,405 - (164,509) 2,404
Other non-current
liabilities 4,337 160,580 477,858 (199,992) 442,783
Total liabilities 1,301,386 2,832,302 536,189 (132,580) 4,537,297
--------------------------- ----------- ------------ ---------- ----------------------- ----------
Other segment information
Capital Expenditure:
- Property, plant
and equipment 21,850 162,454 17,019 (508) 200,815
- Intangible, exploration
and evaluation assets 24,829 3,738 - 624 29,191
--------------------------- ----------- ------------ ---------- ----------------------- ----------
Year ended 31 December
2020
--------------------------- ----------- ------------ ---------- ----------------------- ----------
Oil & Gas properties 572,834 2,156,236 326,366 (1,728) 3,053,708
Other fixed assets 21,727 765 27,588 3,484 53,564
Intangible assets 139,267 89,607 39,219 7,723 275,816
Trade and other
receivables 154,469 1,304 162,222 344 318,339
Deferred tax asset 103,200 0 22,856 (0) 126,056
Other assets 251,240 37,464 247,028 (228,202) 307,530
Total assets 1,242,737 2,285,376 825,279 (218,379) 4,135,013
Trade and other
payables 187,117 76,146 57,959 34,232 355,454
Borrowings 121,264 1,093,965 - 227,847 1,443,076
Decommissioning
provision 826,729 38,399 - - 865,128
Other current liabilities 140,629 6,914 54,652 (195,280) 6,915
Other non-current
liabilities 25,291 193,920 32,284 18,553 270,048
Total liabilities 1,301,030 1,409,344 144,895 85,352 2,940,621
--------------------------- ----------- ------------ ---------- ----------------------- ----------
Other segment information
Capital Expenditure:
- Property, plant
and equipment 14,117 405,279 860 (197) 420,059
- Intangible, exploration
and evaluation assets 1,219 6,625 - 1,147 8,991
--------------------------- ----------- ------------ ---------- ----------------------- ----------
Segment Cash flows
Europe Israel Egypt Other & Total
intercompany
transactions
$'000 $'000 $'000 $'000 $'000
--------------------------- --------- ----------- --------- -------------- -----------
Six months ended
30 June 2021 (unaudited)
Net cash from / (used
in) operating activities 22,329 (2,802) 52,958 (19,420) 53,065
Net cash (used in)
investing activities (41,614) (378,265) (15,695) (3,141) (438,715)
Net cash from financing
activities 22,447 1,075,374 (87,054) 50,819 1,061,586
Net increase/(decrease)
in cash and cash
equivalents, and
restricted cash 3,162 694,307 (49,791) 28,258 675,936
Cash and cash equivalents
at beginning of the
period 13,609 37,421 76,240 75,669 202,939
Effect of exchange
rate fluctuations
on cash held 409 (146) (1) 880 1,142
Cash and cash equivalents
at the end of the
period 17,180 731,582 26,448 104,807 880,017
---------------------------
Six months ended
30 June 2020 (unaudited)
Net cash from / (used
in) operating activities (6,209) (1,359) - (6,933) (14,501)
Net cash (used in)
investing activities (14,380) (227,713) - (542) (242,635)
Net cash from financing
activities 19,746 194,484 - (72,574) 141,656
Net increase/(decrease)
in cash and cash
equivalents 302 (34,588) - (80,049) (114,335)
At beginning of the
year 6,085 110,488 - 237,846 354,419
Effect of exchange
rate fluctuations
on cash held (1,114) (54) - (5,312) (6,480)
Cash and cash equivalents
at end of the period 5,273 75,846 - 151,340 232,459
--------------------------- --------- ----------- --------- -------------- -----------
4. Prior year business combination
Acquisition of Edison E&P
On 17 December 2020, the Group acquired 100 per cent of the
issued share capital and obtained control of Edison Exploration
& Production S.p.A ("Edison E&P"). Edison E&P contains
a portfolio of assets including producing assets in Egypt, Italy,
the UK North Sea and Croatia with development assets in Egypt and
Italy and balanced-risk exploration opportunities across the
portfolio. The acquisition of Edison E&P qualifies as a
business combination as defined in IFRS 3.
The fair values of the identifiable assets and liabilities of
Edison E&P were provisionally estimated as at the date of
acquisition. As of 30 June 2021 no change has been identified to
the ascribed fair values of the identifiable assets and
liabilities.
The base consideration payable of $398.6 million, which excludes
contingent consideration, was agreed as of a locked box date of 1
January 2019 with the impact of economic performance, capital
expenditure and working capital movements from this date to
completion of 17 December 2020 adjusted within the final
consideration payable of $269.9 million from which amount of $266.6
million was paid in December 2020 and amount $3.3 million paid in
January 2021.
The contingent consideration arrangement will vary depending on
future Italian gas prices at the point in time at which first gas
production is delivered from the Cassiopea field in Italy which is
expected in 2024. The potential undiscounted amount of all future
payments that the Group could be required to make under the
contingent consideration arrangement is between $0 and $100
million.
The fair value of the contingent consideration arrangement of
$55.2 million was estimated by applying forward gas price curves
against the expected date of first gas as at acquisition date. This
resulted in an aggregate fair value of $299.3 million being
allocated to the identifiable assets and liabilities acquired,
prior to the recognition of a deferred tax liability of $22.9
million as further described below.
Goodwill of $25.3 million has been recognised upon acquisition.
An amount of $22.9 million was due to the requirement of IAS 12 to
recognise deferred tax assets and liabilities for the difference
between the assigned fair values and tax bases of assets acquired
and liabilities assumed. The assessment of fair value of such
licences is therefore based on cash flows after tax. Hence,
goodwill arises as a direct result of the recognition of this
deferred tax adjustment ("technical goodwill"). None of the
goodwill recognised will be deductible for income tax purposes.
5. Revenue
30 June (Unaudited)
2021 2020
$'000 $'000
-------------------------- ------------ --------
Crude oil sales 98,167 1,914
Gas sales 105,694 -
Petroleum products sales 492 156
Rendering of services 1,113 -
-------------------------- ------------ --------
Total revenue 205,466 2,070
6. Operating profit/(loss) before taxation
30 June (Unaudited)
2021 2020
$'000 $'000
----- ----------------------------------- ---------- ----------
(a) Cost of sales
Staff costs 32,626 6,153
Energy cost 3,475 2,550
Royalty payable 5,814 -
Other operating costs 80,503 1,717
Depreciation and amortisation 33,845 11,581
Stock overlift/(underlift) ( 4,067
movement (8,623) )
------------------------------------ ---- ---------- ----------
Total cost of sales 147,640 17,934
(b) Administrative expenses
Staff costs 7,329 2,744
Other General & administration
expenses 8,815 2,309
Share-based payment charge
included in administrative
expenses 2,247 1,154
Depreciation and amortisation 2,498 385
Auditor fees 779 261
------------------------------------ ---- ----------
Total administrative expenses 21,668 6,853
(c) Selling and distribution expense
Staff costs 29 22
Other Selling and distribution
expense 73 50
------------------------------------ ---- ---------- ----------
Total selling and distribution
expense 102 72
Exploration and evaluation
(d) expenses
Staff costs for Exploration
and evaluation activities 355 141
Other exploration and evaluation
expenses 686 388
------------------------------------ ---- ---------- ----------
Total exploration and evaluation
expenses 1,041 529
(e) Other operating expenses
Transaction costs in relation
to Edison E&P acquisition 1,470 8,405
Impairment on asset held for
sale - 4,935
Intra-group merger costs - 1,524
Loss from disposal of Property
plant & Equipment 36 -
Other indemnities - 203
Write down of inventory - 124
Expected credit losses 279 267
Other expenses 1,286 385
---- ---------- ----------
3,071 15,843
(f) Other income
Income from accounts payable
written off [28] - 3,839
Reversal of prior period accruals 3,496 -
Proceeds from termination of
agreement with Neptune Energy
[29] - 5,000
Other income 75 75
------------------------------------ ---- ---------- ----------
3,571 8,914
7. Net finance cost
30 June (Unaudited)
2021 2020
$'000 $'000
--------------------------------------------------- ---------- ----------
Interest on bank borrowings 89,501 37,608
Interest expense on long term payables 467 3,345
Interest expense on short term liabilities 28 -
Less amounts included in the cost of
qualifying assets (72,969) (37,932)
---------------------------------------------------- ---------- ----------
17,027 3,021
Finance and arrangement
fees 11,869 2,184
Unamortised financing costs -
related to the repayment
of the Karish project finance
[30] 36,200
Other finance costs and bank charges 2,172 678
Loss on interest rate hedges 6,988 -
Unwinding of discount on right of use
asset 837 116
Unwinding of discount on provision for
decommissioning 4,946 180
Unwinding of discount on deferred consideration 5,124 -
Unwinding of discount on contingent consideration 744
Less amounts included in
the cost of qualifying
assets (40,995) (2,616)
Total finance costs 44,912 3,563
Interest income from time deposits (1,534) (396)
Gain from revised estimated loan cash
flow (1,166) (3,987)
Total finance revenue (2,700) (4,383)
---------------------------------------------------- ---------- ----------
Foreign exchange losses/(gain) 13,787 6,637
Net financing costs 55,999 5,817
---------------------------------------------------- ---------- ----------
8. Fair value measurements
The information set out below provides information about how the
Group determines the fair values of various financial assets and
liabilities.
