TIDMGENL
RNS Number : 9500A
Genel Energy PLC
30 March 2017
30 March 2017
Genel Energy plc
Audited results for the year ended 31 December 2016
Genel Energy plc ('Genel' or 'the Company') announces its
audited results for the year ended 31 December 2016.
Results summary ($ million unless stated)
2016 2015
---------- ----------
Production (bopd, working interest) 53,300 84,900
Revenue 190.7 343.9
EBITDAX(1) 130.7 279.4
Depreciation (128.9) (172.5)
Impairment of exploration assets (779.0) (144.1)
Exploration expense (36.1) (28.9)
Impairment of property, plant and
equipment (218.3) (1,038.0)
Impairment of receivables (191.3) -
Operating loss (1,222.9) (1,104.1)
Cash flow from operating activities 131.0 71.2
Capital expenditure(2) 61.2 157.2
Free cash flow(3) 59.1 (179.2)
Cash(4) 407.0 455.3
Net debt(5) 241.2 238.8
KRG receivable 253.5 422.9
EPS (c per share) (448.60) (417.30)
1. EBITDAX is earnings before interest, tax, depreciation,
amortisation, exploration expense and impairment which is operating
loss adjusted for the add back of depreciation ($128.9 million),
exploration costs written off ($36.1 million) and any impairments
($1,188.6 million)
2. Capital expenditure is additions of intangible assets and
additions of property, plant and equipment (oil and gas assets
only)
3. Free cash flow is net cash generated from operating
activities less cash outflow due to purchase of intangible assets
and purchase of property, plant and equipment (oil and gas assets
only)
4. Cash reported at 31 December 2016 excludes $19.5 million of restricted cash
5. Net debt is reported debt less cash
Highlights
-- The KRG's February 2016 commitment to pay contractor export
payments and address outstanding receivables led to a significant
increase in cash proceeds during 2016
-- $207 million cash proceeds were received in 2016 (2015: $148
million), with Genel generating $59 million in free cash flow
(2015: $179 million outflow)
-- $67 million in cash proceeds received in 2017 to date,
representing full settlement of invoices for 2016 production
-- 2016 net production averaged 53,300 bopd (2015: 84,900), at
the lower end of revised guidance
-- Strong liquidity position at the end of 2016, with
unrestricted cash balances of $407 million ($455 million at
end-2015)
Outlook
-- Signature of amended PSCs and Gas Lifting Agreement in
February 2017, with a focus now on concluding negotiations with
potential partners
-- Continued engagement with the KRG over accelerating the recovery of outstanding receivables
-- Tawke 2017 production expected to average around year to date
production levels of 111,000 bopd, in line with the Operator's
guidance
-- Peshkabir-2 Cretaceous discovery in early 2017 - accelerated
appraisal and early production planning
-- 2017 capex guidance for Taq Taq and Tawke reiterated at
$50-75 million. KRI gas business and Africa exploration expenditure
also reiterated at c.$50 million
-- Bond buy-back announced today (see separate press release)
Murat Özgül, Chief Executive of Genel, said:
"While 2016 was a challenging year at Taq Taq, Tawke continues
to produce at a stable level, and regular payments for our oil
production in the Kurdistan Region of Iraq helped generate free
cash flow in the year. The improved financial position of the
Kurdistan Regional Government bodes well for a continuation of
these payments.
The signing of definitive agreements in February 2017 allows us
to focus on concluding negotiations with potential partners,
helping unlock the significant value in our gas assets. We move
into 2017 with clear priorities: maximising the value of our oil
assets, accelerating the recovery of the receivable, and building
on the increased momentum in the development of our gas
assets."
Enquiries:
Genel Energy
Phil Corbett, Head of Investor
Relations
Andrew Benbow, Head of Public
Relations +44 20 7659 5100
Vigo Communications
Patrick d'Ancona +44 20 7830 9700
There will be a presentation for analysts and investors today at
1000 BST, with an associated webcast available on the Company's
website, www.genelenergy.com.
This announcement includes inside information.
Disclaimer
This announcement contains certain forward-looking statements
that are subject to the usual risk factors and uncertainties
associated with the oil & gas exploration and production
business. Whilst the Company believes the expectations reflected
herein to be reasonable in light of the information available to
them at this time, the actual outcome may be materially different
owing to factors beyond the Company's control or within the
Company's control where, for example, the Company decides on a
change of plan or strategy. Accordingly no reliance may be placed
on the figures contained in such forward looking statements.
CHAIRMAN'S STATEMENT
I am pleased to welcome you to Genel Energy's sixth annual
results statement.
Last year we spoke of Genel Energy's resilience, and 2016 saw
this tested once again. There is now greater stability in the oil
industry, and there are opportunities in the Genel portfolio that
provide clear reasons for optimism going forward.
Following a difficult 2015 for the entire oil industry, after
hitting a low in February 2016, the oil price and operating
environment improved across the remainder of the year. For the
Kurdistan Region of Iraq, an economy almost entirely dependent on
income from its oil exports, these tailwinds have begun to make a
difference.
At the start of the year the continued fall in the oil price,
coupled with the financial cost of the fight against ISIS and the
ongoing lack of budget transfers from Baghdad, placed a significant
financial strain on the KRG. Despite this the KRG reaffirmed its
commitment to pay exporters based on the contractual entitlements
under the Production Sharing Contract governing each licence.
Payments for exports were made throughout the year, with over
half a billion dollars paid for gross exports from Taq Taq and
Tawke. This resulted in Genel generating free cash flow in the
year, a testament to our low cost base and a notable achievement
during a difficult time for the industry. The recovery in the oil
price facilitates ongoing and regular payments, and provides a
basis from which the KRG can turn its attention to progressing the
gas development.
Despite the disappointment associated with the further
impairments to our balance sheet, there remains significant value
potential in the portfolio. Maximising the recovery of oil from our
fields, the recovery of our full receivable entitlement, as well as
the development of our gas assets, remain key priorities for Genel
going forward.
KRI oil assets
Payments throughout 2016 enabled a resumption of investment at
Taq Taq and Tawke. Tawke's production performance remains robust,
and the asset is now the primary driver of value in Genel's oil
business. We will work together with the operator, DNO, as the
field continues to generate significant cash flow and value for the
partners in years ahead.
The regularity of payments also allowed appraisal drilling at
the nearby Peshkabir discovery, with very encouraging initial
results. Further appraisal activity is planned for 2017, but we
already believe the potential exists to add to our production going
forward.
Challenges continue at the Taq Taq field, and production
performance has been disappointing. Work done in 2016, and the
first two months of 2017, helped to refine our understanding of the
remaining potential. This regrettably led to a further write-down
of reserves. Additional drilling in 2017, and further investment at
the field, will be targeted and appropriate in order to maximise
the recovery of remaining oil and generate positive cash flow from
operations on an annual basis.
Momentum in the gas business
As we look ahead, of great encouragement is the momentum behind
the development of the Miran and Bina Bawi gas fields. Across the
industry, 2016 saw accelerated adoption of natural gas usage, with
the Middle East recording the strongest regional growth rate.
Turkey continues to be one of the largest gas consuming markets in
the world, and its willingness to diversify supply away from the
88% it gets from just three countries provides a compelling reason
for Turkey and the KRG to drive forward the development of Genel's
fields. Miran and Bina Bawi alone have the potential to help meet a
meaningful percentage of this demand.
The finalisation of documentation of the Production Sharing
Contracts and Gas Lifting Agreements for both fields in February
2017 is a significant milestone.
There remain many challenges to bringing these assets to
production, but this is a company-changing opportunity.
Management changes
In order to ensure that we have an appropriate team in place to
best deliver on our strategy, Paul Schofield was appointed Chief
Operating Officer in May 2016. With thirty five years' management
and technical experience encompassing all aspects of the upstream
oil and gas business, Paul has been a welcome addition to the
team.
Jim Leng and Sir Graham Hearne retired from the Board during
2016, having both made valuable contributions in the establishment
of Genel Energy as a respected London-listed company. It was a
great pleasure working with them. Simon Lockett was added to the
Board, bringing significant knowledge and experience of the oil
sector.
Post-period end, we have also welcomed Tolga Bilgin to the
Board.
Responsible operations
2016 was the tenth anniversary of Genel Energy drilling at Taq
Taq, and we are proud of the work done to support the local
community and the KRI as a whole in that time. Since drilling began
Taq Taq has been a major source of revenue to the KRG, and we have
also invested around $25 million on local community projects,
funding over 178 separate projects, as well as currently providing
employment to over 400 local people. This work continues, and is a
credit to the team in the KRI.
As well as the local community, we take our responsibilities to
our employees, contractors, and partners seriously. In 2016 we
achieved our target of zero injuries across the business, something
that we will strive to emulate in 2017 and beyond.
Outlook
We recognise that 2016 share price performance has been
disappointing, and the Board and management team are focused on a
strategy to reverse this trend. We retain high-impact onshore
exploration opportunities in the portfolio, our oil fields remain
cash flow generative, and our gas assets provide a very large scale
opportunity that is rare for an independent E&P company.
The regularity of payments for our oil production, coupled with
our confidence in them continuing throughout 2017 and beyond,
provides us with optionality regarding our financial position. The
Board will continue to assess the appropriate capital structure for
the business as the framework for our gas development evolves ahead
of our 2019 bond refinancing.
With the opportunities available in our portfolio we are
confident that we have the strategy and team to grow the business
in coming years. We look forward to updating you on progress
throughout 2017.
CEO STATEMENT
The last three years have been a difficult period for Genel. The
entire E&P sector struggled with a collapsing oil price
environment, the Kurdistan Region of Iraq faced a challenging
security situation, and our Taq Taq field has suffered from sharp
production declines and subsequent reserve downgrades.
While acknowledging the recent disappointing share price
performance and cumulative impact of impairments, there are now
clearer opportunities for value creation than there have been for
some time, driven by the significant opportunity afforded by our
gas assets.
Genel has operated in the KRI, and worked alongside the
Kurdistan Regional Government, for over a decade. We have
acknowledged the difficult times that the KRG has faced
economically, and the hard work that has delivered a working
payment mechanism for oil exports.
2016 was a watershed for contractor payments, with Genel
receiving $207 million in the year, an increase from $148 million
in 2015. This led us to generate free cash flow after interest
payments for the period, a notable performance at a time of low oil
prices.
The willingness and ability of the Kurdistan Regional Government
to make regular payments has been welcome at a time when they
continue to implement significant austerity measures. Our key focus
is the recovery of outstanding receivables. In February 2016 a
mechanism was implemented by the KRG through which the receivable
would begin to be recovered.
Alongside monthly payments for current sales based on a proxy
for contractual PSC entitlement, the KRG agreed to make further
payments equivalent to five percent of the monthly netback revenue
derived from our producing fields towards the recovery of
outstanding entitlements. This was a promising start, and we will
continue to work with the KRG to build on this.
As part of its commitment to transparent governance, the KRG has
engaged internationally recognised auditing firms to audit the KRI
oil sector. This process will also cover unpaid entitlements to oil
companies. We are confident that once this audit process is
complete, the KRG will remain committed to the full settlement of
unpaid entitlements in a timely fashion, and we remain focused on
recovering the full amount of our receivable.
Building a transformational gas business
While the oil business continues to generate cash, the gas
business is now moving forward towards development. In 2016,
hampered by the KRG's economic crisis and regional geopolitical
events, progress was slower than expected. Expenditure was
accordingly kept to a minimum, with the Pre-FEED and upstream Gas
Development Plan studies for the Miran and Bina Bawi fields being
the focus of activity.
An updated view on discount rates, and the pace of the
development timetable, amongst other factors, has led the Company
to reduce the carrying value of the Miran and Bina Bawi fields in
the Company's accounts from $1,448 million to $867 million. Despite
this write-down, the development of our gas assets represents a
huge opportunity for the Company, and for the Kurdistan Region of
Iraq as a whole.
Indeed, while 2016 progress was slow, momentum has recently
returned to the gas project. We are very pleased to have finalised
documentation for the amended Miran and Bina Bawi Production
Sharing Contracts and Gas Lifting Agreements. This was an important
milestone allowing us to focus on the next step of concluding
negotiations with potential partners, which will be the catalyst
for pre-development activity to start in earnest in order to move
the KRI gas project towards FID.
Our focus in 2017 is the positive conclusion of discussions with
a strategic partner for the project, followed by a completion of
the midstream agreement and financing of the gas processing
facility.
The development of our Miran and Bina Bawi assets has the
potential to be transformational for Genel, and we are focused on
demonstrating the value proposition to the industry and market.
Genel has been central to the Kurdistan Region of Iraq's
development as an oil province, and we now look forward to playing
the same role in the development of gas exports which will provide
a huge boost to the KRG's economy.
Cash generative oil assets
Despite a period of export pipeline downtime in the first
quarter of 2016, Tawke field performance remained strong, producing
an average of 107,000 bopd in the year. Regular payments allowed
investment in the field to restart in the first quarter and
continue throughout the year, with the development programme
offsetting natural well decline at the field.
Tawke reserve estimates also remain stable, with gross proved
plus probable (2P) reserves estimated at 504 MMbbls, compared to
543 MMbbls at year-end 2015, with the difference between that and
the prior year being primarily the production in 2016. The Tawke
field is now our cornerstone oil asset. It remains a low cost
field, and we look forward to working with DNO to maximise the cash
generation and value of this key asset in the future. We expect
that Tawke production in 2017 will average around year to date
production levels, in line with the Operator's current view.
The Peshkabir discovery, under the Tawke PSC, provides potential
upside. Following the discovery of Jurassic oil in the Peshkabir--1
well in 2012, the Peshkabir-2 well, spudded in October 2016,
discovered additional oil in the Cretaceous horizon in the southern
flank of the field in early 2017.
The Tawke partners are considering a number of options to step
up the appraisal of the new discovery, including the drilling of a
third well in the second half of 2017. Options are also under
consideration for possible early Peshkabir production from
Peshkabir-2, incorporating oil transportation to the Tawke field's
production facilities at Fishkabur 12 kilometres away.
Taq Taq field performance in 2016 was disappointing. It is both
a mature and complex field, where the recent production decline has
been faster than expected. Having produced over 200 million barrels
of oil, the focus is now on maximising oil recovery while
controlling costs, with an overall aim of generating positive cash
flow from operations.
There remains continued uncertainty at the field over reserves
estimation and future production rates, and the Company has removed
guidance for Taq Taq in 2017. Ongoing work at Taq Taq is aimed at
maximising oil recovery at Taq Taq and its value to Genel.