The fair values of the Group's non-current liabilities measured
at amortised cost are considered to approximate their carrying
amounts at the reporting date.
The carrying value less any estimated credit adjustments for
financial assets and financial liabilities with a maturity of less
than one year are assumed to approximate their fair values due to
their short term-nature. The fair value of the group's finance
lease obligations is estimated using discounted cash flow analysis
based on the group's current incremental borrowing rates for
similar types and maturities of borrowing and are consequently
categorized in level 2 of the fair value hierarchy.
Contingent consideration
As part of the share purchase agreement (the "SPA") dated 4 July
2019 between Energean and Edison Spa provides for a contingent
consideration of up to $100.0 million subject to the commissioning
of the Cassiopea development gas project in Italy. The
consideration was determined to be contingent on the basis of
future gas prices (PSV) recorded at the time of the commissioning
of the field, which is expected in 2024. No payment will be due if
the arithmetic average of the year one (i.e., the first year after
first gas production) and year two (i.e., the second year after
first gas production) Italian PSV Natural Gas Futures prices is
less than EUR10/Mwh when first gas production is delivered from the
field. US$100 million is payable if that average price exceeds
EUR20/Mwh. The contingent consideration to be payable in 2026 is
estimated at acquisition date to amount to $61.7m, which discounted
at the selected cost of debt results in a present value of $55.2m
as at the acquisition date. The fair value of the consideration
payable has been recognized at level 3 in the fair value hierarchy
and has been estimated by reference to the sales and purchase
agreement and by simulating PSV pricing by reference to the
forecasted PSV pricing, historical volatility and a log normal
distribution.
As at 30 June 2021, the two year future curve of PSV prices
increased from the date of acquisition and indicate an average
price in excess of EUR20/Mwh for 2023 it is probable that the
average price will exceed EUR20/Mwh from 2023. The Group monitors
closely the future PSV prices however given the current volatility
in the commodity markets, the Group's estimate as at 30 June 2021
of the fair value of the contingent consideration payable in 2026
has not materially changed since the previous reporting date.
At 30 June 2021 the fair value has been increased to $56.1
million (31 December 2020: $55.2 million) for the unwinding cost
recognised in income statement within finance cost.
Fair values of derivative financial instruments
The Group held financial instruments at fair value at 30 June
2021 related to interest rate derivatives. All derivatives are
recognised at fair value on the balance sheet with valuation
changes recognised immediately in the income statement, unless the
derivatives have been designated as a cash flow hedge. Fair value
is the amount for which the asset or liability could be exchanged
in an arm's length transaction at the relevant date. Where
available, fair values are determined using quoted prices in active
markets. To the extent that market prices are not available, fair
values are estimated by reference to market-based transactions, or
using standard valuation techniques for the applicable instruments
and commodities involved. Values recorded are as at the balance
sheet date, and will not necessarily be realised.
As at 30 June 2021 the Group's interest rate derivative (Level
2) is not designated as hedging instruments.
The fair value hierarchy of financial assets and financial
liabilities that are not measured at fair value (but fair value
disclosure is required) is as follows:
Fair value hierarchy as at 30 June 2021 (Unaudited)
Level 1 Level 2 Level 3 Total
$'000 $'000 $'000 $'000
------------------------------ --- --------------- --------------- --------- -----------------
Financial assets
Trade and other receivables
(note 17) - 237,673 - 237,673
Cash and cash equivalents
and bank deposits (note
14) 880,017 - - 880,017
Restricted cash 266,241 - - 266,241
---------------------------------------- -------------- ------------ --------- ----------------
Total 1,146,258 237,673 - 1,383,931
----------------------------------- --------------- --------------- --------- -----------------
Financial liabilities
Financial liabilities held
at amortised cost:
Trade and other payables
- current - 272,207 - 272,207
Trade and other payables
- non-current - 1,435 - 1,435
Borrowings (note 20) - 2,838,829 - 2,838,829
Deferred consideration
for acquisition of minority - 159,551 - 159,551
Net obligations under
finance leases (note
23) - 53,254 - 53,254
Deferred licence payments
(note 23) - 54,712 - 54,712
Convertible loan notes
(note 20) - 39,590 - 39,590
Financial liabilities
held at FVTPL:
Interest rate derivatives - 2,405 - 2,405
Contingent consideration
(note 4) - - 56,091 56,091
----------------------------------- --------------- --------------- --------- -----------------
Total - 3,421,983 56,091 3,478,074
----------------------------------- --------------- --------------- --------- -----------------
Fair value hierarchy as at 31 December 2020
Level 1 Level 2 Level Total
3
$'000 $'000 $'000 $'000
----------------------------- --- -------------------- ------------ -------- ----------------
Financial assets
Trade and other receivables
(note 17) - 246,307 - 246,307
Cash and cash equivalents
and bank deposits (note
14) 202,939 - - 202.939
---------------------------------- ------------------------ -------- --------- ---------------
Total 202,939 246,307 - 449,246
---------------------------------- -------------------- ------------ -------- ----------------
Financial liabilities
Financial liabilities
held at amortised cost:
Borrowings (note 20) - 1,443,076 - 1,443,076
Net obligations under
finance leases (note
23) - 47,623 - 47,623
Deferred licence payments
(note 22) - 69,518 - 69,518
Financial liabilities -
held at FVTPL:
Interest rate derivatives - 6,915 - 6,915
Contingent consideration
(note 4) - - 55,222 55,222
---------------------------------- -------------------- ------------ -------- ----------------
Total - 1,567,132 55,222 1,622,354
---------------------------------- -------------------- ------------ -------- ----------------
9. Taxation
30 June (Unaudited)
2021 2020
$'000 $'000
----------------------------------- ------------ --------
Corporation tax - current period (21,565) -
Corporation tax - prior years 448 386
Deferred tax (Note 13) 5,943 21,415
----------------------------------- ------------ --------
Total taxation income / (expense) (15,174) 21,801
----------------------------------- ------------ --------
(b) Reconciliation of the total tax charge
The Group calculates its income tax expense as per IAS 34 by
applying a weighted average tax rate calculated based on the
statutory tax rates in Greece (25%), Israel (23%), Italy (24%) and
United Kingdom (40%) weighted according to the profit or loss
before tax earned by the Group in each jurisdiction where deferred
tax is recognised or material current tax charge arises. The
effective tax rate for the period is -74% (30 June 2020: -22%).
The tax (charge)/credit of the period can be reconciled to the
loss per the consolidated income statement as follows:
30 June (Unaudited)
2021 2020
$'000 $'000
----------------------------------------------- ----------- ---------
Profit/(loss) before tax (20,484) (99,069)
----------------------------------------------- ----------- ---------
Tax calculated at 19.70% weighted average
rate (2020: 24.95%) [31] 4,035 24,724
Impact of different tax rates 13 (19)
Reassessment of recognised deferred tax asset
in the current period (348) (90)
Permanent differences [32] (1,912) (2,608)
Non recognition of deferred tax on current
period losses [33] (4,486) (1,265)
Tax effect of non-taxable income - 625
Foreign taxes [34] (21,535)
Tax effect of non-taxable income [35] 10,985
Other adjustments [36] (2, 374 ) 47
Prior year tax 448 387
----------------------------------------------- ----------- ---------
Taxation income/(expense) (15,174) 21,801
----------------------------------------------- ----------- ---------
10. Loss per share
The earnings per share has been calculated by dividing the net
profit or loss for the period by the weighted average number of
shares outstanding during the period ended 30 June 2021 and 30 June
2020.
30 June (Unaudited)
2021 2020
$'000 $'000
--------------------------------------- -------------- --------------
Total loss attributable to equity
shareholders (35,550) (76,826)
Effect of dilutive potential ordinary
shares - -
--------------------------------------- -------------- --------------
(35,550) (76,826)
Number of shares
Basic weighted average number
of shares 177,117,612 177,089,406
Dilutive potential ordinary shares - -
--------------------------------------- -------------- --------------
Diluted weighted average number
of shares 177,117,612 177,089,406
--------------------------------------- -------------- --------------
Basic loss per share ($0.20)/share ($0.43)/share
--------------------------------------- -------------- --------------
Diluted loss per share ($0.20)/share ($0.43)/share
--------------------------------------- -------------- --------------
11. Property, plant and equipment
Oil and gas Leased assets Other property, Total
properties plant and
equipment
Property, plant and $'000 $'000 $'000 $'000
equipment at Cost
-------------------------- ------------ --------------
At 1 January 2020 2,147,163 9,117 56,699 2,212,979
Additions 411,932 1,951 1,581 415,464
Acquisition of subsidiary 646,507 40,549 2,132 689,188
Lease modification - (1,519) - (1,519)
Disposal of assets (4,795) - (5,328) (10,123)
Capitalized borrowing
cost 94,929 - - 94,929
Capitalized depreciation 576 - - 576
Change in decommissioning
provision 39,620 - - 39,620
Transfer from Intangible
assets 41,822 - - 41,822
Foreign exchange impact 52,575 743 5,153 58,471
At 31 December 2020 3,430,329 50,841 60,237 3,541,407
Additions 195,062 2,250 85 197,397
Lease modifications - 10,009 - 10,009
Disposal of assets (23) - (36) (59)
Capitalized borrowing
cost 112,829 - - 112,829
Capitalised depreciation 106 - - 106
Change in environmental
rehabilitation provision (2,500) - - (2,500)
Transfer from Intangible
assets 13,787 - - 13,787
Foreign exchange impact (40,666) (1,535) (1,726) (43,927)
At 30 June 2021 3,708,924 61,565 58,560 3,829,049
Accumulated Depreciation
At 1 January 2020 263,512 3,448 43,748 310,708
Charge for the period
Expensed 18,105 3,073 2,149 23,327
Impairments 64,727 - 572 65,299
Foreign exchange impact 30,299 458 4,044 34,801
At 31 December 2020 376,643 6,979 50,513 434,135
Charge for the period 28,374 4,550 616 33,540
Disposal of assets - - (23) (23)
Foreign exchange impact (12,140) (202) (1,492) (13,834)
At 30 June 2021 392,877 11,327 49,614 453,818
Net carrying amount
At 31 December 2020 3,053,686 43,862 9,724 3,107,272
At 30 June 2021 3,316, 047 50, 238 8, 946 3,375,231
Included in the carrying amount of leased assets at 30 June 2021
is right of use assets related to oil and gas properties and Other
property, plant and equipment of $43.3 million and $6.9 million
respectively.
The depreciation charged on these classes for the six-month
ending 30 June 2021 were $4.1 million and $0.4 million
respectively.
The additions to oil & gas properties for the period of six
months ended 30 June 2021 is mainly due to development costs of
Karish field related to the EPCIC contract (FPSO, Sub Sea and
On-shore construction cost) at the amount of $161.8 million ,
development cost for Cassiopea project in Italy at the amount of
$8.4 million and NEA/NI project in Egypt at the amount of $17.5
million.
Borrowing costs capitalised for qualifying assets, included in
oil & gas properties, for the six months ended 30 June 2021
amounted to $123.4 million (year ended 31 December 2020: $94.9
million). The weighted average interest rates used:
-- 7.66% (for the six months ended 30 June 2021)
-- 8.72% (for the year ended 31 December 2020)
During the year 2020 the Group executed an impairment test for
the Prinos CGU (Prinos and Epsilon fields). In that period,
indicators of impairment were noted for the Prinos CGU, being a
reduction in both short-term (Dated Brent forward curve) and
long-term price assumptions and a change in the Group's Prinos
field production forecast, which have resulted in an impairment of
$65.3 million in the carrying value of the Prinos CGU.
12. Intangible assets
Exploration
and evaluation Other Intangible
assets Goodwill assets Total
$'000 $'000 $'000 $'000
Intangibles at Cost
At 1 January 2020 71,601 75,800 1,941 149,342
Additions 8,379 - 612 8,991
Acquisition of subsidiary 115,438 25,346 18,348 159,132
Capitalized borrowing
costs 2,761 - - 2,761
Transfers to property,
plant and equipment (41,822) - - (41,822)
Exchange differences 1,856 - 1,454 3,310
At 31 December 2020 158,213 101,146 22,355 281,714
Additions 28,255 - 937 29,192
Capitalized borrowing
costs 1,134 - - 1,134
Transfers to property,
plant and equipment (278) - (13,509) (13,787)
Exchange differences (500) (3,218) (3,718)
At 30 June 2021 186,824 101,146 6,565 294,535
Accumulated amortisation
and impairments
At 1 January 2020 261 - 1,405 1,666
Charge for the period - - 1,375 1,375
Impairment 2,936 - - 2,936
Exchange differences (193) - 114 (79)
At 31 December 2020 3,004 - 2,894 5,898
Charge for the period 2,031 - 772 2,803
Exchange differences (114) (253) (367)
30 June 2021 4,921 - 3,413 8,334
Net Carrying Amount
At 31 December 2020 155,209 101,146 19,461 275,816
At 30 June 2021 181,903 101,146 3,152 286,201
Borrowing costs capitalised for qualifying assets for the period
ended 30 June 2021 amounted to $1.1 million (31 December 2020: $2.8
million). The weighted average interest rate used was 7.34% (31
December 2020: 8.72%).
13. Net deferred tax (liability)/ asset
Deferred Property, Right Decom-missioning Prepaid Inventory Tax Deferred Retirement Accrued Total
tax plant of use expenses losses expenses benefit expenses
(liabilities)/assets and asset and other for tax liability and other
equipment IFRS receivables (1) short--term
16 liabilities
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
At 1 January
2020 (137,998) (1,078) - (971) 733 90,412 - 913 7,646 (40,343)
Acquisition
of subsidiary
(Note 4) 10,080 60,752 - 70,832
Increase
/ (decrease)
for the period
through:
profit or
loss (Note
9) 8,381 819 8,877 (3,474) (98) 7,384 - 53 (434) 21,508
other comprehensive
income - - - 130 - - - - 1,603 1,733
Exchange
difference (4,006) (33) - (336) 60 7,293 - 84 655 3,717
31 December
2020 (123,543) (292) 8,877 (4,651) 695 165,841 - 1,050 9,470 57,447
Increase
/ (decrease)
for the period
through:
profit or
loss (Note
9) (14,853) 67 (774) 1,053 (659) 12,261 1,908 43 6,897 5,943
other comprehensive ( 1,591
income ) (1,591)
Reclassifications
in the current
period [37] (28,442) - 33,644 2,025 (233) (4,903) 6,010 200 (8,301) -
Exchange
difference (243) 6 (421) 132 (13) (2,742) (32) (139) (3,452)
30 June 2021 (167,081) (219) 41,326 (1,441) (210) 170,457 7,918 1,261 6,336 58,347
31 December
30 June 2021 2020
$'000 $'000
Deferred tax liabilities (70,151) (68,609)
Deferred tax assets 128,498 126,056
Net deferred tax assets / (liabilities) 58,347 57,447
At 30 June 2021 the Group has gross unused tax losses of $757.3
million (as of 31 December 2020: $783.6 million) available to
offset against future profits. Out of the total tax losses, $380.4
million come from the Greek operations whereas amount of $18.1
million comes from the Israeli operations and specifically the
Karish licence which is in the development phase and expected to
commence production by 2021. Tax losses of $329.6 million comes
from the Italian and UK operations of the former Edison E&P
Group.