In 2016 capital expenditure totalled $61 million across Genel's
entire business, a reduction of 30% on initial guidance and almost
$100 million down on the prior year. Both fields continue to
benefit from low capital and operating costs, and appropriate
expenditure remains a key priority for Genel. As such, investment
at both Taq Taq and Tawke will keep pace with the payments that we
receive.
Development of reserves and resources
The reduction in the Company's 2P reserves at the end of 2016
primarily reflects the updated assessment of Taq Taq 2P reserves, a
consequence of a reassessment of the gross rock volume above the
oil water contact and fracture porosity in the undrained Cretaceous
Shiranish reservoir. The Peshkabir Cretaceous discovery represents
the best current prospect for near-term reserve bookings, and we
look forward to spudding the Peshkabir-3 appraisal well in the
second half of the year.
As with all aspects of the business, our focus on cost and value
means we will prioritise those areas of the portfolio that meet our
value creation criteria. In this regard, following the drilling of
the CS-12 well and a subsequent review of licence prospectivity we
have agreed the sale of our 40% interest in the Chia Surkh licence
to Petoil, subject to KRG approval. On completion Petoil will pay
Genel an initial consideration of $2 million, and an additional $25
million in staged payments contingent on future crude oil
production from the Chia Surkh licence.
In line with our strategy to concentrate on low-cost, onshore
activity with high-impact potential, we look forward to stepping up
activity in Somaliland. The potential is significant - our licences
cover an area the size of the entire KRI, with the geology
analogous to the proven hydrocarbon province in Yemen. The
acquisition of 2D seismic data on the Odewayne and SL-10B/13 blocks
is now underway. The data will be acquired as part of a Somaliland
government-owned project, with the Company purchasing the
associated data from the government. We look forward to maturing
prospects towards drilling in the medium term.
The Company is currently in discussions with the Moroccan
government over the nature, scope, and timing of the activity
related to the maximum future exploration commitment of c.$30
million.
Outlook
We have very clear priorities for the coming year. We will look
to maximise recovery from our oil fields while controlling costs,
with an overall aim of generating positive cash flow from
operations. As ever, we continue to keep a close eye on our
financial position, cost control is key across the business, and
investment will match the payment environment.
We are encouraged by the frequency of payments in early 2017 and
look forward to that continuing over the balance of 2017. We are
focused on working with the KRG to accelerate the recovery of the
receivable for the oil that we have produced in recent years. The
KRG has already stated that an increase in the oil price would lead
to an increase in the allocation of netback revenues paid to IOCs
each month, and the improvement we have seen in their economic
situation bodes well in this regard. The receipt of full cash
entitlements remains our focus, although there are other options
available.
2017 is a very important year for Genel and especially the
development of the gas business. We are working with the KRG and in
discussions with counterparties to move things rapidly forward,
promising an improved future for Genel and the KRI.
OPERATING REVIEW
Production and sales
Net working interest production in 2016 averaged 53,300 bopd, at
the lower end of the Company's 53-60,000 bopd guidance range, which
was revised from 60-70,000 bopd in July 2016. Production declined
by 37% year-on-year, with the underperformance versus initial
guidance primarily a result of greater than anticipated declines at
Taq Taq during the year.
Following a hiatus in drilling activity in the second half of
2015, development activity at both Taq Taq and Tawke resumed in
early 2016 as the KRG's payment announcement provided confidence of
ongoing cash receipts. Investment at Tawke helped to offset natural
well declines at the field, with drilling activity at Taq Taq only
partially mitigating natural well decline.
During 2016, the majority of production from both fields was
exported by the KRG through the KRI-Turkey pipeline. The Taq Taq
field also continued to supply the domestic Bazian refinery. Small
volumes from both fields were also supplied into the domestic
market, principally during downtime in the KRI-Turkey pipeline. All
sales routes from both fields are currently invoiced at the same
price under the terms of the February 2016 payment mechanism. The
Company continues to expect that the majority of production from
both fields will be exported by the KRG through the KRI-Turkey
pipeline. The KRI domestic market does provide a secondary sales
route in the event of meaningful disruptions to KRI-Turkey pipeline
uptime.
The Company announced on 28 March 2017 that previous guidance
for 2017 Taq Taq gross average production of 24-31,000 bopd had
been removed given the ongoing uncertainties in reserves estimation
and future production from the field. Consequently, the previous
35-43,000 bopd 2017 production guidance for the Company has also
been removed.
Average 2017 year to date production for the Company is 40,000
bopd, representing its net share of Taq Taq and Tawke
production.
Reserves and resources
At 31 December 2016, Genel's proven plus probable (2P) net
working interest reserves were 161 MMbbls. In the 2015 Annual
Report and Accounts, end-2015 2P net reserves were reported as 264
MMbbls. Shortly after publication of the Company's 2015 results,
the Tawke operator updated its assessment of end-2015 Tawke
reserves and resources, leading to a revision of the Company's
end-2015 net 2P reserve position to 242 MMbbls (as stated in the
table below). Compared to this latter figure, end-2016 net 2P
reserves represent a 33% year-on-year reduction.
Reserves and resources development
Remaining reserves Resources (MMboe)
(MMboe)
=====================
Contingent Prospective
=====================
1P 2P 1C 2C
Gross Net Gross Net Gross Net Gross Net Gross Net
===================== ====== ===== ====== ===== ====== ==== ====== ====== ====== ======
31 December
2015 447 123 777 242 1,065 798 2,186 1,552 3,433 1,994
=====================
Production (61) (19) (61) (19) - - - - - -
Acquisitions - - - - - - - - - -
and disposals
=====================
Extensions
and discoveries - - - - - - 48 12 - -
New developments - - - - - - - - - -
=====================
Revision of
previous estimates (11) (5) (119) (62) 15 13 (82) (15) 492 317
--------------------- ------ ----- ------ ----- ------ ---- ------ ------ ------ ------
31 December
2016 375 99 597 161 1,080 811 2,152 1,549 3,925 2,311
===================== ====== ===== ====== ===== ====== ==== ====== ====== ====== ======
Year-end 2016 gross Tawke 2P reserves were estimated by the
operator, DNO ASA, at 504 MMbbls, compared to 543 MMbbls at
year-end 2015. The year-on-year change is explained by production
in 2016 of 39 MMbbls. Genel's net share of Tawke 2P reserves at
end-2016 is 126 MMbbls. At the Peshkabir field, gross 2P reserves
at year-end 2016 were unchanged at 32 MMbbls (8 MMbbls net to
Genel).
On 29 February 2016, the Company announced that the 2P initial
gross recoverable reserves (referred to in the industry as
Estimated Ultimate Recovery, or EUR) for the Taq Taq field had been
downgraded from 683 MMbbls to 356 MMbbls. On 28 March 2017 the
Company announced a further downward revision of Taq Taq 2P EUR to
267 MMbbls, implying gross 2P reserves of 61 MMbbls at year-end
2016 (from 172 MMbbls at year-end 2015). Genel's net share of Taq
Taq 2P reserves at year-end 2016 is 27 MMbbls. The further
reduction of 2P EUR for Taq Taq is a consequence of a reassessment
of the gross rock volume above the oil water contact and fracture
porosity in the undrained Cretaceous Shiranish reservoir, following
an analysis of reservoir surveillance data and well performance
from 2016 and the first two months of 2017.
Following a technical and commercial review of development
planning for the Miran oil discovery, and capital allocation
decisions across Genel's business, the Company has decided that it
would be prudent to move Miran oil volumes from reserves to
resources pending clarity on the nature and timing of partner(s)
for the KRI gas business. This reduced 2P reserves by 23 MMbbls
(net).
At 31 December 2016, Genel's 2C net contingent resources were
1,549 MMboe. In the 2015 Annual Report and Accounts, 31 December
2015 net 2C resources were reported as 1,252 MMboe. Shortly after
publication of the Company's 2015 results, the Tawke operator
updated its assessment of end-2015 Tawke reserves and resources,
resulting in the Company's end-2015 2C net resources position being
upgraded to 1,284 MMboe. Furthermore, a decision has been taken to
include KRI gas business resource estimates on a raw gas instead of
sales gas basis at end-2016. This, amongst other factors, results
in a comparable end-2015 2C resource number of 1,552 MMboe.
Compared to this latter figure, 31 December 2016 2C net resources
were practically unchanged year-on-year.
In 2016, 2C resources attributable to the Chia Surkh PSC were
reduced following a block wide assessment of volumes following the
CS-12 drilling results. Elsewhere, net Peshkabir 2C resources of 12
MMboe were added following the Cretaceous discovery in early 2017.
Net Miran oil 2C resources of 39 MMbbls were added to 2C following
their removal from 2P reserves.
KRI oil assets
Tawke PSC (25% working interest)
The Tawke field produced a gross average of 107,000 bopd in
2016, compared to 135,000 bopd in 2015, representing a 21% decline
year on year. The majority (98%) of sales from the field were by
the KRG through the KRI-Turkey pipeline, with the remainder either
being refined at the Tawke field or sold in the domestic market. A
total of 33 development wells have been drilled at the field, with
28 of these currently producing. Surface facilities capacity is
currently 200,000 bopd with water handling capacity of up to 16,000
bpd.
Following the KRG's February 2016 payment announcement, well
intervention and drilling activity at Tawke field recommenced. In
the first half of 2016, a workover programme on eight existing
wells was implemented, which helped offset natural well declines.
In the second half of the year, four new production wells were
drilled, three of which were in the shallow Jeribe reservoir and
the fourth in the main Cretaceous reservoir. Combined, these
development wells added in excess of 10,000 bopd (sum of initial
well rates) of new production for investment of $11 million, again
offsetting declines from the existing well stock.
The firm programme for Tawke in 2017 includes two further
development wells (T-35 and T-21N) in the main Cretaceous reservoir
and two shallow Jeribe wells. Workovers of existing wells are also
planned. Additional activity in 2017, which includes further
Cretaceous and Jeribe wells, is contingent on reservoir performance
and regular payments from the KRG for current sales and unpaid
entitlements.
The Tawke field has produced an average of 111,000 bopd in 2017
year to date and is currently producing 108,000 bopd. The Company
expects that the average Tawke production in 2017 will be around
year to date production levels, in line with operator guidance.
Taq Taq (44% working interest, joint operator)
The Taq Taq field produced an average of 60,000 bopd in 2016, a
48% year-on-year decline. A total of 28 development wells have been
drilled at the Taq Taq field.
During the year, 68% of field output was sold by the KRG through
the KRI-Turkey pipeline, with a further 29% trucked to the domestic
Bazian refinery and the remainder sold into the domestic
market.
During 2016, three existing production wells were side-tracked.
All three sidetracks (TT-27x, TT-07z and TT-16y) were a
contributing a total of 9,000 bopd at year-end 2016, most of which
was from the TT-16y well. Production rates from the other two
sidetracks were lower than anticipated due to the well completions
being compromised as a result of drilling and completion
problems.
Notwithstanding the contribution from the side-track wells
drilled in 2016, Taq Taq field production underperformed
expectations in the year, primarily as a rising oil water contact
in the Shiranish reservoir reduced the productivity from key wells.
Following the analysis of reservoir surveillance data and well
performance from 2016 and the first two months of 2017, assumptions
on gross rock volume above the oil water contact and fracture
porosity in the undrained Shiranish formation were reassessed. This
resulted in a further reduction in gross proven and probable (2P)
EUR from 356 MMbbls at end-2015 to 267 MMbbls at end-2016. These
changes have been supported by McDaniel & Associates in its
updated Competent Person's Report (CPR) dated 28 March 2017.
In addition, the Company has been working on an updated Field
Development Plan ('FDP') for the Taq Taq field. The scope of this
activity has been extended to incorporate the results of recent
well performance and will be further refined on the back of future
development activity. The strategy at Taq Taq is to maximise
recovery from the field while controlling costs, with an overall
aim of generating positive cash flow from operations.
The Taq Taq field has produced an average of 28,000 bopd in 2017
to date. The Company has previously stated that the field is
reliant on production from a limited number of key wells -
production is currently 19,000 bopd from 15 wells, with five of
these wells accounting for 77% of field production. Recently, key
producing wells have exhibited high rates of decline as a result of
water breakthrough, exacerbating the decline rate across the field.
Taq Taq field water production is currently 13,000 bpd,
representing a water cut of c.40%, significantly less than total
water handling capacity of 55,000 bwpd. The Company currently
intends to announce Taq Taq field production on a monthly basis
going forward.
The TT-29z well is currently drilling at the field and aims to
reduce the uncertainty on the free water level in the north flank,
which in turn will give better understanding on remaining reserves
at this location. TT-29 will also target a shallower Tertiary
anomaly which could add new reserves if successful. Operations on
the well are scheduled to complete in mid-2017. In addition, the
firm 2017 programme for Taq Taq comprises two sidetracks of
existing Cretaceous producers, further development of the Pilaspi
reservoir and ESP/jet pump installation.
The Company remains of the view that Taq Taq is under drilled on
the flanks of the field. Accordingly, an opportunity register,
which consists of new development well locations and remedial work
on existing wells, is being prepared. The Company is working with
its partner in the field to determine the optimal forward
development programme. The partners have agreed to further refine
the future activity as the results of ongoing development activity
are known. Future activity levels at Taq Taq are also subject to
the continuation by the KRG of regular payments for crude sales and
historical receivables.
KRI gas assets
Miran and Bina Bawi fields (100% working interest, operator)
In 2016, Genel continued to work towards the commercialisation
of the significant resource base at the Miran and Bina Bawi fields,
currently estimated at 11 tcf (gross 2C basis) of raw gas. The
focus during 2016 was on finalising the upstream PSCs and terms of
gas supply to the midstream processing facilities. At the asset
level, the focus was on preliminary engineering studies, with both
the upstream Gas Development Plan and midstream pre-FEED awarded in
mid-2016.
In February 2017, the Company announced that it had finalised
Amended and Restated Production Sharing Contacts and Gas Lifting
Agreements for the Miran and Bina Bawi fields. As a result, Genel's
interests in both Miran and Bina Bawi increased to 100% (from 75%
and 80% respectively). These changes are not reflected in year-end
2016 reserves and resources as they occurred after the reporting
date of 31 December 2016.
The GLAs contain conditions precedent, which, inter alia,
include the execution of final agreements on the midstream gas
processing facilities and pipeline transportation, the execution of
the financing documents and the completion of updated competent
person's reports for Miran and Bina Bawi.
Both Genel and the KRG have the option to terminate the GLAs by
February 2018. If the conditions precedent are not satisfied within
12 months, the KRG has a right to terminate the GLAs. In the event
of termination, and a subsequent failure to conclude new gas
lifting agreements within one year period, the KRG can also
terminate the Miran and Bina Bawi PSCs. During the three year
period following such a termination, Genel would have a right of
first refusal to participate in the development of the Miran and
Bina Bawi gas fields with a 49% working interest on the same terms
offered to any third party. With this part of the gas documentation
finalised, Genel is now focused on the next step of concluding
negotiations with potential partners.
In mid-2016, the Company awarded the pre-Front End Engineering
Study ('FEED') contract for the midstream facilities to Fluor and
Gas Development Plan ('GDP') to Baker Hughes RDS. The midstream
pre-FEED was completed in early 2017 and has identified a number of
potential sites for the processing facilities at both Miran and
Bina Bawi. In addition, an option to process gas from Miran and
Bina Bawi at one plant located close to the Taq Taq field is under
consideration. The next step in the midstream development planning
entails a full FEED study and Environmental Impact Assessment.
The GDP, which has now been completed, has focussed on dynamic
reservoir modelling, production profiles, drilling locations, well
completion concepts and the subsurface reservoir management plan
for Miran and Bina Bawi. The GDP is broadly supportive of the
findings of the existing third party CPRs for Miran and Bina Bawi
with respect to the level of contingent resources at both
fields.
Capital expenditure estimates for the upstream development and
midstream processing facilities are still at a very preliminary
stage. In particular, further sub-surface work may be needed at
both Miran and Bina Bawi to refine the distribution of resources
across the fields, potential well locations, and well
deliverability. The Company envisages that this activity, if
implemented, would be funded as part of a farm-down of its 100%
upstream interest in both fields. As a result, the Company believes
that is appropriate that updated cost estimates for the gas project
await finalisation of the partnership structure for both the
upstream and midstream.
In 2016, the Company formally relinquished its 40% interest in
the Dohuk licence.
Exploration and appraisal
Cost effective onshore E&A activity, both in the KRI and
internationally, is an important part of the Company's growth
strategy. This strategy yielded tangible success in early 2017 with
the Cretaceous discovery at Peshkabir-2. Further appraisal of
Peshkabir will be the focus in 2017, in addition to committed
activity on the Africa exploration portfolio.
KRI
The Peshkabir-2 well was spudded in October 2016 to both
appraise the 2012 Jurassic discovery and explore Cretaceous
prospectivity 18 km to the west of the Tawke field. In January
2017, the Tawke partners announced that oil had been discovered in
the Cretaceous, with the well flowing at a stable rate of 3,800
bopd of 28deg API oil. The well has reached a planned depth of
3,500 metres and was completed to facilitate rigless testing of the
Jurassic, during March and April 2017. The Tawke partners plan to
appraise the Cretaceous discovery with the Peshkabir-3 well later
in 2017, as well as investigate the potential for early production
from Peshkabir-2 via the existing Tawke facilities. The Tawke
operator's initial estimate of gross 2C contingent resources for
the Peshkabir Cretaceous discovery is 48 MMboe.
The CS-12 exploratory appraisal well on the Chia Surkh licence
spudded on 30 March 2016, with a view to refining the resource
potential of the licence after the successful CS-10 and CS-11 wells
in 2013. Genel was carried on its share of the CS-12 well costs by
its partner Petoil. The well was drilled to a measured depth of
2,500 metres ahead of time and budget. The primary Oligocene and
Eocene objectives proved to be water bearing. A testing programme
in the previously proven Miocene section established a modest level
of oil resources.
Following consideration of the well results and a review of the
prospectivity on the licence, the Company signed a Sales and
Purchase Agreement in January 2017 to transfer its 40% interest in
the Chia Surkh licence to its partner, Petoil, which remains
subject to approval by the Ministry of Natural Resources. Petoil
will pay Genel an initial consideration of $2 million, and an
additional $25 million in staged payments contingent on future
crude oil production from a commercial development at Chia
Surkh.
As part of a portfolio high-grading exercise, the Company's 40%
working interest in the Ber Bahr licence is in the process of
relinquishment.
Africa
Onshore Somaliland, the acquisition of 2D seismic data on the
Odewayne (Genel 50%, operator) and SL-10B/13 (Genel 75%, operator)
blocks commenced in March 2017. The data will be acquired as part
of a Somaliland government owned speculative 2D seismic acquisition
project, with the Company purchasing the associated data from the
government. This new data is expected to deliver a step change in
the company's understanding of this highly prospective but
underexplored area. The current 2D seismic will satisfy the
outstanding commitment in the current exploration phase on both
licences. Any further activity beyond the current exploration phase
is discretionary.
The Company is currently in discussions with the Moroccan
government over the nature, scope and timing of the activity
related to the maximum future exploration commitment of c.$30
million.
CHIEF FINANCIAL OFFICER'S REVIEW
Results summary ($ million unless stated)
2016 2015
---------- ----------
Production (bopd, working interest) 53,300 84,900
Revenue 190.7 343.9
EBITDAX(1) 130.7 279.4
Depreciation (128.9) (172.5)
Impairment of exploration assets (779.0) (144.1)
Exploration expense (36.1) (28.9)
Impairment of property, plant and
equipment (218.3) (1,038.0)
Impairment of receivables (191.3) -
Operating loss (1,222.9) (1,104.1)
Cash flow from operating activities 131.0 71.2
Capital expenditure(2) 61.2 157.2
Free cash flow(3) 59.1 (179.2)
Cash(4) 407.0 455.3
Net debt(5) 241.2 238.8
KRG receivable 253.5 422.9
EPS (c per share) (448.60) (417.30)
1. EBITDAX is earnings before interest, tax, depreciation,
amortisation, exploration expense and impairment which is operating
loss adjusted for the add back of depreciation ($128.9 million),
exploration costs written off ($36.1 million) and any impairments
($1,188.6 million)
2. Capital expenditure is additions of intangible assets and
additions of property, plant and equipment (oil and gas assets
only)
3. Free cash flow is net cash generated from operating
activities less cash outflow due to purchase of intangible assets
and purchase of property, plant and equipment (oil and gas assets
only)
4. Cash reported at 31 December 2016 excludes $19.5 million of restricted cash
5. Net debt is reported debt less cash
2016 was a challenging year for the oil sector globally as the
price of Brent crude fell to $27/bbl in January before recovering
to $55/bbl at the end of the year. These financial challenges were
particularly felt by the KRI, with the oil price drop deepening its
ongoing economic crisis, while the war with ISIS and the influx of
displaced persons had an ongoing impact on the KRG's financial
position, and in turn the ability to pay oil companies, including
Genel, for both current production and past receivable balances.
Despite these challenges significant progress was made during 2016
towards establishing a working payment system and, despite the
macro headwinds and the decline in production at Taq Taq, the
Company delivered positive free cash flow in the year.
This achievement is due to a combination of factors:
The resumption of regular payments for oil deliveries by the
KRI
We received $153.4 million from the KRG for oil delivered by
Genel during 2016. Whilst arrears remained outstanding for October,
November and December deliveries at the end of the year, and the
temporary payment system does not reflect our view of our
entitlement, receiving nine payments for both Taq Taq and Tawke
sales during 2016 represents significant progress from the 2015
payment backdrop. Since year-end the outstanding arrears for 2016
deliveries have been settled in full.
The initiation of payments towards recovery of the
receivable
Total payments of $53.9 million were received by Genel towards
repayment of the receivable during 2016. Whilst this initial
payment stream is limited in comparison to the amount outstanding,
we welcome both the initiation of the payment flows and the KRG's
public commitment to increase the quantum as their financial
situation improves.
Our low cost asset base and the structure of the Production
Sharing Contracts
Our oil assets remain amongst the lowest cost in the world, with
operating costs of less than $2.0/bbl in 2016. These low operating
costs combine with efficient capital expenditure and appropriate
fiscal terms to fairly balance risk and reward at different oil
prices between the oil producers and the KRG.
The flexible nature of our capital expenditure
We have flexibility in our capital expenditures and are able to
moderate spend on our producing assets to match payment flows, with
our capital expenditure accordingly dropping 61% year-on-year. We
have no committed capital in our gas business and so have also been
able to match spending to the pace of the project.
A continued focus on costs across the business
We have maintained a tight control on costs and continue to
ensure that we are structured and resourced appropriately for the
external environment. Total headcount has fallen from 223 at the
end of 2014 to 129 at the end of 2016, and total general and
administrative costs have reduced from $47.0 million to $26.0
million over the same period.
There are elements of the 2016 accounts that warrant further
comment:
Impairments to our producing assets
The further reduction in reserves and amended production outlook
for Taq Taq, together with an increase in the discount rate applied
to our impairment testing as a result of the continued regional
financial challenges, has led to an impairment of $180.8 million.
Our oil price assumptions for impairment purposes are set out on
page 23 and we have provided sensitivities on the two key estimates
in the relevant note. The change in discount rate and oil price has
also impacted our carrying value of Tawke, resulting in an
impairment of $37.5 million.
Impairments to our exploration assets, including the gas
business
Genel has invested over $1.4 billion in the acquisition and
early development of the Miran and Bina Bawi fields. They represent
a very attractive and low cost gas project, close to market with a
governmental buyer in place, with the potential to generate
significant value for both the KRG and Genel. In light of a revised
timing and phasing of the project to reflect slower progress
towards a final investment decision than previously anticipated, we
have reviewed our carrying value for gas for impairment purposes.
This revised timing, together with the revisions to our discount
rate and oil price assumptions detailed above, has resulted in an
impairment charge of $581.3 million. We have also impaired Chia
Surkh by $197.7 million following the CS-12 well result and the
expected completion of the subsequent sale of our interest to
Petoil.
Impairment to the receivable
We have again provided substantial disclosure around the
accounting approach taken in relation to the receivable. Our
accounting follows the commercial judgment that the KRG intends to
repay the debt and has the capability to do so over time, given a
rising oil price. The current mechanism of repayment is linked to a
percentage of field netback revenues, and we have used an
assumption of this percentage multiplied by forecast field
production and oil price to calculate future cash flows and a
present value. Given the higher oil price has not yet resulted in a
higher percentage being applied by the KRG to field revenue we have
reduced our future assumptions to a flat 5% payment for impairment
purposes, in line with current levels. This assumption, together
with the reduction in forecast Taq Taq production and amended oil
prices results in a book impairment of $191.3 million. This has no
impact whatsoever on our right to recover the amount due from the
KRG, which we are entitled to recover in full, which is the nominal
value of $515.9 million.
As we look to 2017 there is a clear set of financial priorities
for the Company:
-- Continue to press the KRG for timely and full payments for
oil deliveries, and for a transparent mechanism for reconciliation
and recovery of the receivable
-- Secure equity and debt investment into the gas assets,
thereby progressing the project towards first gas
-- Continue to focus on all aspects of the Company's cost base,
whether capital, operating or administrative expenditure
-- Manage liquidity appropriately ahead of the 2019 maturity of the Company's bond debt
Financial results for the year
Income statement
Production of 53,300 bopd was significantly reduced compared to
last year (2015: 84,900 bopd). The combination of lower production,
lower oil price and lower capex reducing cost oil by 44%, resulted
in a 45% reduction in revenue to $190.7 million (2015: $343.9
million) and a 53% reduction to EBITDAX of $130.7 million (2015:
$279.4 million).
Despite lower production, production costs of $35.1 million were
broadly in line with last year ($36.3 million) as a result of lower
capitalisation of costs due to lower capital activity. Lower
production reduced depreciation of oil assets to $127.8 million
(2015: $172.0 million).
Impairment of exploration assets includes $581.3 million
relating to the Miran and Bina Bawi gas assets and the write-off of
$197.7 million relating to the Chia Surkh licence following the
drilling of CS-12. In addition, $36.1 million has been accrued
relating to expenditures in the current year on exploration
activity and exit/relinquishment of exploration licences.
Impairment of property plant and equipment was $218.3 million in
2016 (2015: $1,038.0 million relating to Taq Taq).
General and administrative costs were $26.0 million (2015: $28.7
million).
Finance income of $16.2 million (2015: $1.3 million) was
comprised of $14.2 million discount unwind on trade receivables and
$2.0 million of bank interest income. Finance expense of $61.0
million (2015: $57.8 million) was comprised of $51.0 million of
bond interest together with non-cash discount unwind expense of
$10.0 million.
In the KRI, the Company is either exempt from tax or tax due has
been paid on its behalf by the KRG from the KRG's own share of
revenues, resulting in no tax payment required or expected to be
made by the Company. Tax presented in the income statement of $0.4
million relates to taxation of the Turkish and UK service
companies.
Capital expenditure
Capital expenditure in the year was $61.2 million (2015: $157.2
million). Cost recovered development spend of $40.3 million (2015:
$109.2 million) was incurred on the producing assets in the KRI
with spend on exploration and appraisal assets amounting to $20.9
million (2015: $48.0 million), principally incurred on the Miran
and Bina Bawi PSCs.
Cash flow and cash
Net cash flow from operations was $131.0 million (2015: $71.2
million). This was positively impacted by $53.9 million (2015: nil)
of proceeds being received for the KRG receivable, and $153.4
million (2015: $148.2 million) received for current sales.
Operating expense, exploration expense and corporate costs amounted
to a cash outflow of $56.3 million (2015: $87.0 million), with net
payment of creditors resulting in a cash out flow of circa $20
million (2015: inflow circa $10 million).
Cash flows for capital spend on Taq Taq and Tawke was $51.2
million (2015: $120.2 million), with $20.7 million (2015: $130.2
million) cash out flow on exploration and evaluation assets -
principally Miran and Bina Bawi.
Free cash flow was $59.1 million compared to a cash outflow of
$179.2 million last year. After which, $35.4 million was used to
buy back bonds with nominal value of $55.4 million and $52.0
million (2015: $46.1 million) was paid on bond interest
expense.
$19.5 million of cash is restricted and therefore excluded from
reported cash of $407.0 million (2015: $455.3 million). Overall
there was a net decrease in cash of $47.8 million compared to a
decrease of $33.0 million last year, which included bond issuance
proceeds of $196.2 million.
Debt
The Company has $730.0 million of bonds maturing in 2019 in
issuance, of which $55.4 million are held by the company resulting
in total externally held debt of $674.6 million (2015: $730.0
million) and net debt of $241.2 million (2015: $238.8 million).
The bond has three financial covenant maintenance tests, which
are summarised in the table below:
YE2016
Net debt / EBITDAX < 3.0 1.8
Equity ratio > 40% 60%
Minimum liquidity > $75m
(>$100m from May 2018) 407
Receivables
At 31 December 2016, the reported KRG receivable was $253.5
million (2015: $422.9 million), detailed disclosure is provided on
this balance in the significant accounting estimates and judgements
section of note 1 and in note 10 to the financial statements.