With respect to the Greek tax losses carried forward, the
majority of them ($374.3 million) come from the Prinos exploitation
area, whereas an amount of $1.5 million comes from Ioannina and
Katakolo areas which are in the exploration and development phase
respectively.
A deferred tax asset of $170.5 million has been recognised as of
30 June 2021 (as of 31 December 2020: $165.8 million) in respect of
such tax losses. This represents the losses which are expected to
be utilised based on Group's projection of future taxable profits
in the jurisdictions in which the losses reside. It is considered
probable based on business forecasts that such profits will be
available.
14. Cash and cash equivalents
30 June 31 December
2021 (Unaudited) 2020
$'000 $'000
Cash at bank 878,580 197,514
Deposits in escrow 1,437 5,425
880,017 202,939
Bank demand deposits comprise deposits and other short-term
money market deposit accounts that are readily convertible into
known amounts of cash. The effective interest rate on short--term
bank deposits was 0.3% for the six months period ended 30 June 2021
(year ended 31 December 2020: 1.07%).
Deposits in escrow comprise mainly cash retained as a bank
security pledge for the Group's performance guarantees in its
exploration blocks. These deposits can be used for funding the
exploration activities of the respective blocks.
15. Restricted Cash
Restricted cash comprise mainly cash retained under the Senior S
ecured Notes requirement as follows:
-- Short term - US$163.3 million Interest Payment Account for
the accrued interest period until 30 June 2022 (less coupons
actually paid) and from 30 June 2022 the Interest Reserve Account
will be funded 6 months forward
-- Long term - US$100 million Debt Payment Fund that would be
released upon achieving three quarters annualized production of 3.8
BCM/year from Karish asset in Israel.
The remaining amount of $2.96 included in restricted cash is
related to cash collateral provided under a letter of credit
facility for issuing bank guarantees for Group's activities in
Israel up to $75 million.
16. Inventories
30 June 20201
(Unaudited) 31 December 2020
$'000 $'000
Raw materials and supplies 53,057 56,073
Crude oil 24,959 16,946
Total inventories 78,016 73,019
In the period ended 30 June 2021 the write-down of crude oil
inventory to net realisable value amounted to $nil million (six
months ended 30 June 2020: $5.6 million) which is included in "cost
of sales".
17. Trade and other receivables
30 June 31 December
2021 (Unaudited) 2020
$'000 $'000
Trade and other receivables-Current
Financial items:
Trade receivables 185,967 226,118
Receivables from partners under JOA 28,190 -
Other receivables 3,213 -
Government subsidies [38] 3,371 3,481
Receivables from related parties (note 24) - 22
220,741 229,621
Non-financial items:
Deposits and prepayments [39] 26,974 38,756
Refundable VAT 32,747 49,414
Other taxes receivable 209 -
Deferred insurance expenses 579 507
Accrued interest income 735 41
61,244 88,718
281,985 318,339
Trade and other receivables-Non Current
Financial items:
Accrued interest income 1 -
Other tax recoverable 16,931 16,686
16,932 16,686
Non-financial items:
Deferred borrowing fees 49 -
Deposits and prepayments 12,945 13,409
Other deferred expenses 209 -
Other non-current assets 1,417 1,473
14,620 14,882
31,552 31,568
18. Share capital
The below tables outline the share capital of the Company.
Equity share capital Share capital Share premium
allotted and fully
paid
Number $'000 $'000
Issued and authorized
At 1 January 2020 177,089,406 2,367 915,388
Issued during the year
- New shares - - -
- Share based payment - - -
At 31 December 2020 177,089,406 2,36 7 915,388
Issued during the period
- Share based payment 51,361 1
At 30 June 2021 177,140,767 2,368 915,388
19. Non--controlling interests
Name of subsidiary Voting rights Share of loss Accumulated balance
30 June Year ended 30 June (Unaudited) Year ended 30 June Year ended
(Unaudited) 31 December 31 December (Unaudited) 31 December
2021 2020 2021 2020 2021 2020
% % $'000 $'000 $'000 $'000
Energean Israel
Ltd - 30.00 (106) (3,173) - 266,299
Total - 30.00 (106) (3,173) - 266,299
On 25 February 2021, the Group completed the acquisition of the
remaining 30% minority interest in Energean Israel Limited from
Kerogen Investments No.38 Limited, Energean now owns 100% of
Energean Israel Limited.
This resulted in a reduction of the Group's reported
non-controlling interest balance to $nil at 30 June 2021.
The Total Consideration includes:
-- An up-front payment of $175 million (the "Up-Front
Consideration") paid at completion of the transaction
-- Deferred cash consideration amounts totalling $180 million,
which are expected to be funded from future cash flows and
optimisation of the group capital structure, post-first gas from
the Karish project. The deferred consideration is discounted at the
selected unsecured liability rate of 9.77%.
-- $50 million of convertible loan notes (the "Convertible Loan
Notes"), which have a maturity date of 29 December 2023, a strike
price of GBP 9.50 and a zero-coupon rate.
The following is a schedule of additional interest acquired in
Energean Israel Limited:
$'000
Cash consideration paid to non-controlling shareholders at
completion 175,000
Deferred cash consideration 154,499
Convertible Loan Notes - Liability Component 38,337
Convertible Loan Notes - Equity Instrument Component 10,459
Cost related to the transaction 1,677
Carrying value of the 30% minority interest (266,193)
Difference recognised in retained earnings 113,779
The Acquisition of the remaining 30% minority interest in
Energean Israel adds 2P reserves of 29.5 billion cubic metres
("Bcm") of gas and 30 million barrels of liquids, representing
approximately 219 million barrels of oil equivalent ("MMboe") in
total, to the Group.
20. Borrowings
30 June (Unaudited) 31 December
2021 2020
$'000 $'000
Non-current
Bank borrowings - after two years but withing
five years
4,5% Senior Secured notes due 2024 ($625
million) 615,419 -
4,875% Senior Secured notes due 2026 ($625
million) 615,030 -
Senior Credit facility ($237 million) 229,485 227,848
EBRD Senior Facility Loan ($180 million) 75,696 84,420
EBRD Subordinated Facility Loan ($20 million) 15,128 17,824
Convertible loan notes ($50 million) - (note
19) 39,590 -
Bank borrowings - more than five years
5.375% Senior Secured notes due 2028 ($625
million) 614,818 -
5.875% Senior Secured notes due 2031 ($625
million) 614,643 -
Carrying value of non-current borrowings 2,819,809 330,092
Current
6,83% EBRD Senior Facility Loan due 2024
($97,6 million) 19,020 19,020
Senior Credit Facility for the Karish-Tanin
Development ($1,450 million) - 1,093,964
Carrying value of current borrowings 19,020 1,112,984
Carrying value of total borrowings 2,838,829 1,443,076
The Group has provided security in respect of certain borrowings
in the form of share pledges, as well as fixed and floating charges
over certain assets of the Group.
US$2,500,000,000 senior secured notes:
On 24 March 2021, the Group completed the issuance of US$2.5
billion aggregate principal amount of senior secured notes.
The Notes have been issued in four series as follows:
-- Notes in an aggregate principal amount of US$625 million,
maturing on 30 March 2024, with a fixed annual interest rate of
4.500%.