Net assets
Net assets at 31 December 2016 were $1,333.4 million (2015:
$2,574.8 million) and consist primarily of oil and gas assets of
$1,538.7 million (2015: $2,602.1 million), trade receivables of
$253.5 million (2015: $422.9 million) and net debt of $241.2
million (2015: $238.8 million).
Liquidity / cash counterparty risk management
The Company monitors its cash position, cash forecasts and
liquidity on a regular basis. The Company holds surplus cash held
in government gilts or treasury bills or on time deposits with a
number of major financial institutions. Suitability of banks is
assessed using a combination of sovereign risk, credit default swap
pricing and credit rating.
Dividend
No dividend (2015: nil) will be paid for the year ended 31
December 2016.
Going concern
The directors have assessed that the cash balance held provides
the Company with adequate headroom over forecast operational and
potential acquisition expenditure for the 12 months following the
signing of the annual report for the period ended 31 December 2016
for the Company to be considered a going concern.
Consolidated statement of comprehensive income
For the period ended 31 December 2016
Notes 2016 2015
$m $m
-------------- ----------------
Revenue 190.7 343.9
Production costs 3 (35.1) (36.3)
Depreciation of oil assets 3 (127.8) (172.0)
Gross profit 27.8 135.6
Impairment of exploration assets 3 (779.0) (144.1)
Exploration expense 3 (36.1) (28.9)
Impairment of property, plant
and equipment 3 (218.3) (1,038.0)
Impairment of receivables 3 (191.3) -
General and administrative
costs 3 (26.0) (28.7)
Operating loss (1,222.9) (1,104.1)
Operating loss is comprised
of:
EBITDAX 130.7 279.4
Depreciation 3 (128.9) (172.5)
Impairment of exploration assets 3 (779.0) (144.1)
Exploration expense 3 (36.1) (28.9)
Impairment of property, plant
and equipment 3 (218.3) (1,038.0)
Impairment of receivables 3 (191.3) -
Gain arising from bond buy
back 15 19.2 -
Finance income 5 16.2 1.3
Finance expense 5 (61.0) (57.8)
Loss before income tax (1,248.5) (1,160.6)
Income tax expense 6 (0.4) (1.0)
Total comprehensive expense (1,248.9) (1,161.6)
-------------- ----------------
Attributable to:
Shareholders' equity (1,248.9) (1,161.6)
-------------- ----------------
(1,248.9) (1,161.6)
-------------- ----------------
Loss per ordinary share c c
Basic 7 (448.60) (417.30)
Diluted 7 (448.60) (417.30)
Consolidated balance sheet
At 31 December 2016
Notes 2016 2015
$m $m
--------- ---------
Assets
Non-current assets
Intangible assets 8 916.7 1,672.7
Property, plant and equipment 9 622.0 929.4
Trade and other receivables 10 172.6 365.3
--------- ---------
1,711.3 2,967.4
Current assets
Trade and other receivables 10 94.6 79.0
Restricted cash 11 19.5 -
Cash and cash equivalents 11 407.0 455.3
521.1 534.3
Total assets 2,232.4 3,501.7
---------
Liabilities
Non-current liabilities
Trade and other payables 12 (87.7) (78.0)
Deferred income 13 (39.2) (46.0)
Provisions 14 (23.0) (25.2)
Borrowings 15 (648.2) (694.1)
--------- ---------
(798.1) (843.3)
Current liabilities
Trade and other payables 12 (95.3) (80.6)
Deferred income 13 (5.6) (3.0)
---------
(100.9) (83.6)
Total liabilities (899.0) (926.9)
--------- ---------
Net assets 1,333.4 2,574.8
========= =========
Owners of the parent
Share capital 17 43.8 43.8
Share premium account 4,074.2 4,074.2
Retained earnings (2,784.6) (1,543.2)
--------- ---------
Total equity 1,333.4 2,574.8
Consolidated statement of changes in equity
For the period ended 31 December 2016
Total
Share Share Retained shareholders' Total
capital premium earnings equity NCI equity
$m $m $m $m $m $m
--------- --------- ---------- --------------- ------ ----------
At 1 January
2015 43.8 4,074.2 (392.3) 3,725.7 7.8 3,733.5
Total comprehensive
expense - - (1,161.6) (1,161.6) - (1,161.6)
Share-based payments - - 2.9 2.9 - 2.9
Release of NCI(1) - - 7.8 7.8 (7.8) -
At 31 December
2015 and
1 January 2016 43.8 4,074.2 (1,543.2) 2,574.8 - 2,574.8
Total comprehensive
expense - - (1,248.9) (1,248.9) - (1,248.9)
Share-based payments - - 7.5 7.5 - 7.5
At 31 December
2016 43.8 4,074.2 (2,784.6) 1,333.4 - 1,333.4
--------- --------- ---------- --------------- ------ ----------
(1) The non-controlling interest of $7.8m was released following
the expiry of the C shares of Genel Energy Holding Company
Limited.
Consolidated cash flow statement
For the period ended 31 December 2016
Notes 2016 2015
$m $m
---------- ------------------
Cash flows from operating
activities
Loss for the period (1,248.9) (1,161.6)
Adjustments for:
Gain on bond buy back 15 (19.2) -
Finance income 5 (16.2) (1.3)
Finance expense 5 61.0 57.8
Taxation 6 0.4 1.0
Depreciation and amortisation 3 128.9 172.5
Exploration expense 36.1 10.7
Impairment of exploration
assets 3 779.0 144.1
Impairment of property, plant
and equipment 3 218.3 1,038.0
Impairment of receivables 3 191.3 -
Other non-cash items 7.5 1.1
Changes in working capital:
Proceeds against overdue
receivable 53.9 -
Trade and other receivables (49.6) (190.2)
Trade and other payables
and provisions (13.2) (0.9)
---------- ------------------
Cash generated from operations 129.3 71.2
Interest received 2.0 1.0
Taxation paid (0.3) (1.0)
---------- ------------------
Net cash generated from operating
activities 131.0 71.2
Cash flows from investing
activities
Purchase of intangible assets (20.7) (130.2)
Purchase of property, plant
and equipment (51.2) (120.2)
Restricted cash 11 (19.5) -
Acquisition of intangibles - (3.9)
---------- ------------------
Net cash used in investing
activities (91.4) (254.3)
Cash flows from financing
activities
Repurchase of Company bonds 15 (35.4) -
Net proceeds from bond issuance - 196.2
Interest paid (52.0) (46.1)
---------- ------------------
Net cash generated from/(used
in) financing activities (87.4) 150.1
Net decrease in cash and cash
equivalents (47.8) (33.0)
Foreign exchange loss (0.5) (0.8)
Cash and cash equivalents
at 1st January 11 455.3 489.1
---------- ------------------
Cash and cash equivalents
at 31 December 11 407.0 455.3
---------- ------------------
Notes to the consolidated financial statements
1. Summary of significant accounting policies
1.1 Basis of preparation
The consolidated financial statements of Genel Energy Plc (the
Company) have been prepared in accordance with International
Financial Reporting Standards as adopted by the European Union and
interpretations issued by the IFRS Interpretations Committee
(together "IFRS") and are prepared under the historical cost
convention except as where stated and comply with Jersey company
law. The significant accounting policies are set out below and have
been consistently applied throughout the period.
Items included in the financial information of each of the
Company's entities are measured using the currency of the primary
economic environment in which the entity operates (the functional
currency). The consolidated financial statements are presented in
US dollars to the nearest million ($m) rounded to one decimal
place, except where otherwise indicated.
For explanation of the key judgements and estimates made by the
Company in applying the Company's accounting policies, refer to
significant accounting estimates and judgement on pages 23 and
25.
The Company provides non-Gaap measures to provide greater
understanding of its financial performance and financial position.
EBITDAX is presented in order for the users of the accounts to
understand the underlying cash profitability of the Company, which
excludes the impact of costs attributable to exploration activity,
which tend to be one-off in nature, and the non-cash costs relating
to depreciation, amortisation and impairments. Free cash flow is
presented in order to show the free cash flow generated that is
available for the Board to use to finance or invest in the
business. Net debt is reported in order for users of the accounts
to understand how much debt remains unpaid if the Company paid its
debt obligations from its available cash. There have been no
changes in related parties since year-end and there are not
significant seasonal or cyclical variations in the Company's total
revenues.
Going concern
At the time of approving the consolidated financial statements,
the directors have a reasonable expectation that the Company has
adequate resources to continue in operational existence for the 12
months from the balance sheet date and therefore its consolidated
financial statements have been prepared on a going concern
basis.
Foreign currency
Foreign currency transactions are translated into the functional
currency of the relevant entity using the exchange rates prevailing
at the dates of the transactions or at the balance sheet date where
items are re-measured. Foreign exchange gains and losses resulting
from the settlement of such transactions and from the translation
at period-end exchange rates of monetary assets and liabilities
denominated in foreign currencies are recognised in the statement
of comprehensive income within finance income or finance costs.
Consolidation
The consolidated financial statements consolidate the Company
and its subsidiaries. These accounting policies have been adopted
by all companies.
Subsidiaries
Subsidiaries are all entities over which the Company has
control. The Company controls an entity when it is exposed to, or
has rights to, variable returns from its involvement with the
entity and has the ability to affect those returns through its
power over the entity. Subsidiaries are fully consolidated from the
date on which control is transferred to the Company. They are
deconsolidated from the date that control ceases. Transactions,
balances and unrealised gains on transactions between companies are
eliminated.
Joint arrangements
Arrangements under which the Company has contractually agreed to
share control with another party, or parties, are joint ventures
where the parties have rights to the net assets of the arrangement,
or joint operations where the parties have rights to the assets and
obligations for the liabilities relating to the arrangement.
Investments in entities over which the Company has the right to
exercise significant influence but neither control nor joint
control are classified as associates.
The Company recognises its assets and liabilities relating to
its interests in joint operations, including its share of assets
held jointly and liabilities incurred jointly with other
partners.
Acquisitions
The Company uses the acquisition method of accounting to account
for business combinations. Identifiable assets acquired and
liabilities and contingent liabilities assumed in a business
combination are measured at their fair values at the acquisition
date. The Company recognises any non-controlling interest in the
acquiree at fair value at time of recognition or at the
non-controlling interest's proportionate share of net assets.
Acquisition-related costs are expensed as incurred.
Farm-in/farm-out
Farm-out transactions relate to the relinquishment of an
interest in oil and gas assets in return for services rendered by a
third party or where a third party agrees to pay a portion of the
Company's share of the development costs (cost carry). Farm-in
transactions relate to the acquisition by the Company of an
interest in oil and gas assets in return for services rendered or
cost-carry provided by the Company.
Farm-in/farm-out transactions undertaken in the development or
production phase of an oil and gas asset are accounted for as an
acquisition or disposal of oil and gas assets. The consideration
given is measured as the fair value of the services rendered or
cost-carry provided and any gain or loss arising on the
farm-in/farm-out is recognised in the statement of comprehensive
income. A profit is recognised for any consideration received in
the form of cash to the extent that the cash receipt exceeds the
carrying value of the associated asset.
Farm-in/farm-out transactions undertaken in the exploration
phase of an oil and gas asset are accounted for on a no gain/no
loss basis due to inherent uncertainties in the exploration phase
and associated difficulties in determining fair values reliably
prior to the determination of commercially recoverable proved
reserves. The resulting exploration and evaluation asset is then
assessed for impairment indicators under IFRS6.
1.2 Significant accounting judgements, estimates and
assumptions
The preparation of the financial statements in accordance with
IFRS requires the Company to make judgements and assumptions that
affect the reported results, assets and liabilities. Where
judgements and estimates are made, there is a risk that the actual
outcome could differ from the judgement or estimate made. The
Company has assessed the following as being areas where changes in
judgements, estimates or assumptions could have a significant
impact on the financial statements.
Estimation of future oil price
The estimation of future oil price has a significant impact
throughout the financial statements, primarily in relation to the
estimation of the recoverable value of property, plant and
equipment, intangible assets and trade receivables. It is also
relevant to the assessment of going concern and the viability
statement.
The Company's forecast of average Brent oil price for future
years is based on a range of publicly available market estimates
and is summarised in the table below, with the 2021 price then
inflated at 2% per annum.
$/bbl 2017 2018 2019 2020 2021
------------ ----- ----- ----- ----- -----
Forecast 55 60 68 72 76
------------ ----- ----- ----- ----- -----
Prior year
forecast 45 55 65 75 77
------------ ----- ----- ----- ----- -----
Estimation of hydrocarbon reserves and resources and associated
production profiles
Estimates of hydrocarbon reserves and resources are inherently
imprecise, require the application of judgement and are subject to
future revision. The Company's estimation of the quantum of oil and
gas reserves and resources and the timing of its production and
monetisation impact the Company's financial statements in a number
of ways, including: testing recoverable values for impairment; the
calculation of depreciation and amortisation; assessing the cost
and likely timing of decommissioning activity and associated costs;
and the carrying value of trade receivables. This estimation also
impacts the assessment of going concern and the viability
statement.
Proven and probable reserves are estimates of the amount of
hydrocarbons that can be economically extracted from the Company's
assets. The Company estimates its reserves using standard
recognised evaluation techniques. Proven and probable reserves
("2P" - generally accepted to have circa 50% probability) are used
for the assessment of the Company's assets classified as property,
plant and equipment and therefore form the basis of testing for
depreciation and testing for impairment. Under PRMS definition, 2P
reserves only refers to projects that are currently justified for
or are already in development.
Hydrocarbons that are not assessed as 2P are considered to be
resources and are classified as exploration and evaluation assets.
Estimates of resources for undeveloped or partially developed
fields are subject to greater uncertainty over their future life
than estimates of reserves for fields that are substantially
developed and being depleted.
As a field goes into production, the amount of proved reserves
will be subject to future revision once additional information
becomes available through, for example, the drilling of additional
wells or the observation of long-term reservoir performance under
producing conditions. As those fields are further developed, new
information may lead to revisions.
Assessment of reserves and resources are determined using
estimates of oil and gas in place, recovery factors and future
commodity prices, the latter having an impact on the total amount
of recoverable reserves.
Change in accounting estimate
The Company has updated its estimated reserves and resources
with the accounting impact summarised below under estimation of oil
and gas asset values and estimation of recoverable value of trade
receivables.
Estimation of oil and gas asset values
Estimation of the asset value of oil and gas assets is
calculated from a number of inputs that require varying degrees of
estimation. Principally oil and gas assets are valued by estimating
the future cash flows based on a combination of reserves and
resources, costs of appraisal, development and production,
production profile and future sales price and discounting those
cash flows at an appropriate discount rate.
Future costs of appraisal, development and production are
estimated taking into account the level of development required to
produce those reserves and are based on past costs, experience and
data from similar assets in the region, future petroleum prices and
the planned development of the asset. However, actual costs may be
different from those estimated.
Discount rate is assessed by the Company using various inputs
from market data, external advisers and internal calculations.
Discount rates used for impairment testing are disclosed in the
relevant note.
Change in accounting estimate - Oil assets (property, plant and
equipment)
In early 2017, the Company updated its estimation of the
reserves and production profiles of Taq Taq and Tawke and
commissioned an update of the Competent Persons Report for Taq Taq
and of the technical assessment for Tawke. This process has
resulted in an amendment to the estimated oil reserves at Taq Taq,
where estimated 2P oil reserves were reduced. These reserves
assessments were used, together with updated estimates for the
other components of the assessment, to perform impairment testing
on both assets. In addition, the discount rate used for impairment
testing of oil assets has increased from 12.5% to 15%. This
increase reflects market perception of a sustained increase in KRI
risk given continued political and financial uncertainty. The
calculated present values of the assets have resulted in an
impairment expense of $218.3 million. Sensitivities to oil price,
discount rate and production are provided in note 9.
Change in accounting estimate - Gas assets (intangible
assets)
The gas assets have been tested for impairment as a result of a
revision to the assumed date of project sanction and phasing
together with updated cost estimates. The combination of these
factors has resulted in both a reduction and delay in the timing of
the cash flows associated with the asset and a consequent reduction
in its carrying value. In addition, the estimate of the discount
rate used for impairment testing of gas assets has increased from
12.5% to 15%. This increase reflects investor perception of a
sustained increase in both Turkish and KRI risk given the continued
political and financial uncertainty in both countries. The revised
estimates and assumptions have resulted in an impairment expense of
$581.3 million. Sensitivities to oil price and discount rate are
provided in note 8.
Estimation of netback price and entitlement used to calculate
reported revenue, trade receivables and forecast future cash
flows
Netback price is used to value the Company's revenue, trade
receivables and its forecast cash flows used for impairment testing
and viability. The Company does not have direct visibility on the
components of the netback price because sales are managed by the
KRG, but invoices are currently raised for payments on account
using a netback price that has been temporarily agreed with the KRG
for the purpose of receiving interim payments. For revenue
recognition, the Company has estimated the netback price using the
methodology agreed with the KRG for receiving these payments on
account.
In line with its IOC payment process that began in September
2015 and was given structure by its announcement on 1 February
2016, the KRG has commenced an audit of cost, production and
revenue, including detailed analysis of the components of netback.
The Company expects to then reach agreement with the KRG on the
appropriate netback adjustment to use in the calculation of the
Company's entitlement under the PSC and the resulting trade
receivable balance. The audit and reconciliation process began this
year, but is not complete and may take some time and conversations
with the KRG are ongoing.
The outputs of the reconciliation and settlement process may
result in changes to the estimates made by the Company. A $1/bbl
difference in netback price would impact current year revenue by
circa $4 million and trade receivables by circa $4 million.
Estimation of the recoverable value of trade receivables
Trade receivables of $253.5 million relates to money owed by the
KRG principally for export sales that were made after mid-2014. The
KRG has stated publicly on a consistent basis that it intends to
pay full entitlement following a reconciliation process.
When assessing the nominal value of the receivable the Company
has taken into account the latest information on the entitlement it
is owed under the PSC for oil that has been sold but not yet paid
for. In addition, a calculation has been made for the interest that
has accrued on the balance under the terms of the PSC at LIBOR plus
2%. The Company has excluded consideration of any value for export
sales that were made before mid-2014 (including exports marketed by
the State Oil Marketing Organisation ("SOMO") where payment is
outstanding). The total unrecognised receivable balance relating to
these sales excluding interest is estimated at circa $300m.
The Company expects that ultimately a reconciliation calculating
full entitlement under the terms of the PSC will be agreed with the
KRG - this reconciliation will form the basis for calculating
amounts owed and for agreeing a mechanism to settle the
balance.
Subject to the reconciliation process that has been started by
the KRG, the Company is fully confident of its contractual right to
the nominal value of the receivable. The Company expectation is
that it will be settled with cash, although it is possible that the
debt could be settled in a number of ways such as with assets or
through an improvement in future contractual terms. The success and
pace of the recovery of the balance depends on some or all of a
number of factors, including: the financial environment in the KRI
and the financial budget of the KRG; oil price; volumes of
production from the KRI as a whole as well as from the Company's
fields; and ongoing negotiations with regard to various sources of
potential finance for the KRI.
On 1 February 2016, the KRG announced an interim mechanism to
make monthly payments to the IOCs. The mechanism has two
components: the first component is a proxy for monthly entitlement
due under the terms of the PSC; the second component is intended to
contribute towards repayment of the receivable. The contribution
towards the receivable was set at and currently remains at 5% of
field revenue. The KRG stated that it intends to increase this
percentage as the oil price improves.
Previously when assessing the recoverable value of the
receivable, the Company assessed that the percentage of field
revenue paid towards the receivable would be increased to 10% from
July 2017 and to 20% from January 2018.
Whilst the KRG made the current 5% payments relatively
consistently over the current year and at half year was broadly up
to date, by year-end payments were two months in arrears against
the agreed schedule. In addition, contrary to the KRG's stated
intention to increase payments, there has been no increase in
payments despite oil price increasing from $30/bbl in February 2016
to over $50/bbl. Although the Company expects either an increase in
payments, or an alternative structure to be agreed to accelerate
the recovery of the receivable, the Company has assessed that there
is not sufficient evidence to offset existing contrary evidence and
support the use of these expectations as assumptions for impairment
testing. Consequently the Company has used the current basis of
payment of 5% of field revenue for the purposes of assessing
impairment and does not currently take into account the potential
for increased payments or alternative methods of settling the
balance.
The carrying value of trade receivables is compared to the
present value of the forecast monthly contributions using the
effective interest rate for the period in which the revenue was
recognised. For the period over which the receivable was
recognised, the Company has assessed the effective interest rate to
be between 8% and 13% using an adjusted prevailing Iraqi government
2028 bond as a proxy, resulting in a blended rate of 8.3%.
Change in accounting estimate
As explained above, for the purposes of impairment testing the
Company has assumed the percentage of field revenue paid towards
the receivable is fixed at the current mechanism of 5%. When
combined with the updated production, reserves and oil price
outlook this resulted in an impairment of $191.3 million.
Business combinations
The recognition of business combinations requires the excess of
the purchase price of acquisitions over the net book value of
assets acquired to be allocated to the assets and liabilities of
the acquired entity. The Company makes judgements and estimates in
relation to the fair value allocation of the purchase price.
The fair value exercise is performed at the date of acquisition.
Owing to the nature of fair value assessments in the oil and gas
industry, the purchase price allocation exercise and
acquisition-date fair value determinations require subjective
judgements based on a wide range of complex variables at a point in
time. The Company uses all available information to make the fair
value determinations.
In determining fair value for acquisitions, the Company utilises
valuation methodologies including discounted cash flow analysis.
The assumptions made in performing these valuations include
assumptions as to discount rates, foreign exchange rates, commodity
prices, the timing of development, capital costs, and future
operating costs. Any significant change in key assumptions may
cause the acquisition accounting to be revised.
1.3 Accounting policies
Revenue
Revenue for petroleum sales is recognised when the significant
risks and rewards of ownership are deemed to have passed to the
customer, it can be measured reliably and it is assessed as
probable that economic benefit will flow to the Company. For
exports this is when the oil enters the export pipe, for domestic
sales this is when oil is collected by truck by the customer.
Revenue is recognised at fair value. The fair value is comprised
of entitlement due under the terms of the PSC and royalty income.
Entitlement has two components: cost oil, which is the mechanism by
which the Company recovers its costs incurred on an asset, and
profit oil, which is the mechanism through which profits are shared
between the Company, its partners and the KRG. The Company pays
capacity building payments on profit oil, which becomes due for
payment once the Company has received the relevant proceeds. Profit
oil revenue is always reported net of any capacity building
payments that will become due. Royalty income is earned on partner
sales from the Taq Taq field and is recognised when it becomes due
or, when received in advance, amortised in line with partner
entitlement.
The Company's oil sales are made to the KRG and are valued at a
netback price, which is calculated from the estimated realised
sales price for each barrel of oil sold, less selling,
transportation and handling costs and estimates to cover additional
costs. A netback adjustment is used to estimate the price per
barrel that is used in the calculation of entitlement and is
explained further in significant accounting estimates and
judgements.
Income tax arising from the Company's activities under
production sharing contracts is settled by a third party at no cost
and on behalf of the Company. However the Company is not able to
measure the tax that has been paid on its behalf and consequently
revenue is not reported gross of income tax paid.
Intangible assets
Exploration and evaluation assets
Oil and gas assets classified as exploration and evaluation
assets are explained under Oil and Gas assets below.
Other intangible assets
Other intangible assets (predominately software) that are
acquired by the Company are stated at cost less accumulated
amortisation and less accumulated impairment losses. Amortisation
is expensed on a straight-line basis over the estimated useful
lives of the assets of between 3 and 5 years from the date that
they are available for use.
Property, plant and equipment
The Company's oil and gas assets classified as property, plant
and equipment are explained under Oil and Gas assets below.
Other property, plant and equipment
Other property, plant and equipment are principally the
Company's leasehold improvements and other assets and are carried
at cost, less any accumulated depreciation and accumulated
impairment losses. Costs include purchase price and construction
cost. Depreciation of these assets commences is expensed on a
straight-line basis over their estimated useful lives of between 3
and 5 years from the date they are available for use.
Oil and gas assets
Costs incurred prior to obtaining legal rights to explore are
expensed to the statement of comprehensive income.
Exploration, appraisal and development expenditure is accounted
for under the successful efforts method. Under the successful
efforts method only costs that relate directly to the discovery and
development of specific oil and gas reserves are capitalised as
exploration and evaluation assets within intangible assets. Costs
of activity that do not identify oil and gas reserves are
expensed.
All lease and licence acquisition costs, geological and
geophysical costs and other direct costs of exploration, evaluation
and development are capitalised as intangible assets or property,
plant and equipment according to their nature. Intangible assets
comprise costs relating to the exploration and evaluation of
properties which the directors consider to be unevaluated until
assessed as being 2P reserves and commercially viable.
Once assessed as being 2P reserves they are tested for
impairment and transferred to property, plant and equipment as
development assets. Where properties are appraised to have no
commercial value, the associated costs are expensed as an
impairment loss in the period in which the determination is
made.
Development expenditure is accounted for in accordance with IAS
16-Property, plant and equipment. Assets are depreciated once they
are available for use and are depleted on a field-by-field basis
using the unit of production method. The sum of carrying value and
the estimated future development costs are divided by total
forecast 2P production to provide a $/barrel unit depreciation
cost. Changes to depreciation rates as a result of changes in
reserve quantities and estimates of future development expenditure
are reflected prospectively.
The estimated useful lives of property, plant and equipment and
their residual values are reviewed on an annual basis and changes
in useful lives are accounted for prospectively. The gain or loss
arising on the disposal or retirement of an asset is determined as
the difference between the sales proceeds and the carrying amount
of the asset and is recognised in the statement of comprehensive
income for the relevant period.
Where exploration licences are relinquished or exited for no
consideration or costs incurred are neither derisking nor adding
value to the asset, the associated costs are expensed to the income
statement.
Subsequent costs
The cost of replacing part of an item of property and equipment
is recognised in the carrying amount of the item if it is probable
that the future economic benefits embodied within the part will
flow to the Company, and its cost can be measured reliably. The net
book value of the replaced part is expensed. The costs of the
day-to-day servicing and maintenance of property, plant and
equipment are recognised in the statement of comprehensive
income.
Leases
Leases in which a significant portion of the risks and rewards
of ownership are retained by the lessor are classified as operating
leases. Payments made under operating leases (net of any incentives
received from the lessor) are expensed to the statement of
comprehensive income on a straight-line basis over the period of
the lease.
Financial assets and liabilities
Classification
The Company assesses the classification of its financial assets
on initial recognition as either at fair value through profit and
loss, loans and receivables or available for sale. The Company
assesses the classification of its financial liabilities on initial
recognition at either fair value through profit and loss or
amortised cost.
Recognition and measurement
Regular purchases and sales of financial assets are recognised
at fair value on the trade-date - the date on which the Company
commits to purchase or sell the asset. Loans and receivables are
subsequently carried at amortised cost using the effective interest
method.
Trade and other receivables
Trade receivables are amounts due from crude oil sales, sales of
gas or services performed in the ordinary course of business. If
payment is expected within one year or less, trade receivables are
classified as current assets otherwise they are presented as
non-current assets. Trade receivables are recognised initially at
fair value and subsequently measured at amortised cost using the
effective interest method, less provision for impairment.
Cash and cash equivalents
In the consolidated balance sheet and consolidated statement of
cash flows, cash and cash equivalents includes cash in hand,
deposits held on call with banks, other short-term highly liquid
investments and includes the Company's share of cash held in joint
operations.
Interest-bearing borrowings
Borrowings are recognised initially at fair value, net of any
discount in issuance and transaction costs incurred. Borrowings are
subsequently carried at amortised cost; any difference between the
proceeds (net of transaction costs) and the redemption value is
recognised in the statement of comprehensive income over the period
of the borrowings using the effective interest method.
Fees paid on the establishment of loan facilities are recognised
as transaction costs of the loan to the extent
that it is probable that some or all of the facility will be
drawn down. In this case, the fee is deferred until the draw-down
occurs. To the extent there is no evidence that it is probable that
some or all of the facility will be drawn down, the fee is
capitalised as a pre-payment for liquidity services and amortised
over the period of the facility to which it relates.
Borrowings are presented as long or short-term based on the
maturity of the respective borrowings in accordance with the loan
or other agreement. Borrowings with maturities of less than twelve
months are classified as short-term. Amounts are classified as
long-term where maturity is greater than twelve months. Where no
objective evidence of maturity exists, related amounts are
classified as short-term.
Trade and other payables
Trade and other payables are recognised initially at fair value.
Subsequent to initial recognition they are measured at amortised
cost using the effective interest method.
Provisions
Provisions are recognised when the Company has a present
obligation as a result of a past event, and it is probable that the
Company will be required to settle that obligation. Provisions are
measured at the Company's best estimate of the expenditure required
to settle the obligation at the balance sheet date, and are
discounted to present value where the effect is material. The
unwinding of any discount is recognised as finance costs in the
statement of comprehensive income.