-- Notes in an aggregate principal amount of US$625 million,
maturing on 30 March 2026, with a fixed annual interest rate of
4.875%.
-- Notes in an aggregate principal amount of US$625 million,
maturing on 30 March 2028, with a fixed annual interest rate of
5.375%.
-- Notes in an aggregate principal amount of US$625 million,
maturing on 30 March 2031, with a fixed annual interest rate of
5.875%.
The interest on each series of the Notes will be paid
semi-annually, on 30 March and on 30 September of each year,
beginning on 30 September 2021.
On 29 April 2021 the Group satisfied the escrow release
conditions in respect of its US$2.5 billion aggregate principal
amount of the Notes offering. As a result of satisfying the said
escrow release conditions, the proceeds of the Offering were
released from escrow.
The Notes are listed for trading on the TACT Institutional of
the Tel Aviv Stock Exchange Ltd. (the "TASE").
The use of proceeds from the Offering is as follows :
-- To repay outstanding Senior Credit Facility for the
Karish-Tanin Development facility and outstanding amount under a
US$700 million term loan;
-- To replace the existing undrawn amounts available under those facilities;
-- To fund certain reserve accounts; and
-- For transaction expenses and the Group's general corporate purposes.
The Company had undertook to provide the following collateral in
favor of the Trustee:
-- First rank Fixed charges over the shares of Energean Israel
Limited, Energean Israel Finance Ltd and Energean Israel
Transmission Ltd, the Karish & Tanin Leases, the gas sales
purchase agreements ("GSPAs"), several bank accounts, Operating
Permits (once issued), Insurance policies, the Company exploration
licenses (Block 12, Block 21, Block 23, Block 31 and 80% of the
licenses under "Zone D") and the INGL Agreement.
-- Floating charge over all of the present and future assets of
Energean Israel Limited and Energean Israel Finance Ltd.
-- Energean Power FPSO (subject to using commercially reasonable
efforts, including obtaining Israel Petroleum Commissioner approval
and any other applicable governmental authority).
Senior Credit Facility for the Karish-Tanin Development:
On 29 April 2021, following the release of the senior secured
notes proceeds of $2.5bn, the Company repaid its existing
outstanding facility.
Capital management
The Group defines capital as the total equity and net debt of
the Group. Capital is managed in order to provide returns for
shareholders and benefits to stakeholders and to safeguard the
Group's ability to continue as a going concern.
30 June 2021
(Unaudited) 31 December 2020
$'000 $'000
Net Debt
Current borrowings 19,020 1,112,984
Non-current borrowings 2,819,809 330,092
Total borrowings 2,838,829 1,443,076
Less: Cash and cash equivalents (880,017) (202,939) (202,939)
Restricted cash (266,241) -
Net Debt (1) 1,692,571 1,240,137
Total equity (2) 790,448 1,194,392
Gearing Ratio (1/2): 214.13% 103.83%
Reconciliation of liabilities arising from financing
activities
Borrowing Derivatives Gain
costs de-designated from
including as cash revised
amortisation flow hedges estimated
of during the loan Foreign Fair
1 January Cash Cash Lease arrangement period cash exchange value 30 June
2021 inflows outflows Reclassification Additions modification fees flow impact changes 2021
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
(1, 559,213 ( 34,676 ( 6,915 3,164,
30 June 2021 1,622,354 2, 793,000 ) ) 190,776 10,055 143,102 4,641 (1,146) 2,864 ) 842
Secured Senior
Notes 2,500,000 (37,218) (36,663) 33,791 - 2,459,910
Convertible
loan notes
(note
19) - - - 38,337 - 1,253 - - - - 39,590
Long -term
borrowings 330,092 175,000 (200,131) (31) - - 16,484 - (1,146) 41 - 320,309
Current
portion
of long-term
borrowings 1,112,984 118,000 (1,297,062) 2,080 - - 82,984 - 34 - 19,020
Lease
liabilities 47,623 - (5,875) (62) 2,250 10,055 837 - (1,574) - 53,254
Deferred
licence
payments 69,518 - (14,344) - - - (462) - - - 54,712
Contingent
consideration 55,222 - - - - 744 - - - 55,966
Deferred
consideration
for
acquisition
of minority - - - - 150,189 - 5,124 - 4,363 159,676
Derivatives
not
designated
as hedging
instruments 6,915 - (4,583) - - - 2,347 4,641 - (6,915) 2,405
21. Retirement benefit liability
21.1 Provision for retirement benefits
30 June 2021
(Unaudited) 31 December 2020
$'000 $'000
Defined benefit obligation 6,695 7,839
Provision for retirement benefits
recognised 6,695 7,839
Allocated as:
Non current portion 6,695 7,839
21.2 Defined benefit obligation
30 June 2021 (Unaudited) 31 December
2020
$'000 $'000
At 1 January 7,839 4,265
Acquisition of subsidiary 3,021
Current service cost 183 364
Interest cost 21 39
Extra payments or expenses 69 557
Actuarial losses - from changes
in financial assumptions 50 49
Benefits paid (1,197) (866)
Transfer in/(out) (35) -
Exchange differences (235) 410
At 30 June / 31 December 6,695 7,839
22. Provisions
Provision for Litigation and Total
environment rehabilitation other provisions
$'000 $'000 $'000
At 1 January 2021 865,127 16,408 881,535
New provisions - 1,227 1,227
Change in estimates (2,500) - (2,500)
Payments (1,710) (1,710)
Unwinding of discount 4,946 - 4,946
Currency translation
adjustment (15,002) (517) (15,519)
At 30 June 2021 850,861 17,118 867,979
Current provisions 12,975 - 12,975
Non-current provisions 837,886 17,118 855,004
Decommissioning provision
The decommissioning provision represents the present value of
decommissioning costs relating to oil and gas properties, which are
expected to be incurred up to 2040, when the producing oil and gas
properties are expected to cease operations. The future costs are
based on a combination of estimates from an external study
completed at the end of 2019 and internal estimates. These
estimates are reviewed regularly to take into account any material
changes to the assumptions. However, actual decommissioning costs
will ultimately depend upon future market prices for the necessary
decommissioning works required that will reflect market conditions
at the relevant time. Furthermore, the timing of decommissioning is
likely to depend on when the fields cease to produce at
economically viable rates. This, in turn, will depend upon future
oil and gas prices, which are inherently uncertain.
The decommissioning provision represents the present value of
decommissioning costs relating to assets in Italy, Greece, UK,
Israel and Croatia. No provision is recognized for Egypt as there
is no legal or constructive obligation as at 30 June 2021.
Inflation Discount rate Cessation of 30 June
assumption assumption production 2021 31 December 2020
30 June 2021 30 June 2021 assumption $'000 $'000
Greece 1.01% - 1.3% 0.8% 2034 17,186 16,082
Italy 0.6%-1.4% 1.45% 2021-2040 536,180 551,464
UK 1.9% 0.35% 2022-2030 243,700 239,708
Israel 1.02%-1.6% 2.0% 2040 34,708 38,399
Croatia na na 2022 19,087 19,474
Total 850,861 865,127
Litigation and other claims provisions
Litigation and other claim provision relates to litigation
actions currently open in Italy with the Termoli Port Authority in
respect of the fees payable under the marine concession regarding
FSO Alba Marina serving the Rospo Mare field in Italy. Energean
Italy Spa has appealed these cases to the Campobasso Court of
Appeal. None of the other cases has yet had a decision on the
substantive issue. The Group contain a provision of EUR4.7 million
against an adverse outcome of these court cases.
Energean Italy Spa has currently open litigations with five
municipalities in Italy related to the imposition of real estate
municipality taxes (IMU/TASI), interest and related penalties
concerning the periods 2016 to 2019. For the years before 2019,
Edison SpA bears uncapped liability for any amount assessed
according the sale and purchase agreement (SPA) signed between the
companies while the Company is liable for any tax liability related
to tax year 2019. For all five cases, Energean Italy Spa (together
with Edison SpA, as appropriate) filed appeals presenting strong
legal and technical arguments for reducing the assessed taxes to
the lowest possible level as well as cancelling entirely the
imposed penalties. The Group strongly believes based on legal
advice received that the outcome of the court decisions will be in
its favour with no material exposure expected, therefore the Group
recognised a provision of $1.2 million in respect of this
claims.
Amount of $1.8 million provision relates to leasing cost charged
to ENI on the floating storage located in the Leoanis plan. The
Group following a claim from ENI accounted for this provision since
these overestimated costs were required to be reimbursement.
Other provisions include non-income tax provision and other
potential claim in Egypt.
It is not currently possible to accurately predict the timing of
the settlement of these claims and therefore the expected timing of
the cash flows.
23. Trade and other payables
30 June 2021 (Unaudited) 31 December 2020
$'000 $'000
Trade and other payables-Current
Financial items:
Trade accounts payable
[40] 214,290 193,987
Payables to partners under
JOA [41] 46,922 64,752
Deferred licence payments
due within one year [42] - 14,344
Other creditors 10,995 12,502
Short term lease liability 12,247 10,561
284,454 296,146
Non-financial items:
Accrued Expenses(38) 79,149 49,812
Other finance costs accrued 34,840 2,630
Social insurance and other
taxes 3,947 5,695
Income taxes 30 1,171
117,966 59,308
402,420 355,454
Trade and other payables-Non
Current
Financial items:
Deferred consideration
for acquisition of minority
(note 19) 159,551 -
Deferred licence payments(40) 54,712 55,174
Contingent consideration
(note 4 ) 56,091 55,222
Long term lease liability 41,007 37,062
Other payables 1,435 -
312,796 147,458
Non-financial items:
Long term prepayment [43] 35,525 29,105
Social insurance 497 630
36,022 29,735
348,818 177,193
24. Share based payments
Analysis of share-based payment charge
30 June (Unaudited)
2021 2020
$'000 $'000
Energean DSBP Plan 530 290
Energean Long Term Incentive
Plans 1,944 1,075
Total share-based payment charge 2,474 1,365
Capitalised to intangible and
tangible assets 207 33
Expensed as cost of sales 5
Expensed as administration expenses 2,247 1,154
Expensed to exploration and
evaluation expenses 14 174
Expensed as other expenses 1 4
Total share-based payment charge 2,474 1,365
Energean Long Term Incentive Plan (LTIP)
Under the LTIP, Senior Management can be granted nil exercise
price options, normally exercisable from three to ten years
following grant provided an individual remains in employment. The
size of awards depends on both annual performance measures and
Total Shareholder Return (TSR) over a period of up to three years.
There are no post-grant performance conditions. No dividends are
paid over the vesting period; however, Energean's Board may decide
at any time prior to the issue or transfer of the shares in respect
of which an award is released that the participant will receive an
amount (in cash and/or additional Shares) equal in value to any
dividends that would have been paid on those shares on such terms
and over such period (ending no later than the Release Date) as the
Board may determine. This amount may assume the reinvestment of
dividends (on such basis as the Board may determine) and may
exclude or include special dividends.
The weighted average remaining contractual life for LTIP awards
outstanding at 30 June 2021 was 1.6 years, number of shares
outstanding 2,036,982 and weighted average price at grant date
GBP5.99.
Deferred Share Bonus Plan (DSBP)
Under the DSBP, the portion of any annual bonus above 30 per
cent of the base salary of a Senior Executive nominated by the
Remuneration Committee was deferred into shares.
Deferred awards are usually granted in the form of conditional
share awards or nil-cost options (or, exceptionally, as
cash-settled equivalents). Deferred awards usually vest two years
after award although may vest early on leaving employment or on a
change of control.
The weighted average remaining contractual life for DSBP awards
outstanding at 30 June 2021 was 1.3 years, number of shares
outstanding 234,902 and price at grant date GBP6.75.
25. Related parties
25a. Related party relationships
Balances and transactions between the Company and its
subsidiaries, which are related parties, have been eliminated on
consolidation and are not disclosed in this note.
The Directors of Energean Plc are considered to be the only key
management personnel as defined by IAS 24. The following
information is provided in relation to the related party
transaction disclosures provided in note 25b below:
-- Adobelero Holdings Co Ltd . is a beneficially owned holding
company controlled by Panos Benos, the CFO of the Group.
-- Growthy Holdings Co Ltd is a beneficially owned holding
company controlled by Matthaios Rigas, the CEO of the Group.
-- Oil Co Investments Limited is beneficially owned and
controlled by Efstathios Topouzoglou, a Non-Executive Director of
the Group. The nature of the Group's transactions with the above
related parties is mainly financing activities.
-- Kerogen Capital is an independent private equity fund manager
specialising in the international oil and gas sector, which until
February 2021 held the 30% of Energean Israel ordinary shares not
held by the group (please refer to note 19).
-- Seven Maritime Company (Seven Marine) is a related party
company controlled by one the Company's shareholder Mr Efstathios
Topouzoglou. Seven Marine owns the offshore supply ships Valiant
Energy and Energean Wave which support the Group's investment
program in northern Greece.
-- Capital Earth: During the period ended 30 June 2021 the Group
received consultancy services from Capital Earth Limited, a
consulting company controlled by the spouse of one of Energean's
executive directors, for the provision of Group Corporate Social
Responsibility Consultancy and Project Management Services.
25b. Related party transactions
Purchases of goods and services
30 June (Unaudited)
2021 2020
$'000 $'000
Nature of transactions
Other related party
"Seven Marine" Vessel leasing 993 1,189
Other related party Construction
"Prime Marine Energy of field support
Inc" vessel 3,300 -
Other related party
"Capital Earth Ltd" Consulting services 46 63
4,339 1,252
Following a competitive tender process, the Group has entered
into an agreement to purchase a Field Support Vessel ("FSV") from
Prime Marine Energy Inc., a company controlled by director and
shareholder at Energean plc, for US$33.3 million. The FSV is being
constructed to meet the Group's specifications and will provide
significant in-country capability to support the Karish project,
including FPSO re-supply, crew changes, holdback operations for
tanker offloading, emergency subsea intervention, drilling support
and emergency response. The purchase of this multi-purpose vessel
will enhance operational efficiencies and economics when compared
to the leasing of multiple different vessels for the various
activities.
25c. Related party balances
Payables
30 June 2021 31 December
(Unaudited) 2020
$'000 $'000
Nature of balance
Seven Marine Vessel leasing 882 407
882 407
26. Commitments and contingencies
In acquiring its oil and gas interests, the Group has pledged
that various work programmes will be undertaken on each
permit/interest. The exploration commitments in the following table
are an estimate of the net cost to the Group of performing these
work programmes:
30 June 2021 31 December
(Unaudited) 2020
$'000 $'000
Capital Commitments:
Due within one year 97,351 102,255
Due later than one year but within
two years 138,665 84,855
Due later two years but within five
years 75,344 200,895
311,360 388,005
Contingent liabilities:
Performance guarantees:
Greece 4,751 6,743
Israel 64,740 62,101
UK 98,078 96,655
Italy 9,455 15,361
Montenegro 594 614
177,618 181,474
Performance guarantees are mainly in respect of committed work
programmes and certain financial obligations.
Issued guarantees:
Karish and Tanin Leases - As part of the requirements of the
Karish and Tanin Lease deeds, the Group provided the Ministry of
National Infrastructures, Energy and Water with bank guarantees in
the amount of US$10 million for each lease (total US$20 million).
The bank guarantees were in force until 29 December 2019, and were
renewed in March 2021 until 31 March 2022.
Blocks 12, 21, 23 and 31 in Israel - As part of the requirements
of the exploration and appraisal licences which granted to the
Group during the Israeli offshore BID in December 2017, the Group
provided the Ministry of National Infrastructures, Energy and Water
in January 2018 with bank guarantees in the amount of US$6.0
million for all 5 blocks mentioned above. The bank guarantees are
in force until 13 January 2023.