Decommissioning
Provision is made for the cost of decommissioning assets at the
time when the obligation to decommission arises. Such provision
represents the estimated discounted liability for costs which are
expected to be incurred in removing production facilities and site
restoration at the end of the producing life of each field. A
corresponding cost is capitalised to property, plant and equipment
and subsequently depreciated as part of the capital costs of the
production facilities. Any change in the present value of the
estimated expenditure attributable to changes in the estimates of
the cash flow or the current estimate of the discount rate used are
reflected as an adjustment to the provision.
Offsetting
Financial assets and liabilities are offset and the net amount
reported in the balance sheet when there is a legally enforceable
right to offset the recognised amounts and there is an intention to
settle on a net basis or realise the asset and settle the liability
simultaneously.
Impairment
Oil and gas assets
The carrying amounts of the Company's oil and gas assets are
reviewed at each reporting date to determine whether there is any
indication of impairment. If any such indication exists then the
asset's recoverable amount is estimated.
The recoverable amount of an asset or cash-generating unit is
the greater of its value in use and its fair value less costs of
disposal. For value in use, the estimated future cash flows arising
from the Company's future plans for the asset are discounted to
their present value using a pre-tax discount rate that reflects
market assessments of the time value of money and the risks
specific to the asset. For fair value less costs of disposal, an
estimation is made of the fair value of consideration that would be
received to sell an asset less associated selling costs.
For the purpose of impairment testing, assets are grouped
together into the smallest group of assets that generates cash
inflows from continuing use that are largely independent of the
cash inflows of other assets or groups of assets (cash generating
unit).
The estimated recoverable amount is then compared to the
carrying value of the asset. Where the estimated recoverable amount
is materially lower than the carrying value of the asset an
impairment loss is recognised if the carrying amount of an asset or
its cash-generating unit exceeds its recoverable amount.
Non-financial assets that suffered impairment are reviewed for
possible reversal of the impairment at each reporting date.
Property, plant and equipment and intangible assets
Impairment testing of oil and gas assets is explained above.
When impairment indicators exist for other non-financial assets,
impairment testing is performed based on the higher of value in use
and fair value less costs to sell.
Financial assets
A financial asset is assessed at each reporting date to
determine whether there is any objective evidence that it is
impaired. A financial asset is considered to be impaired if
objective evidence indicates that one or more events have had a
negative effect on the estimate of future cash flows of that asset.
An impairment loss in respect of a financial asset measured at
amortised cost is calculated as the difference between its carrying
amount, and the present value of the estimated future cash flows
discounted at the original effective interest rate. All impairment
losses are recognised as an expense in the statement of
comprehensive income.
An impairment loss is reversed if the reversal can be related
objectively to an event occurring after the impairment loss was
recognised.
Explanation of impairment testing of trade receivables is
provided under significant accounting estimates and judgements.
Share capital
Ordinary shares are classified as equity.
Employee benefits
Short-term benefits
Short-term employee benefit obligations are expensed to the
statement of comprehensive income as the related service is
provided. A liability is recognised for the amount expected to be
paid under short-term cash bonus or profit-sharing plans if the
Company has a present legal or constructive obligation to pay this
amount as a result of past service provided by the employee and the
obligation can be estimated reliably.
Share-based payments
The Company operates a number of equity-settled, share-based
compensation plans. The economic cost of awarding shares and share
options to employees is recognised as an expense in the statement
of comprehensive income equivalent to the fair value of the benefit
awarded. The fair value is determined by reference to option
pricing models, principally Monte Carlo and adjusted Black-Scholes
models. The charge is recognised in the statement of comprehensive
income over the vesting period of the award.
At each balance sheet date, the Company revises its estimate of
the number of options that are expected to become exercisable. Any
revision to the original estimates is reflected in the statement of
comprehensive income with a corresponding adjustment to equity
immediately to the extent it relates to past service and the
remainder over the rest of the vesting period.
Finance income and finance costs
Finance income comprises interest income on cash invested,
foreign currency gains and the unwind of discount on any assets
held at amortised cost. Interest income is recognised as it
accrues, using the effective interest method.
Finance expense comprises interest expense on borrowings,
foreign currency losses and discount unwind on any liabilities held
at amortised cost. Borrowing costs directly attributable to the
acquisition of a qualifying asset as part of the cost of that asset
are capitalised over the respective assets.
Taxation
Under the terms of the KRI PSCs, the Company is not required to
pay any cash taxes although it is uncertain whether the Company is
exempt from tax or whether tax has been paid on its behalf. If tax
has been paid on its behalf by the government, then it is not known
at what rate tax has been paid due to uncertainty in relation to
the workings of any existing tax payment mechanism. It is estimated
that the tax rate would be between 0% and 40%. If tax has been paid
it would result in a gross up of revenue with a corresponding debit
entry to taxation expense with no net impact on the income
statement or on cash. In addition, it would be assessed whether any
deferred tax asset or liability was required to be recognised.
Segmental reporting
IFRS8 requires the Company to disclose information about its
business segments and the geographic areas in which it operates. It
requires identification of business segments on the basis of
internal reports that are regularly reviewed by the CEO, the chief
operating decision maker, in order to allocate resources to the
segment and assess its performance.
Related parties
Parties are related if one party has the ability, directly or
indirectly, to control the other party or exercise significant
influence over the party in making financial or operational
decisions. Parties are also related if they are subject to common
control. Transactions between related parties are transfers of
resources, services or obligations, regardless of whether a price
is charged and are disclosed separately within the notes to the
consolidated financial information.
New standards
Effective 1 January 2016, the Company has adopted the following
amendments to standards: Annual improvements to IFRSs 2012-2014
Cycle; Amendments to IFRS 10 Consolidated Financial Statements;
Amendments to IFRS 11 Joint Arrangements; Amendments to IFRS 12
Disclosure of Interests in Other Entities; Amendments to IAS 1
Presentation of Financial Statements; Amendments to IAS 16
Property, Plant and Equipment; Amendments to IAS 27 Separate
Financial Statements; Amendments to IAS 28 Investments in
Associates and Joint Ventures; Amendments to IAS 38 Intangible
Assets. The adoption of these amendments has had no material impact
on the Company's results or financial statement disclosures.
The following new standards issued by the IASB and endorsed by
the EU have yet to be adopted by the Group: IFRS 9 Financial
Instruments (effective 1 January 2018); IFRS 15 Revenue from
Contracts with Customers (effective 1 January 2018). The Company's
review of IFRS15 and IFRS9 is underway but is not yet completed,
with neither currently expected to have a material impact on the
results or financial statements of the Company.
The following new accounting standards and amendments to
existing standards have been issued but are not yet effective and
have not yet been endorsed by the EU: IFRS 16 Leases (effective 1
January 2019); Amendments to IFRS 2 Share Based Payments (effective
1 January 2018); Amendments to IAS 7 Statement of Cash Flows
(effective 1 January 2017); Amendments to IAS 12 Income Taxes
(effective 1 January 2017); Clarifications to IFRS 15 Revenue from
Contracts with Customers (effective 1 January 2018). The Company is
currently assessing the impact of adopting the new accounting
standards noted above on its audited consolidated financial
statements. The Group has not early adopted any other standard,
amendment or interpretation that was issued but is not yet
effective.
2. Segmental information
The Company has three reportable business segments: oil, gas and
exploration. Capital expenditure decisions for the oil segment are
considered in the context of the cash flows expected from the
production and sale of crude oil. The segments have been changed
from geographical to asset type in order to better reflect how the
Chief Operating Decision Maker now considers the deployment of
capital. The oil segment is comprised of the producing assets, Taq
Taq and Tawke, which are located in the KRI and make predominantly
all sales to the KRG; the gas segment is comprised of the upstream
and midstream activity on Miran and Bina Bawi also in the KRI; the
exploration segment is comprised of the company's exploration
activity, principally located in the KRI, Somaliland and
Morocco.
For the period ended 31 December 2016
Oil Gas Expl. Other Total
$m $m $m $m $m
Revenue 190.7 - - - 190.7
Cost of sales (162.9) - - - (162.9)
-------- -------- -------- -------- ----------
Gross profit 27.8 - - - 27.8
Exploration expense - (0.7) (35.4) - (36.1)
Impairment of exploration
assets - (581.3) (197.7) - (779.0)
Impairment of property,
plant and equipment (218.3) - - - (218.3)
Impairment of receivables (191.3) - - - (191.3)
General and administrative
costs - - - (26.0) (26.0)
-------- -------- -------- -------- ----------
Operating loss (381.8) (582.0) (233.1) (26.0) (1,122.9)
Operating loss is comprised
of
EBITDAX 155.7 - - (25.0) 130.7
Depreciation (127.9) - - (1.0) (128.9)
Exploration expense - (0.7) (35.4) - (36.1)
Impairment of exploration
assets - (581.3) (197.7) - (779.0)
Impairment of property,
plant and equipment (218.3) - - - (218.3)
Impairment of receivables (191.3) - - - (191.3)
----------------------------- -------- -------- -------- -------- ----------
Gain arising from bond
buy back - - - 19.2 19.2
Finance income 14.3 - - 1.9 16.2
Finance expense (1.1) (0.1) - (59.8) (61.0)
Loss before tax (368.6) (582.1) (233.1) (64.7) (1,248.5)
Capital expenditure 40.6 12.1 8.5 - 61.2
Total assets 933.1 872.5 59.7 367.1 2,232.4
Total liabilities (93.3) (97.9) (47.3) (660.5) (899.0)
Total assets and liabilities in the other segment are
predominantly cash and debt balances. 'Other' includes corporate
assets, liabilities and costs, elimination of intercompany
receivables and intercompany payables, which are non-segment
items.
For the period ended 31 December 2015
Restated(1) Restated(1) Restated(1) Restated(1) Restated(1)
Oil Gas Expl. Other Total
$m $m $m $m $m
-------------- ------------ ------------ ------------ --------------
Revenue 343.9 - - - 343.9
Cost of sales (208.3) - - - (208.3)
-------------- ------------ ------------ ------------ --------------
Gross profit 135.6 - - - 135.6
Exploration expense - - (28.9) - (28.9)
Impairment of exploration
assets - - (144.1) - (144.1)
Impairment of property,
plant and equipment (1,038.0) - - - (1,038.0)
General and administrative
costs (2.6) - - (26.1) (28.7)
-------------- ------------ ------------ ------------ --------------
Operating loss (905.0) - (173.0) (26.1) (1,104.1)
Operating loss is
comprised of
EBITDAX 305.0 - - (25.6) 279.4
Depreciation (172.0) - - (0.5) (172.5)
Exploration expense - - (28.9) - (28.9)
Impairment of exploration
assets - - (144.1) - (144.1)
Impairment of property,
plant and equipment (1,038.0) - - - (1,038.0)
---------------------------- -------------- ------------ ------------ ------------ --------------
Finance income - - - 1.3 1.3
Finance expense (0.9) (0.1) - (56.8) (57.8)
Loss before tax (905.9) (0.1) (173.0) (81.6) (1,160.6)
-------------- ------------ ------------ ------------ --------------
Capital expenditure 109.2 18.3 29.7 - 157.2
Total assets 1,438.2 1,430.5 256.1 376.9 3,501.7
Total liabilities (105.5) (87.5) (23.4) (710.5) (926.9)
(1) The Company has changed its assessment of segments as
explained above and consequently has restated its prior year
segmental reporting.
Total assets and liabilities in the other segment are
predominantly cash and debt balances. 'Other' includes corporate
assets, liabilities and costs, elimination of intercompany
receivables and intercompany payables, which are non-segment items.
All of the oil and gas segments are located in the KRI, with the
exploration segment located principally in the KRI, Somaliland and
Morocco. All revenue relates to sales made to the KRG.
3. Operating costs
2016 2015
$m $m
--------- ------------
Production costs 35.1 36.3
Depreciation and amortisation of
oil and gas assets 127.8 172.0
Cost of sales 162.9 208.3
--------- ------------
Impairment of exploration assets 779.0 144.1
Exploration expense 36.1 28.9
--------- ------------
Exploration costs 815.1 173.0
--------- ------------
Impairment of property, plant and
equipment (note 9) 218.3 1,038.0
Impairment of receivables (note
10) 191.3 -
--------- ------------
Corporate cash costs 17.4 26.7
Corporate share based payment expense 7.5 1.5
Depreciation and amortisation of
corporate assets 1.1 0.5
--------- ------------
General and administrative expenses 26.0 28.7
--------- ------------
Depreciation has reduced as a result of a lower
carrying value of assets and lower production
volumes, offset by an increase in estimates
of future capital expenditure. Corporate cash
costs have reduced as a result of restructuring
programmes. The expensing of the cost of share
based payments and depreciation and amortisation
of corporate assets has increased as a result
of reduced capitalisation because of reduced
capital activity. Impairment of exploration
assets is explained in note 8. Exploration
expense relates to accruals for costs or obligations
relating to licences where there is ongoing
activity or that have been, or are in the process
of being, relinquished.
Fees payable to the Company's auditors: 2016 2015
$m $m
---- ----
Audit of consolidated financial
statements and subsidiary accounts 0.4 0.4
Tax and advisory services 0.1 0.2
Total fees 0.5 0.6
---- ----
4. Staff costs and headcount
2016 2015
$m $m
---- ----
Wages and salaries 20.9 38.1
Social security costs 1.2 2.9
Share based payments 7.5 2.7
---- ----
29.6 43.7
---- ----
Reduction in staff costs caused by the restructuring
programme have been partly offset by a normalised
share based payment charge following the reversal
of previously expensed costs due to the lapsing
of options associated with leavers. Average
headcount was:
2016 2015
Turkey 73 102
KRI 19 25
UK 21 32
Somaliland 24 24
--------- ------------
137 183
--------- ------------
5. Finance expense and income
2016 2015
$m $m
------ ------
Bond interest payable (51.0) (50.1)
Unwind of discount on liabilities (10.0) (7.7)
------ ------
Finance expense (61.0) (57.8)
------ ------
Bank interest income 2.0 1.3
Unwind of discount on trade receivables 14.2 -
Finance income 16.2 1.3
------ ------
Annual bond interest has increased because there has been a full
year of interest payable on the $230 million nominal value of bonds
issued in March 2015, offset by the buyback of $55.4m nominal value
of bonds in March 2016 (see note 15).
6. Taxation
A taxation charge of $0.4 million (2015: $1.0 million) was made
in the Turkish and UK services companies. All other corporation tax
due has been paid on behalf of the Company by the government from
the government's share of revenues and there is no tax payment
required or expected to be made by the Company.
Under the terms of the KRI PSCs, the Company is not required to
pay any cash taxes although it is uncertain whether the Company is
exempt from tax or whether tax has been paid on its behalf. If tax
has been paid on its behalf by the government, then it is not known
at what rate tax has been paid due to uncertainty in relation to
the workings of any existing tax payment mechanism. It is estimated
that the tax rate would be between 0% and 40%. If tax has been paid
it would result in a gross up of revenue with a corresponding debit
entry to taxation expense with no net impact on the income
statement or on cash. In addition, it would be assessed whether any
deferred tax asset or liability was required to be recognised.
7. Earnings per share
Basic
Basic earnings per share is calculated by dividing the profit
attributable to equity holders of the Company by the weighted
average number of shares in issue during the period.
2016 2015
----------- -----------
Loss attributable to equity holders
of the Company ($m) (1,248.9) (1,161.6)
Weighted average number of ordinary
shares - number (1) 278,395,190 278,351,746
Basic earnings per share - cents
per share (448.60) (417.30)
(1) Excluding the purchase of own shares now held as treasury
shares
Diluted
Because the Company reported a loss in both years, diluted EPS
is anti-dilutive and therefore diluted EPS is the same as basic
EPS.
2016 2015
----------- -----------
Loss attributable to equity holders
of the Company ($m) (1,248.9) (1,161.6)
Weighted average number of ordinary
shares - number(1) 278,395,190 278,351,746
Adjustment for performance shares,
restricted shares and share options 1,853,008 1,896,452
Total number of shares 280,248,198 280,248,198
Diluted earnings per share - cents
per share (448.60) (417.30)
(1) Excluding the purchase of own shares now held as treasury
shares
8. Intangible assets
Exploration
and evaluation Other
assets assets Total
$m $m $m
--------------- ------- -------
Cost
At 1(st) January 2015 1,676.6 5.8 1,682.4
Acquisitions 101.0 - 101.0
Additions 48.0 0.5 48.5
Other 2.4 - 2.4
Exploration costs written
off (144.1) - (144.1)
Transfer to property,
plant and equipment (note
9) (12.9) - (12.9)
--------------- ------- -------
Balance at 31 December
2015 and 1(st) January
2016 1,671.0 6.3 1,677.3
Additions 20.9 - 20.9
Discount unwind of contingent
consideration 9.8 - 9.8
Impairment of exploration
assets and transfer to
assets held for sale (199.7) - (199.7)
Exploration costs written
off (4.6) - (4.6)
Balance at 31 December
2016 1,497.4 6.3 1,503.7
Accumulated amortisation
and impairment
At 1(st) January 2015 - (3.1) (3.1)
Amortisation charge for
the period - (1.5) (1.5)
--------------- ------- -------
At 31 December 2015 and
1 January 2016 - (4.6) (4.6)
Amortisation charge for
the period - (1.1) (1.1)
Impairment of gas assets (581.3) - (581.3)
--------------- ------- -------
At 31 December 2016 (581.3) (5.7) (587.0)
--------------- ------- -------
Net book value
At 31(st) December 2016 916.1 0.6 916.7
At 31(st) December 2015 1,671.0 1.7 1,672.7
--------------- ------- -------
Exploration and evaluation assets are principally: the Company's
PSC interests in exploration and appraisal assets in the Kurdistan
Region of Iraq, comprised of the Miran (book value: $528.6 million,
2015: $754.9 million) and Bina Bawi (book value: $338.4 million,
2015: $671.9 million) gas assets; and its interest in licences in
Somaliland. Impairment of Miran and Bina Bawi is explained in
significant accounting estimates and judgements in note 1. In
addition, costs of $197.7 million have been written off in relation
to the Chia Surkh licence following the drilling of CS-12. The
Company has agreed to sell the asset for an initial consideration
of $2.0 million, with further consideration of up to $25 million
contingent on the asset achieving specified production milestones -
completion is conditional on KRG consent being obtained. The
balance has been transferred to assets held for sale within
debtors. The net book value of $0.6 million (2015: $1.7 million) of
other assets is principally software.
Sensitivities
Miran Bina Bawi
$m $m
------------------------ ---------- ----------
Brent +/- $10/bbl 69 / (74) 14 / (14)
141 / 127 /
Discount rate +/- 2.5% (106) (93)
------------------------ ---------- ----------
9. Property, plant and equipment
Oil and Other
gas assets assets Total
$m $m $m
------------- --------- ----------
Cost
At 1(st) January 2015 2,432.8 9.2 2,442.0
Additions 109.2 - 109.2
Transfer from intangible assets
(see note 8) 12.9 - 12.9
Other 4.0 (0.3) 3.7
At 31 December 2015 and 1(st)
January 2016 2,558.9 8.9 2,567.8
Addition 40.3 - 40.3
At 31 December 2016 2,599.2 8.9 2,608.1
Accumulated depreciation and
impairment
At 1(st) January 2015 (422.1) (4.7) (426.8)
Depreciation charge for the
period (172.0) (1.6) (173.6)
Impairment (1,038.0) - (1,038.0)
------------- --------- ----------
At 31 December 2015 and 1(st)
January 2016 (1,632.1) (6.3) (1,638.4)
Depreciation charge for the
period (127.8) (1.6) (129.4)
Impairment (218.3) - (218.3)
At 31 December 2016 (1,978.2) (7.9) (1,986.1)
------------- --------- ----------
Net book value
At 31 December 2016 621.0 1.0 622.0
At 31 December 2015 926.8 2.6 929.4
------------- --------- ----------
Oil and gas assets comprise principally the Company's share of
oil assets at the Taq Taq and Tawke producing fields in the
Kurdistan Region of Iraq. Impairment of Taq Taq and Tawke is
explained in significant accounting estimates and judgements in
note 1.
Sensitivities
Taq Taq Tawke
$m $m
----------------------------- -------- -------
Carrying value 140 481
Long term Brent +/- $10/bbl +/- 8 +/- 24
Discount rate +/- 2.5% +/- 9 +/- 40
Production and reserves
+/- 10% +/- 16 +/- 36
----------------------------- -------- -------
10. Trade and other receivables
2016 2015
$m $m
------ ------
Trade receivables - non current 172.6 365.3
Trade receivables - current 80.9 57.6
Other receivables and prepayments 13.7 21.4
267.2 444.3
------ ------
Trade receivables are monies owed by the KRG for export sales
made via the KRG pipeline since mid-2014. The total amount owed by
the KRG is estimated to be $515.9 million. For the significant
balance that is overdue, caused by non-payment in the past, the
Company has calculated its carrying value assuming the percentage
of field revenue paid towards the receivable is fixed at the
current mechanism of 5%. This assumption has been combined with
updated production, reserves and oil price outlook, resulting in
the carrying value of trade receivables being $253.5 million.
Further information is provided in in the significant accounting
estimates and judgements in note 1.
Ageing of trade receivables
Under the terms of the PSC, payment is due within 30 days.
Proceeds received are allocated between current and past sales in
accordance with the allocation provided by the KRG under the
current payment mechanism. Proceeds allocated to the receivable are
allocated on a first-in-first-out basis.
Year of sale
Period ended 31 December of
2016 amounts overdue
--------------------
Not due 2016 2015 2014 Total
$m $m $m $m $m
--- ------- ------ ----- ----- -----
Trade receivables at 31
December 2016 17 30 - 207 254
------- ------ ----- ----- -----
Year of sale
Year-ended 31 December 2015 of amounts overdue
---------------------
Not 2015 2014 Total
due
$m $m $m $m
---- ---------- --------- -----
Trade receivables at 31
December 2015 23 168 232 423
---- ---------- --------- -----
Movement on trade receivables in the period
2016 2015
$m $m
-------- --------
Carrying value at 1 January 422.9 232.9
Revenue excl. royalty 186.2 338.6
Net proceeds (182.8) (148.2)
Discount unwind 14.2 -
Impairment (191.3) -
Other 4.3 (0.4)
-------- --------
Carrying value at period end 253.5 422.9
-------- --------
Recovery of the carrying value of the receivable
Explanation of the assumptions and estimates in testing the KRG
receivable for impairment are provided in note 1. The estimated
recovery of the carrying value of the receivable based on the
existing mechanism is summarised in the following table, which
summarises the cash flows arising on payments being received based
on 5% of field revenue:
2017 2018 2019 2020+ Total
----- ----- ----- ------ ------
Nominal balance recovered
in the period 81 36 41 159 317
Net present value of total
cash flows 254
Sensitivities
The key sensitivity to the carrying value of trade receivables
is the KRG prioritisation of payments of amounts owed to IOCs. The
KRG has paid 5% of field revenue through 2016. It is the Company's
assumption that the KRG will continue to pay IOCs and if a
combination of oil price, KRG production volumes and KRG cost
reductions increase KRG cash generation, the KRG will increase the
percentage of field revenue paid towards the receivable.
Impairment testing is sensitive to a number of inputs, but
principally: the cash generated from field revenue; and the
percentage of field revenue paid towards the receivable.
Cash generated from field revenue
Cash generated from field revenue is an output of production
volumes in the period, netback derived from Brent oil price and
timing of payments. The sensitivity of the carrying value of the
receivable to changes in cash generated from field revenue is
provided in the table below:
-20% -10% Base +10% +20%
----- ----- ----- ----- -----
Current payment mechanism
(5%) 236 245 254 261 269
Percentage of field revenue paid towards the receivable
Impairment testing assumes that the receivable is recovered from
a percentage of field revenues. In the downside case this would be
nil - either through interrupted production or non-payment by the
KRG. The Company have analysed KRG cash generation and estimate
that it is possible that the KRG will increase payments towards the
receivable in the future. Sensitivity to a stepped increase in
payments is provided below:
% of field revenue NPV at different
paid towards receivable effective interest
rates
------------------------------- -------------------------
2017 2018 2019 2020+ Base Base Base
less 8.3%(1) plus
2.5% 2.5%
------ ------ ------ ------- ------ --------- ------
Current payment
mechanism 5% 5% 5% 5% 269 254 240
Stepped increase
in payments 5% 10% 15% 20% 404 378 355
(1) The weighted average rate is 8.3%, see significant
accounting estimates and judgements for further explanation
Fair value
The fair value of the receivable, based on the current 5%
payment mechanism, has been estimated as circa $200 million. The
Company assess the KRG receivable to be categorised as Level 3
under IFRS13. Fair value has been calculated using the cash flows
assuming 5% of field revenue is paid towards the receivable, from
2P production profiles using the price deck disclosed in the
accounting policies note. The resulting cash flows are discounted
using the estimated appropriate discount rate for the KRG
receivable. The discount rate is estimated by taking the discount
rate calculated for current KRG sales using the approach outlined
in the significant accounting estimates and judgements section of
the accounting policies note and adding an additional premium to
reflect the inferior credit quality of the receivable to the KRG's
current sales.
Amounts owed for export sales marketed by the Federal Government
of Iraq
In addition to the trade receivables owed by the KRG for sales
made principally from mid- 2014, the Company is owed monies for
export sales that were made prior to mid-2014. These were export
sales made through the FGI controlled pipe and consequently the
marketing and collection of cash was controlled by the State Oil
Marketing Organisation (SOMO) of the FGI. No revenue or receivable
has been recognised for these sales because the directors assessed
that it was not probable that economic benefit would flow -
consequently it is also not considered for the purposes of
impairment testing of trade receivables. It is estimated that the
Company is owed circa $300 million excluding interest for these
export sales.
11. Cash and cash equivalents and restricted cash
2016 2015
$m $m
------ ------
Cash and cash equivalents 407.0 455.3
Restricted cash 19.5 -
426.5 455.3
------ ------
Cash is primarily held on time deposit with major financial
institutions or in US Treasury. Restricted cash of $19.5 million is
principally related to the Company's exploration activities in
Morocco.
12. Trade and other payables
2016 2015
$m $m
------ ------
Trade payables 13.6 15.1
Other payables 37.3 15.2
Accruals 49.4 50.3
Deferred consideration for Bina
Bawi asset 82.7 78.0
183.0 158.6
------ ------
Non-current 87.7 78.0
Current 95.3 80.6
------ ------
183.0 158.6
------ ------
The Company's payables are predominantly short-term in nature or
are repayable on demand and, as such, for these payables there is
minimal difference between contractual cash flows related to the
financial liabilities and their carrying amount.
Deferred consideration includes a balance of $82.7m originally
recognised at its discounted fair value. The nominal value of this
balance is $145.0 million and its payment is contingent on gas
production at the Bina Bawi asset meeting a certain volume
threshold. The unwind of the deferred consideration is capitalised
against the asset and the balance reassessed at each balance sheet
date.
13. Deferred income
2016 2015
$m $m
----- -----
Non-current 39.2 46.0
Current 5.6 3.0
44.8 49.0
----- -----
Deferred income relates to payments received in the past
relating to future revenue and is recognised in line with the
explanation provided in the revenue section of the accounting
policies note.
14. Provisions
2016 2015
$m $m
------ -----
Balance at 1(st) January 25.2 19.4
Interest unwind 0.9 0.8
Additions 0.6 5.0
Reversal (3.7) -
Balance at 31 December 23.0 25.2
------ -----
Non-current 23.0 25.2
Current - -
------ -----
Balance at 31 December 23.0 25.2
------ -----
Provisions cover expected decommissioning and abandonment costs
arising from the Company's assets. The decommissioning and
abandonment provision is based on the Company's best estimate of
the expenditure required to settle the present obligation at the
end of the period discounted at 4%. The cash flows relating to the
decommissioning and abandonment provisions are expected to occur
between 2031 and 2039.
15. Borrowings and net debt
Net
1 Bond other
Jan buy Discount changes 31 Dec
2016 back unwind in cash 2016
$m $m $m $m $m
-------- ------- --------- --------- --------
2014 Bond issue
maturing May 2019 694.1 (54.6) 8.7 - 648.2
Cash (455.3) 35.4 - 12.9 (407.0)
Net Debt 238.8 (19.2) 8.7 12.9 241.2
-------- ------- --------- --------- --------
In March 2016, the Company repurchased $55.4 million nominal
value of its own bonds for net cash of $35.4m. The purchased bonds
had a book value of $54.6 million and have been retained by the
Company with it being most likely that the bonds will be cancelled.
Consequently Company net debt was reduced by $19.2 million and the
$730 million bond is reported net of the $55.4m nominal value of
bonds held by the Company. The bond is reported net of unamortised
discount on issuance and issuance costs. The fair value of the net
$675m bond at 31 December 2016 was $549 million (FY2015: fair value
of $730 million bond was $511m).