Blocks 55, 56, 61 and 62 , also known as "ZONE D" - As part of
the requirements of the exploration and appraisal licences which
granted to the Group during the Israeli 2nd offshore BID in July
2019, the Group provided the Ministry of National Infrastructures,
Energy and Water in January 2018 with bank guarantees in the amount
of US$3.2 million for all 4 blocks mentioned above. The bank
guarantees are in force until 28 September 2022.
Israeli Natural Gas Lines ("INGL") - As part of the agreement
signed with INGL on June 2019 the Group provided INGL bank
guarantee at the amount of 92 million ILS (approx. US$28.6 million)
in order to secure the first milestone payment from INGL. The first
bank guarantee at the amount of 92 million ILS (approx. US$28.3
million) was issued on June 2019 and is in force until 21 November
2021. During Q2 2021 an additional bank guarantee was issued to
secure INGL's additional milestone payment in total of 18 million
ILS (approx. US $5.6 million). This bank guarantee is in force
until 30 June 2022.
Israel Custom Authority - As part of the ongoing importation
related Karish development, the Group provided the Israeli Custom
authority bank guarantees in 2019 at the amount of 12 million ILS
(approx. $3.7 million). During Q2 2021 total amount of 8 million
ILS (approx. $2.5 millions) of the guarantees was revoked. The
remaining bank guarantees at amount of 4 million ILS (approx.
US$1.1 million). The bank guarantees are in force until 28 February
2022.
United Kingdom: Following Edison E&P acquisition the Group
issued letters of credit amount $92.1 million for United Kingdom
decommissioning obligations and obligations under the United
Kingdom licenses
Italy: Following Edison E&P acquisition the Group issued
letters of credit amount $13.3 million for decommissioning
obligations and obligations under the Italian licenses
Legal cases and contingent liabilities
The Group had no material contingent liabilities as of 30 June
2021 and 31 December 2020.
27. Subsequent events
Compensation to gas buyers due to late supply:
During August 2021 and in accordance with the GSPAs signed with
a group of gas buyers, the Group has agreed to pay compensation to
these counterparties due to the fact the gas supply date is taking
place beyond a certain date as defined in the GSPAs (being 30 June
2021). The compensation will be paid on a monthly basis starting on
August 2021 and is estimated at approx. US$23 million. The
compensation is accounted as variable purchase consideration under
IFRS 15 hence recognised once production commences and gas is
delivered to the offtakers
Gas buyer request for arbitration:
During August 2021 a gas buyer sent a request to the
International Court of Arbitration ("ICC") asking for arbitration
on its rights of termination due to the fact the gas supply date is
taking place beyond a certain date which defined in the GSPA. If
the agreement it is terminated, the Group has identified multiple
alternative routes to monetise those gas volumes (being 0.8
Bcm/yr), including both domestic and international markets, and
hence is confident of profitably selling them
28. Subsidiary undertakings
At 30 June 2021, the Group had investments in the following
subsidiaries:
Name of subsidiary Country of incorporation Principal activities Shareholding Shareholding
/ registered office
At 30 At 31 December
June 2021 2020
(%) (%)
Energean E&P 22 Lefkonos Street,
Holdings Ltd 2064 Nicosia, Cyprus Holding Company 100 100
Energean Capital 22 Lefkonos Street,
Ltd 2064 Nicosia, Cyprus Holding Company 100 100
Oil and gas
44 Baker Street, exploration,
Energean MED London W1U 7AL, development
Limited United Kingdom and production 100 100
Oil and gas
32 Kifissias Ave. exploration,
Energean Oil 151 25 Marousi Athens, development
& Gas S.A. Greece and production 100 100
Oil and gas
exploration,
Energean International 22 Lefkonos Street, development
Limited 2064 Nicosia, Cyprus and production 100 100
Oil and gas
Energean Israel exploration,
Limited (Note 22 Lefkonos Street, development
19) 2064 Nicosia, Cyprus and production 100 70
Oil and gas
exploration,
Energean Montenegro 22 Lefkonos Street, development
Limited 2064 Nicosia, Cyprus and production 100 100
Energean Israel 560A rue de Neudorf,
Finance SARL L-2220, Luxembourg Financing activities 100 70
Energean Israel
Transmission Andre Sakharov 9, Gas transportation
LTD Haifa, Israel license holder 100 70
Energean Israel Andre Sakharov 9,
Finance LTD Haifa, Israel Financing activities 100 70
Oil and gas
exploration,
Energean Egypt 22 Lefkonos Street, development
Limited 2064 Nicosia, Cyprus and production 100 100
Oil and gas
exploration,
Energean Hellas 22 Lefkonos Street, development
Limited 2064 Nicosia, Cyprus and production 100 100
Oil and gas
exploration,
Energean Italy Piazza Sigmund Freud development
S.p.a. 1 and production 100 100
20154 Milan,Italy
Oil and gas
exploration,
Energean International Piazza Sigmund Freud development
E&P S.p.a. 1 and production 100 100
20154 Milan,Italy
Oil and gas
Via Salvatore Quasimodo exploration,
Energean Sicilia 2 - 97100 Ragusa development
Srl (Ragusa) and production 100 100
Oil and gas
44 Baker Street, exploration,
Energean Exploration London W1U 7AL, development
Limited United Kingdom and production 100 100
Oil and gas
44 Baker Street, exploration,
Edison E&P UK London W1U 7AL, development
Ltd United Kingdom and production 100 100
Building 11, 273 Oil and gas
Edison Egypt Palestine Street exploration,
Energy Services New Maadi , Cairo development
JSC EGYPT and production 98 98
29. Exploration, Development and production interests
Country Fields Fiscal Group's Field Phase
Regime working
interest
Israel
Karish Concession 100% Development
Tanin Concession 100% Development
Blocks 12, 21, 23, Concession 100% Exploration
31
Four licences Zone Concession 80% Exploration
D
Egypt
Abu Qir PSC 100% Production
Abu Qir North PSC 100% Production
Abu Qir West PSC 100% Production
Yazzi PSC 100% Development
Python PSC 100% Development
Field A (NI-1X) PSC 100% Exploration
Field B (NI-3X) PSC 100% Exploration
NI-2X PSC 100% Exploration
North East Hap'y PSC 30% Exploration
Viper (NI-4X) PSC 100% Exploration
Greece
Prinos Concession 100% Production
Epsilon Concession 100% Development
Prinos exploration Concession 100% Exploration
area
South Kavala Concession 100% Production
Katakolo Concession 100% Undeveloped
Ioannina Concession 40% Exploration
West Patraikos Concession 50% Exploration
Block-2 Concession 75% Exploration
Italy
Vega A Concession 100% Production
Vega B Concession 100% Production
Rospo Mare Concession 100% Production
Verdicchio Concession 100% Production
Vongola Mare Concession 95% Production
Gianna Concession 100% Development
Accettura Concession 50% Production
Anemone Concession 19% Production
Appia Concession 50% Production
Argo-Cassiopea Concession 40% Development
Azalea Concession 16% Production
Calipso Concession 49% Production
Candela Dolce Concession 40% Production
Candela Povero Concession 40% Production
Carlo Concession 49% Production
Cassiano Concession 50% Production
Castellaro Concession 50% Production
Cecilia Concession 49% Production
Clara East Concession 49% Production
Clara North Concession 49% Production
Clara Northwest Concession 49% Production
Clara West Concession 49% Production
Comiso Concession 100% Production
Cozza Concession 85% Production
Daria Concession 49% Production
Didone Concession 49% Production
Emma West Concession 49% Production
Fauzia Concession 40% Production
Giovanna Concession 49% Production
Leoni Concession 50% Production
Monte Urano-San Lorenzo Concession 40% Production
Naide Concession 49% Production
Portocannone Concession 62% Production
Quarto Concession 33% Production
Ramona Concession 49% Production
Regina Concession 25% Production
Salacaro Concession 50% Production
San Giorgio Mare Concession 95% Production
San Marco Concession 100% Production
Santa Maria Mare Concession 96% Production
Santo Stefano Concession 95% Production
Sarago Mare Concession 85% Production
Sinarca Concession 40% Production
Talamonti Concession 50% Production
Tresauro Concession 25% Production
UK
Garrow Concession 68% Production
Kilmar Concession 68% Production
Scott Concession 10% Production
Telford Concession 16% Production
Wenlock Concession 80% Production
Glengorm Concession 25% Exploration
Isabella Concession 10% Exploration
Montenegro
Block 26, 30 Concession 100% Exploration
Croatia
Irena PSC 70% Exploration
Izabela PSC 70% Production
Malta
Blocks 1, 2 and 3 Concession 100% Exploration
of Area 3
[1] The Intergovernmental Panel on Climate Change (IPCC) is the
United Nations body for assessing the science related to climate
change
[2] 2020 emissions are quoted on a pro forma basis, i.e. stated
as if Energean had owned Edison E&P for the full year. The
transaction closed on 17 December 2020.
[3] As measured under the TechnipFMC EPCIC
[4] The 1bn boe is composed of a combination of CPR-estimated
volumes and management estimates
[5] 2020 emissions are quoted on a pro forma basis, i.e. stated
as if Energean had owned Edison E&P for the full year. The
transaction closed on 17 December 2020
[6] Cash Cost of production is defined in the Financial Review section
[7] Including flux of $10.3 million and purchased oil of $2.5
million
[8] Cash SG&A and Adjusted EBITDAX is defined in the Financial Review section
[9] After working capital movements
[10] As measured under the TechnipFMC EPCIC
[11] As measured under the TechnipFMC EPCIC
[12] The 1 bn boe is composed of a combination of CPR-estimated
volumes and management estimates
[13] 2020 emissions are quoted on a pro forma basis, i.e. stated
as if Energean had owned Edison E&P for the full year. The
transaction closed on 17 December 2020
[14] Cash cost of production is defined later in the financial
review
[15] Cash SG&A is defined later in the financial review
[16] Adjusted EBITDAX is defined later in the financial review.
Energean uses Adjusted EBITDAX as a core business KPI.
[17] Adjusted EBITDAX calculation has been changed to exclude
the impact of the non-cash item of share-based payment charges.
This adjustment is aligned with the underlying Group's adjusted
EBITDAX calculation which excludes the impact of costs which tend
to be one-off in nature and the non-cash costs. Comparative EBITDAX
has been restated accordingly.
[18] Numbers may not sum due to rounding
[19] Inclusive of restricted cash
[20] The share premium account represents the total net proceeds
on issue of the Company's shares in excess of their nominal value
of GBP 0.01 per share less amounts transferred to any other
reserves.
[21] Other reserves are used to recognise remeasurement gain or
loss on cash flow hedges and actuarial gain or loss from the
defined retirement benefit plan.
[22] Refer to note 19
[23] The share-based payments reserve is used to recognise the
value of equity-settled share-based payments granted to parties
including employees and key management personnel, as part of their
remuneration.
[24] The foreign currency translation reserve is used to record
unrealised exchange differences arising from the translation of the
financial statements of entities within the Group that have a
functional currency other than US dollar.
[25] Represents the acquisition of the remaining 30% minority
interest in Energean Israel Limited from Kerogen Investments No.38
Limited, for more details please refer to note 19
[26] Non-cash revenues from Egypt arise due to taxes being
deducted at source from invoices as such revenue and tax charges
are grossed up to reflect this deduction but no cash inflow or
outflow results.
[27] Adjusted EBITDAX is a non-IFRS measure used by the Group to
measure business performance. It is calculated as profit or loss
for the period, adjusted for discontinued operations, taxation,
depreciation and amortisation, share-based payment charge,
impairment of property, plant and equipment, other income and
expenses (including the impact of derivative financial instruments
and foreign exchange), net finance costs and exploration and
evaluation expenses.
[28] Related to derecognition of specific accounts payables
balances in the Greek subsidiary following waiver agreements with
creditors
[29] Related to termination fees paid from Neptune Energy
following the termination of the agreement for Neptune Energy to
acquire Edison E&P's UK and Norwegian subsidiaries from the
Group.
[30] On 29 April 2021, the Group fully repaid the Israel Project
Finance Facility before the maturity date of 31 December 2021 and,
as such, the unamortised financing costs have been expensed in the
period.
[31] For the reconciliation of the tax rate, the weighted
average rate of the statutory tax rates in Greece (25%), Israel
(23%), Italy (24%) and United Kingdom (40%) was used weighted
according to the profit or loss before tax earned by the Group in
each jurisdiction. These are jurisdictions where current and/or
deferred tax is recognised.
[32] Permanent differences mainly consisted of non-deductible expenses.
[33] Tax losses generated from entities which are not expected
to generate sufficient taxable profits in the near future and for
which deferred tax is not recognised.
[34] Income tax paid in Egypt branch based on the Production Sharing Agreement (PSA) regime
[35] Utilisation of foreign tax credits in Italy to offset
taxable profits arising from the operations in the Egyptian
branch
[36] Other adjustments mainly related to the tax effect of
consolidation differences due to the elimination of intra-group
transactions.
[37] These reclassifications primarily relate to the assets and
liabilities acquired in the Edison E&P acquisition which
completed in December 2020 and reflect updated information on the
allocation of the deferred taxes across the relevant
categories.
[38] Government subsidies mainly relate to grants from Greek
Public Body for Employment and Social Inclusion (OAED) to
financially support the Kavala Oil S.A. labour cost from
manufacturing under the action plan for promoting sustainable
employment in underdeveloped or deprived districts of Greece, such
as the area of Kavala.
[39] Included in deposits and prepayments, are mainly
prepayments for goods and services under the GSP Engineering,
Procurement, Construction and Installation Contract (EPCIC) for
Epsilon project.
[40] Included in trade payables and accrued expenses in 30 June
2021 and FY2020, are mainly Karish field related development
expenditures (mainly FPSO and Sub Sea construction cost) .
[41] Payables related to operated Joint operations primarily in
Italy
[42] In December 2016, Energean Israel acquired the Karish and
Tanin offshore gas fields for $40.0 million closing payment with an
obligation to pay additional consideration of $108.5 million plus
interest inflated at an annual rate of 4.6% in ten equal annual
payments. As at 30 June 2021 the total discounted deferred
consideration was $54.71 million (as at 31 December 2020: $69.52
million). The Sale and Purchase Agreement ("SPA") includes
provisions in the event of Force Majeure that prevents or delays
the implementation of the development plan as approved under one
lease for a period of more than ninety (90) days in any year
following the final investment decision ("FID") date. In the event
of Force Majeure the applicable annual payment of the remaining
consideration will be postponed by an equivalent period of time,
and no interest will be accrued in that period of time as well. Due
to the effects of the COVID-19 pandemic which constitute a Force
Majeure event, postponing the deferred payment due in March 2022 by
the number of days that such Force Majeure event last. As of 30
June 2021 Force Majeure event length has not been finalised as the
COVID-19 pandemic continue to affect the progress of the project ,
and in such the deferred payment due in March 2022 will be made
after 1 July 2022 . As at 30 June 2021 the total discounted
deferred consideration was $54.7 million (31 December 2020: $69.5
million).
[43] In June 2019, Energean signed a Detailed Agreement with
Israel Natural Gas Lines ("INGL") for the transfer of title (the
"hand over") of the near shore and onshore part of the
infrastructure that will deliver gas from the Karish and Tanin FPSO
into the Israeli national gas transmission grid. As consideration,
INGL will pay Energean 369 million Israeli new shekel (ILS),
approximately $102 million for the infrastructure being built by
Energean which will be paid in accordance with milestones detailed
in the agreement. The agreement covers the onshore section of the
Karish and Tanin infrastructure and the near shore section of
pipeline extending to approximately 10km offshore. It is intended
that the hand over to INGL will become effective shortly after the
delivery of first gas from the Karish field expected in mid-2022 .
Following hand over, INGL will be responsible for the operation and
maintenance of this part of the infrastructure.
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END
IR UPUAUBUPGPUG
(END) Dow Jones Newswires
September 02, 2021 02:00 ET (06:00 GMT)
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