Net
New Merger other 31
1 Jan Bond of Discount changes Dec
2015 Issue bonds unwind in cash 2015
$m $m $m $m $m $m
-------- -------- --------- --------- --------- --------
2014 Bond issue
maturing May 2019 491.4 - 196.2 6.5 - 694.1
2015 Bond issue
maturing May 2019 - 196.2 (196.2) - - -
Cash (489.1) (196.2) - - 230.0 (455.3)
Net Debt 2.3 - - 6.5 230.0 238.8
-------- -------- --------- --------- --------- --------
On 10 April 2015, the Company issued a new $230m bond with a
maturity of May 2019 and an annual coupon rate of 7.5% payable
twice annually. The new bond was then merged with the existing
$500m bond maturing May 2019, resulting in a merged $730m nominal
value bond with a maturity date of May 2019 paying coupon of
7.5%.
16. Financial Risk Management
Financial risk factors
Credit risk
Credit risk is managed on a Company basis, except for credit
risk relating to trade receivable balances, which is explained in
significant accounting estimates and judgements in note 1.
Credit risk arises from cash and cash equivalents, trade and
other receivables and other assets. The carrying amount of
financial assets represents the maximum credit exposure. The
maximum credit exposure to credit risk at 31st December was:
2016 2015
$m $m
---------------------------- ----- -----
Trade and other receivables 265.8 440.1
Cash and cash equivalents 407.0 455.3
672.8 895.4
---------------------------- ----- -----
Credit risk for trade receivables is explained in note 10. There
are no other receivables overdue at the period end and no provision
for doubtful debt has been made. Cash is deposited in US treasury
bills or term deposits with banks that are assessed as appropriate
based on, among other things, sovereign risk, CDS pricing and
credit rating.
Liquidity risk
The Company is committed to ensuring it has sufficient liquidity
to meet its payables as they fall due. At 31 December 2016 the
Company had cash and cash equivalents of $407.0 million (2015:
$455.3 million) - see note 11.
Currency risk
As substantially all of the Company's transactions are measured
and denominated in US dollars, the exposure to currency risk is not
material and therefore no sensitivity analysis has been
presented.
Interest rate risk
The Company reported borrowings of $648.2 million (2015: $694.1
million) in the form of a bond maturing in May 2019, with fixed
coupon interest payable of 7.5% on the nominal value of $675
million. Although interest is fixed on existing debt, whenever the
Company wishes to borrow new debt or refinance existing debt, it
will be exposed to interest rate risk. A 1% increase in interest
rate payable on a balance similar to the existing debt of the
Company would result in an additional cost of $6.8m per annum.
Capital management
The Company manages its capital to ensure that it remains
sufficiently funded to support its business strategy and maximise
shareholder value. The Company's short term funding needs are met
principally from the cash flows generated from its operations and
available cash of $407.0 million.
17. Share capital
Suspended
Voting Voting Total
Ordinary Ordinary Ordinary
shares shares Shares
------------ ----------- -----------
At 1 January 2015 - fully
paid(1) 33,538,301 246,709,897 280,248,198
Conversion of suspended ordinary
voting shares on 13 February
2015 as a result of a sale
of 2,000,000 and 1,400,000
voting ordinary shares by
affiliated shareholders to
third parties on 10 December
2014 and 16 December 2014
respectively (3,916,616) 3,916,616 -
At 31 December 2015 and 1
January 2016 29,621,685 250,626,513 280,248,198
Conversion of suspended voting
ordinary shares on 24 February
2016 as a result of a sale
of 27,339,017 voting ordinary
shares by affiliated shareholders
to third parties between
22 September 2015 and 13
February 2016 (29,621,685) 29,621,685 -
At 31 December 2016 - fully
paid(1) - 280,248,198 280,248,198
------------ ----------- -----------
1. Voting ordinary shares includes 1,853,008 (2015: 1,865,720) treasury shares
On the sale of voting ordinary shares from an affiliated
shareholder to a third party, the affiliated shareholders have a
right of conversion of suspended voting ordinary shares to voting
ordinary shares in order to maintain their voting ordinary share
percentage at just below 30% of the Company. Details of those sales
and resulting conversions are set out below.
Between the 22 September 2015 and 13 February 2016 27,339,017
voting ordinary shares were transferred from affiliated
shareholders to third parties. On 24 February 2016 29,621,685
suspended voting ordinary shares were converted to ordinary shares
in accordance with the terms of the suspended voting ordinary
shares.
On 13 February 2015 3,916,616 suspended voting ordinary shares
were converted to voting ordinary shares in accordance with the
terms of the suspended voting ordinary shares.
There have been no changes to the authorised share capital since
it was determined to be 10,000,000,000 ordinary shares of GBP0.10
per share.
18. Share based payments
The Company has three share-based payment plans: a performance
share plan, restricted share plan and a share option plan. The main
features of these share plans are set out below.
Key features PSP RSP SOP
------------ ----------------------- --------------------- -----------------------
Form of Performance Restricted Market value
awards shares. shares. options.
The intention The intention Exercise price
is to deliver is to deliver is set equal
the full value the full value to the average
of vested shares of shares share price
at no cost to at no cost over a period
the participant to the participant of up to 30
(e.g. as conditional (e.g. as conditional days to grant.
shares or nil-cost shares
options). or nil-cost
options).
------------ ----------------------- --------------------- -----------------------
Performance Performance Performance Performance
conditions conditions will conditions conditions may
apply. For awards may or may or may not
granted to date, not apply. apply. For awards
these are based For awards granted to date,
on relative granted there are
TSR measured to date, there no performance
against a Group are no conditions.
of industry performance
peers over a conditions.
three-year period.
------------ ----------------------- --------------------- -----------------------
Vesting Awards will Awards typically Awards typically
period vest when the vest over three vest after three
Remuneration years. years. Options
Committee determine are exercisable
whether the until the 10th
performance anniversary
conditions of the grant
have been met date.
at the end
of the performance
period.
------------ ----------------------- --------------------- -----------------------
Dividend Provision of Provision of Provision of
equivalents additional cash/shares additional additional cash/shares
to reflect dividends cash/shares to reflect dividends
over the vesting to reflect over the vesting
period may dividends over period may
or may not the vesting or may not
apply. For awards period may apply. For awards
granted to date, or may not granted to date,
dividend equivalents apply. For dividend equivalents
do not apply. awards granted do not apply.
to date, dividend
equivalents
do
not apply.
------------ ----------------------- --------------------- -----------------------
In 2016, awards were made under the performance share plan and
restricted share plan, no awards were made under the share option
plan, the numbers of outstanding shares under the PSP, RSP and SOP
as at 31st December 2016 are set out below:
PSP RSP SOP CEO
Options Options award
(nil (nil (nil
cost) cost) cost)
------------ ---------- ---------- ----------
Outstanding at the beginning
of the year 1,748,823 968,138 325,727 375,000
Granted during the year 3,399,136 2,118,008 - -
Forfeited / lapsed during
the year (794,621) (334,429) (89,131) -
Exercised during the - (275,308) - -
year
------------ ---------- ---------- ----------
Outstanding at the end
of the year 4,353,338 2,476,409 236,596 375,000
------------ ---------- ---------- ----------
Exercisable at the end
of the year 102,131 63,802 140,088 93,750
The range of exercise prices for share options outstanding at
the end of the period is nil to 1,046.00p. The weighted average
remaining contractual life of the outstanding share options is 2
years. The blended exercise price for SOPs is 890p.
Fair value of options granted has been measured either by use of
the Black-Scholes pricing model or by use of a formula based on
past calculations. The model takes into account assumptions
regarding expected volatility, expected dividends and expected time
to exercise. In the absence of sufficient historical volatility for
the Company, expected volatility was estimated by analysing the
historical volatility of FTSE-listed oil and gas producers over the
three years prior to the date of grant. The expected dividend
assumption was set at 0%. The risk-free interest rate incorporated
into the model is based on the term structure of UK Government zero
coupon bonds. The inputs into the fair value calculation for RSP
and PSP awards granted in 2015 and fair values per share using the
model were as follows:
RSP RSP RSP PSP PSP
7/5/2016 8/5/2016 19/9/2016 7/5/2016 8/5/2016
--------- --------- ---------- --------- ---------
Share price at grant
date 125p 110p 110p 125p 125p
Exercise price - - - - -
Fair value on measurement
date 125p 110p 110p 32p 32p
1-3 1-3 1-3 3-6 3-6
Expected life years years years years years
Expected dividends - - - - -
Fair value on measurement
date 125p 110p 110p 32p 32p
Share price at balance
sheet date 72p 72p 72p 72p 72p
Change in share price
between grant date
and 31 December 2016 -36% -23% -23% -36% -36%
--------- --------- ---------- --------- ---------
The weighted average fair value for PSP awards granted in the
period is 32p and for RSP awards granted in the period is 125p.
Total share based payment charge for the year was $7.5m
(2015:$2.9 million), which is fixed using the share price at the
date of grant. In the previous year the charge included the
reversal of previously expensed costs principally caused by the
non-vesting of options.
19. Capital commitments and operating lease commitments
Under the terms of its PSCs and JOAs, the Company has certain
commitments that are generally defined by activity rather than
spend. The Company's capital programme for the next few years is
explained in the operating review and is in excess of the activity
required by its PSCs and JOAs.
The Company leases temporary production and office facilities
under operating leases. During the period ended 31 December 2016
$3.8 million (2015: $4.0 million) was expensed to the statement of
comprehensive income in respect of these operating leases.
Drill rigs are leased on a day-rate basis for the purpose of
drilling exploration or development wells. The aggregate payments
under drilling contracts are determined by the number of days
required to drill each well and are capitalised as exploration or
development assets as appropriate.
The Company had no material outstanding commitments for future
minimum lease payments under non-cancellable operating leases.
20. Related parties
The directors have identified related parties of the Company
under IAS24 as being: the shareholders; members of the Board; and
members of the executive committee, together with the families and
companies, associates, investments and associates controlled by or
affiliated with each of them. The compensation of key management
personnel including the directors of the Company is as follows:
2016 2015
$m $m
----------------------------------------- ---- ----
Board remuneration 1.0 1.8
Key management emoluments and short-term
benefits 7.4 9.0
Share-related awards 0.1 1.6
8.5 12.4
---- ----
There are no other significant related party transactions.
21. Subsidiaries and joint arrangements
For the period ended 31(st) December 2016 the principal
subsidiaries and joint operations of the Company were the
following:
Ownership
Country % (ordinary
Entity name of Incorporation shares)
-------------------------------------------------- ------------------ ------------
Genel Energy Holding Company Limited (1) Jersey 100
Genel Energy Finance Plc(2) UK 100
Genel Energy Finance 2 Plc(1) Jersey 100
Genel Energy Finance 3 Plc(2) UK 100
Genel Energy Netherlands Holding 1 Cooperatief
B.A. (3) Netherlands 100
Genel Energy Netherlands Holding 2 B.V.
(3) Netherlands 100
Genel Energy International Ltd(4) Anguilla 100
Taq Taq Operating Company Limited(4) BVI 55
Genel Energy Miran Bina Bawi Limited(2) UK 100
Cayman
A&T Petroleum Company Limited(5) Islands 100
Genel Energy Africa Exploration Limited(2) UK 100
Genel Energy Africa Limited (2) UK 100
Genel Energy Exploration 2 Limited(2) UK 100
Genel Energy Limited(2) UK 100
Genel Energy Somaliland Limited(2) UK 100
Genel Energy Gas Company Limited(1) UK 100
Phoenicia Energy Company Limited(6) Malta 100
Genel Energy UK Services Limited(2) UK 100
Genel Energy Yonetim Hizmetleri Anonim Sirketi(7) Turkey 100
Genel Energy Petroleum Services Limited(2) UK 100
Isle of
Barrus Petroleum Limited(8) Man 100
Barrus Petroleum Cote d'Ivoire Sarl(9) Cote d'Ivoire 100
Taq Taq Petoleum Refinery Company Limited(10) BVI 100
Taq Taq Drilling Company Limited(11) BVI 55
--------------------------------------------------- ------------------- ------------
(1) Registered office is 12 Castle Street, St Helier, Jersey JE2
3RT
(2) Registered office is Fifth floor, 36 Broadway, London SW1H
0DB
(3) Registered office is Prins Bernhardplein 200, 1097 JB,
Amsterdam, Netherlands
(4) Registered office is PO Box 1338. Maico Building, The
Valley, Anguilla and is a joint operation service company through
which the Company jointly operates the Taq Taq PSC with its
partner
(5) Registered office is PO box 309 Ugland House, Grand Cayman,
KY1-1104, Cayman Islands
(6) Registered office is 85 St John Street, Valletta, VLT 1165,
Malta
(7) Registered office is Next Level İ Merkezi, , Eski ehir Yolu,
, Dumlupınar Bulvarı, No:3A-101, Sö ütözü, Ankara, 06500,
Turkey
(8) Registered office is 6 Hope Street, Castletown, IM9 1AS,
Isle of Man
(9) Registered office is 7 Boulevard Latrille Cocody, 25 B.P.
945 Abidjan 25, Cote d'Ivoire
(10) Registered office is Ellen L Skelton Building, Fishers
Lane, Road Town, Tortola, BVI
(11) Registered office is 3(rd) Floor, Geneva Place, Waterfront
Drive, PO Box 3175, Road Town, Tortola, BVI
22. Annual report
Copies of the 2016 annual report will be despatched to
shareholders in April 2017 and will also be available from the
Company's registered office at 12 Castle Street, St Helier, Jersey
JE2 3RT and at the Company's website- www.genelenergy.com.
23. Statutory accounts
The financial information for the year ended 31 December 2016
contained in this preliminary announcement has been audited and was
approved by the board on 29 March 2017. The financial information
in this statement does not constitute the Company's statutory
accounts for the years ended 31 December 2016 or 2015. The
financial information for 2016 and 2015 is derived from the
statutory accounts for 2015, which have been delivered to the
Registrar of Companies, and 2016, which will be delivered to the
Registrar of Companies and issued to shareholders in April 2017.
The auditors have reported on the 2016 and 2015 accounts; their
report was unqualified and did not include a reference to any
matters to which the auditors drew attention by way of emphasis
without qualifying their report. The statutory accounts for 2016
are prepared in accordance with International Financial Reporting
Standards (IFRS) as adopted for use in the European Union. The
accounting policies (that comply with IFRS) used by Genel Energy
plc are consistent with those set out in the 2015 annual
report.
This information is provided by RNS
The company news service from the London Stock Exchange
END
FR SEAFAUFWSEED
(END) Dow Jones Newswires
March 30, 2017 02:01 ET (06:01 GMT)
Genel Energy (LSE:GENL)
Historical Stock Chart
From Jun 2024 to Jul 2024
Genel Energy (LSE:GENL)
Historical Stock Chart
From Jul 2023 to Jul 2024
